Text

Emergency Plan Implementing Procedures Manual Volume C Revision 2003-08
	ML032410149
Person / Time
Site:	Oconee
Issue date:	08/26/2003
From:	Rosalyn Jones; Duke Power Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	-RFPFR
	Download: ML032410149 (156)
	v • d • e

Duke R. A.

JONES

rPowero Vice President A Duke Energy Company Duke Power 29672 Oconee Nuclear Site 7800 Rochester Highway Seneca, SC 29672 864 885 3158 864 885 3564 fax August 26, 2003 U. S. Nuclear Regulatory Commission Document Control Desk Washington, D. C.

20555

Subject:

Oconee Nuclear Station Docket Nos. 50-269, -270, -287 Emergency Plan Implementing Procedures Manual Volume C Revision 2003-08 Please find attached for your use and review copies of the revision to the Oconee Nuclear Station Emergency Plan: Volume C Revision 2003-08, August 2003.

This revision is being submitted in accordance with 10 CFR 50-54(q) and does not decrease the effectiveness of the Emergency Plan or the Emergency Plan Implementing Procedures.

Any questions or concerns pertaining to this revision please call Rodney Brown, Emergency Planning Manager at 864-885-3301.

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

Very t

ours, R.

. Jies.

VP, Ocon e Nuclear Site xc:

(w/2 copies of attachments)

Mr. Luis Reyes, Regional Administrator, Region II U. S. Nuclear Regulatory Commission 61 Forsyth St., SW, Suite 24T23 Atlanta, GA 30303 w/copy of attachments Mr. James R. Hall Rockville, Maryland (w/o Attachments, Oconee Nuclear Station)

NRC Resident Inspector J. R. Brown, Manager, Emergency Planning AtY www. duke-energy. com

August 26, 2003 OCONEE NUCLEAR SITE INTRASITE LETTER

SUBJECT:

Emergency Plan Implementing Procedures Volume C, Revision 2003-08 Please make the following changes to the Emergency Plan Implementing Procedures Volume C by following the below instructions.

REMOVE Cover Sheet 2003-07 Table of Contents page 1 & 2 RP/0/B/1000/001 -

02/11/03 RP/0/B/1000/019 -

01/27/03 RP/0/B/1000/020 -

12/11/02 RP/0/B/1000/017 -

11/04/02 EM 5.1,-Rev. 10 -

Engineering Emergency Response Plan -

07/02/02 INSERT Cover Sheet 2003-08 Table of Contents page 1 & 2 RP/0/B/1000/001 -

07/29/03 RP/0/B/1000/019 -

08/25/03 RP/0/B/1000/020 -

08/25/03 RP/0/B/1000/017 -

07/02/03 EM 5.1,-Rev. 11 -

Engineering Emergency Response Plan -

08/19/03

DUKE POWER EMERGENCY PLAN IMPLEMENTING PROCEDURES VOLUME C APPROVED:

W. W. Foster, Manager Safety Assurance 08/26/2003 Date Approved 08/26/2003 Effective Date VOLUME C REVISION 2003-08 AUGUST 2003

VOLUME C TABLE OF CONTENTS HP/IOB/1009/018 HP/OB/10091020 HP/OIB/ 1009/021 HP/OIB/1009/022 RP/O/B/1000/001 RP/OIB/1000/002 RP/O/B/1000/003 A RP/O/B/1000/007 RP/0/B/ 1000/009 RP/0/B/1000/010 RP/O/B/1000/015 A RP/O/B/10001015 B RP/0/B/1000/0 15 C RP/O/B/1000/016 RP/O/B/1000/017 RP/0B/I1000/0 18 RP/O/B/1000/019 RP/IOB/1000/020 RP/OIB/1000/021 RP/0/B/1000/022 RP/I/B/1000/024 RP/0/1B/1000/028 RP/OIB/ 1000/029 RP/O/B/1000/031 Off-Site Dose Projections Estimating Food Chain Doses Under Post Accident Conditions Source Term Assessment Of A Gaseous Release From Non-Routine Release Points On Shift Off-Site Dose Projections Emergency Classification Control Room Emergency Coordinator Procedure ERDS Operation Security Event Procedure For Site Assembly Procedure For Emergency Evacuation/Relocation Of Site Personnel Offsite Communications From The Control Room Offsite Communications From The Technical Support Center Offsite Communications From The Emergency Operations Facility Medical Response Spill Response Core Damage Assessment Technical Support Center Emergency Coordinator Procedure Emergency Operations Facility Director Procedure Operations Interface (EOF)

Procedure For Site Fire Damage Assessment And Repair Protective Action Recommendations Communications & Community Relations World Of Energy Emergency Response Plan Fire Brigade Response Joint Information Center Emergency Response Plan 08/29/02 10/09/98 12/01/97 04/08/03 07/29/03 08/29/02 01/21/03 08/29/02 05/06/03 02/26/03 I

12/11/01 12/11/01 12/11/01 09/12/02 07/02/03 09/30/97 08/25/03 08/25/03 11/04/02 06/02/03 11/10/99 02/17/97 04/22/03 06/12/00 1

Revision 2003-08 August 2003

SRIOtB(2000/00 1 Business Management SSG Functional Area Directive 102 NSC-110 Engineering Manual 5.1 Human Resources Procedure Radiation Protection Manual Section 11.3 Radiation Protection Manual Section 11.7 Safety Assurance Directive 6.1 Safety Assurance Directive 6.2 Training Division VOLUME C TABLE OF CONTENTS Standard Procedure For Public Affairs Response To The Emergency Operations Facility Business Management Emergency Plan SSG Emergency Response Plan - ONS Specific Nuclear Supply Chain - SCO Emergency Response Plan Engineering Emergency Response Plan ONS Human Resources Emergency Plan Off-Site Dose Assessment And Data Evaluation Environmental Monitoring For Emergency Conditions Safety Assurance Emergency Response Organization Emergency Contingency Plan Training Division Emergency Response Guide DTG-007 05/29/03 10/15/02 04/30/03 04/02/01 08/19/03 01/07/02 04/06/99 11126101 11/11/02 03/27/00 05/01/03 I'

2 Revision 2003-08 August 2003

NSD 703 (R04-01)

Duke Power Company PROCEDURE PROCESS RECORD (I)IDNo. RP/O/B/1000/001 Revision No. 014 INFORMATION ONLY

'IREPARATION (2)

Station (3)

Procedure Title _

OCONEE NUCLEAR STATION Emergency Classification (4)

Prepared By Rodney Brown (Signature) 4 I'-

(5)

Requires NSD 228 Applicability Determination?

0 Yes (New procedure or revision with major changes) 0 No (Revision with minor changes)

Cl No (To incorporateprevio ppoechanvs)

(6)

Reviewed By (QR)

Cross-Disciplinary Review By (QR)NA_5 Reactivity Mgmt Review By (QR)NA Mgmt Involvement Review By (Ops Supt) NA (7) Additional Reviews Reviewed By Reviewed By Temporary Approval (if necessary)

Date 07/29/2003 Date Z Date

-Date

_Date J.,k4/.

I2~gg Date Date By (OSM/QR)

Date By

_(QR)

Date (9)

Approved By L

Date p7/Z PERFORMANCE (Compare with control copy every 14 calendar days while work is being performed)

(10) Compared with Control Copy Date Compared with Control Copy Date Compared with Control Copy Date (11) Date(s) Performed Work Order Number (WO#)

COMPLETION (12) Procedure Completion Verification:

o Unit 0 Unit 1 0 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?

0 Yes D NA Data sheets attached, completed, dated, and signed?

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

o Yes 0 NA Procedure requirements met?

Verified By Date (13) Procedure Completion Approved Date (14) Remarks (Attach additional pages)

Duke Power Company Oconee Nuclear Site Emergency Classification Reference Use Procedure No.

RP/OIB/1000/001 Revision No.

014 Electronic Reference No.

OX002WOS

RP/O/B/1000/001 Page 2 of 6 Emergency Classification NOTE:

This procedure is an implementing procedure to the Oconee Nuclear Site Emergency plan and must be forwarded to Emergency Planning within seven (7) working days of approval.

1. Symptoms 1.1 This procedure describes the immediate actions to be taken to recognize and classify an emergency condition.

1.2 This procedure identifies the four emergency classifications and their corresponding Emergency Action Levels (EALs).

1.3 This procedure provides reporting requirements for non-emergency abnormal events.

1.4 The following guidance is to be used by the Emergency Coordinator/EOF Director in assessing emergency conditions:

1.4.1 The Emergency Coordinator/EOF Director shall review all applicable initiating events to ensure proper classification.

1.4.2 The BASIS Document (Volume A, Section D of the Emergency Plan) is available for review if any questions arise over proper classification.

1.4.3 IF An event occurs on more than one unit concurrently, THEN The event with the higher classification will be classified on the Emergency Notification Form.

A. Information relating to the problem(s) on the other unit(s) will be captured on the Emergency Notification Form as shown in RP/O/B/1000/015A, (Offsite Communications From The Control Room),

RP/OJB/1000/015B, (Offsite Communications From The Technical Support Center) or RP/OIB/1000/015C, (Offsite Communications From The Emergency Operations Facility).

1.4.4 IF An event occurs, AND A lower or higher plant operating mode is reached before the Classification can be made, THEN The classification shall be based on the mode that existed at the time the event occurred.

2

RP/O/B/1000/001 Page 3 of 6 1.4.5 The Fission Product Barrier Matrix is applicable only to those events that occur at Hot Shutdown or higher.

A. An event that is recognized at Cold Shutdown or lower shall not be classified using the Fission Product Barrier Matrix.

1. Reference should be made to the additional enclosures that provide Emergency Action Levels for specific events (e.g., Severe Weather, Fire, Security).

1.5 IF THEN A transient event should occur, Review the following guidance:

1.5.1 IF AND THEN 1.5.2 IF An Emergency Action Level (EAL) identifies a specific duration The Emergency Coordinator/EOF Director assessment concludes that the specified duration is exceeded or will be exceeded, (i.e.;

condition cannot be reasonably corrected before the duration elapses),

Classify the event.

A plant condition exceeding EAL criteria is corrected before the specified duration time is exceeded, THEN The event is NOT classified by that EAL.

A. Review lower severity EALs for possible applicability in these cases.

NOTE:

Reporting under 10CFR50.72 may be required for the following step. Such a condition could occur, for example, if a follow up evaluation of an abnormal condition uncovers evidence that the condition was more severe than earlier believed.

1.5.3 IF AND THEN A plant condition exceeding EAL criteria is not recognized at the time of occurrence, but is identified well after the condition has occurred (e.g.; as a result of routine log or record review)

The condition no longer exists, An emergency shall NOT be declared.

3

RP/OIB/1000/001 Page 4 of 6 1.5.4 IF An emergency classification was warranted, but the plant condition has been corrected prior to declaration and notification, THEN The Emergency Coordinator must consider the potential that the initiating condition (e.g.; Failure of Reactor Protection System) may have caused plant damage that warrants augmenting the on shift personnel through activation of the Emergency Response Organization.

A. IF An Unusual Event condition exists, THEN Make the classification as required.

a

1.

The event may be terminated in the same notification or as a separate termination notification.

B.

IF An Alert, Site Area Emergency, or General Emergency condition exists, THEN Make the classification as required, AND Activate the Emergency Response Organization.

1.6 Emergency conditions shall be classified as soon as the Emergency Coordinator/EOF Director assessment determines that the Emergency Action Levels for the Initiating Condition have been exceeded.

2. Immediate Actions 2.1 Determine the operating mode that existed at the time the event occurred prior to any protection system or operator action initiated in response to the event.

2.2 IF The unit is at Hot Shutdown or higher AND The condition/event affects fission product barriers, THEN GO TO Enclosure 4.1, (Fission Product Barrier Matrix).

2.2.1 Review the criteria listed in Enclosure 4.1, (Fission Product Barrier Matrix) and make the determination if the event should be classified.

4

RP/O/B/1000/001 Page 5 of 6 2.3 Review the listing of enclosures to determine if the event is applicable to one of the categories shown.

2.3.1 IF One or more categories are applicable to the event, 2.3.2 THEN Refer to the associated enclosures.

2.3.3 Review the EALs and determine if the event should be classified.

A. IF An EAL is applicable to the event, THEN Classify the event as required.

2.4 IF The condition requires an emergency classification, THEN GO TO RP/0/B/1000/002, (Control Room Emergency Coordinator Procedure) Subsequent Actions.

2.5 Continue to review the emergency conditions to assure the current classification continues to be applicable.

3. Subsequent Actions 3.1 Continue to review the emergency conditions to assure the current classification continues to be applicable.

5

RP/0/B1000/001 Page 6 of 6

4. Enclosures Enclosures 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.11 4.12 Fission Product Barrier Matrix System Malfunctions Abnornal Rad Levels/Radiological Effluents Loss Of Shutdown Functions Loss of Power Fires/Explosions And Security Actions Natural Disasters, Hazards, And Other Conditions Affecting Plant Safety Radiation Monitor Readings For Emergency Classification Unexpected/Unplanned Increase In Area Monitor Readings Definitions Operating Modes Defined In Improved Technical Specifications Instructions For Using Enclosure 4.1 Page Number 7

8 10 12 14 15 16 19 20 21 25 26 6

(

End' te 4.1 Fission Product Barrier Matrix RP//B/

J/

Page of 1 DETERMINE THE APPROPRIATE CLASSIFICATION USING THE TABLE BELOW:

CIRCLE EALS CHOSEN. ADD POINTS TO CLASSIFY. (SEE NOTE BELOW) adotra ARR$Q lS-57j ifONA

§iM7)TBARR S ' t Potential Loss (4 Points)

Loss (5 Points)

Potential Loss (4 Points)

Loss (5 Points)

Potential Loss I Point)

Loss (3 Points)

RCS Leakrate > Makeup capacity RCS Leak rate > available makeup Average of the 5 highest Average of the 5 highest CETC CETC 2 12000 F 2 15 minutes Rapid unexplained containment of one HPI pump in normal capacity as indicated by a loss of CETC 2 12000 F OR pressure decrease after increase makeup mode (approx. 160 gpm) subcooling 2

700° F CETC 700 F 2 15 minutes with OR with Letdown isolated.

a valid RVLS reading 0 containment pressure or sump level not consistent with LOCA SGTR > Makeup capacity of one Valid RVLS reading of 0" Coolant activity 2 300 jiCi/ml DEl RB pressure 59 psig Failure of secondary side of SG HPI pump in normal makeup AR results in a direct opening to the mode (approx. 160 gpm) with RB pressure > 10 psig and no environment with P/S leakage 10 Letdown isolated.

NOTE: RVLS is NM RBCU or RBS gpm in the same SG Entry into the PTS (Pressurized I RIA 57/58 reading 2 1.0 R/hr valid if one or more Hours Since SD RIA57/58 I

Hours Since SD R1A57/58 lHr Failure of secondary side of SG Thermal Shock) Operation RCPs are running QR if results in a direct opening to the l NOTE'-

is ecunder2RlA57reading216R/hr LPIpump(s)are 0-<0.5 a 300/150 0 -

0.5 2

1800/860 environment withP/Sleakage 10 N T TSis e tr dunder r n i g either of the following:

2 RIA 58 reading >- 1.0 R/hnnng gpm in the other SG A cooldown below 400 0F @

0.5 - < 2.0

> 80/40 0.5 - < 2.0 2400/195 Feeding SG with secondary side

> 100F/hr. has occurred.

3RIA 57/58 reading 2 1.0 R/hr failure from the affected unit l

HPI has operated in the 2.0 - 8.0 232/16 2.0 - 8.0 2 280/130 l*

HPI has operated in the injection mode while NO RCPs were operating.

HPI Forced Cooling RCS pressure spike 2 2750 psig Hydrogen concentration 9%

Containment isolation is incomplete and a release path to the environment exists Emergency Coordinator/EOF Emergency Coordinator/EOF Emergency Coordinator/EOF Emergency Coordinator/EOF Director Emergency Coordinator/EOF Emergency Coordinator/EOF Director judgment Director judgment Director judgment judgment Director judgment Director judgment UNUSUAAL EVNT (3 Total Points)

ALERT (4-6 Total Points)

SITE AREA EMERGENCY (7-10 Total Points)

GENERAL EMERGENCY (11-13 Total Points)

OPERATING MODE:

1, 2,3,4 OPERATING MODE-1, 2,3,4 OPERATING MODE: 1, 2, 3, 4 OPERATING MODE:

1, 2,3,4 Loss of any two barriers Any potential loss of Containment Any potential loss or loss of the Fuel Clad Loss of any two barriers and potential loss of the Loss of one barrier and potential loss of either third barrier Any loss of containment Any potential loss or loss of the RCS RCS or Fuel Clad Barriers Loss of all three barriers Potential loss of both the RCS and Fuel Clad Barriers INITIAL NOTIFICATION REQUIREMENTS:

INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1,23,4 NOTIFY 1,2,3,4 NOTIFY 1,2,3,4 NOTIFY 1,2,3,4 NOTE:

An event with multiple events could occur which would result in the conclusion that exceeding the loss or potential loss threshold is JMfr fl.ENI (i.e., within 1-3 hours). In this IMMINENT LOSS situation, use judgment and classify as if the thresholds are exceeded.

7

(

Encl-"'re 4.2 Systems (

functions RP/O/B/ TO 1 Page 1lot" UNUSUAL EVENT s~~~~Ml

1. RCS LEAKAGE (BD 14)

OPERATING MODE: 1, 2,3,4 A.

Unidentified leakage 2 10 gpm B.

Pressure boundary leakage 2 10 gpm C.

Identified leakage 2 25 gpm

2.

UNPLANNED LOSS OF MOST OR ALL SAFETY SYSTEM ANNUNCIATION/

INDICATION IN CONTROL ROOM FOR > 15 MINUTES (BD 15)

OPERATING MODE:

1, 2,3,4 A.l Unplanned loss of > 50% of the following annunciators on one unit for> 15 minutes:

UnIts 1 & 3 I SAI-9,14-16, and 18 3 SAI-9, 14-16, and 18 1,

UNPLANNED LOSS OF MOST OR ALL SAFETY SYSTEM ANNUNCIATIONI INDICATION IN CONTROL ROOM (BD 19)

OPERATING MODE:

1, 2,3,4 A.1 Unplanned loss of > 50% of the following annunciators on one unit for > 15 minutes:

Units I & 3 I SAI-9,14-16, and 18 3 SAI-9, 14-16, and 18 2 SAI-9,14-16 AND UNL2 2 SAI-9,14-16 AND A.2 Loss of annunciators or indicators requires additional personnel (beyond normal shift complement) to safely operate the unit

3.

INABILITY TO REACH REQUIRED SHUTDOWN WITHIN LIMITS (BD 16)

OPERATING MODE: 1, 2, 3,4 A.

