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Text

Initial Exam 2011-301 Final RO Written Exam
	ML111380080
Person / Time
Site:	Oconee
Issue date:	05/17/2011
From:	; NRC/RGN-II
To:	; Duke Energy Corp
References
	50-269/11-301, 50-270/11-301, 50-287/11-301, ES-401, ES-401-7
	Download: ML111380080 (245)
	v • d • e

ES-401 Site-Specific RO Written Examination Form ES-401-7 Cover Sheet U.S. Nuclear Regulatory Commission Site-Specific RO Written Examination Applicant Information Name:

Date: 0511312011 Facility/Unit: Oconee Region: I II lii IV Reactor Type: W CE BW GE Start Time: Finish Time:

Instructions Use the answer sheets provided to document your answers. Staple this cover sheet on top of the answer sheets. To pass the examination, you must achieve a final grade of at least 80.00 percent. Examination papers will be collected 6 hours0.25 days 0.0357 weeks 0.00822 months after the examination begins.

Applicant Certification All work done on this examination is my own. I have neither given nor received aid.

Applicants Signature Results Examination Value Points Applicants Score Points Applicants Grade Percent

Oconee Nuclear Station Question:

I 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

1TA and 1TB lockout Current conditions:

Reactor power = 1% decreasing

Group 2 rod 6 position = 58% withdrawn The EOP directs the operator to (1) AND the reason for this action is to (2)

Which ONE of the following completes the above sentence?

A. 1. GO TO Rule 1 (ATWS/Unanticipated Nuclear Power Production)

2. ensure reactor power is within the heat removal capacity of natural circulation B. 1. GO TO Rule I (ATWS/Unanticipated Nuclear Power Production)

2. achieve a shutdown margin of at least I % AK/K.

C. 1.OpenlHP-24and IHP-25

2. ensure adequate RCS inventory during the subsequent RCS cooldown D. 1.OpenlHP-24and 1HP-25

2. achieve a shutdown margin of at least I % AK/K.

Page 1 of 75

Oconee Nuclear Station Question:

2 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Time = 1200:

Reactor power = 100%

BOTH Main FDW Pumps trip Time = 1205:

Reactor power = 26% slowly decreasing

PORV has failed open

1) In accordance with Rule 6 (HPI), the MAXIMUM power level at which HPI can be throttled is (1)

2) The reason power level is used to determine if throttling HPI is appropriate is that it ensures (2)

Which ONE of the following completes the statements above?

A. 1.1%

2. Boron addition continues until power is less than 1%

B. 1.5%

2. Boron addition continues until power is less than 5%

C. 1.1%

2. sufficient core cooling exists until power level is low enough that HP! Forced cooling can remove the heat D. 1.5%

2. sufficient core cooling exists until power level is low enough that HP! Forced cooling can remove the heat Page 2 of 75

Oconee Nuclear Station Question: 3 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 100%

Current conditions:

SBLOCA

IA and I B SG Levels at the LOSCM setpoint

TBVs in AUTO and CLOSED Which ONE of the following combinations of parameters describes the indications that boiler-condenser mode heat transfer is occurring?

RCS primary water level is (1) and SG Pressures will (2)

A. 1. below the SG secondary water level

2. increase until the TBV setpoint is reached B. 1. below the SG secondary water level

2. decrease until SG pressure stabilizes at Tsat for the RCS temperature C. 1. above the SG upper tube sheet

2. increase until the TBV setpoint is reached D. 1. abovetheSGuppertubesheet

2. decrease until SG pressure stabilizes at Tsat for the RCS temperature Page 3 of 75

Oconee Nuclear Station Question:

4 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

0435:

Reactor power = 100%

0440

RCS pressure = 1120 psig stable

Reactor Building pressure peaked at 4.6 psig and is now 2.8 psig slowly decreasing

EOP Enclosure 5.1 (ES Actuation) initiated 0514

RCS Pressure = 1100 psig decreasing 0515

RCS Pressure 178 psig decreasing

Reactor Building pressure = 8.8 psig increasing Which ONE of the following describes the status of the LPI pumps at 0515?

A. 1A and 1 B LPI pumps are operating from the initial ES actuation B. 1A and 1 B LPI pumps are off and must be restarted C. 1A and 1 B LPI pumps are operating after automatically re-starting when RCS pressure decreased below 500 psig D. 1 A and 1 B LPI pumps are operating after automatically re-starting when RCS pressure decreased below 550 psig Page 4 of 75

Oconee Nuclear Station Question: 5 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 80%

IA and lB FDW Masters in HAND

1A Feedwater Flow = 4.4 x 10 LB/HR

1 B Feedwater Flow 4.4 x 106 LB/HR Current conditions:

IB1 RCP trips

1) Reactor power must be reduced to a MAXIMUM of (1) % CTP.

2) When the MAXIMUM power level is reached, a Main FDW flow of (2) 106 LB/HR will be established to the IA SG?

Which ONE of the following completes the statements above?

A. 1.65

2. 5.4 B. 1.74

2. 5.4 C. 1.65

2. 6.1 D. 1.74

2. 6.1 Page 5 of 75

Oconee Nuclear Station Question:

6 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

1C LPI Pump is in service providing normal decay heat removal.

Current conditions:

Loss of offsite power occurs

Power restored via CT-4

1A and lB LPI Pumps NOT available Which ONE of the following describes the requirements to start the 1 C LPI Pump to restore decay heat removal?

Manual reset of Load Shed is_J1) and starting of 1C LPI Pump is allowed afteraMlNiMUMof (2) seconds.

A. 1. NOT required

2. 5 B. 1. required

2. 5 C. 1. NOT required

2. 30 D. 1. required

2. 30 Page 6 of 75

Oconee Nuclear Station Question:

7 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 90%

1 B Main Feedwater pump trips Current conditions:

Reactor power = 62% stable

RCS pressure = 21 85 psig slowly decreasing

Pressurizer level = 229 inches slowly decreasing

Pressurizer temperature = 649.4°F slowly increasing

Pressurizer Heater Bank I switch is ON

Pressurizer Heater Bank 2 (Groups B & D) is in AUTO and are ON

Pressurizer Heater Banks 3 and 4 are in AUTO and off

1) The pressurizeris (1).

2) The pressurizer saturation circuit (2)

Which ONE of the following completes the statements above?

A. 1. subcooled

2. is responding as expected B. 1. subcooled

2. has failed C. I. saturated

2. is responding as expected D. 1. saturated

2. has failed Page 7 of 75

Oconee Nuclear Station Question:

8 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor Power = 100%

Current conditions:

Both Main FDW pumps trip

Reactor Power = 47% and decreasing

RCS pressure = 2252 psig increasing

1) The MINIMUM RCS pressure at which 1SA1/E6 (CRD ELECTRONIC TRIP E) will actuate is (2)

2) Opening (1) AC CRD Breakers will result in a reactor trip.

Which ONE of the following completes the statements above?

A. 1. 2355 psig

2. AandC B. 1. 2450 psig

2. AandC C. 1. 2355 psig

2. Band C D. 1. 2450 psig

2. BandC Page 8 of 75

Oconee Nuclear Station Question:

9 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Reactor power = 49% decreasing

Primary to secondary leakage in 1A SG

Pzr level 1 55 inches and increasing slowly

ALL HPI Pumps running

1HP-26 and 1HP-27 open

1HP-5 closed

1) 1RIA-59 & 1RIA-60 (1) be used to determine the SG tube leak rate.

2) The reactor (2) required to be manually tripped.

Which ONE of the following completes the statements above?

A. 1. may

2. is NOT B. 1. may

2. is C. 1. may NOT

2. is NOT D. 1. may NOT

2. is Page 9 of 75

Oconee Nuclear Station Question:

10 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

TDEFWP operating

Main FDW is not available

1) TDEFWP bearing oil cooling is currently provided by (1)

2) If a loss of ALL AC power occurs, TDEFWP bearing oil cooling will be provided by (2)

Which ONE of the following completes the statements above?

A. 1. CCW

2. LPSW B. 1. CCW

2. HPSW C. 1. RCW

2. LPSW D. 1. RCW

2. HPSW Page 10 of75

Oconee Nuclear Station Question:

11 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

ACB-4 closed

Switchyard Isolation Current conditions:

Keowee Unit 2 emergency lockout

230 KV Yellow Bus Differential lockout

1) The MFB will be re-energized from (1) in accordance with EOP Enclosure 5.38 (Restoration of Power).