Required operating mode not reached within TS LCO action statement time (CONTINUED)

A.2 Loss of annunciators indicators requires additional personnel (beyond normal shift complement) to safely operate the unit AND A.3 Significant plant transient in progress QRa A.4 Loss of the OAC and ALL PAM indications (END)

1.

INABILITY TO MONITOR A SIGNIFICANT TRANSIENT IN PROGRESS (BD21)

OPERATING MODE: 1, 2,3,4 A. I Unplanned loss of > 50% of the following annunciators on one unit for > 15 minutes:

Units I & 3 I SAI-9,14-16, and 18 3 SAI-9, 14-16, and 18 Unit 2 2 SAI-9,14-16 AND A.2 A significant transient is in progress AND A.3 Loss of the OAC and ALL PAM indications AND A.4 Inability to directly monitor any one of the following functions:

1.

Subcriticality

2.

Core Cooling

3.

Heat Sink

4.

RCS Integrity

5.

Containment Integrity

6.

RCS Inventory (END)

INITIAL NOTIFICATION REQUIREMENTS:

INIAL NOTIFICATION REQUIREMENTS:

INITIAL NOTIFICATION REQUIREMENTS:

tNITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 8

(

Encdevire 4.2 Systems(

Ifunctions RP/O/BI"/,00 1 Page 2d

4. UNPLANNED LOSS OF ALL ONSITE OR OFFSITE, COMMUNICATIONS (BD 17)

OPERATING MODE: All A. Loss of all onsite communications capability (ROLM system, PA system, Pager system, Onsite Radio system) affecting ability to perform Routine operations B. Loss of all onsite communications capability (Selective Signaling, NRC ETS lines, Offsite Radio System, AT&T line) affecting ability to communicate with offsite authorities.

5. FUEL CLAD DEGRADATION (BD 18)

OPERATING MODE: All:

A.

DEI - >5p.Ci/ml (END)

INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1,2,3,4 9

(

Encdr-re 4.3 Abnormal Rad Lev Radiological Effluent RP/O/13

-'/OO 1 Page o 1

ANY UNPLANNED RELEASE OF

1. ANY UNPLANNED RELEASE OF

1.

BOUNDARY DOSE RESULTING FROM

1.

BOUNDARY DOSE RESULTING FROM GASEOUS OR LIQUID RADIOACTIVITY GASEOUS OR LIQUID RADIOACTIVITY ACTUAIJMMINENT RELEASE OF ACTUAL/ IMMINENT RELEASE OF TO THE ENVIRONMENT THAT TO THE ENVIRONMENT THAT GASEOUS ACTiVITY (BD 32)

GASEOUS ACTIVITY (BD 36)

EXCEEDS TWO TIMES THE SLC EXCEEDS 200 TIMES RADIOLOGICAL LIMITS FOR 60 MINUTES OR LONGER TECHNICAL SPECIFICATIONS FOR 15 OPERATING MODE: All OPERATING MODE: All (BD 23)

MINUTES OR LONGER (BD 28)

OPERATNG MOE: Allg-a--

A.

Valid reading on RIA 46 of?~ 2.09E+05 cpm A.

Valid reading on RIA 46 of ? 2.09E+06 cpm OPERATING MODE:

All OPERATING MODE: All for >15 minutes (See Note 2) for 215 minutes (See Note 3)

A.

Valid indication on radiation monitor RIA 33 A.

Valid indication on RIA 46 of 2.09E+04 cpm B.

Valid reading on RIA 57 or 58 as shown on B.

Valid reading on RIA 57 or 58 as shown on of 4.06E+06 cpm for >60 minutes for >15 minutes (See Note I).8 (See Note 2).8 (See Note 3)

(See Note I)

B. Valid

.ndi n on radiation monitor IA 45 B. l RIA 33 HIGH Alarm C.

Dose calculations result in a dose projection at C.

Dose calculations result in a dose projection at B.

Valid indication on radiation monitor RIA 45h ie b u dayo:teste b u d r f

of 2 9.35E+05 cpm for > 60 minutes AN D

the site boundary of the site boundary of.

(See Note 1)

? 00 mRemTEDEor500mRemCDEadult C.l 2 1000mRemTEDE effluent being released exceeds B.2 Liquid effluent being released exceeds 200 thyroid C.

Ulquide~uentbemgreleasedexceedstwo times the level of SLC 16.11.1 for> 15 minutes X

times SLC 16.11.1 for> 60 minutes as as determined by Chemistry Procedure D.

Field survey results indicate site boundary dose C.2 2 5000 mRem CDE adult thyroid determined by Chemiustry Procedure C.

Gaseous effluent being released exceeds 200 rates exceeding 2100 mRad/hr expected to D.

Gaseous effluent being released exceeds two times the level of SLC 16.11.2 for >15 minutes continue for more than one hour D.

Field survey results indicate site boundary dose times SLC 16.11.2 for>60 minutes as as determined by RP Procedure rates exceeding 1000 mRad/hr expected to determined by RP Procedure continue for more than one hour NOTE 1: If monitor reading is sustained

2.

RELEASE OF RADIOACTIVE D. l Analyses of field survey samples indicate adult fOTE the tIe perio indica i

tained MATERIAL OR INCREASES IN thyroid dose commitment of 2 500 mRem AND the required assessments (procedure RADIATION LEVELS THAT IMPEDES CDE (3.84 E7 pCi/ml) for one hour of D. I Analyses of field survey samples indicate adult calculations) cannot be completed within TO MAINTAIN SAFE OPERATION OR thyroid dose commitment of 5000 mRem this period, declaration must be made on the TO ESTABLISH OR MAINTAIN COLD CDE for one hour of inhalation valid Radiation Monitor reading.

SHUTDOWN (BD 30)

NOTE 2: If actual Dose Assessment cannot be completed within 15 minutes, then the l

OPERATING MODE: All valid radiation monitor reading should be NOTE 3: If actual Dose Assessment cannot used for emergency classification.

be completed within 15 minutes, then the A.

Valid radiation reading ? 15 mRad/hr in CR, valid radiation monitor reading should be CAS, or, Radwaste CR used for emergency classification.

B.

Unplanned/unexpected valid area monitor readings exceed limits stated in Enclosure 4.9 (CONTINUJED)

(CONTINUED)

(END)

INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 Assumptions used for calculation of vent nonhtors RIA 45 & 46:

1.

Average annual meteorology (1.672 E-6 sechn). serni-elevated

2.

Vent flow rte 65,000 cn (average daily flow rate)

3.

No credit as taken for vent filration

4.

One hour eleae duration for Unusual Event, 15 minute duration for Alen, Site Arco Emergenc. General Emegency

5.

Geerae Emergeny PAGs a I rent TEDE Asd 5 tern CDE; Site Area Emergency determination is taed on 10% of the General Emergency PAGa

6.

Calculations for monitor readings we baed on wDIse body dose 7

Standard ODC?. guidance together with NUMARC guzimle indicates that effluent releases ae based on Technical Specimfcaslon releases 10

(

EncIe ire 4.3 Abnormal Rad LevT tadiological Effluent RP//B/r")/oo1 Page 2 o

.JT

N________________

=

L3F(

2 UNEXPECTED INCREASE IN PLANT RADIATION OR AIRBORNE CONCENTRATION (BD 25)

1.

MAJOR DAMAGE TO IRRADIATED FUEL OR LOSS OF WATER LEVEL THAT HAS OR WILL RESULT IN THE UNCOVERING OF IRRADIATED FUEL OUTSIDE THE REACTOR VESSEL (BD 31) 1 2.

LOSS OF WATER LEVEL IN THE REACTOR VESSEL THAT HAS OR WILL UNCOVER FUEL IN THE REACTOR VESSEL (BD 35)

OPERATING MODE: All A.

LT 5 reading 14 and decreasing with makeup not keeping up with leakage WITH fuel in the core B.

Uncontrolled water level decrease in the SFP and fuel transfer canal with all irradiated fuel assemblies remaining covered by water C.

I R/hr radiation reading at one foot away from a damaged storage cask located at the ISFSI D.

Valid area monitor readings exceeds limits stated in Enclosure 4.9.

(END)

OPERATING MODE: All A.

Valid RIA 3,6,41, OR 49 HIGH Alarm OPERATING MODE: 5,6 A. I Failure of heat sink causes loss of Cold Shutdown condition AND B.

HIGH Alarm for portable area monitors on the main bridge or SFP bridge A.2 LT 5 indicates 0 inches after initiation of RCS makeup C

Report of visual observation of irradiated fuel uncovered D.

Operators determine water level drop in either the SFP or fuel transfer canal will exceed makeup capacity such that irradiated fuel will be uncovered (END)

B. I Failure of heat sink causes loss of Cold Shutdown condition I.2 Either train ultrasonic level indication less than 0 inches and decreasing after initiation of RCS makeup NOTE: This Initiating Condition is also located in Enclosure 4.4., (Loss of Shutdown Functions). High radiation levels will also be seen with this condition.

(END)

INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1, I3,4 NOTIFY 1,;

23, 4 NOTSY 1, 2,3, 4 11

(

Enc(

re 4.4 Loss of Shutdown Functions RP/O/B/I J/OO1 Page 1 of 2 I I 11 -

1-1--.1. - -.1-1--i-11

-

DMOR&M T -

5*

1

1.

FAILURE OF RPS TO COMPLETE OR INITIATE A Rx SCRAM (D 39)

1.

FAILURE OF RPS TO COMPLETE OR INITIATE A Rx SCRAM (BD 42)

1.

FAILURE OF RPS TO COMPLETE AUTOMATIC SCRAM AND MANUAL SCRAM NOT SUCCESSFUL WITH INDICATION OF CORE DAMAGE (BD 45)

OPERATING MODE 1, 2,3 A. I Valid reactor trip signal received or required WIHOUT automatic scram AND A.1.1 DSS has inserted Control Rod Groups 5,6,7 OR A. 1.2 Manual trip from the Control Room is successful and reactor power is less than 5% and decreasing

2.

INABILITY TO MAINTAIN PLANT IN COLD SHUTDOWN (BD 41)

OPERATING MODE:

1, 2 A. I Valid reactor trip signal received or required WITHOUT automatic scram AND A.2 DSS has NOT inserted Control Rod Groups 5, 6, 7 AND A.3 Manual trip from the Control Room was NOT successful in reducing reactor power to less than 5% and decreasing OPERATING MODE: 1, 2 A. 1 Valid Rx trip signal received or required WITHOUT automatic scram AND A.2 Manual trip from the Control Room was NOT successful in reducing reactor power to < 5%

and decreasing AND A.3 Average of the 5 highest CETCs 1200 Fon ICCM (END)

OPERATING MODE: 5.6 A. I Loss of LPI and/or LPSW AND A.2 Inability to maintain RCS temperature below 2000 F as indicated by either of the following:

A.2.1 RCS temperature at the LPI Pump Suction DR A.2.2 Average of the 5 highest CETCs as indicated by ICCM display OR A.2.3 Visual observation (END) 2.

COMPLETE LOSS OF FUNCTION NEEDED TO ACHIEVE OR MAINTAIN HOT SHUTDOWN (BD 43)

OPERATING MODE:

1,:

A.

Average of the 5 highest CET shown on ICCM B.

Unable to maintain reactor sul C.

SSF feeding SG per EOP (CONTINUED) 2,3,4 Cs 1200F bcritical INIlAL NOTIFICATION REQUIREMENTS:

INITIAL NOTIFICATION REQUIREMENTS:

NITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFYl,2,3,4 NOTIFYl, 2,3,4 NOTIFY 1, 2,3,4 12

(

Enc(

re 4.4 Loss of Shutdown Functions RP/B(

J/o1 Page 2 of 2

3.

LOSS OF WATER LEVEL IN THE REACTOR VESSEL THAT HAS OR WILL UNCOVER FUEL IN THE REACTOR VESSEL (BD 44)

OPERATING MODE, 5,6 A. 1 Failure of heat sink causes loss of Cold Shutdown conditions AMD A.2 LT-5 indicates 0 inches after initiation of RCS Makeup B. I Failure of heat sink causes loss of Cold Shutdown conditions AND B.2 Either train ultrasonic level indication less than 0 inches and decreasing after initiation of RCS makeup (END)

INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1, 2,3,4 13

(

Enc(

.e 4.5 Loss of Power RP/O/B/f

,001 Page of

-0 L

E r

A--gir7 7 77

1.

LOSS OF ALL OFFSITE POWER TO

1.

LOSS OF ALL OFFSITE AC POWER AND

1.

LOSS OF ALL OFFSITE AC POWER AND

1.

PROLONGED LOSS OF ALL OFFSITE ESSENTIAL BUSSFS FOR GREATER LOSS OF ALL ONSITE AC POWER TO LOSS OF ALL ONSITE AC POWER TO POWER AND ONSITF AC POWER THAN 15 MINUTES (BD 47)

ESSENTIAL BUSSES (BD49)

ESSENTIAL BUSSES (BD 51)

(BD 54)

OPERATING MODE: All OPERATING MODE: 5,6 OPERATING MODE: 1, 2,3,4 OPERATING MODE:

1, 2,3,4 Defueled A.1 Loss of all offsite AC power to both the Red A.l MFB I and 2 de-energized A.l MFB I and 2 de-energized and Yellow Busses for > 15 minutes A.1 MFB I and 2 de-energized AND AND AM AND A