2) 230 KV Yellow Bus Differential lockout (2) automatically reset when the fault is removed.

Which ONE of the following completes the statements above?

A. 1. CT-4

2. will B. 1. CT-4

2. will NOT C. 1. CT-5

2. will D. 1. CT-5

2. will NOT Page 11 of75

Oconee Nuclear Station Question:

12 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Reactor power = 100%

EFPD=400

Switchyard Isolation

1) SG levels will be automatically controlled at (I)

2) An expected range of (2) delta T between Tcold and CETC would indicate that Natural Circulation has been established.

Which ONE of the following completes the statements above?

A. 1.50%OR

2. 30°Fto4O°F B. 1. 50% OR

2. 55°F to 65°F C. 1. 24OinchesXSUR

2. 30°Fto4O°F D. I. 24OinchesXSUR

2. 55°Fto65°F Page 12 of 75

Oconee Nuclear Station Question:

13 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Reactor power = 100%

I SA-04/E-6 (125 Volt Ground Trouble) actuates

1) 1 SA-04/E-6 ARG directs the Operator to (1) to determine if the ground is on the battery or the Bus.

2) 1 SA-04/E-6 actuating indicates that the ground is located on (2)

Which ONE of the following completes the statements above?

A. 1. rotate the Ground Relay Selector Switch

2. Unit I ONLY B. 1. rotate the Ground Relay Selector Switch

2. any Unit C. 1. isolate the battery from the Bus

2. Unit I ONLY D. 1. isolate the battery from the Bus

2. any Unit Page 13 of 75

Oconee Nuclear Station Question:

14 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Reactor power = 100%

1 LPSW-6 fails closed Which ONE of the following is the RCP Motor Stator MINIMUM temperature (°F) that would require immediately tripping the RCP in accordance with AP/16 (Abnormal Reactor Coolant Pump Operation)?

A. 190 B. 225 C. 260 D. 295 Page 14 of 75

Oconee Nuclear Station Question: 15 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 100%

Instrument Air Pressure decreasing

AP122 (Loss of Instrument Air) initiated Current conditions:

Instrument Air pressure = 75 psig slowly decreasing

FDW Pump liP = 35 psig stable

1) Service Air (1) supplying the Instrument Air system.

2) The reactor (2) required to be manually tripped in accortiance with AP/22.

A. 1.is

2. is B. 1.is

2. is NOT C. 1. is NOT

2. is D. 1. is NOT

2. is NOT Page 15 of 75

Oconee Nuclear Station Question:

16 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Time = 0400

Reactor power = 35% stable

SA-16/C-1 (230 KV Swyd Isolate ES Permit) actuated

230 KV Yellow Bus voltage = 224.2 KV increasing Current conditions:

Time = 0401

AP/34 (Degraded Grid) in progress

230 KV Yellow Bus voltage = 226.8 KV increasing

RCS pressure = 1345 psig decreasing

RB pressure = 2.6 psig increasing

1) At0401 ES Channels (1) have actuated.

2) At 0402 Unit ls MFBs will be energized from (2)

Which ONE of the following completes the statements above?

A. 1. iand2ONLY

2. CT-i B. 1. 1 through 6

2. CT-i C. 1. iand2ONLY

2. CT-4 D. 1. 1 through 6

2. CT-4 Page 16 of 75

Oconee Nuclear Station Question:

17 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 100%

Current conditions:

IA and lB Main FDW pumps tripped

All EFDW pumps unavailable

RCS temperature = 581°F increasing

Main Steam pressure = 987 psig decreasing

CBP feed is being established per Rule 3 (Loss of Main/Emergency Feedwater)

I) Initially CBP flow will be controlled to (1)

2) TBVs are throttled to reduce MS pressure (2)

Which ONE of the following completes the statements above?

A. 1. establish 25 inches SU in each SG

2. to allow CBP flow to enter the SG B. 1. establish 25 inches SU in each SG

2. to ensure SG pressure is less than RCS pressure C. 1. stabilize RCS pressure and temperature

2. to allow CBP flow to enter the SG D. 1. stabilize RCS pressure and temperature

2. to ensure SG pressure is less than RCS pressure Page 17 of 75

Oconee Nuclear Station Question: 18 IL T39 ONS RO NRC Examination (1 point)

Given the following Unit 1 conditions:

Time = 1200

Reactor trips from 100% power due a 1A MSLB

BOTH SG pressures rapidly decreasing

CoreSCM=0°F Time = 1204

Tcold reaches lowest value of 41 6°F Time = 1215

Tcold = 498°F stable

Core SCM = 78°F stable

Rule 2 (Loss of SCM) is complete

IA SG tube leakage = 5 gpm

1) (1) was the EOP tab that was entered first from Subsequent Actions.

2) Rule 8 (Pressurized Thermal Shock) (2) required to be invoked.

Which ONE of the following completes the statements above?

A. 1. Loss of SCM

2. is B. 1. Loss of SCM

2. is NOT C. 1. Excessive HeatTransfer

2. is D. 1. Excessive Heat Transfer

2. is NOT Page 18 of 75

Oconee Nuclear Station Question:

19 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power =100%

Computer Reactor Calculation Package NOT running

FDW Masters in MANUAL

Reactor Diamond in MANUAL Current conditions:

CR Group 3 Rod 4 = 0% withdrawn

1 NI-5 = 89.3%

1 NI-6 = 88.6%

1 NI-7 = 95.9%

1 NI-8 = 86.8%

1) TS 3.2.3 (QPT) (1) required to be entered.

2) The MINIMUM Core Thermal power at which QPT is required to be monitored in accordance with TS 3.2.3 (QPT) is greater than (2) RTP.

Which ONE of the following completes the statements above?

REFERENCE PROVIDED A. 1.is

2. 20%

B. 1.is

2. 40%

C. 1. is NOT

2. 20%

D. 1. is NOT

2. 40%

Page 19 of 75

Oconee Nuclear Station Question:

20 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 68% increasing Current conditions:

Control Rod group 7 Rod 6 = 0% withdrawn

1) An ICS Asymmetric Rod Runback (1) occur.

2) If occurring, depressing the HOLD pushbutton on the LCP (2) stop an ICS Asymmetric Rod Runback.

Which ONE of the following completes the statements above?

A. 1. will

2. will B. 1. will

2. will NOT C. 1. will NOT

2. will D. 1. will NOT

2. will NOT Page 20 of 75

Oconee Nuclear Station Question:

21 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

Pzr level channel 3 is selected Current conditions:

A break in the Pzr level channel 3 reference leg occurs

1) Pzr level three will indicate (1) than actual level

2) SASS will select Pzr level (2)

Which ONE of the following completes the statements above?

A. 1. higher

2. one B. 1. higher

2. two C. 1. lower

2. one D. 1. lower

2. two Page 21 of 75

_________

Oconee Nuclear Station Question:

22 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor in MODE 3 Current conditions:

I DIB inverter DC Input breaker trips The associated source range power will be restored using the inverter Which ONE of the following completes the statement above?

A. ASCO Switch B. Static Transfer Switch C. Manual Transfer Switch D. Inverter Bypass Switches Page 22 of 75

Oconee Nuclear Station Question:

23 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

RCS DEl activity = 1.78 pCi/gm

AP/21 (High Activity in RCS) in progress Current conditions:

Reactor power reduction in progress

1) AP/21 directs that power reduction rate be limited to a MAXIMUM of (1)

2) The reason for this rate is to minimize (2)

Which ONE of the following completes the statements above?

A. 1. =3%FP/hr

2. additional gap activity entering the RCS.

B. 1. =3%FP/hr

2. the magnitude of the iodine spike associated with the Rx shutdown.

C. 1. =10%FP/hr

2. additional gap activity entering the RCS.

D. 1. =10%FP/hr

2. the magnitude of the iodine spike associated with the Rx shutdown.

Page 23 of 75

Oconee Nuclear Station Question:

24 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 25%

1FDW-41 (lB Main FDW Control) in MANUAL Current conditions:

ICS HAND power lost

1) Assuming no operator action, a lB SC (1) will occur.