A.2 Failure to restore power to at least one MF A.2 SSF fails to maintain Hot Shutdown A.2 Unt auxliarie are eing spplie fromA.2 Failure to restore power to at least one MPH within 15 minutes from the time of loss of A.2 Unit auxiliaries are being supplied from within 15 minutes from the time of loss of both both offsite and onsite AC power AND Keowee or CT5

~~~~~~~offsite and onsite AC power

2.

UNPLANNED LOSS OF REQUIRED DC

2.

AC POWER CAPABILITY TO

2.

LOSS OF ALL VITAL DC POWER A.3 At least one of the following conditions exist:

POWER FOR GREATER THAN 15 ESSENTIAL BUSSES REDUCED TO A (BD 52)

MINUTES (D

48)

SINGLE SOURCE FOR GREATER THAN A.3.1 Restoration of power to at least one 15 MINUTES (BD 50)

OPERATING MODE: 1, 2, 3,4 MFB within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is NOT likely OPERATING MODE: 5, 6 OPERATING MODE:

I, 2, 3, 4 A. I Unplanned loss of vital DC power to required OR A. I Unplanned loss of vital DC power to required DC busses as indicated by bus voltage less than A.3.2 Indications of continuing DC busses as indicated by bus voltage less A.

AC power capability has been degraded to a 110 VDC degradation of core cooling based than I110 VDC single power source for > 15 mnutes due to the on Fssion Product Barrierl loss of all but one of:

AND monitoring P Unit Normal Transformer A.2 Failure to restore power to at least one required (END)

A.2 Failure to restore power to at least one required UntSU Transformer DC bus within 15 minutes from the time of lossl DC bus within 15 minutes from the time of loss Another Unit SU Transformer CT4 (END)l (END) l~~~~~

(END)

INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 14

(

Encdr-ire 4.6 Fires/Explosion; i Security Actions RP/O/B/

')/OO 1 Page 1 o luNUSAL IVENT ALERT

-j Mru~

1.

FIRES/EXPLOSIONS WITHIN THE PLANT (BD 57)

1.

FIRE/EXPLOSION AFFECTING OPERABILITY OF PLANT SAFETY SYSTEMS REQUIRED TO ESTABLISH/MAINTAIN SAFE SHUTDOWN (BD 59)

1.

SECURITY EVENT IN A PLANT VITAL AREA (BD 61)

OPERATING MODE: All

1.

SECURITY EVENT RESULTING IN LOSS OF ABILITY TO REACH AND MAINTAIN COLD SHUTDOWN (RD 62)

OPERATING MODE: All OPERATING MODE: All OPERATING MODE: All L

NOTE: Within the plant means Turbine Building, Auxiliary Building, Reactor Building, Keowee Hydro.

NOTE: RP(0B/000/007, (Security Event),

shall be used in conjunction with all security related emergency classifications NOTE: RP/01B/100/007, (Security Event),

shall be used in conjunction with all security related emergency classifications A.

Fire within the plant not extinguished within 15 minutes of Control Room notification or verification of a Control Room alarm NOTE: Only one train of a system needs to be affected or damaged in order to satisfy this condition.

A. I Fire/explosions AND A.1.1 Affected safety-related system parameter indications show degraded performance OR B.

Unanticipated explosion within the plant resulting in visible damage to permanent structures/equipment

2.

CONFIRMED SECURITY THREAT INDICATES POTENTIAL DEGRADATION IN THE LEVEL OF SAFETY OF PLANT (RD 58)

OPERATING MODE: All NOTE: RP/0/B/1000/007, (Security Event), shall be used in conjunction with all security related emergency classifications.

A.

Intrusion into any of the following plant areas by a hostile force:

Reactor Building Auxiliary Building Keowee Hydro B.

Bomb detonated in any of the following areas:

Keowee Hydro Keowee Dam ISFSI Reactor Building Auxiliary Building SSF (END)

A.

B.

Loss of physical control of the control room due to security event Loss of physical control of the Aux Shutdown panel and the SSF due to a Security Event (END)

A.1.2 Plant personnel report visible damage to permanent structures or equipment required for safe shutdown 2

SECURITY EVENT IN A PLANT PROTECTED AREA (BD 60)

OPERATING MODE: All NOTE: RP/O/B/1000/007, (Security Event),

shall be used in conjunction with all security related emergency classifications.

A.

Discovery of bomb within plant protected area and outside security vital areas B.

Hostage/Extortion situation C.

Violent civil disturbance within the owner controlled area D.

Credible Security threat to the site (END)

A.

Intrusion into plant protected area by a hostile force B.

Bomb discovered in an area containing safety related equipment (END)

INITIAL NOTIFICATION REQUIREMENTS:

t INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY.

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 15

(

Enclo-ire 4.7 Natural Disasters, Hazards and 6

. Conditions Affecting Plant Safety RP/O/B/} '-9/001 Page

~5NAJ4W~NT ALERT 1

~

GINER4J~13fX

1.

NATURAL AND DESTRUCTIVE PHENOMENA AFFECTING THE PROTECTED AREA (BD 64)

OPERATING MODE: All A.

Tremor felt and valid alarm on the strong motion accelerograph B

Tornado striking within Protected Area Boundary C.

Vehicle crash into plant structures/systems within the Protected Area Boundary D.

Turbine failure resulting in casing penetration or damage to turbine or generator seals (CONTINUED)

1.

NATURAL AND DESTRUCTIVE PHENOMENA AFFECTING THE PLANT VITAL AREA (BD 69)

OPERATING MODE: All A.

Tremor felt and seismic trigger actuates (0.05g)

B.1 Tornado, high winds, missiles resulting from turbine failure, vehicle crashes, or other catastrophic event AND NOTE: Only one train of a safety-related system needs to be affected or damaged in order to satisfy these conditions.

1.

CONTROL ROOM EVACUATION AND PLANT CONTROL CANNOT BE ESTABLISHED (BD 75)

OPERATING MODE: All A. I Control Room evacuation has been initiated AND A.2 2.

1.

OTHER CONDITIONS WARRANT DECLARATION OF GENERAL EMERGENCY (BD 78)

OPERATING MODE: All A. I Emergency Coordinator/EOF Director judgment indicates:

A. 1.1 Actual/imminent substantial core degradation with potential for loss of containment Control of the plant cannot be established from the Aux Shutdown Panel or the SSF within 15 minutes KEOWEE HYDRO DAM FAILURE (ED 76)

DE A. 1.2 Potential for uncontrolled radionuclide releases that would result in a dose projection at the site boundary greater than 1000 mRem TEDE or 5000 mRem CDE Adult Thyroid B.I.I Visible damage to permanent structures or equipment required for safe shutdown of the unit QR B. 1.2 Affected safety system parameter indications show degraded performance

2.

RELEASE OF TOXIC/FLAMMABLE GASES JEOPARDIZING SYSTEMS REQUIRED TO MAINTAIN SAFE OPERATION OR ESTABLISH MAINTAIN COLD SHUTDOWN (BD 71)

OPERATING MODE: All A.

Report/detection of toxic gases in concentrations that will be life-threatening to plant personnel B.

Report/detection of flammable gases in concentrations that will affect the safe operation of the plant:

Reactor Building

Auxiliary Building

Turbine Building

Control Room (CONTINUED)

OPERATING MODE: All A.

Imminent/actual dam failure includes any of the following:

Keowee Hydro Dam

Little River Dam

Dikes A, B, C, or D Intake Canal Dike

3.

OTHER CONDITIONS WARRANT DECLARATION OF SITE AREA EMERGENCY (BD 77)

(END)

OPERATING MODE:

All A.

Emergency Coordinator/EOF Director judgment (END)

INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1. 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 16

(

Enct --ire 4.7 Natural Disasters, Hazards and 6 r Conditions Affecting Plant Safety RP/O/B/- -/001 Page 2.

`

7.7:_

2.

NATURAL AND DESTRUCTIVE PHENOMENA AFFECTING KEOWEE HYDRO (BD 66)

OPERATING MODE: All A.

Reservoir elevation 2 807 feet with all spillway gates open and the lake elevation continues to rise

3.

TURBINE BUILDING FLOOD (BD 72)

OPERATING MODE: All A.

Turbine Building flood requiring use of AP/1,2,3/A/1700/10, (Turbine Building Flood)

4.

CONTROL ROOM EVACUATION HAS BEEN INITIATED (BD 73)

B.

Seepage readings increase or decrease greatly or seepage water is carrying a significant amount of soil particles C

New area of seepage or wetness, with large amounts of seepage water observed on dam, dam toe, or the abutments D.

Slide or other movement of the dam or abutments which could develop into a failure E.

Developing failure involving the powerhouse or appurtenant structures and the operator believes the safety of the structure is questionable

3.

RELEASE OF TOXIC OR FLAMMABLE GASES DEEMED DETRIMENTAL TO SAFE OPERATION OF THE PLANT (BD 67)

OPERATING MODE: All A.

Report/detection of toxic or flammable gases that could enter within the site area boundary in amounts that can affect normal operation of the plant OPERATING MODE: All A. I Evacuation of Control Room AND ONE OF THE FOLLOWING:

AND A. 1.1 Plant control IS established from the Aux shutdown Panel or the SSF QR A. 1.2 Plant control IS BEING established from the Aux Shutdown Panel or SSF

5.

OTHER CONDITIONS WARRANT CLASSIFICATION OF AN ALERT (BD 74)

OPERATING MODE: All A. I Emergency Coordinator judgment indicates that:

A. 1.

Plant safety may be degraded AND A1.2 Increased monitoring of plant functions is warranted (END)

B.

Report by local, county, state officials for potential evacuation of site personnel based on offsite event (CONTINUED)

INITIAL NOTIFICATION REQUIREMENTS:

INITIL NOTIFICATION REQUIREMENTS:

INITLIL NOTIFICATION REQUIREMENTS:

INITIAL NOTIFICATION REQUIREMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 NOTIFY 1, 2,3,4 17

(

Encl -re 4.7 Natural Disasters, Hazards and r Conditions Affecting Plant Safety RP/O/B/

T /001 Page 3 o(

-r 4

OTHER CONDITIONS EXIST WHICH WARRANT DECLARATION OF AN UNUSUAL EVENT (BD 68)

OPERATING MODE: All A.

Emergency Coordinator determines potential degradation of level of safety has occurred (END)

INITUAL NOTIICATION REQUMEMENTS:

SEE EMERGENCY TELEPHONE DIRECTORY NOTIFY 1, 2,3,4 18

(

Enc(

.re 4.8 Radiation Monitor Readings for Emergency Classification Rp//B/(,/001 Page of NOTE:

IF Actual Dose Assessment cannot be completed within 15 minutes.

THEN The valid monitor reading should be used for Emergency Classification.

All RIA values are considered GREATER THAN or EQUAL TO HOURS SINCE 1rA 58R/ r*

REACTOR TRIPPED Site Area Emergency General Emergency Site Area Emergency General Emergency 0.0 - < 0.5 5.9E+003 5.9E+004 2.6E+003 2.6E+004 0.5 - < 1.0 2.6E+003 2.6E+004 1.1E+003 1.1E+004 1.0 - < 1.5 1.9E+003 1.9E+004 8.6E+002 8.6E+003 1.5 - < 2.0 1.9E+003 1.9E+004 8.5E+002 8.5E+003 2.0 - < 2.5 1.4E+003 1.4E+004 6.3E+002 6.3E+003 2.5 - < 3.0 1.2E+003 1.2E+004 5.7E+002 5.7E+003 3.0 - < 3.5 1.LE+003

.LIE+004 5.2E+002 5.2E+003 3.5 - < 4.0 1.OE+003 1.OE+004 4.8E+002 4.8E+003 4.0 - < 8.0 1.OE+003

_1.OE+004 4.4E+002 4.4E003

RIA 58 is partially shielded Assumptions used for calculation of high range in-containment monitors RIA 57 and 58:

1. Average annual meteorology (7.308 E6 sec/m3)

2.

Design basis leakage (5.6 E6 mi/hr)

3.

One hour release duration

4.

General Emergency PAGs are 1 rem TEDE and 5 rem CDE; Site Area Emergency determination is based on 10% of the General Emergency PAGs

5.

Calculations for monitor readings are based on CDE because thyroid dose is limiting

6.

No credit is taken for filtration

7.

LOCA conditions are limiting and provide the more conservative reading 19

(

Enc(

re 4.9 Unexpected/Unplanned Increase In Area Monitor Readings RP/0/1B/

.J/001 Page 1 of 1 NOTE:

This Initiating Condition is not intended to apply to anticipated temporary increases due to planned events (e.g.; incore detector movement, radwaste container movement, depleted resin transfers, etc.).

UNITS 1, 2, 3 MONITOR NUMBER UNUSUAL EVENT l000x ALERT NORMAL LEVELS mRAD/HR rmRAD/HR RIA 7, Hot Machine Shop Elevation 796 150 25000 RIA 8, Hot Chemistry Lab Elevation 796 4200 2 5000 RIA 10, Primary Sample Hood Elevation 796 830 25000 RIA 1 1, Change Room Elevation 796 210 25000 RIA 12, Chem Mix Tank Elevation 783 800

Ž 5000 RIA 13, Waste Disposal Sink Elevation 771 650 25000 RIA 15, HPI Room Elevation 758 NOTE*

>5000 NOTE:

RIA 15 normal readings are approximately 9 mRad/hr on a daily basis. Applying l000x normal readings would put this monitor greater than 5000 mRad/hr just for an Unusual Event. For this reason, an Unusual Event will NOT be declared for a reading less than 5000 mRad/hr.

20

.10 RP/OJB/1000/001 Definitions/Acronyms Page 1 of 4

1. List of Definitions and Acronyms I NOTE:

Definitions are italicized throughout procedure for easy recognition.

1.1 ALERT - Events are in process or have occurred which involve an actual or potential substantial degradation of the level of safety of the plant. Any releases are expected to be limited to small fractions of the EPA Protective Action Guideline exposure levels.

1.2 BOMB - A fused explosive device 1.3 CONDITION A - Failure is Imminent or Has Occurred - A failure at the dam has occurred or is about to occur and minutes to days may be allowed to respond dependent upon the proximity to the dam.

1.4 CONDITION B - Potentially Hazardous Situation is Developing - A situation where failure may develop, but preplanned actions taken during certain events (such as major floods, earthquakes, evidence of piping) may prevent or mitigate failure.

1.5 CIVIL DISTURBANCE - A group of ten (10) or more people violently protesting station operations or activities at the site.

1.6 CREDIBLE THREAT - The determination of what is a credible threat to the site will be the responsibility of Security Manager/designee in consultation with the OSM. The determination of "credible" is made through use of information found in the Oconee Nuclear Station Safeguards Contingency Plan and Security implementing procedures.

1.7 EXPLOSION - A rapid, violent, unconfined combustion, or a catastrophic failure of pressurized equipment that imparts energy of sufficient force to potentially damage permanent structures, systems, or components. A sudden failure of a pressurized pipe/line could fit this definition. This definition includes MS line rupture and FW line ruptures.

1.8 EXTORTION - An attempt to cause an action at the station by threat of force.

1.9 FIRE - Combustion characterized by heat and light. Sources of smoke, such as slipping drive belts or overheated electrical equipment, do NOT constitutefires. Observation of flames is preferred but is NOT required if large quantities of smoke and heat are observed.

1.10 GENERAL EMERGENCY - Events are in process or have occurred which involve actual or imminent substantial core degradation or melting with potential for loss of containment integrity. Releases can be reasonably expected to exceed EPA Protective Action Guidelines exposure levels outside the Exclusion Area Boundary.

21

.10 RP/OJB/1000/001 Definitions/Acronyms Page 2 of 4 1.11 HOSTAGE - A person or object held as leverage against the station to ensure demands will be met by the station.

1.12 INTRUSIONJINTRUDER - Suspected hostile individual present in a Protected Area without authorization.

1.13 INABILITY TO DIRECTLY MONITOR - Operational Aid Computer data points are unavailable or gauges/panel indications are NOT readily available to the operator.

1.14 LOSS OF POWER - Emergency Action Levels (EALs) apply to the ability of electrical energy to perform its intended function, reach its intended equipment. Ex. - If both MFBs, are energized but all 4160v switchgear is not available, the electrical energy can not reach the motors intended. The result to the plant is the same as if both MFBs were de-energized.

1.15 PROTECTED AREA - Encompasses all Owner Controlled Areas within the security perimeter fence.

1.16 REACTOR COOLANT SYSTEM (RCS) LEAKAGE - RCS Operational Leakage as defined in the Technical Specification Basis B 3.4.13:

RCS leakage includes leakage from connected systems up to and including the second normally closed valve for systems which do not penetrate containment and the outermost isolation valve for systems which penetrate containment.

A.

Identified LEAKAGE LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE).

LEAKAGE, such as that from pump seals, gaskets, or valve packing (except RCP seal water injection or leakoff), that is captured and conducted to collection systems or a sump or collecting tank; LEAKAGE through a steam generator (SG) to the Secondary System: Primary to secondary LEAKAGE must be included in the total calculated for identified LEAKAGE.

B.

Unidentified LEAKAGE All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE.

C.

Pressure Boundary LEAKAGE LEAKAGE (except SG LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

1.17 RUPTURED (As relates to Steam Generator) - Existence of Primary to Secondary leakage of a magnitude sufficient to require or cause a reactor trip and safety injection.

1.18 SABOTAGE - Deliberate damage, mis-alignment, or mis-operation of plant equipment with the intent to render the equipment unavailable.

22

.10 RP/O/B/1000/001 Definitions/Acronyms Page 3 of 4 1.19 SAFETY-RELATED SYSTEMS AREA - Any area within the Protected area which contains equipment, systems, components, or material, the failure, destruction, or release of which could directly or indirectly endanger the public health and safety by exposure to radiation.

1.20 SIGNIFICANT PLANT TRANSIENT - An unplanned event involving one or more of the following:

(1) Automatic turbine runback>25% thermal reactor power (2) Electrical load rejection >25% full electrical load (3) Reactor Trip (4) Safety Injection System Activation 1.21 SITE AREA EMERGENCY - Events are in process or have occurred which involve actual or likely major failures of plant functions needed for the protection of the public. Any releases are NOT expected to result in exposure levels which exceed EPA Protective Action Guideline exposure levels outside the Exclusion Area Boundary.

1.22 SELECTED LICENSEE COMMITMENT (SLC) -Chapter 16 of the FSAR 1.23 SITE BOUNDARY - That area, including the Protected Area, in which DPC has the authority to control all activities including exclusion or removal of personnel and property (1 mile radius from the center of Unit 2).

1.24 TOXIC GAS - A gas that is dangerous to life or health by reason of inhalation or skin contact (e.g.; Chlorine).

1.25 UNCONTROLLED - Event is not the result of planned actions by the plant staff.

1.26 UNPLANNED -

An event or action is UNPLANNED if it is not the expected result of normal operations, testing, or maintenance. Events that result in corrective or mitigative actions being taken in accordance with abnormal or emergency procedures are UNPLANNED.

1.27 UNUSUAL EVENT - Events are in process or have occurred which indicate a potential degradation of the level of safety of the plant. No releases of radioactive material requiring offsite response or monitoring are expected unless further degradation of safety systems occurs.

1.28 VALID - An indication or report or condition is considered to be VALID when it is conclusively verified by: (1) an instrument channel check; or, (2) indications on related or redundant instrumentation; or, (3) by direct observation by plant personnel such that doubt related to the instrument's operability, the condition's existence, or the report's accuracy is removed. Implicit with this definition is the need for timely assessment.

1.29 VIOLENT - Force has been used in an attempt to injure site personnel or damage plant property.

23

.10 RP/O/B/1000/00l Definitions/Acronyms Page 4 of 4 1.30 VISIBLE DAMAGE - Damage to equipment or structure that is readily observable without measurements, testing, or analyses. Damage is sufficient to cause concern regarding the continued operability or reliability of affected safety structure, system, or component.

Example damage: deformation due to heat or impact, denting, penetration, rupture.

24

.11 Operating Modes Defined In Improved Technical Specifications RP/O/11000/001 Page 1 of 1 MODES REACTIVITY

% RATED AVERAGE CONDITION THERMAL REACTOR COOLANT MODE TITLE POWER (a)

TEMPERATURE (Kff)

(F) 1 Power Operation

>0.99

> 5 NA 2

Startup

>0.99

<5 NA 3

Hot Standby

<0.99 NA

>250 4

Hot Shutdown (b)

< 0.99 NA 250 > T > 200 5

Cold Shutdown (b)

< 0.99 NA

< 200 6

Refueling (c)

NA NA NA (a) Excluding decay heat.

(b) All reactor vessel head closure bolts fully tensioned.

(c) One or more reactor vessel head closure bolts less than fully tensioned.

25

.12 RP/OIB/1000/001 Page 1 of 2 Instructions For Using Enclosure 4.1

1. Instructions For Using Enclosure 4.1 - Fission Product Barrier Matrix 1.1 If the unit was at Hot S/D or above, (Modes 1, 2, 3, or 4) and one or more fission product barriers have been affected, refer to Enclosure 4. 1, (Fission Product Barrier Matrix) and review the criteria listed to determine if the event should be classified.

1.1.1 For each Fission Product Barrier, review the associated EALs to determine if there is a Loss or Potential Loss of that barrier. Circle any that apply.

NOTE:

An event with multiple events could occur which would result in the conclusion that exceeding the loss or potential loss thresholds is imminent (i.e. within 1-3 hours). In this situation, use judgement and classify as if the thresholds are exceeded.

1.2 Three possible outcomes exist for each barrier. No challenge, potential loss, or loss.

Use the worst case for each barrier and the classification table at the bottom of the page to determine appropriate classification.

1.3 The numbers in parentheses out beside the label for each column can be used to assist in determining the classification. If no EAL is met for a given barrier, that barrier will have 0 points. The points for the columns are as follows:

Barrier Failure Points RCS Potential Loss 4

Loss 5

Fuel Clad Potential Loss 4

Loss 5

Containment Potential Loss 1

Loss 3

1.3.1 To determine the classification, add the highest point value for each barrier to determine a total for all barriers. Compare this total point value with the numbers in parentheses beside each classification to see which one applies.

1.3.2 Finally as a verification of your decision, look below the Emergency Classification you selected. The loss and/or potential loss EALs selected for each barrier should be described by one of the bullet statements.

26

.12 RP/O/B/1000/001 Page 2 of 2 Instructions For Using Enclosure 4.1 EXAMPLE: Failure to properly isolate a 'B' MS Line Rupture outside containment, results in extremely severe overcooling.

PTS entry conditions were satisfied.

Stresses on the 'B' S/G resulted in failure of multiple SIG tubes.

RCS leakage through the SIG exceeds available makeup capacity as indicated by loss of subcooling margin.

Barrier EAL Failure Points RCS SGTR > Makeup capacity of one HPI pump in Potential Loss 4

nornal makeup mode with letdown isolated Entry into PTS operating range Potential Loss 4

RCS leak rate > available makeup capacity as Loss 5

indicated by a loss of subcooling Fuel Clad No EALs met and no justification for No 0

classification on judgment Challenge Containment Failure of secondary side of SG results in a Loss 3

direct opening to the environment RCS 5 + Fuel 0 + Containment 3 = Total 8 A. Even though two Potential Loss EALs and one Loss EAL are met for the RCS barrier, credit is only taken for the worst case (highest point value) EAL, so the points from this barrier equal 5.

B.

No EAL is satisfied for the Fuel Clad Barrier so the points for this barrier equal 0.

C. One Loss EAL is met for the Containment Barrier so the points for this barrier equal 3.

D. When the total points are calculated the result is 8, therefore the classification would be a Site Area Emergency.

E. Look in the box below "Site Area Emergency". You have identified a loss of two barriers. This agrees with one of the bullet statements.

The classification is correct.

27

INSD 7qTION ONLY Duke Power Company PROCEDURE PROCESS RECORD (t)wDNo.

RP/OIB/1000/019 Revision No. 014 PREPARATION (2)

Station (3)

Procedure Title OCONEE NUCLEAR STATION Technical Sunnort Center Emeryencv Coordinator Procedure (4)

Prepared By Rodney Brown (Signature)

Date 08/22/03 (5)

Requires NSD 228 Applicability Determination?

0 Yes (New procedure or revision with major changes) 0 No (Revision with minor changes) o No (To incor rt reviously approved changes)

(6)

Reviewed By 1

<i j~tZ~Z (QR)

Date 81as/o3 Cross-Disciplinary Revi9By (QR)NA bA Date

/a Id Reactivity Mgmt Review By (QR)NA HA) Date

/

Mgmt Involvement Review By (Ops Supt) NAAW Date

/4/d (7)

Additional Reviews Reviewed By Date Reviewed By Date Temporary Approval if necessary)

By (OSM!QR)

Date By (QR)

Date (9)

Approved By Date a/Z</ d PERFORMANCE (Compare wit control copy every 14 calendar days while work is being performed)

(10) Compared with Control Copy Date Compared with Control Copy Date Compared with Control Copy Date (11) Date(s) Performed Work Order Number (WO#)

COMPLETION (12) Procedure Completion Verification:

o Unit 0 0 Unit 1 0 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 D NA Required enclosures attached?

o Yes 0 NA Data sheets attached, completed, dated, and signed?

o Yes 0 NA Charts, graphs, etc. attached, dated, identified, and marked?

o Yes 0 NA Procedure requirements met?

"~

Verified By Date (13) Procedure Completion Approved Date (14) Remarks (Attach additionalpages)

Duke Power Company Oconee Nuclear Station Technical Support Center Emergency Coordinator Procedure Reference Use Procedure No.

RP/OIB1000/019 Revision No.

014 Electronic Reference No.

OX002WPG

RPI/OB/1000/019 Page 2of21 Technical Support Center Emergency Coordinator Procedure NOTE:

This procedure is an implementing procedure to the Oconee Nuclear Site Emergency Plan and must be forwarded to Emergency Planning within seven (7) working days of approval.

1. Symptoms 1.1 Conditions exist where events are in progress or have occurred which indicate a potential degradation in the level of safety of the plant and activation of the Emergency Response Organization has been initiated.

2. Immediate Actions NOTE:

.2 contains listing of abbreviations/acronyms.

Actions in Sections 2.0 and 3.0 are NOT required to be followed in any particular sequence.

Place keeping aids:

at left of steps may be used for procedure place keeping (0).

Major events are required to be documented in the TSC Emergency Coordinator Log.

0 2.1 Establish the Technical Support Center as operational by doing the following:

El 2.1.1 Use the attached Enclosure 4.3, (TSC Personnel Log Sheets) for sign-in by all personnel reporting to the TSC. Assign responsibility to the TSC Log Keeper.

0 2.1.2 Ensure Names are also listed on the TSC Personnel Status Board in the TSC NOTE:

The TSC must assume turnover from the Control Room within 75 minutes of the initiating Emergency Classification time.

l 2.1.3 Determine the following minimum staff requirements for TSC activation.

NAME Emergency Coordinator Dose Assessment Liaison Nuclear Engineering Offsite Communicator Tech Assistant to EC

RP/O/B/1000/o19 Page 3 of 21 El 2.1.4 Verify that the phone system is operational or make other provisions for communications.

0 2.1.5 Verify that the OSC is Operational.

El 2.1.6 Verify that a log of TSC actions and activities has been started.

El 2.1.7 IF Activation of the Alternate TSC is required prior to completion of turnover with the OSM.

THEN REFER TO Step 1.0 of Enclosure 4.6, (Alternate TSC/OSC Activation).

E 2.2 Receive turnover from the Operations Shift Manager using Enclosure 4. 1, (Operations Shift Manager To TSC Emergency Coordinator Turnover Sheet)

TSC and OSC Activated Time El 2.3 Determine the status of Site Accountability from the TSC Offsite Communicator.

El 2.3.1 Request the TSC/OSC Liaison to have a Search & Rescue Team dispatched from the OSC if personnel within the Protected Area have not been accounted for by their group.

E 2.4 Verify that the electronic status board is set up and that someone is available to maintain it.

E 2.5 Discuss any off-site radiological concerns with the TSC Dose Assessment Liaison.

RP/0/B/1000/019 Page 4 of 21 5 2.6 Activate the TSC/OSC Public Address (PA) System (7) 0 2.6.1 Flip the power switch UP on the PA system amplifier located inside the communications cabinet.

O 2.6.2 Depress the microphone switch and hold in position while making PA announcements.

O 2.6.3 Announce the following information over the TSC/OSC PA System:

O A. The current Emergency Classification level and plant status.

O B. TSC/OSC activation time (7)

O C. "Anyone who has consumed alcohol within the past five (5) hours notify either the Emergency Coordinator in the TSC or the OSC Manager in the OSC.'

0 D. "Personnel should assume that areas are contaminated until surveyed by

."t O E.

"No eating or drinking, until the TSC and OSC are cleared by RP."

RP//B/1000/019 Page 5 of 21 D 2.7 Turn office page over ride switch ON, and dial 70 on the Emergency Coordinator's phone.

2.7.1 Announce the following information over the Plant Public Address System:

Drill Message:

Attention all site personnel. This is

. I am the Emergency Coordinator.

(name)

This is a drill. This is a drill.

You have been assembled as a part of an emergency exercise. The simulated emergency conditions are If this were a real emergency, you would be asked to remain assembled waiting on further information, or given instructions to leave the site in accordance with our site evacuation plan. At this time, however, we will continue with the emergency exercise and you may now return to your normal work assignments. I repeat.... you may now return to your normal work assignments.

Thank you for your participation.

Emergency Message:

Attention all site personnel. This is

. I am the Emergency Coordinator.

(name)

This is an emergency message.

At the present time we have a(n) emergency classification. The plant status is as follows Please remain at your site assembly location until you receive further instructions.

Information will be provided to you as conditions change.

RP/O/B/1000/019 Page 6 of 21 f 2.8 Contact the State Director Emergency Planning at the SEOC.

NAME TELEPHONE NUMBERS SDEP 1(803) 737-8500 2.8.1 Inform the TSC Offsite Communicator whenever the SEOC is activated.

2.8.2 IF The SEOC has not been activated, THEN Contact the County Directors of Emergency Planning (CDEP) to discuss plant status.

Oconee CDEP 1(864) 638-4200 Pickens CDEP 1(864) 898-5943 o 2.9 Perform the following concurrently.

Use Step 2.10 for emergency classification.

Use Step 2.11 for turnover to the EOF Director.

Use steps in 3.0 for tasks that must continue regardless of emergency classification.

(Step 2.10 on next page)

RP/O/B/1000/019 Page 7 of 21 0 2.10 Review emergency classification and verify that it meets the criteria of RP/0/B/1000/001 (Emergency Classification).

Discuss changing plant conditions with the Superintendent of Operations.

Discuss emergency classification prior to making recommendations.

a 2.10.1 IF An Unusual Event Classification exists, THEN Initiate the following actions:

0 A. Notify counties/state within 15 minutes of event classification.

NOTE:

Remind the TSC NRC Communicator to complete the NRC Event Notification Worksheet and Plant Status Sheet prior to contacting the NRC.

NRC should be notified immediately after notification of Offsite Agencies but NOT later than one (1) hour after declaration of the emergency.

a B. Notify NRC of event classification NOTE:

Condition B for Keowee Hydro Project Dams/Dikes also requires notification of the Georgia Emergency Management Agency and National weather service. Remind the TSC Offsite Communicator to notify these agencies in addition to and after SC State, Oconee County, and Pickens County.

.7 provides a description of Condition A and B.

{9}

I o C. IF Condition B at Keowee exists, THEN Notify Hydro Central (refer to Section 6 of the Emergency Telephone Directory, Keowee Hydro Project Dam/Dike Notification).

a D. Discuss classification with SDEP and CDEP

{4}

NAME TELEPHONE NUMBERS 1(803) 737-8500 SDEP Oconee CDEP 1(864) 638-4200 Pickens CDEP 1(864) 898-5943 (Unusual Event Classification guidance continued on next page)

RP/O/B/1000/019 Page 8 of 21 0 E. IF An Unusual Event classification is being terminated THEN REFER TO Enclosure 4.5, (Emergency Classification Termination Criteria) of this procedure for termination guidance.

NOTE:

The EP Section shall develop a written report, for signature by Site Vice President, to the State Emergency Preparedness Agency, Oconee County EPD, and Pickens County EPD within 24 working hours of the event termination.

0 1. Notify Emergency Planning that the Unusual Event has been terminated.

0 2.

Emergency Planning shall hold a critique following termination of the Unusual Event.

(Step 2.10.2, Alert Classification on next page)

RP/O/BI1000/019 Page 9 of 21 E 2.10.2 IF An Alert Classification exists, THEN Initiate the following actions:

0 A. Notify counties/state within 15 minutes of event classification O B. Follow Up Notifications (updates) are required a minimum of every 60 minutes Significant changes in plant status should be communicated to offsite agencies as they occur o C. Notify NRC of change in classification O D. Start ERDS (TSC NRC Communicator - RP/O/BI1000/003A, ERDS Operation) 0 E.

Discuss change in classification with the State Director of Emergency Preparedness (SDEP) and County Directors of Emergency Preparedness (CDEP)

NAME TELEPHONE NUMBERS 1(803) 737-8500 SDEP

1. IF The SEOC has not been activated, THEN Contact the CDEP to discuss plant status.

Oconee CDEP 1(864) 6384200 Pickens CDEP 1(864) 898-5943 NOTE:

Condition B for Keowee Hydro Project Dams/Dikes also requires notification of the Georgia Emergency Management Agency and National Weather Service. Remind the TSC Offsite Communicator to notify these agencies in addition to and after SC State, Oconee County, and Pickens County.

(2)

...7 provides a description of Condition A and B.

{9)

I OF. IF Condition B at Keowee exists, THEN Notify Hydro Central (refer to Section 6 of the Emergency Telephone Directory, Keowee Hydro Project Dam/Dike Notification).

{4}

(Step 2.10.3, Site Area Emergency Classification on next page)

RP/O/B/1000/019 Page 10 of 21 O 2.10.3 IF A Site Area Emergency Classification exists, THEN Initiate the following actions:

O A. Notify counties/state within 15 minutes of event classification E B. IF Condition A, Dam Failure (Keowee or Jocassee) exists, THEN Make the following protective action recommendations to Oconee County and Pickens County for imminent/actual dam failure and include on the Emergency Notification Form under Section 15 (B) and (D):

1. Move residents living downstream of the Keowee Hydro Project dams to higher ground.

2.

Prohibit traffic flow across bridges identified on your inundation maps until the danger has passed.

E C. Follow Up Notifications (updates) are required a minimum of every 60 minutes

1. Significant changes in plant status should be communicated to offsite agencies as they occur E D. Notify NRC of change in classification E E.

Start ERDS (TSC NRC Communicator - RP/O/B/1000/003A, ERDS Operation)

E F.

Discuss change in classification with SDEP and CDEP NAME TELEPHONE NUMBERS SDEP 1(803) 737-8500

1. IF The SEOC has not been activated, THEN Contact the CDEP to discuss plant status.

Oconee CDEP 1(864) 6384200 Pickens CDEP 1(864) 898-5943 E G. IF Condition A, Dam Failure (Keowee or Jocassee) exists, THEN REFER TO Step 3.1.

RP/O/B/1000/019 Page 11 of 21 NOTE:

Condition B for Keowee Hydro Project Dams/Dikes also requires notification of the Georgia Emergency Management Agency and National Weather Service. Remind the TSC Offsite Communicator to notify these agencies in addition to and after SC State, Oconee County, and Pickens County.

{2}

.7 provides a description of Condition A and B.

{9 I

OH. IF Condition B at Keowee exists, THEN Notify Hydro Central (refer to Section 6 of the Emergency Telephone Directory, Keowee Hydro Project Dam/Dike Notification).

{4)

(Step 2.10.4, General Emergency Classification, on next page)

RP/O/B/1000/019 Page 12 of 21 2.10.4 IF A General Emergency Classification exists, THEN Initiate the following actions:

O A. Evacuate 2 mile radius and 5 miles downwind unless conditions make evacuation dangerous. Shelter all sectors not evacuated. Request the TSC Dose Assessment Liaison to determine the actual sectors affected.

E B. IF Condition A, Dam Failure (Keowee or Jocassee) exists, THEN Make the following protective action recommendations to Oconee County and Pickens County for imminent/actual dam failure and include on the Emergency Notification Form under Section 15B and D:

1. Move residents living downstream of the Keowee Hydro Project dams to higher ground.

2.

Prohibit traffic flow across bridges identified on your inundation maps until the danger has passed.

O C. Notify counties/state within 15 minutes of event classification o D. Follow Up Notifications (updates) are required a minimum of every 60 minutes

1. Significant changes in plant status should be communicated to offsite agencies as they occur 0 E.

Notify NRC of change in classification 0 F.

Start ERDS (TSC NRC Communicator - RP/OIB/1000/003A, ERDS Operation)

[ G. Discuss change in classification and Protective Action Recommendations with SDEP and/or CDEP. Provide any known information concerning conditions that would make evacuation dangerous.

NAME TELEPHONE NUMBERS SDEP 1(803) 737-8500

1. IF The SEOC has not been activated, THEN Contact the CDEP to discuss plant status.

Oconee CDEP 1(864) 638-4200 Pickens CDEP 1(864) 898-5943

RP/OB/1000/019 Page 13 of 21 flH. IF Condition A, Dam Failure (Keowee or Jocassee) exists, THEN REFER TO Step 3.1.

NOTE:

Condition B for Keowee Hydro Project Dams/Dikes also requires notification of the Georgia Emergency Management Agency and National Weather Service. Remind the TSC Offsite Communicator to notify these agencies in addition to and after SC State, Oconee County, and Pickens County.

{2}

.7 provides a description of Condition A and B.

(91 I

OI. IF Condition B at Keowee exists, THEN Notify Hydro Central (refer to Section 6 of the Emergency Telephone Directory, Keowee Hydro Project Dam/Dike Notification).

{4)

(Step 2.11 on next page)

RP/0BI1000/019 Page 14 of 21 0 2.11 When notified by the EOF Director that the Emergency Operations Facility (EOF) is operational, notify the following TSC personnel to exchange information with their counterpart in the EOF.

TSC Dose Assessment Liaison TSC Offsite Communicator Control Room/EOF Liaison (Operations Network)

NOTE:

EOF Director will notify the Emergency Coordinator when the information has been received and establish a time for turnover. Turnover should be initiated as soon as possible. A goal of 30 minutes should be used to complete turnover after the EOF is declared Operational.

(1)

O 2.11.1 Obtain the current copy of the Emergency Notification Form and plant status.

The EOF Director shall provide to the Emergency Coordinator the information he has been provided with in the following areas:

Present Emergency Classification Initial Emergency Classification Time Time Initiating Condition/Unit affected Present status of affected unit(s), including significant equipment out of service Improving Stable Degrading Status of unaffected unit(s):

Unit 1 shutdown at or at

% power Unit 2 shutdown at or at _%

power Unit 3 shutdown at or at power Emergency Releases:

NO YES Airborne _

Liquid Is occurring Has occurred Time _

Normal Operating Limits:

Below Above Protective Action Recommendations Site Evacuation NO _

YES If yes, location Time of evacuation

{7}

Last Message Number Next Message due at

RP/0/B/1000/019 Page 15 of 21 0 2.11.2 Emergency Coordinator turnover to EOF Director complete.

EOF Activated Time _

0 2.11.3 Request NRC Communicator to notify the NRC EOC that the EOF is activated.

0 2.11.4 Make announcement to TSC/OSC that EOF is activated.

{6) 3.

Subsequent Actions 3.1 IF Condition A, Dam Failure (Keowee or Jocassee) exists, THEN Perform the following actions:

O 3.1.1 Notify Hydro Central and provide information related to the event. Refer to Section 6 of the Emergency Telephone Directory.

(4)

O 3.1.2 Relocate Keowee personnel to the Operational Support Center if events occur where their safety could be affected.

0 3.1.3 Notify Hydro Central if Keowee personnel are relocated to the OSC.

14 NOTE:

A loss of offsite communications capabilities (Selective Signaling and the WAN) could occur within 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after Keowee Hydro Dam failure. Rerouting of the Fiber Optic Network through Bad Creek should be started AS SOON AS POSSIBLE.

0 3.1.4 IF The EOF is NOT activated, THEN Notify Telecommunications Group in Charlotte to begin rerouting the Oconee Fiber Optic Network. Refer to Selective Signaling Section of the Emergency Telephone Directory (page 9).

0 3.1.5 Notify Security to alert personnel at the Security Track/Firing Range and Warehouse #5 to relocate to work areas inside the plant.

0 3.1.6 Relocate personnel at the following locations to the World of Energy/Operations Training Center:

I NOTE:

Plant access road to the Oconee Complex could be impassable within 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months if the Keowee Hydro Dam fails. A loss of the Little River Dam or Dikes A-D will take longer to affect this road.

Oconee Complex Oconee Garage Oconee Maintenance Training Facility

RP/O/B/1000/019 Page 16 of 21 0 3.1.7 Ensure Operations has dispatched operators to the SSF and established communications.

0 3.2 Periodically evaluate with TSC personnel the need to conduct evacuation. Log the status of this action on the TSC Status Board.

NOTE:

Twenty-four (24) hour staffing must be accomplished prior to personnel being evacuated from the site. RP/O/B/1000/010, (Procedure for Emergency Evacuation/Relocation of Site Personnel).

Determine if personnel with special radiological exposure limits need to be evacuated (e.g.; declared pregnant women, personnel with radio-pharmaceutical limitations).

3.2.1 Consider the following for making Site Evacuation decisions:

Alert - determined by actual plant conditions Site Area Emergency - consider evacuation/relocation of non-essential site personnel. World of Energy personnel should be evacuated at the same time as non-essential personnel.

General Emergency - evacuate all non-essential personnel. Notify the EOF Director to evacuate the World of Energy.

Notify the EOF anytime personnel are relocated on site or evacuated from the site.