2) If the AUTO pushbutton is depressed on the 1 FDW-41 Hand/Auto Station 1FDW-41 will (2)

Which ONE of the following completes the statements above?

A. 1. overfeed

2. transfer to AUTO.

B. 1. overfeed

2. remain in MANUAL.

C. 1. underfeed

2. transfer to AUTO.

D. 1. underfeed

2. remain in MANUAL.

Page 24 of 75

Oconee Nuclear Station Question:

25 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 100%

ACB-4 closed

Keowee Unit I output 48 MWe Current conditions:

RCS pressure = 1568 psig decreasing ACB-1 is (1)to (2)

Which ONE of the following completes the statement above?

A. 1. open

2. ensure Keowee Unit I is separated from the 230 KV grid B. 1. open

2. ensure Keowee is available to energize Unit I MFBs via the underground C. 1. closed

2. allow the yellow bus to remain energized in the event a switchyard isolation occurs D. 1. closed

2. allow continued Keowee generation to the grid Page 25 of 75

Oconee Nuclear Station Question:

26 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 100%

Current conditions:

Reactor power = 0.01% decreasing

ISA-2/E-2 (HP Loop A Injection Flow HIGH) actuated

1SA-181D-6 (RC System Approaching Saturation Conditions) actuated

LOOP A SCM = 0°F stable

LOOP A CORE SCM = 10°F decreasing

HPI Flow Train A = 604 gpm stable

HPI Flow Train B = 340 gpm stable

1) Statalarm (1) will require mitigating actions to be taken first.

2) The OAC Core SCM uses the average of the (2) in its calculation.

Which ONE of the following completes the statements above?

A. 1. 1 SA-2/E-2

2. 5 highest of the 24 qualified CETCs B. 1. 1 SA-21E-2

2. operable 47 CETCs C. 1. ISA-18/D-6

2. 5 highest of the 24 qualified CETCs D. 1. 1SA-18/D-6

2. operable 47 CETCs Page 26 of 75

Oconee Nuclear Station Question:

27 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor trips from 100% powerdueto a SBLOCA Current conditions:

Rule2inprogress

ALL RCPs are secured

Both Main FDW pumps secured

lAand lB MDEFDW pumps operating

IA and 1 B EFW flow = 300 gpm stable

lAand lB SG Ievels 108 inchesXSUR increasing

RCS temperature = 468 °F decreasing

Core SCM = 0°F stable 112 hour0.0013 days 0.0311 hours 1.851852e-4 weeks 4.2616e-5 months

Calculated C/D rate = 56 °F1 Which ONE of the following describes how the Reactor Operator is required to feed the SGs in accordance with Rule 2 (LOSCM)?

A. Stop EFW flow until TS C/D rates are within limits B. Maintain 300 gpm per header until the LOSCM set point is reached C. Increase EFW flow to 450 gpm per header until the LOSCM set point is reached D. Decrease EFW flow to control C/D rates within TS limits however SG levels must continue to increase to the LOSCM set point Page 27 of 75

Oconee Nuclear Station Question:

28 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 65%

ILPSW-6 (UNIT I RCP COOLERS SUPPLY) fails closed Current conditions:

AP/16 (Abnormal RCP Operation) in progress

RCP Temperatures:

IAI 1A2 IBI 1B2 Upper Guide 182°F 197°F 188°F 185°F Bearing Temp Seal Return 169°F 174°F 227°F 187°F Temp Which ONE of the following is required per AP/1 6?

A. Manually trip the Reactor and stop ALL RCPs B. Manually trip the Reactor and stop RCPs 1A2 & I BI ONLY C. Stop RCP 1A2 ONLY and verify FDW re-ratios properly D. Stop RCP 1 Bi ONLY and verify FDW re-ratios properly Page 28 of 75

Oconee Nuclear Station Question: 29 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

Current conditions:

Letdown flow is being increased per chemistry request

1) The letdown high temperature interlock set point is (1) .

2) At temperatures greater than the interlock, the demineralizers will (2)

Which ONE of the following completes the statements above?