RP/O/B/1000/019 Page 17 of 21 WARNING: Use of the Outside Air Booster Fans during a Security Event may introduce incapacitating agents into the Control Room.

15 }

[ 3.3 Periodically evaluate the need to operate the outside air booster fans (Control Room Pressurization and Filter System - CRVS) with TSC personnel. Log status of this system on the TSC Status Board.

NOTE:

Outside air booster fans are used to provide positive pressure in the Control Room/TSC/OSC to prevent smoke, toxic gas, or radioactivity from entering the area as required by NUREG 0737, Control Room Habitability.

Chlorine Monitor Alarm will either stop the outside air booster fans OR will not allow them to start.

0 3.3.1 IF Smoke/toxic gas in the Turbine Building or Auxiliary Building is expected to reach the Control Room, THEN Instruct the Control Room to turn ON the outside air booster fans.

Fans On__

Time o A. Request OSC to verify operability of the Control Room Ventilation System per AP/1,3/A11700/018, (Abnormal Release of Radioactivity).

3.3.2 IF RLA-39 is in Alarm THEN Verify that the Control Room has turned on the outside air booster fans.

0 A. Request OSC to verify operability of the Control Room Ventilation System per AP/l1,3/A11700/018, (Abnormal Release of Radioactivity).

0 B. Request backup air sample from the OSC to verify RIA alarm 0 C. IF Air sample determines that RIA-39 alarm is not valid, THEN Secure outside air booster fans.

RP/O/B/1000/019 Page 18 of 21 O D. IF Air sample determines that RIA-39 alarm is valid, THEN Isolate the source of airborne contamination to the Control Room/TSCIOSC o E. IF Dose levels in the Control Roomr/TSC/OSC are being increased by the addition of outside filtered air, THEN Secure outside air booster fans.

Fans Off Time 0 3.4 Periodically evaluate the need to activate the Alternate TSC and/or OSC.

3.4.1 IF Activation of the Alternate TSC and/or OSC is required, THEN REFER TO Step 2.0 of Enclosure 4.6, (Alternate TSC/OSC Activation).

3.4.2 Notify the EOF Director once relocation to the Alternate TSC is completed.

NOTE:

The NRC will send a response team to the site at a Site Area or General Emergency Classification.

I 3.5 IF An NRC team is enroute, THEN Perform the following steps:

0 3.5.1 Notify Alternate Emergency Coordinator to report to the TSC for an update on plant conditions.

A. Record Alternate Emergency Coordinator's name on Enclosure 4.4 (NRC Site Team Response Form).

B. Brief Alternate Emergency Coordinator on current plant conditions.

0 3.5.2 Provide Enclosure 4.4 (NRC Site Team Response Form), to the TSC NRC Communicator.

A. Instruct TSC NRC Communicator to complete Steps 1.2 - 1.5 of.4 (NRC Site Team Response Form).

0 3.5.3 Notify OSC Manager and request RP Manager and Security to implement actions required to process NRC Site Team.

RP/O/B/1000/019 Page 19 of 21 O 3.6 Provide periodic updates to the EOFD concerning plant status. Request the EOFD to provide dose assessment and field monitoring data to the TSC on a periodic basis.

3.6.1 IF Failed Fuel Condition Three (3) has been determined, THEN Immediately notify the EOFD.

A. Failed Fuel Condition Three (3) requires additional Protective Action Recommendations.

o 3.7 Authorize exposure greater than normal operating limits for planned equipment repair missions and/or emergency lifesaving missions.

3.7.1 Approval may be either verbal or written.

3.7.2 This authority may be delegated to the RP Manager in the OSC.

O 3.8 Update TSC and OSC personnel approximately every 30 minutes on the Emergency Classification and plant status via the TSC/OSC public address system. (Timer is available in the Emergency Procedures Cart) o 3.9 Establish twenty-four (24) hour staffing and have the Managers prepare as needed.

3.9.1 TSC Personnel Log Sheets (Enclosure 4.3) are to be used for this purpose.

NOTE:

Long term use of the SFP as a makeup source will deplete the SFP inventory.

Engineering has evaluated and approved the following method for refilling of the SFP with filtered lake water.

E 3.10 IF Offsite fire apparatus is needed to provide water to the Spent Fuel Pool, THEN Request the EOFD to contact the Oconee CDEP to provide sufficient fire apparatus (at least 3 pumper trucks of 1000 gpm, or greater capacity) to Oconee Nuclear Site (if available, Keowee Ebenezer, Corinth Shiloh, or Keowee Key Rural Volunteer Fire Departments should be requested to provide support).

0 3.10.1 Provide the OSC Manager with the following information and request support from the OSC:

Fire apparatus is being dispatched from Oconee County to provide water to the Spent Fuel Pool Request Security Liaison to have Security Officers meet the fire apparatus at the determined site entrance Request Maintenance Manager to initiate MP/0/A13009/012A (Emergency Plan For Refilling Spent Fuel Pool).

RP/9/B/1000/019 Page 20 of 21 NOTE:

10CFR50.54(x) allows for reasonable actions that depart from a License Condition or Technical Specification to be performed in an emergency when this action is immediately needed to protect the health and safety of the public and no action consistent with the License Condition or Technical Specification that can provide adequate or equivalent protection is immediately apparent.

10CFR50.54(y) requires approval of any 10CFR50.54(x) actions by a Licensed Senior Operator.

Implementation of Oconee Severe Accident Guidelines (OSAG) requires the use of 10CFR50.54 (x) and (y) provisions.

o 3.11 IF Plant conditions require a decision to implement 10CFR50.54(x),

THEN Perform the following steps:

o 3.11.1 Obtain approval of a Licensed Senior Reactor Operator prior to taking any action.

o 3.11.2 Document decision and actions taken in the affected units log.

o 3.11.3 Document decision and actions taken in the Control Room Emergency Coordinator Log.

NOTE:

NRC must be notified of any 10CFR50.54(x) decisions and actions within one (1) hour.

I o 3.11.4 Request Control Room/TSC NRC Communicator to report decision and actions taken to the NRC.

l NOTE:

10CFR50.72 requires NRC notification for specific plant conditions.

I 0 3.12 IF Plant conditions require NRC notification under 10CFR50.72, THEN Request the Control Room/TSC NRC Communicator to provide this notification using the guidance in OMP 1-14, (Notifications).

RP/OIB/1000/019 Page 21 of 21 0 3.13 IF A LOCA exists inside containment, THEN Initiate the following actions:

3.13.1 Request the Operations Superintendent to have Operations personnel refer to OP/1,2,3/A/1 102/023, (Operation Of Containment Hydrogen Recombiner System).

3.13.2 Request the Operations Superintendent to have Operations personnel refer to OP/0/A/1 104/019 (Control Room Ventilation System) to verify proper operation of the Control Room Ventilation System.

13) o 3.14 Announce SAMG transition to TSC/OSC/EOF personnel so proper signage can be displayed with current plant conditions.

(6) o 3.15 Establish a Recovery Organization (Section M of the ONS Emergency Plan, Volume A, located in the Operations Shift Manager's office) once the emergency has been terminated.

3.15.1 Request the OSC Manager to review Section M of the Emergency Plan (Volume 17A is located in Unit 3 Control Room) to begin preparation for recovery.

3.16 Emergency Planning Section shall be responsible for completing all Procedure Process Records of Emergency Plan Implementing procedures initiated by the TSC.

0 3.17 Ensure TSC is returned to ready condition for next drill or actual event.

0 3.17.1 Ensure TSC PA override switch is put in off position.

{8)

4. Enclosures 4.1 Operations Shift Manager to TSC Emergency Coordinator Turnover Sheet 4.2 Emergency Preparedness Acronyms 4.3 TSC Personnel Log 4.4 NRC Site Team Response Form 4.5 Emergency Classification Termination Criteria 4.6 Alternate TSC/OSC Activation 4.7 Keowee Hyrdo Project Dams/Dikes - Condition A/B Descriptions

{9}

4.8 References I'

.1 RP/O/B/1000/019 Page 1 of 2 Operations Shift Manager To TSC Emergency Coordinator Turnover Sheet EMERGENCY CLASSIFICATION TIME DECLARED DESCRIPTION OF EVENT Unit One Status:

Reactor Power RCS Pressure RCS Temperature Auxiliaries Being Supplied Power From ES Channels Actuated MAJOR EQUIPMENT OUT OF SERVICE JOBS IN PROGRESS Unit Two Status:

Reactor Power RCS Pressure RCS Temperature Auxiliaries Being Supplied Power From ES Channels Actuated MAJOR EQUIPMENT OUT OF SERVICE JOBS IN PROGRESS Unit Three Status:

Reactor Power RCS Pressure RCS Temperature Auxiliaries Being Supplied Power From ES Channels Actuated MAJOR EQUIPMENT OUT OF SERVICE JOBS IN PROGRESS

.1 Operations Shift Manager To TSC Emergency Coordinator Turnover Sheet Classification Procedure in Use:

RP/O/B/1000/002 Control Room Emergency Coordinator Procedure Is RP/OIB/1000O3A, ERDS Operation, in use?

Yes No RPOJB/1000/019 Page 2 of 2 If Yes, Unit No. _

Step No. __

Is RP/OB/1000/007, (Security), in use?

Yes No If Yes, Step No.

Is RP/IOB/1000/016, (Medical), in use?

Yes No If Yes, Step No.

Is RP/OIB/1000I017, (Spill Response), in use?

Yes No If Yes, Step No.

Is RP/IOB/1000/022, (Fire/Flood), in use?

Yes No If Yes, Step No.

Is RP/IOB/1000/29, (Fire Brigade) in use?

Yes No If Yes, Step No.

Is Step 5.4 of OMP 1-18 (Implementation Standard During Abnormal And Emergency Events) in use?* Yes No

If yes, implementation of emergency worker exposure limits must be announced over Public Address System.

(3)

IF Condition A, Dam Failure, has been declared for Keowee Hydro Project, THEN provide the following information to the TSC Emergency Coordinator:

Status of Offsite Agency Notifications Recommendations made to offsite agencies Status of relocation of site personnel What is the status of Site Assembly? (This question is only applicable for those times that the Emergency Response Organization is activated after hours, holidays, or weekends.)

Next message due to Offsite Agencies at Time:

Operations Shift Manager/CR Emergency CoordinatorlTSC Time:

Time:

.2 Emergency Preparedness Acronyms

1. Emergency Preparedness Acronyms CDEP County Director of Emergency Preparedness EC Emergency Coordinator EOF Emergency Operations Facility EOFD Emergency Operation, Facility Director ETS Emergency Telephone System LEC Law Enforcement Center NRC Nuclear Regulatory Commission EOC Emergency Operations Center OSC Operational Support Center PAR Protective Action Recommendation SCC State/County Communicator SDEP State Director of Emergency Preparedness SEOC State Emergency Operations Center SWP State Warning Point TSC Technical Support Center RP/O/B/10000/19 Page 1 of 1

(

Enclosure (g TSC Personn' Cog RP/O/B/r (919 Pa'-

of 2 DATE:

PRIMARY RELIEF POSITION NAME SOCIAL SECURITY TIME SHIFT NAME SOCIAL SECURITY SHIFT IN AT SCHEDULE Las, Firt M SCHEDULE (Last, First, MI)

EMPLOYEE ID TSC

(

st MI)

EMPLOYEE ]ID Emergency Coordinator**

Offslte Communicator**

Dose Assessment Liaison*

Nuclear Engineering**

Tech Assist to EC (Mech Engineer)**

Operations Superintendent TSC/OSC Liaison

45 Minute Responder

- 75 Minute Responder

C Enclosurf TSC Personn\\ tog RP/O/B/(

'019 Pai. z of 2 PRIMARY RELIEF POSITION NAME SOCIAL SECURITY TIME SHIFT NAME SOCIAL SECURITY SHIFT (Last, First, MI)

IN AT SCHEDULE (Last, First, MI)

SCHEDULE EMPLOYEE ID TSC EMPLOYEE ID TSCIOSC Liaison Support Engineering Manager NRC Communicator (ENS)

Dose Assessors Engineering Mgr.

Assistant Operations Superintendent Assistant Emergency Planning Community Relations (WOE)

Local IT

.4 NRC Site Team Response Form RP/O/BI1000/019 Page 1 of 1

1. NRC Site Team Response Form 1.1 Alternate Emergency Coordinator (name) 1.2 NRC Site Team Personnel Information:

NAME SOCIAL SECURITY NUMBER 1.3 Estimated Time of Arrival (ETA):

1.4 Mode of Transportation:

Access Gate (Circle One): Hwy 130 - Main Station/WOE Entrance (Gate 1)

Hwy 183 - Intake Owner Controlled Area (OCA) Gate (Gate 3)

Hwy 183 - Complex/Branch OCA Gate (Gate 4) 1.5 Telecopy this form to the OSC and Security using Speed Dial Code 031 or One-Touch Dial Code 31.

1.6 GET and BBA Requirements Waived:

RP Manager Date

.5 RP/O/B/1000/019 Emergency Classification Termination Page 1 of 1 Criteria IF The following guidelines applicable to the present emergency condition have been met or addressed, THEN An emergency condition may be considered resolved when:

O 1.1 Existing conditions no longer meet the existing emergency classification criteria and it appears unlikely that conditions will deteriorate further.

O 1.2 Radiation levels in affected in-plant areas are stable or decreasing to below acceptable levels.

O 1.3 Releases of radioactive material to the environment greater than Technical Specifications are under control or have ceased.

0 1.4 The potential for an uncontrolled release of radioactive material is at an acceptably low level.

0 1.5 Containment pressure is within Technical Specification requirements.

O 1.6 Long-term core cooling is available.

] 1.7 The shutdown margin for the core has been verified.

O 1.8 A fire, flood, earthquake, or similar emergency condition is controlled or has ceased.

0 1.9 Offsite power is available per Technical Specification requirements.

o 1.10 All emergency action level notifications have been completed.

o 1.11 The Area Hydro Manager has been notified of termination of Condition B for Keowee Hydro Project.

E 1.12 The Regulatory Compliance Section has evaluated plant status with respect to Technical Specifications and recommends Emergency Classification termination.

0 1.13 Emergency terminated. Request the TSC Offsite Communicator to complete an Emergency Notification Form for a Termination Message using guidance in RP/O/B/1000/015B, (Offsite Communications From The Technical Support Center), and provide information to offsite agencies.

Date/Time of Termination:

/

Emergency Coordinator Initials:

Return to Step 2.10.1.E.1

.6 RP/O/B11000/019 Alternate TSC/OSC Activation Page 1 of 2 K-- 1. Activation of the Alternate TSC prior to completion of turnover with the OSM O 1.1 Request OSC Manager/SPOC Supervisor to initiate steps to setup the Alternate TSC located in RP/O/B/1000/25 (OSC Manager Procedure).

o 1.2 Request TSC Logkeeper (or designee) to announce over the plant PA that the Alternate TSC is being activated.

o 1.3 Relocate TSC personnel, except for the following, to the Alternate TSC, Room 316 of the Oconee Office Building:

O 1.3.1 TSC Offsite Communicator (1) 0 1.3.2 TSC Logkeeper 0 1.3.3 Emergency Planning (if available) 0 1.4 Return to Step 2.2 of this procedure and complete turnover with the OSM.

0 1.4.1 Report to the Alternate TSC with remaining support personnel after completion of turnover.

.6 RP/1B/1000/019 Alternate TSC/OSC Activation Page 2 of 2

<-'2. Activation of the Alternate TSC/OSC 0 2.1 Direct the TSC/OSC liaison to inform the OSC Manager of the need to relocate the following emergency response facilities:

TSC OSC TSC and OSC O 2.2 Provide guidance on best available route to personnel being relocated to the Alternate TSC.

2.2.1 IF A radiological release is in progress, THEN Direct the TSC/OSC Liaison to request RP to determine the best available route to the Alternate TSC.

0 2.3 Direct the following TSC personnel to report to the Alternate TSC to assist with setup of the facility and establish communications with the TSC:

(1) TSC Offsite Communicator (1) Dose Assessor Ops Superintendent Assistant TSC/OSC liaison Technical Assistant 0 2.4 Direct the TSC NRC Communicator to inform the NRC that the Alternate TSC is being activated.

E 2.5 Direct the remaining TSC personnel to report to the Alternate TSC.

0 2.6 Inform the EOF Director that the Alternate TSC is being activated and that TSC personnel, including the Emergency Coordinator, are enroute to that facility.

0 2.7 Return to Step 3.4.2 of this procedure after reporting to the Alternate TSC.

.7 RP/O/B/1000/019 Keowee Hydro Project Dams/Dikes -

Page 1 of 1 Condition A/B Descriptions NOTE:

Duke Power Company (DPC) Hydro Group personnel are responsible for evaluation/inspection of Keowee Hydro Project Dams/Dikes AND determining if a Condition A or B exists.

DPC Hydro Group personnel will communicate the results of evaluations/inspections to the Keowee Hydro Operator. The Keowee Hydro Operator will notify the OSM.

1. Condition A - Failure is Imminent or has occurred A failure at the dam/dike has occurred or is about to occur.

2. Condition B - Potentially Hazardous Situation is developing A situation where failure may develop, but preplanned actions taken during certain events (e.g., major flood, earthquakes, evidence of piping) may prevent or mitigate failure.

The following situations will result in a Condition B determination/declaration:

Reservoir elevation at Keowee Hydro Station is 807 ft msl with all spillway gates open and lake elevation continuing to rise.

Situations involving earth dam or abutments as follows:

a) Large increase or decrease in seepage readings OR seepage water is carrying a significant amount of soil particles; b) New area of seepage or wetness, with large amounts of seepage water observed on dam, dam toe, or the abutments; c) A slide or other movement of the dam or abutments which could develop into a failure.

Developing failure involving the powerhouse or appurtenance structures is highly irregular to the point where the operator feels safety of the structures is questionable.

Developing failure involving the concrete spillway or bulkhead is unusual and the safety of the structure is questionable.

Any other situation involving plant structures which shows the potential for a developing failure.

.8 RP/O/B/1000/019 References Page 1 of 1

1. PIP 0-98-04996

2.

PIP 0-99-00743

3.

PIP 0-01-01395

4.

PIP 0-01-03460

5.

PIP 0-01-03696

6.

PIP 0-02-00264

7.

PIP 0-02-03705

8.

PIP 0-02-7089

9.

PIP-0-03-2447 I

NSD 703 (R04-01)

INFORMATION ONLY R'TEPARATION (2)

Station (3)

Procedure Title _

Duke Power Company PROCEDURE PROCESS RECORD (1) n) No. RP/0/B/10/020 Revision No. 008 OCONEE NUCLEAR STATION Emermencv Operations Facilitv Director Procedure In (4)

Prepared By Rodney Brown (Signature),

Date 08/22/03 (5)

Requires NSD 228 Applicability Determination?

D Yes (New procedure or revision with major changes) 0 No (Revision with minor changes)

D No (To inc orate previouly approved changes)

(6) Reviewed By (QR)

Date 2

Cross-Disciplinary Re By (QR)NAi

) Date 0

Reactivity Mgmt Review By _QR)NA__Qu Date 5

Mgmt Involvement Review By (Ops Supt) NA M)

Date didb 2 (7) Additional Reviews Reviewed By Date Reviewed By Date Temporary Approval (if necessary)

By (OSM/QR)

Date By

._(QR)

Date (9)

Approved By fi7 Date

'OF/ Z PERFORMANCE (Compare with control copy every 14 calendar days while work is being performed)

(10) Compared with Control Copy Date Compared with Control Copy Date Compared with Control Copy Date (11) Date(s) Performed Work Order Number (WO#)

COMPLETION (12) Procedure Completion Verification:

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

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

0 Yes 0 NA Required enclosures attached?

o Yes 0 NA Data sheets attached, completed, dated, and signed?

o Yes 0 NA Charts, graphs, etc. attached, dated, identified, and marked?

o Yes 0 NA Procedure requirements met?

Verified By Date (13) Procedure Completion Approved Date (14) Remarks (Attach additionalpages)

Duke Power Company Oconee Nuclear Site Emergency Operations Facility Director Procedure Reference Use Procedure No.

RP/O/B/1000/020 Revision No.

008 Electronic Reference No.

OX002WPH

RlP/O/B/1000020 Page 2 of 10 Emergency Operations Facility Director Procedure NOTE:

This procedure is an implementing procedure to the Oconee Nuclear Site Emergency Plan and must be forwarded to Emergency Planning within seven (7) working days of approval.

1. Symptoms 1.1 Conditions exist where events are in progress or have occurred which indicate a potential degradation of the level of safety of the plant and activation of the Emergency Response Organization has been initiated.

2. Immediate Actions NOTE:

Place Keeping Aids: 0 at left of steps may be used for procedure place keeping (0).

Major events are required to be documented in the EOF Director's log.

The EOF must be operational within 75 minutes of an Alert or higher classification (except for security events involving intrusion/attempted intrusion into the site during normal working hours). Turnover may or may not have occurred. Turnover should occur with the TSC at a time that will not decrease the effectiveness of communications with the offsite agencies.

{7}

Enclosure 3.4, (Emergency Preparedness Acronyms) contains a list of abbreviations.

o 2.1 Sign in on the EOF Personnel Status Board.

o 2.2 Initiate a log of major activities and decisions.

o 2.3 Assure EOFD PA system has been turned on in the telephone room.

o 2.4 Turn switch to "ALL CALL" for announcements to all rooms.

2.4.1 Select individual room if only one room is to receive announcement.

o 2.5 Notify the Emergency Coordinator in the TSC of arrival and establish an open phone line.

2.5.1 Dial 66-3921 OR 66-3704 on the 6244350 line (

Reference:

Emergency Telephone Directory, page 14).

{5 1