A. 1. 130°F

2. remove Boron from the RCS B. 1. 130°F

2. release ions and sulfur to the RCS C. 1. 135°F

2. remove Boron from the RCS D. 1. 135°F

2. release ions and sulfur to the RCS Page 29 of 75

Oconee Nuclear Station Question:

30 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 100%

230 EFPD

Spare Purification Demineralizer removed from service after six weeks of continuous operation Current conditions:

Reactor power = 70% stable

394 EFPD

Gp 7 Control Rods = 63%

Spare Purification Demineralizer is placed in service

1) RCS Boron concentration will (1)

2) Axial Imbalance will initially move in a (2) direction.

After the Spare Purification Demineralizer is placed in service, which ONE of the following completes the statements above?

A. 1. decrease

2. negative B. 1. decrease

2. positive C. 1. increase

2. negative D. 1. increase

2. positive Page 30 of 75

Oconee Nuclear Station Question:

31 1LT39 ONS RO NRC Examination (1 point)

Given the following Unit 1 conditions:

RCS pressure = 550 psig

An attempt is made to open 1 LP-1 (LPI RETURN BLOCK FROM RCS)

1) 1LP-1 (1) open.

2) The reason 1 LP-1 has an interlock is to (2)

Which ONE of the following completes the statements above?

A. 1. will

2. prevent over pressurizing LPI suction piping B. 1. will

2. ensure delta p across I LP-1 will allow it to open C. 1. will NOT

2. prevent over pressurizing LPI suction piping D. 1. will NOT

2. ensure delta p across I LP-1 will allow it to open Page 31 of75

Oconee Nuclear Station Question:

32 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Main Steam Line Break has occurred in the RB

RCS pressure decreased to 1458 psig and is increasing

RB pressure peaked at 1.3 psig and is decreasing

1) RCS letdown flow (1) automatically isolated.

2) (2) Component Cooling pump(s) is/are operating, Which ONE of the following completes the statements above?

A. 1. has

2. One B. 1. has

2. No C. 1. has NOT

2. One D. 1. has NOT

2. No Page 32 of 75

Oconee Nuclear Station Question: 33 1LT39 ONSRONRCExamination (1 point)

The Quench Tank (QT) cooler is cooled by (1) and the MINIMUM pressure which will cause the QT rupture disc to rupture is (2) psig.

Which ONE of the following completes the statement above?

A. 1. Component Cooling Water

2. 49 B. 1. Component Cooling Water

2. 55 C. 1. Low Pressure Service Water

2. 49 D. 1. Low Pressure Service Water

2. 55 Page 33 of 75

Oconee Nuclear Station Question:

34 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Reactor power = 100%

CC Surge tank level is visibly decreasing In accordance with AP/20 (Loss of Component Cooling), the

1) makeup source for the CC surge tank will be (1)

2) MA)(IMUM range for maintaining the CC surge tank level will be (2)

Which ONE of the following completes the statements above?

A. 1. Demin Water ONLY

2. 1235inches B. 1. Demin Water ONLY

2. 1830inches C. 1. Demin Water or CC Drain Tank

2. 1235 inches D. 1. Demin Water or CC Drain Tank 2.1830 inches Page 34 of 75

Oconee Nuclear Station Question: 35 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

Current conditions:

1 RIA-50 in HIGH alarm

CC Surge Tank Level = 36 inches increasing Which ONE of the following describes the cause of these indications?

A. CC Cooler leak B. Letdown cooler leak C. CRD Stator cooler leak D. Quench Tank Cooler leak Page 35 of 75

Oconee Nuclear Station Question: 36 1LT39 ONSRONRCExamination (1 point)

I RC-66 (POR\i) pilot valve and pilot valve position indication is powered from which ONE of the following?

A. IDIA B. 1DIB C. 1KI D. IKU Page 36 of 75

Oconee Nuclear Station Question:

37 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 60% stable

IA Main FDW pump operating

IA and lB FDWMastersin MANUAL

Condenser vacuum has decreased to 22 Hg and is now slowly increasing

The reactor trip push button is depressed in accordance with AP/27 (Loss of Condenser Vacuum)

Current conditions:

Reactor power = 23% decreasing

ALL CRD Breakers CLOSED I) The Main Turbine (I) automatically tripped due to the Reactor Trip Confirm signal.