RP/O/B/1000/020 Page 3 of 10 o 2.6 IF the Emergency Response Organization is being activated after normal working hours due to a security event involving an intrusion/attempted intrusion into

site, THEN notify the Operations Shift Manager (Control Room Emergency Coordinator) of arrival and establish a turnover time.

(7) 2.6.1 Dial 9-882-7076 OR 66-3271 on the 6244350 phone.

0 2.7 Assure access control has been established.

o 2.8 Make EOF announcement concerning fitness-for-duty.

"Any one who has consumed alcohol within the past five (5) hours, notify either the EOF Director or the appropriate EOF Manager."

NOTE:

During a security event involving an intrusion/attempted intrusion into the site by a hostile force after normal working hours activation of the TSC will be delayed. In this situation it is not required for the EOF/TSC counterparts to make contact.

{7}

E 2.9 Declare the EOF operational when the following positions are filled, and they have contacted their counterpart in the TSC.

2.9.1 Ensure that the following names are listed on the EOF Personnel Status Board.

NAME EOF Director Offsite Communications Manager State/County Communicator Radiological Assessment Manager Operations Interface Manager Access Control Security Guard 0 2.9.2 EOF Operational Time:

(3)

RP/OB/1000020 Page 4 of 10 I 2.10 Contact the Emergency Coordinator at the TSC and inform him that the EOF is operational and will commence gathering plant status information OR contact the OSM and indicate that the EOF is Operational.

{7) 2.10.1 IF the OSM is contacted, THEN GOTO Step 2.12 to conduct turnover with the OSM.

NOTE:

If the TSC is able to activated, the following individuals will exchange information.

Three separate enclosures will be provided to the EOF Director. These enclosures are a part of RP/OIB/1000/021, (Operations Interface (EOF)), RP/OJB/1000/015C, (Offsite Communications From The Emergency Operations Facility) and RP Manual Section 11.3, (Off-Site Dose Assessment And Data Evaluation)

TSC EOF Dose Assessment Liaison Offsite Communicator Radiological Assessment Manager State/County Communicator EOF Liaison Operations Interface Manager

RP/O/B/1000o/020 Page 5 of 10 NOTE:

EOF Managers will inform the EOFD when information is received.

Turnover with the TSC should be initiated As Soon As Possible. A goal of 30 minutes should be used to complete turnover after the EOF is declared Operational.

{1I 0 2.11 Contact Emergency Coordinator to conduct turnover using the information prepared by the EOF Managers.

Present emergency classification Time Initial emergency classification Time Initiating Condition/Unit affected:

Present status of affected unit(s), including significant pieces of equipment out of service.

Improving __

Stable __

Degrading Status of unaffected unit(s):

Unit 1 shutdown at or at

%power.

Unit 2 shutdown at or at

%power.

Unit 3 shutdown at or at

%power.

Equipment out of service:

Emergency Releases: NO YES Airborne -

Liquid

- Is occurring -

Has occurred __Time_

Normal operating limits: Below Above Protective Action Recommendations:

None _

Oconee County:

Pickens County:

Site Evacuation NO __

YES If yes, where Time of evacuation Last message number _

Next message due at

RPOIB/1000020 Page 6 of 10 0 2.11.1 Request Emergency Coordinator to provide periodic updates to the EOFD concerning plant status.

0 2.11.2 Inform the Emergency Coordinator that the EOFD will provide dose assessment and field monitoring data on a periodic basis.

E 2.11.3 Record EOF Activation Time:

0 2.12 IF the TSC is not activated due to a security event, THEN contact the OSM at 9-882-7076 OR 66-3271 AND conduct turnover using the following information (completed with information from the most recent emergency notification form).

{7)

Present Emergency Classification Time of Classification Initial Emergency Classification Time of Classification Initiating Condition/Unit(s) Affected:

Present status of affected unit(s), including significant equipment out of service.

Plant Condition: Improving Stable Degrading Status of affected unit(s):

Unit 1 shutdown at or at

% Power.

Unit 2 shutdown at or at

% Power.

Unit 3 shutdown at or at

% Power.

Equipment out of service:

Emergency Releases:

None Potential Is Occurring Has Occurred Protective Action Recommendations:

None Oconee County:

Pickens County:

Last Message Number Next Message due at (time):

0 2.12.1 Request the OSM to provide updates to the EOFD concerning plant status as needed.

RP/0/3B/1000/020 Page 7 of 10 o 2.12.2 Inform the OSM that the EOFD will provide dose assessment and field monitoring data as needed.

O 2.12.3 Record EOF Activation Time:

NOTE:

TSC remains responsible for all Offsite Notifications required by Title m (Hazardous Materials Spills).

o 2.13 Announce to all EOF personnel that the EOF is activated. Provide time of activation and name of EOF Director.

NOTE:

For all drills, precede messages with "This is a drill."

Example message:

"May I have your attention please. The EOF is activated as of (time) hours. This is (Name).

I am the EOF Director and have taken responsibility for emergency management from the Emergency Coordinator in the Technical Support Center.

The plant status is..........

RP/0/3BI10001020 Page 8 of 10 0 2.14 Determine that the EOF Managers understand they are responsible for each of the following actions:

NAME EOF Director Emergency Classification Protective Action Recommendations Approval of news releases.

NOTE:

News releases may be approved by Public Spokesperson if the news releases only contain information already approved by the EOFD on the notification form.

Offsite Communications Manager Notification to offsite agencies.

Contact for offsite agency support (i.e.; medical, fire, law enforcement)

Operations Interface Manager Emergency classification recommendation Plant status Radiological Assessment Manager

+

Dose Calculations Field Monitoring HPN Communication TSC radio to the EOF operational NOTE:

The following two managers do not have to be in place in a required time frame. Sign off Step 2.12 when the first four managers are identified. Continuation to Step 2.13 should commence while completing this step.

News Director

+

Interface with news media.

+

Update of company officers.

+

Update Industry groups. This includes INPO.

Provide technical briefers to the SC Emergency Operations Center (SEOC), Pickens Emergency Operations Center (PEOC) and Oconee Emergency Operations Center (OEOC), and the Joint Information Center (JIC). (Note: JIC is in the EOF).

Step 2.14 Continued to next page.

RP/0I11/0001020 Page 9 of 10 Sites Services Group Manager Update of Duke Power Insurance Department Access Control Responsible for any actions relating to Security

+ Facility equipment repair

+ Assure 24 hr. Staffing for EOF positions o 2.15 Notify SEPD and Oconee and Pickens CEPD that the EOF has assumed turnover from the TSC. This duty may be assigned to the following positions:

+ EOF Logkeeper

+ Emergency Planning Manager 2.15.1 Contact SEPD after each message is transmitted to provide additional information/follow-up.

o 2.16 Verify with the News Director that the Executive Vice President, Nuclear Generation, has been notified of the emergency status.

o 2.17 Make an announcement over the EOF PA system requesting persons who are medical first responders or EMT's to register that information with the SSG Manager.

o 2.18 Request the Emergency Planning Manager to notify the Emergency Crisis Operations Center (ECOC) Duty Person (9) 2.18.1 Send page to pager # 777-1008 and provide call back number at EOF.

2.18.2 Provide information to the ECOC Duty Person concerning current event classification and status.

o 2.19 EOF Director may approve entry of personnel to the Emergency Operations Facility if the individual's training is not current. Each case would be decided on its own merits.

Document decision in the EOF Director's log.

o 2.20 Hold round-table discussions with EOF managers every hour. (Secure timer from procedures cart.)

o 2.21 Keep EOF personnel updated on changing plant conditions after each round-table discussion. This duty may be assigned to the EOF Logkeeper.

0 2.22 REFER TO Enclosure 3.1, (Emergency Classification Tracking Sheet).

RP/OAB/1000/020 Page 10 of 10

3. Enclosures 3.1 Emergency Classification Tracking Sheet 3.2 Emergency Classification Termination/Reduction Flowchart 3.3 Recovery Guidelines 3.4 Emergency Preparedness Acronyms 3.5 10 Mile EPZ Map 3.6 References

.1 Emergency Classification Tracking Sheet RP/0/B/1000/020 Page of 16

1. Emergency Classification Tracking Review emergency classification and verify it meets the criteria of RP/0/B/1000/001, (Emergency Classification). Discuss changing plant conditions with Emergency Coordinator. Discuss classification prior to making recommendation.

0 1.1 IF THEN 0 1.2 IF THEN 0 1.3 IF THEN A General Emergency is/or should be classified, GO TO Step 4.0 of this Enclosure, (Enclosure 3.1, Emergency Classification Tracking Sheet).

A Site Area Emergency is/or should be classified, GO TO Step 3.0 of this Enclosure, (Enclosure 3.1, Emergency Classification Tracking Sheet).

An Alert is/or should be classified, GO TO Step 2.0 of this Enclosure, (Enclosure 3.1, Emergency Classification Tracking Sheet).

2. Alert NOTE:

If Steps 2.1 and 2.2 are verified to have been completed by the Emergency Coordinator then they may be marked COMPLETE on this procedure.

0 2.1 Discuss need to change classification with the Emergency Coordinator. Determine the following:

Have any medical emergencies occurred? Status? Transported offsite? Where?

NOTE:

World Of Energy personnel must be evacuated if non-essential site personnel are evacuated.

Status of non-essential personnel evacuation Have any chemical spills occurred? If yes, what?

Has fire brigade responded to any fires? Has offsite fire department responded?

Has a Condition B been determined for a Keowee Hydro Project Dam/Dike?

{2) 0 2.2 Declare an Alert. Notify Offsite Communications Manager to complete an Emergency Notification Form in accordance with RP/0/B/1000/015C, (Offsite Communications From the Emergency Operations Facility), get it approved, and fax to the offsite agencies. (The Alert is officially declared when the Emergency Action Levels for the initiating condition have been exceeded.)

2.2.1 Time of declaration:

.1 RP/O/B/10001020 Page 2 of 16 Emergency Classification Tracking Sheet NOTE:

Message form transmission must begin within 15 minutes of declaration.

Condition B for Keowee Hydro Project Dams/Dikes also requires notification of the Georgia Emergency Management Agency and National Weather Service. Remind the EOF Communications Manager to notify these agencies in addition to and after SC State, Oconee County, and Pickens County.

{2) 0 2.3 When the message form is completed and the form has been sent, contact the SEPD at the SEOC. This is in addition to contact by the State/County Communicator.

NAME Telephone Numbers SEPD 8-1(803)737-8500 D 2.3.1 IF the SEOC has NOT been activated, THEN Contact the County Emergency Preparedness Directors (CEPD) to discuss plant status.

Oconee CEPD 8-1(864)6384200 Pickens CEPD_

8-1(864)898-5943

[ 2.3.2 IF Condition B at Keowee exists, THEN Notify Hydro Central (Refer to Section 6 of the Emergency Telephone Directory, Keowee Hydro Project Dam/Dike Notification).

(2) (6) 0 2.4 Notify Emergency Coordinator of change in classification. Request Emergency Coordinator to notify the NRC EOC regarding current emergency classification.

NOTE:

Announcements should be made approximately every 30 minutes. Provide current plant status also.

o 2.5 Announce the emergency class and the time of classification to EOF personnel.

NOTE:

SSG will manage the staffing sheets and route to the EOF Director.

0 2.6 Evaluate the need for 24-hour staffing and instruct managers to prepare for it if needed.

Telephone numbers and staffing sheets are located in the procedures cart.

.1 RP/O/B/1000/020 Page 3 of 16 Emergency Classification Tracking Sheet O 2.7 Review emergency classification to determine if it is current and meets the criteria of RP/OIB/1000/001, (Emergency Classification).

o 2.7.1 IF the emergency classification remains as an Alert, THEN have the Offsite Communications Manager continue updating the state and counties by message form every 60 minutes.

O 2.7.2 Keep EOF personnel informed concerning plant conditions.

o 2.7.3 Keep EC aware of offsite conditions.

o 2.7.4 Log actions in the EOF Director's log.

o 2.7.5 Remain in this step until plant conditions dictate a change in emergency classification.

0 2.8 IF THEN 0 2.9 IF THEN A Site Area Emergency is determined, GO TO Step 3.0 of this Enclosure, (Enclosure 3.1, Emergency Classification Tracking Sheet).

A General Emergency is determined, GO TO Step 4.0 of this Enclosure, (Enclosure 3.1, Emergency Classification Tracking Sheet).

0 2.10 IF The termination criteria of Enclosure 3.2, (Emergency Classification Termination Criteria) has been met, THEN GO TO Step 5.0 of this Enclosure, (Enclosure 3. 1, Emergency Classification Tracking Sheet).

.1 RP/0/B3/000/020 Page 4 of 16 Emergency Classification Tracking Sheet

3. Site Area Emergency NOTE:

If Steps 3.1 and 3.2 are verified to have been completed by the Emergency Coordinator then they may be marked COMPLETE on this procedure.

0 3.1 Discuss need to change classifications with the Emergency Coordinator. Determine the following:

Have any medical emergencies occurred? Status? Transported offsite? Where?

NOTE:

World Of Energy personnel must be evacuated if non-essential site personnel are evacuated.

Status of non-essential personnel evacuation?

Have any chemical spills occurred? If yes, what?

+ Has fire brigade responded to any fires? Have offsite fire department responded?

Has dam failure for Keowee or Jocassee occurred? Actions taken?

Has a Condition B been determined for a Keowee Hydro Project Dam/Dike?

12) o 3.2 Declare a Site Area Emergency. Notify Offsite Communications Manager to complete an Emergency Notification Form in accordance with RP/O/B/1000/015C, (Offsite Communications From the Emergency Operations Facility), get it approved, and fax to the offsite agencies. (The Site Area Emergency is officially declared when the Emergency Action Levels for the initiating condition have been exceeded.)

3.2.1 Time of declaration:

.1 RP/O/B/1000/020 Page 5 of 16 Emergency Classification Tracking Sheet NOTE:

Message form transmission must begin within 15 minutes of declaration.

Condition B for Keowee Hydro Project Dams/Dikes also requires notification of the Georgia Emergency Management Agency and National Weather Service. Remind the EOF Communications Manager to notify these agencies in addition to and after SC State, Oconee County, and Pickens County.

(21 0 3.3 IF THEN Condition A, Dam Failure (Keowee or Jocassee) exists, Make the following protective action recommendations to Oconee County and Pickens County for imminent/actual dam failure AND include on the Emergency Notification Form under Section 15 (B) and (D):

Move residents living downstream of the Keowee Hydro Project dams to higher ground.

+

Prohibit traffic flow across bridges identified on your inundation maps until the danger has passed 0 3.4 When message form has been sent, contact SEPD. This is in addition to contact by the State/County Communicator.

NAME Telephone Numbers SEPD 8-1(803)737-8500 0 3.4.1 IF THEN Oconee CEPD the SEOC has NOT been activated, Contact the County Emergency Preparedness Directors (CEPD) to discuss plant status.

8-1(864)638-4200 Pickens CEPD 8-1(864)898-5943 0 3.4.2 IF THEN Condition B at Keowee exists, Notify Hydro Central (Refer to Section 6 of the Emergency Telephone Directory, Keowee Hydro Project Dam/Dike Notification).

42) (6) 0 3.5 Notify Emergency Coordinator of change in classification. Request Emergency Coordinator to notify the NRC EOC regarding current emergency classification.

NOTE:

Announcements should be made approximately every 30 minutes. Provide current plant status also.

0 3.6 Announce the emergency class AND the time of classification to EOF personnel.

0 3.7 IF THEN.1 RP/I/B/1000/020 Emergency Classification Tracking Sheet Page 6 of 16 Fire apparatus is needed to provide water to the spent fuel pool, Contact the Oconee CEPD to provide sufficient fire apparatus (at least three pumper trucks of 1000 gpm, or greater, capacity) to Oconee Nuclear Site (If available, Keowee Ebenezer, Corinth Shiloh and Keowee Key Rural Volunteer Fire Departments should be requested to provide support). Provide instructions concerning entry to the site.

NOTE:

A loss of offsite communications capabilities (Selective Signaling and the WAN) could occur within 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months after Keowee Hydro dam failure. Rerouting of the Fiber Optic Network through Bad Creek should be stated AS SOON AS POSSIBLE.

0 3.8 IF A Condition A, Keowee Dam failure, exists, THEN Request Sites Services Group to notify Telecommunications Group in Charlotte to begin rerouting the Oconee Fiber Optic Network. Refer them to Selective Signaling Section of the Emergency Telephone Directory (page 9).

0 3.9 Request Radiological Assessment Manager to provide information regarding potential sectors that would be affected should emergency be upgraded to a General Emergency.

NOTE:

SSG will manage the staffing sheets and route to the EOF Director.

l 0 3.10 Evaluate the need for 24-hour staffing and instruct managers to prepare for it if needed.

Telephone numbers and staffing sheets are available in the emergency procedures cart.

0 3.11 Review emergency classification to determine if it is current and meets the criteria of RP/OIB/1000/001, (Emergency Classification).

0 3.11.1 IF the emergency classification remains as a Site Area Emergency, THEN have the Offsite Communications Manager continue updating the counties by message form every 60 minutes.

0 3.11.2 Keep EOF personnel informed concerning plant conditions.

0 3.11.3 Keep EC aware of offsite conditions.

0 3.11.4 Log actions in the EOF Director's log.

o 3.11.5 Remain in this step until plant conditions dictate a change in emergency classification.

0 3.12 IF THEN A General Emergency is determined, GO TO Step 4.0 of this enclosure, (Enclosure 3.1, Emergency Classification Tracking Sheet).

.1 RPIOBi/1000/020 Page 7 of 16 Emergency Classification Tracking Sheet 0 3.13 IF the termination criteria of Enclosure 3.2, (Emergency Classification Termination Criteria) has been met, THEN GO TO Step 5.0 of this enclosure, (Enclosure 3.1, Emergency Classification Tracking Sheet).

0 3.14 IF the reduction criteria of Enclosure 3.2, (Emergency Classification Termination Criteria) has been met, THEN REFER TO Step 3.16.

o 3.15 Notify Offsite Communications Manager to complete a message form in accordance with RPIOIB/1000/015C, (Offsite Communications From The Emergency Operations Facility),

get it approved, and send it to the offsite agencies.

o 3.16 When message form has been sent, contact SEPD to discuss emergency classification reduction. This is in addition to contact by the State/County Communicator.

NAME Telephone Numbers SEPD 8-1(803)737-8500 3.16.1 IF the SEOC has NOT been activated, THEN Contact the County Emergency Preparedness Directors (CEPD) to discuss plant status.

Oconee CEPD 8-1(864)638-4200 Pickens CEPD 8-1(864)898-5943 o 3.17 Consider the present working copy procedure as being completed since the classification is reduced to an Alert.

o 3.17.1 Obtain a new working copy of RP/0/B/1000/020, (Emergency Operations Facility Director Procedure) from the procedures cart and GOTO Enclosure 3.1, (Emergency Classification Tracking Sheet) Step 2.1.

.1 RP/0B/1000/020 Emergency Classification Tracking Sheet Page 8 of 16

4. General Emergency NOTE:

If Steps 4.1 AND 4.2 are verified to have been completed by the Emergency Coordinator then they may be marked COMPLETE on this procedure.

0 4.1 Discuss changing plant conditions AND emergency classification with Emergency Coordinator prior to making recommendation. Determine the following:

Have any medical emergencies occurred? Status? Transported offsite? Where?

NOTE:

World Of Energy personnel must be evacuated if non-essential site personnel are evacuated.

Status of non-essential personnel evacuation?

Have any chemical spills occurred? If yes, what?

Has fire brigade responded to any fires? Have offsite fire departments responded?

Has dam failure at Keowee or Jocassee occurred? Actions taken?

Has a Condition B been determined for a Keowee Hydro Project Dam/Dike?

{2}

NOTE:

The General Emergency is officially declared at this time.

Protective Action recommendations are the sole responsibility of the EOF Director. Use input from other managers. Continually review plant status for change in Protective Action Recommendations. Review the requirements of RP/O/B/1000/024, (Protective Action Recommendations).

0 4.2 Declare a General Emergency. Initial protective action recommendation is to evacuate 2 mile radius and 5 miles downwind.

4.2.1 Time of Declaration:

.1 RP/0/B/1000/020 Emergency Classification Tracking Sheet Page 9 of 16 NOTE:

Message form transmission must begin within 15 minutes of declaration.

Condition B for Keowee Hydro Project Dams/Dikes also requires notification of the Georgia Emergency Management Agency and National Weather Service. Remind the EOF Communications Manager to notify these agencies in addition to and after SC State, Oconee County, and Pickens County.

(2) 0 4.2.2 Notify Offsite Communications Manager to begin completing a message form in accordance with RP/IOB/1000/O15C, (Offsite Communications From The Emergency Operations Facility).

A. Request Radiological Assessment Manager to determine the exact sectors to be evacuated and sheltered using HP/OIB/1009/018, (Offsite Dose Projections).

NOTE:.5, (10 Mile EPZ Map), provides a map of the 10 mile EPZ for reference.

(8)

B. Provide the following protective action recommendations for use by the offsite communicator to complete the emergency notification form.

PICKENS COUNTY OCONEE COUNTY 0-2 2-5 f

5-10 0-2 1 2-5 J

5-10 mile mile l

mile mile l

mile mile AC Al BI Cl A2 B2 C2 AO Dl El Fl D2 E2 F2 EVACUATE I

SHELTER I

I (8)

C. IF Condition A, Dam Failure (Keowee or Jocassee) exists, THEN Make the following protective action recommendations to Oconee County and Pickens County for imminent/actual dam failure and include on the Emergency Notification Form under Section 15 (B) and (D):

Move residents living downstream of the Keowee Hydro Project dams to higher ground.

Prohibit traffic flow across bridges identified on your inundation maps until the danger has passed.

.1 RP/OB/l1000/020 Page 10 of 16 Emergency Classification Tracking Sheet O 4.3 When message form is completed and the form has been sent, contact SEPD. This is in addition to contact by the State/County Communicator.

Protective Action Recommendation: Read from the approved emergency notification form the protective action recommendations. Provide any known information concerning conditions that would make evacuation dangerous.

0 4.3.1 IF the State Emergency Operations Center has been activated, THEN contact the SEPD.

NAME Telephone Numbers SEPD 8-1(803)737-8500 O 4.3.2 IF the State Emergency Operations Center has NOT been activated, THEN contact the CEPD.

Oconee CEPD 8-1(864)6384200 Pickens CEPD 8-1(864)898-5943 0 4.3.3 Request SEPD or CEPD to call back after a decision has been made on actual protective actions recommended by the State and Counties for the plume exposure pathway population.

A. Record below the actions that have been taken by SEPD or CEPD:

B. Information received from:

Time:

0 4.4 Notify the Emergency Coordinator of the change in classification AND the current protective action recommendations. Request Emergency Coordinator to notify the NRC EOC of the change in emergency classification AND the protective action recommendations.

NOTE:

Announcements should be made approximately every 30 minutes. Provide current plant status also.

0 4.5 Announce the emergency class AND the time of classification to EOF personnel. Provide the current protective action recommendations.

5 4.6 IF THEN 0 4.7 IF THEN.1 RP/OIB/1000/020 Emergency Classification Tracking Sheet Page 1 of 16 Condition B at Keowee exists, Notify Hydro Central (Refer to Section 6 of the Emergency Telephone Directory, Keowee Hydro Project Dam/Dike Notification).

12){6)

Fire apparatus is needed to provide water to the Spent Fuel Pool, Contact the Oconee CEPD to provide sufficient fire apparatus (at least three pumper trucks of 1000 gpm, or greater, capacity) to Oconee Nuclear Site (If available, Keowee Ebenezer, Corinth Shiloh and Keowee Key Rural Volunteer Fire Departments should be requested to provide support). Provide instructions concerning entry to the site.

0 4.8 Evaluate plant status.

0 4.8.1 IF emergency classification remains as a General Emergency, THEN have Offsite Communications Manager continue updating the counties by message form every 60 minutes.

0 4.8.2 Keep EOF personnel informed concerning plant conditions.

0 4.8.3 Keep EC aware of offsite conditions.

0 4.8.4 Log actions in the EOF Director's log.

o 4.8.5 Remain in this step until plant conditions dictate a change in protective action OR emergency classification.

0 4.8.6 IF Additional protective action recommendations are required by RP/O/B/1000/024, (Protective Action Recommendations),

THEN GO TO Step 4.9.

0 A. Additional PAR Determination Time:

44) 0 4.8.7 IF The termination criteria of Enclosure 3.2, (Emergency Classification Termination Criteria) are met, THEN GO TO Step 5.0 of this Enclosure, (Enclosure 3. 1, Emergency Classification Tracking Sheet).

NOTE:

Transmission of a change in protective action recommendations must begin within 15 minutes of determination.

0 4.9 Notify Offsite Communications Manager to complete a message form in accordance with RP/IOB/lOOOIOl5C, (Offsite Communications From The Emergency Operations Facility) providing the additional protective action recommendations, get it approved, and send it to the offsite agencies.

.1 RP/0B/1000/020 Page 12 of 16 Emergency Classification Tracking Sheet E 4.10 When the message form has been sent, contact SEPD. This is in addition to contact by the State/County Communicator.

Protective Action Recommendation: Read from the approved emergency notification form the protective action recommendations. Provide any known information concerning conditions that would make evacuation dangerous.

E 4.10.1 IF the State Emergency Operations Center has been activated, THEN contact the SEPD.

NAME Telephone Numbers SEPD 8-1(803)737-8500 o 4.10.2 IF the State Emergency Operations Center has NOT been activated, THEN contact the CEPD.

Oconee CEPD 8-1(864)638-4200 Pickens CEPD 8-1(864)898-5943 E 4.10.3 Request SEPD or CEPD to call back after a decision has been made on actual protective actions recommended by the State and Counties for the plume exposure pathway population.

A. Record below the actions that have been taken by SEPD or CEPD:

B. Information received from:

Time:

D 4.11 Notify the Emergency Coordinator of the change in protective action recommendations.

4.11.1 Request Emergency Coordinator to notify the NRC EOC of the change in protective action recommendations.

NOTE:

Announcements should be made approximately every 30 minutes. Provide current plant status also.

El 4.12 Announce the current protective action recommendation AND plant status to EOF personnel.

.1 RP/O/B/1000/020 Emergency Classification Tracking Sheet Page 13 of 16 0 4.13 Evaluate Plant status.

4.13.1 IF emergency classification remains as a General Emergency, THEN have the Offsite Communications Manager continue updating the counties by message form every 60 minutes.

O 4.13.2 Keep EOF personnel informed concerning plant conditions.

[ 4.13.3 Keep EC aware of offsite conditions.

o 4.13.4 Log actions in the EOF Director's log.

o 4.13.5 Remain in this step until plant conditions dictate a change in protective action OR emergency classification.

o 4.13.6 IF Additional protective action recommendations are required by RP10/B/1000/024, (Protective Action Recommendations),

THEN GO TO Step 4.14.

0 A. Additional PAR Determination Time:

{4}

0 4.13.7 IF The termination criteria of Enclosure 3.2, (Emergency Classification Termination Criteria) are met, THEN GO TO Step 5.0 of this Enclosure, (Enclosure 3.1, Emergency Classification Tracking Sheet).

NOTE:

Transmission of a change in protective action recommendations must begin within 15 minutes of determination.

0 4.14 Notify Offsite Communications Manager to complete a message form in accordance with RP/O/B/1000/015C, (Offsite Communications From The Emergency Operations Facility) providing the additional protective action recommendations, get it approved, and send it to the offsite agencies.

.1 RP/0/B/1000/020 Page 14 of 16 Emergency Classification Tracking Sheet l 4.15 When the message form has been sent, contact SEPD. This is in addition to contact by the State/County Communicator.

Protective Action Recommendation: Read from the approved emergency notification form the protective action recommendations. Provide any known information concerning conditions that would make evacuation dangerous.

I 4.15.1 IF the State Emergency Operations Center has been activated, THEN contact the SEPD.

NAME Telephone Numbers SEPD 8-1(803)737-8500 0 4.15.2 IF the State Emergency Operations Center has NOT been activated, TIEN contact the CEPD.

Oconee CEPD 8-1(864)638-4200 Pickens CEPD 8-1(864)898-5943 o 4.15.3 Request SEPD or CEPD to call back after a decision has been made on actual protective actions recommended by the State and Counties for the plume exposure pathway population.

A. Record below the actions that have been taken by SEPD or CEPD:

B. Information received from:

Time:

o 4.16 Notify the Emergency Coordinator of the change in protective action recommendations.

4.16.1 Request Emergency Coordinator to notify the NRC EOC of the change in protective action recommendations.

NOTE:

Announcements should be made approximately every 30 minutes. Provide current plant status also.

o 4.17 Announce the current protective action recommendation AND plant status to EOF personnel.

.1 RP/O/B/1000/020 Emergency Classification Tracking Sheet Page 15 of 16 l NOTE:

SSG will manage the staffing sheets and route to the EOF Director.

I I

I o 4.18 Evaluate the need for 24-hour staffing and instruct managers to prepare for it if needed.

Telephone numbers and staffing sheets are available in the emergency procedures cart.

o 4.19 WHEN termination criteria are met, GO TO Step 5.0 of Enclosure 3.1 (Emergency Classification Tracking Sheet).

i. Termination I41 0

5.1 IF Terminating from an Alert or Site Area Emergency, THEN GO TO Step 5.3.

0 5.2 IF In a General Emergency, THEN Discuss with the NRC Director of Site Operations (NRCDSO) and the SEPD that the termination criteria have been met.

5.2.1 Secure agreement from the two directors to terminate the event.

5.2.2 Document names and time decision made below.

NAME Telephone Numbers Time SEPD 8-1(803)737-8500 NRCDSO (In person in EOF) 0 5.3 Request Offsite Communications Manager to complete message form and send it in accordance with RP/O/B/1000/015C, (Offsite Communications From The Emergency Operations Facility) to terminate the emergency.

O 5.4 IF terminating from an Alert or a Site Area Emergency, THEN notify the following agencies.

NAME Telephone Numbers 8-1(803)737-8500 SEPD 5.4.1 IF the SEOC has NOT been activated, THEN contact the County Directors of Emergency Planning (CEPD).

Oconee CEPD_

8-1(864)6384200 Pickens CEPD 8-1(864)898-5943

.1 Emergency Classification Tracking Sheet RP/03/BlOOO/020 Page 16 of 16 0 5.5 IF THEN terminating from an emergency involving dam failure (Keowee or Jocassee),

discuss termination with Hydro Central (Refer to Section 6 of the Emergency Telephone Directory, Keowee Hydro Project Dam/Dike Notification).

{6}

0 5.6 Establish Recovery Organizations if needed.

5.6.1 GO TO Enclosure 3.3, (Recovery Guidelines).

5.6.2 IF Recovery Organizations are NOT required, THEN GO TO Step 5.7.

0 5.7 Request Emergency Planning to provide a copy of the License Event Report (LER) to state and county agencies at the time it is sent to the NRC.

.2 RP/OJBI1000/020 Page 1 of 2 Emergency Classification Termination Criteria

.2 Emergency Classification Termination Criteria RP/0B/1000/020 Page 2 of 2 AL TERMINATE THE CURRENT CLASSIFICATION AND

+

DECLARE THE PLANT IN RECOVERY CONTINUE WITH THE CURRENT CIASSIFICAT1ON UNTIL A RECOVERY CAN BE DECLARED TABLE 1 RECOVERY CONDITIONS NO NEW EVACUATION OR SHELTERING PROTECTIVE ACTIONS ARE ANTICIPATED CONTAINMENT PRESSURE IS LESS THAN DESIGN PRESSURE CONTAINMENT HYDROGEN LEVELS ARE BEING MAINTAINED WITHIN LIMITS LONG TERM CORE/DEBRIS COOLING HAS BEEN ESTABLISHED THE RISKS FROM RECRITICALITY ARE ACCEPTABLY LOW RADIATION PROTECTION IS MONITORING ACCESS TO RADIOLOGICALLY HAZARDOUS AREAS OFF-SITE CONDITIONS DO NOT LIMIT PLANT ACCESS THE NEWS DIRECTOR, NRC OFFICIALS, AND STATE REPRESENTATIVES HAVE BEEN CONSULTED TO DETERMINE THE AFFECTS OF TERMINATION ON THEIR ACTIVITIES THE RECOVERY ORGANIZATION IS READY TO ASSUME CONTROL OF RECOVERY OPERATIONS

.3 RP/IB/1000/020 Recovery Guidelines Page 1 of 2

1. Recovery Guidelines The Recovery Manger shall be responsible for the following:

0 1.1 Make a PA announcement as follows:

"Agreement has been reached between Duke, the State of South Carolina and the NRC that the General Emergency classification is terminated. Recovery Operations are being initiated at the site. Actions are underway to determine when people who have been evacuated from their homes can return. As this information is made available, it will be released to the public."

0 1.2 Establish a Recovery Organization to handle offsite consequences.

1.2.1 The offsite recovery organization will stay at the EOF and work with the counties and state if radiological conditions exist beyond the ONS site boundary.

1.2.2 The onsite recovery organization will be established by the Emergency Coordinator.

o 1.3 Make the following assignments:

Recovery Manager Radiological Assessment Manager Field Monitoring Coordinator Emergency Planning Manager Sites Services Group Manager 0 1.4 Assure staffing for long-term operation.

NOTE:

Once recovery has been determined, the emergency notification message forms are no longer used.

0 1.5 Contact the SEPD to discuss work in progress at the EOF and determine communication channels and notifications expected.

0 1.6 Discuss with each manager the activities they have in progress.

.3 RP/O/B/1000/020 Recovery Guidelines Page 2 of 2 I 1.7 Radiological Assessment Responsibilities 1.7.1 Provide ingestion pathway dose assessments 1.7.2 Provide ongoing communications with DHEC Nuclear Emergency Planning 1.7.3 Evaluate environmental concentrations within the radiological footprint 1.7.4 Provide technical assistance to Joint Information Center 1.7.5 Help plan for reactor building purge as needed o 1.8 Emergency Planning Responsibilities 1.8.1 Communications to the State and County Emergency Directors 1.8.2 Review information being released through the news medium o 1.9 Sites Services Group Manager Responsibilities 1.9.1 Assure ANI (insurance) is set up for public inquiry 1.9.2 Provide services as required O 1.10 Joint Information Center Responsibilities 1.10.1 Providing news releases 1.10.2 Work with media/public to reduce rumors EJ 1.11 Responsibilities of the Site's Outage Manager 1.11.1 Provide Recovery Manager with updates on work in progress at the site O 1.12 Keep the Emergency Operations Facility activated and staffed until consensus is reached by Duke and State of South Carolina there is no basis for continuous staffing.

L 1.12.1 Record time and date that Emergency Operations Facility/Joint Information Center were closed.

A. EOF/JIC Closed Time/Date

.4 Emergency Preparedness Acronyms RP/OIB/10001020 Page 1 of 1 BSHWM CEPD DHEC EC EOF EOFD EPA FAX FEOC FTS-2000 LEC NEP NRCDSO NRC EOC OSC PAR SCC SEPD SEOC SSG SWP TSC Bureau of Solid and Hazardous Waste Management County Emergency Preparedness Director/Division Department of Health and Environmental Control Emergency Coordinator Emergency Operations Facility Emergency Operations Facility Director Emergency Preparedness Agency Facsimile Forward Emergency Operations Center (Clemson)

NRC Emergency Telephone Communication System Law Enforcement Center Nuclear Emergency Planning (BSHWM)

Nuclear Regulatory Commission Director of Site Operations Nuclear Regulatory Commission Emergency Operations Center Operational Support Center Protective Action Recommendations State/County Communicator State Emergency Preparedness Director/Division State Emergency Operations Center (Columbia)

Site Services Group State Warning Point Technical Support Center

.5 10 Mile EPZ Map RP/0/B/1000/020 Page 1 of 1 Radius From Site Pickens County Oconee County (miles)

Sectors Sectors 0-2 AO AO 2-5 A-1, B-1, C-1 D-1, E-1, F-1 5-10 A-2, B-2, C-2 D-2, E-2, F-2

.6 RP/O/B/1000/020 References Page 1 of 1

1. PIP References

1.

PIP 0-98-04996

2.

PIP 0-99-00743

3.

PIP 0-99-03527

4.

PIP 0-99-03971

5.

PIP 0-99-04165

6.

PIP 0-01-03460

7.

PIP 0-02-01452

8.

PIP 0-02-05829

9.

PIP 0-03-04133

INFORMATION nII V 111--

-ilILi k Duke Oconee Nuclear Site E

OPower.

Engineering Manual A Duke Energy Company Section

Title:

EM-5.1 - Engineering Emergency Response Plan Revision No.:

11

Reference:

Approved By:

I4i"'

F Approved Date: August 19, 2003 Revised By:

Revised Date:August 19, 2003 Reviewed By:

Original Date: 05/27/92 Effective Date: August 19, 2003 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 9.1 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 Editoral Changes Only VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Table of Contents 1.0 PURPOSE.I..............................................

2.0 REFERENCES

1 3.0 DEFINITIONS...............................................

1 4.0 RESPONSIBILITIES...............................................

1 5.0 SITE ASSEMBLY AND EVACUATION...............................................

2 6.0 TECHNICAL SUPPORT CENTER...............................................

4 7.0 OPERATIONAL SUPPORT CENTER...............................................

6 8.0 EMERGENCY OPERATIONS FACILITY:...............................................

7 9.0 ENCLOSURES...............................................

7.1 - Oconee Technical Support Center Guideline............................................... 8 iii VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page I of 53 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 an announcement on the station PA system. Notification during unscheduled work hours will be by pager or Community Alert Network using the following:

PAGER CODES:

Blue Delta - EOF/TSC/OSC activated for a drill.

Blue Echo - EOF/TSC/OSC activated for an emergency.

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EM 5.1 Revision No.: II Page 2 of 53 Note: During flooding/dam failure/earthquake conditions assume bridges may be damaged; use caution.

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

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

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.

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 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.:

I Page 3 of 53 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. Do not 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 5 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 a Lotus Note sent to group evacuation coordinators giving instructions for an evacuation.

5.2.2 The Engineering Evacuation Coordinator monitors LOTUS Notes during an emergency, passes evacuation information on to Engineering group administrative assistants, and gets 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.

Accountability Notification:

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EM 5.1 Revision No.: 11 Page 4 of 53 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.

5.2.7 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 Unit 1 or 2 Control Room Lobby, and frisk for possible contamination before entering the Control Room.

EMERGENCY RESPONSE SRWP 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 Mechanical and Civil Engineering Section (MCE). 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.: II Page 5 of 53 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 Modification Engineering. Individuals staffing this position will be contacted by the Community Alert Network (CAN) system.

6.4.2 The Technical Assistant to TSC/OSC Liaison will maintain the Plant status board 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 Systems 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 Systems Engineering will be called by the Community Alert Network 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 functions via the transient monitors

4.

Safety review function

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.

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EM 5.1 Revision No.:

Page 6 of 53 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.

6.7 Offsite 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 classification.

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 Unit 3 Control Room Elevator Lobby, and frisk for possible contamination before entering the Control Room.

EMERGENCY RESPONSE SRWP 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 RES 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 RES 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.: 11 Page 7 of 53 8.0 Emergency Operations Facility:

8.1 The Emergency Operations Facility (EOF) is located in Clemson on Isaqueena Trail next to Duke's Southern Operation Center. TLDs and EDs are not required for this facility.

8.2 Offsite Dose Assessment 8.2.1 The Offsite Dose Assessment persons will report to the Radiological Assessment Manager in the EOF.

They will be responsible for providing Offsite Dose Assessment as needed.

8.3 Technical Briefers:

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

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

8.3.2 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.

8.3.3 The Technical Briefers will keep the Technical Briefer Section Head informed of calls being received and assist in coordinating activities as needed.

8.3.4 The Technical Briefer position is filled by persons from across the organization needed.

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

EM 5.1 Revision No.: 11 Page 8 of 53.1 - Oconee Technical Support Center Guideline Rev. 7 Gregg Swindlehurst 8/6/01 TSCG Section A Date Stephen Parrish 8/6/01 TSCG Section B Date Ron Harris 819/01 TSCG Section C Dale Stephen Parrish 8/6/01 TSCG Section D Date Gregg Swindlehurst 8/6/01 TSCG Section E Date Ken Grayson 8/8/01 TSCG Section F Date Ron Harris 8/9/01 TSCG Section G Date Stephen Parrish 8/6/01 TSCG Section H Date Stephen Parrish 8/6/01 TSCG Section I Date Camilo Abeflana 819/01 TSCG Section J Date JeffRowell 8/9/01 TSCG Section K Date Ed Burchfield 8/9/01 TSCG Section L Date Vance Bowman 3/1/02 TSCG Section M Date VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page 9 of 53 Ron Harris 5/21/02 TSCG Section N Date Gregg Swindlehurst 7112/02 TSCG Section 0 Date VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page 10 of 53 TABLE OF CONTENTS A.

STARTING OR BUMPING A RCP FOLLOWING LOSS OF SCM............................................................... 13 B.

STEAMING A STEAM GENERATOR WITH WATER IN THE STEAM LINE........................................... 19 C.

REFILL THE EWST..........................................................................

21 D.

EVALUATE OUTSIDE AIR BOOSTER FAN OPERATION......................................................................... 23 E.

NATURAL CIRCULATION COOLDOWN CONSIDERATIONS................................................................. 24 F.

MAKEUP AND MONITORING OF THE SFP AND RECOVERY FROM A BOILING CONDITION........ 28 G.

MAKEUP AND MONITORING OF CCW INLET PIPE INVENTORY........................................................ 31 H.

CONSERVE BWST INVENTORY..........................................................................

33

1.

CFT CORE COOLING FOLLOWING LOSS OF DECAY HEAT REMOVAL..................

........................... 35 J.

MITIGATE LPI PUMP INTERACTION AND LPI PUMP RESTART........................................................... 37 K.

ENERGIZE THE ASW SWITCHGEAR FROM AN OPERATING OCONEE UNIT..............

...................... 40 L.

LIMITATIONS ON ALIGNING HPI SUCTION FROM THE SFP................................................................ 42 M.

ENSURE TOTAL LPSW RECIRCULATION FLOW IS *9000 GPM DURING CCW DAM FAILURE.45 N.

N. MANAGE KEOWEE LAKE LEVEL DURING A LOOP.47

0.

OPENING THE ALTERNATE POST-LOCA BORON DILUTION FLOWPATH.51 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page 11 of 53

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 CCW dam failure N.

Manage Keowee Lake Level During a LOOP 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.

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EM 5.1 Revision No.: 11 Page 12 of 53 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.: II Page 13 of 53 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.

HPI 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 spill-over. 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.: 11 Page 14 of 53 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:

I) 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 SG 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.

Adequate 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.: 11 Page 15 of 53

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 Bump/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 cooling. The first figure is a function of RCS cold leg temperature and elapsed time. The second figure is a function of SG 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 SG 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 > 70% prior to reactor trip Verify time since reactor trip is within analyzed limits (< 48 h)

Figure I uses RCS cold leg temperature as a function of elapsed time since reactor trip for various RCS boron concentration pre-conditions. Figure 2 uses SG 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 SG pressure indication.

To use either Figure I or Figure 2, determine:

I. 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 SG 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 SG. 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.: 11 Page 16 of 53 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.: 11 Page 17 of 53 Figure 1: RCP Bump/Restart Criteria 550.0 500.0

- 450.0 0

E CD M

E0 I-400.0 0) 0 0

co0 350.0 0

S la 0

j 300.0 250.0 650 ppmB Pre-Accident

- 550 ppmB Pre-Accident 450 ppmB Pre-Accident

-+--

350 ppmB Pre-Accident

250 ppmB Pre-Acident 150 ppmB Pre-Accident

+ < 50 ppmB Pre-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.: 11 Page 18 of 53 Figure 2: RCP Bump/Restart Criteria 1050.0 Acceptable 1000.0 Operation 950.0 900.0 850.0 800.0 750.0 700.0 a.

650.0 U) 600.0 g

550.0 C

500.0 F

X 450.0-0 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.: I Page 19 of 53 B.

STEAMING A STEAM GENERATOR WITH WATER IN THE STEAM LINE 1.0 SAFETY CONCERN Potential loss of secondary pressure control due to waterhanmner causing steam line rupture and/or loss of turbine-driven pump steam supply.

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

Evidence of a SG 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 SG 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 SG 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 SG despite a reduction in SG 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 SG exit.

With water leaking by the instrument tap, the water will pool in the length of pipe exiting the SG. The level in this pipe will be approximately the same as the level indicated in the SG. 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 SG level has decreased below 96 %OR). 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 SG is allowable as very high steam velocities are required with lower levels.

If there is indication of SG 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.: 11 Page 20 of 53 this condition of operation. However when full range SG level indicates an increasing trend in SG 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 SG should not be steamed at all in this instance, even if the OR level decreases below 96 %OR.

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

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

If full range indication does not indicate SG 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, UPI 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 SG.

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EM 5.1 Revision No.: 11 Page 21 of 53 C.

REFILL THE EWST 1.0 SAFETY CONCERN Loss of HPSW resulting in loss of backup cooling water to HPI 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 due to a Turbine Building flood:

PSW provide cooling water to 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 by a factor of three. Approximately 9% of the total core damage frequency involve failure of this action.

3.3 Implementation Refill the EWST through a method delineated in:

AP/l/A/1700/010, Enclosure 6.1 Two methods are presented in the Enclosure. Options I and 2 will deliver a maximum flow of 1500 gpm.

Consider the following when choosing a method:

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

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EM 5.1 Revision No.: 11 Page 22 of 53 Location on the intake near 2C CCW pump available for fire department engine.

Fire department has length of hard pipe suction hose to reach 4 to 6 feet below water surface.

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

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 4 to 6 feet below water surface.

Fire hydrant HY-7 available. (OFD-124C-1.5) 3.4 Expected Plant Response Employing a method detailed in procedure AP/l/A/1700/010 should result in maintaining or increasing EWST level.

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EM 5.1 Revision No.: II Page 23 of 53 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 (1/3RIA-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 112/3RIA-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.: 11 Page 24 of 53 E.

NATURAL CIRCULATION COOLDOWN CONSIDERATIONS 1.0 SAFETY CONCERN Loss of or degraded natural circulation.

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

Loss of CCW intake canal.

Fire.

Loss of any fire zone due to (10 CFR 50 Appendix R) 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 Coupled - RCS is Subcooled Subcooled natural circulation is indicated by:

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

2. Incore T/C temperature indication should track Tht within approximately 10 0F, and

3. T and TWold temperature difference should be between 30 to 50 'F.

4.

SG level at 50 %OR, 240 in XSUR.

The AT between Tho, and Tcod is expected to be 50 F or less.

The magnitude of the flow rate will decrease as the AT decreases and as core decay heat decreases.

Primar!y/Secondary Coupled - RCS is Saturated Saturated natural circulation is indicated by:

1. Td 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.: 11 Page 25 of 53 With the RCS saturated, incore T/C temperature will track Tht whether natural circulation flow exists or not. The AT between Thot and Told will vary between 50 0F 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 Th,, in the operating loop will indicate core outlet temperature. Td on the operating SG will be approximately equal to T, in the operating SG.

T,0dd in the isolated SG may not be equal to 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 SG may be 10 TF higher than the 50 TF expected with two operating SGs. The loop with the idle SG may prevent primary depressurization.

Interruption 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.: 11 Page 26 of 53 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 SG 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.

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

v 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:

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.

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.

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EM 5.1 Revision No.: 11 Page 27 of 53 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.: 11 Page 28 of 53 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 IRIA-41 (Spent Fuel Pool Bldg Gas Mon) should be monitored for an increase in radiation level inside the Units I 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.

3.3 Implementation Monitor SFP Level Locally VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page 29 of 53 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 HPI 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/1&2/A/l 104/006/C and OP/3/A/I 104/006/E 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:

Procedure MP/0/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 a 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 F 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.

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 1&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 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page 30 of 53 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 &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 V = 53.4X QL - 573 To fill the pool to maximum level V = 42.7xQL -5.14 Unii 3 To fill the pool to normal level V =53.7xQL -6.45 To fill the pool to maximum level V = 43.1 X L -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.: 11 Page 31 of 53 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/fiood)).

Station blackout. (SSF ASW) 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 Gravity flow from CCW discharge Dedicated portable submersible pump Cross connect the Unit I 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, 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 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 I 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 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 The methods to provide makeup to the Unit 2 CCW intake are:

1. Running a Unit 2 CCW pump VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page 32 of 53

-FOREBAY ELEV is above 67 feet

-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 MP/O/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 routed to the yard drain.

Unit 2 and either Unit I or 3 CCW intake and discharge pipes 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 I 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 I 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 operation and/or possible losses due to leakage from the system.

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EM 5.1 Revision No.: 11 Page 33 of 53 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 HPI 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 HPI cooling. Aligning makeup to and replenishing the BWST inventory should be pursued while attempting to conserve the inventory.

HPI forced cooling is initiated by manually establishing HPI 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.: 11 Page 34 of 53 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/1 800/001 Section 502.

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.

3.4 Expected Plant Response The energy storage and conduction capacity of the RB during HPI 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.: 11 Page 35 of 53 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 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 (OPIl(2,3)/A/1 104/001, 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-1 and/or l/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 I 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.: 11 Page 36 of 53 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 CFTs 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.: 11 Page 37 of 53 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 HPI suction from the RBES and restart of an LPI pump following deadhead operation SBLOCA HPI 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 LPIPI-piggyback operation. In particular, under low flow conditions a weak-pump strong-pump interaction is established. The acceptability of the LPIIIPI piggyback alignment with two trains of LPI supplying suction to two HPI pumps through both LP-15 and LP-16 is a function of total BPI 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.: 11 Page 38 of 53 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 1200 gpm if actual flow is <750 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 should be throttled to < 1500 gpm (when taking suction from BWST). The flow rate uncertainty is approximately 143 gpm.

BPI 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 BPI 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.

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EM 5.1 Revision No.: 11 Page 39 of 53 3.4 Expected Plant Response 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.: 11 Page 40 of 53 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 (SI) 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 SBI 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 < IMVA or 137 amps. With both main feeder buses in service, the load on main feeder bus I 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 I are open.

3. Place CT4 BUS I "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.: 11 Page 41 of 53

5. CloseBreakerSI.

6. Have I&E perform procedure IP/O/A/0050/001, Procedure To Provide Emergency Power To An UPI 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.: 11 Page 42 of 53 L.

LIMITATIONS ON ALIGNING HPI 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 HPI 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 HPI 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 HPI 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 BPI 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 SFP.

SFP 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. SFP level will decrease based on the HPI flow rate.

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EM 5.1 Revision No.: 11 Page 43 of 53 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 UPI 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 I 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.: 11 Page 44 of 53 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.

M t....

I

i.

J l

I E

I........

835 Ii I

'I I11 1 11 I

I I 11 I11 1 1 I 1 1 I I I I I III I I I 1 I I 1 I I I

< 830 51 AcceDtable Operation I

I I I I I I I I I -. 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 I I I I.I.

I.

II.

I I.

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.I I

-I I1 1

I I, I I. I II 1111 I

11I1711111 11 ll 111I M ll 1 I 1 111 11 I I;

I I

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I 150 155 160D 16i5 17[)

175 180 185 190 195 20 205 210 Tapwdu(F)

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 UPI pumps. Adjust monitoring frequency based on projections of SFP temperature and level.

HPI 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 UPI 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.: 11 Page 45 of 53 M.

ENSURE TOTAL LPSW RECIRCULATION FLOW IS <9000 GPM DURING CCW DAM FAILURE 1.0 SAFETY CONCERN Total LPSW flow is maintained <9000 gpm during a CCW Dam 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 Case B of AP/1/A/1700/013 (Dam Failure Without Loss of CCW Intake Canal). TheSymptomsforenteringAP/l/A/1700/013are:

Visual observation of decreasing lake level or dam failure Telephone communication of a Keowee or Little River dam failure "CCW LAKE LEVEL LOW" statalarm (ISA-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 I&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. The only available LPSW loads on each unit are listed below as well as the LPSW throttle valve associated with each load.

"B" RBCU and RBACs - 1/2/3LPSW-21 "A" LPI Cooler - 1/2/3LPSW-4 or 1/2/3LPSW-251 "IB" LPI Cooler - 1/2/3LPSW-5 or 1/2/3LPSW-252 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.: 11 Page 46 of 53 3.3 Expected Plant Response Total LPSW flow as indicated on the operating LPSW Pump's discharge flow gauge should indicate <9000 gpm.

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EM 5.1 Revision No.: 11 Page 47 of 53 N.

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 I 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.: 11 Page 48 of 53 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/1,2,3/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. A procedure exists to vent air from the Chiller Condenser Service Water Pump suction piping. This procedure temporarily aligns the LPSW supply, but the procedure restores the CCW supply after venting. As lake level decreases, this would lead to further air binding problems. Procedure changes are pending (ref. PIP 0-02-136) that would allow the LPSW supply to remain aligned to the Chiller VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page 49 of 53 Condenser Service Water Pump during the remainder of the event. Until those procedures are revised, the TSC should consider aligning the LPSW supply and leaving it aligned to prevent the need for repetitive venting.

33.5 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/1,2,3/A/1 700/011). 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 VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: II Page 50 of 53 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.: 11 Page 51 of 53

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.

The primary boron dilution flowpath cannot be opened.

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 4000F 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-1 04 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-I, 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.: 11 Page 52 of 53 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 pot 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 sump 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 will be available to support Oconee Engineering and Operations following any station event, this VERIFY PRINTED COPY AGAINST ELECTRONIC VERSION PRIOR TO USE

EM 5.1 Revision No.: 11 Page 53 of 53 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 fLowpath: 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.

1. Ensure LP-6, LP-9, LP-2 1 are closed

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

3. Secure A BS pump and close BS-I

4. Secure A LPI pump

5. Close LP-19

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

7. Throttle open BS-l 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-1.

9. Align A LPI in DHR alignment.

Step 8: Report to management on the plant response to opening the alternate post-LOCA boron dilution flowpath.

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

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