2) At this time the EOP will direct (2)

Which ONE of the following completes the statements above?

A. I. has

2. maximizing letdown flow B. I. has

2. adjusting FDW flow to control RCS temperature C. I.hasNOT

2. a manual Main Turbine trip D. l.hasNOT

2. adjusting FDW flow to control RCS temperature Page 37 of 75

Oconee Nuclear Station Question: 38 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 3 conditions:

Reactor power = 100%

3KVIB AC Vital Power Panelboard supply breaker trips OPEN

ES Analog Channel C WR RCS pressure signal fails LOW Which ONE of the following describes which (if any) ES digital channels have actuated?

have actuated.

A. NO channels B. Channels 1 thru 4 C. ONLY channels 2 AND 4 D. ONLY channels I AND 3 Page 38 of 75

Oconee Nuclear Station Question: 39 1LT39 ONSRONRCExamination (1 point)

Which ONE of the following describes the power supply to I B RBCU?

A. 1X8 B. 1X9 C. IXS2 D. 1XS3 Page 39 of 75

Oconee Nuclear Station Question:

40 1LT39 ONSRONRCExamination (1 point)

Given the following Unit I conditions:

Initial conditions:

LOCA occurs while operating at 100% power

ES 1-8 actuates Current conditions:

LOCA CD tab in progress

Reactor Engineering confirms Condition Zero per RP/OIB/I 000/018 (Core Damage Assessment)

1) The MAXIMUM RB pressure for securing the RBS pumps is (1)

2) The time requirement since the event for securing the RBS pumps is (2)

Which ONE of the following completes the statements above?

A. 1. <3psig

2. <24hours B. 1. <3psig

2. >24hours C. 1. <lOpsig

2. <24 hours1 days 0.143 weeks 0.0329 months D. 1. <lOpsig

2. >24 hours1 days 0.143 weeks 0.0329 months Page 40 of 75

Oconee Nuclear Station Question:

41 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 1 00%

Current conditions:

LBLOCA in progress

lTD de-energized

1XS4 de-energized

1) The Reactor Building Spray system (1) perform its safety function.

2) Tn-sodium Phosphate is added to water in containment to (2)

Which ONE of the following completes the statements above?

A. 1. will

2. minimize hydrogen production due to the Zirc-water reaction B. 1. will

2. maintain Iodine in solution to minimize dose in the RB atmosphere C. 1. will NOT

2. minimize hydrogen production due to the Zirc-water reaction D. 1. will NOT

2. maintain Iodine in solution to minimize dose in the RB atmosphere Page 41 of 75

Oconee Nuclear Station Question:

42 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 3 conditions:

Initial conditions:

Reactor power = 100%

3MS-1 12 & 3MS-173 (SSRH 3A/3B Controls) are OPEN in MANUAL

3MS-77, 78, 80, 81 (MS to SSRHs) control switches in OPEN Current conditions:

Main Turbine trips

1) 3MS-112 &3MS-1 73 will (1)

2) 3MS-77, 78, 80, 81 will (2)

Which ONE of the following completes the statements above?

A. 1. close

2. close B. 1. close

2. remain open C. 1. remain open

2. close D. 1. remain open

2. remain open Page 42 of 75

Oconee Nuclear Station Question:

43 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

Current conditions:

AP/29 (Rapid Unit Shutdown) is initiated to reduce power to 15%

1) In accordance with AP/29, the (1) Main FDW pump is the preferred pump to be shutdown first.

2) If the FDWPT Handjack is ON during the unit shutdown, the associated (2) will be used to reduce flow.

Which ONE of the following completes the above sentences?

A 1.1A

2. Motor Speed Changer B. 1.1A

2. Motor Gear Unit C. 1.1B

2. Motor Speed Changer D. 1.1B

2. Motor Gear Unit Page 43 of 75

Oconee Nuclear Station Question:

44 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 2 conditions:

Initial conditions:

Both Main FDW pumps trip from 100% power Current conditions:

2A and 2B SG level = 100 inches XSUR decreasing

The air line to 2FDW-316 valve actuator is severed

1) Over the next fifteen minutes 2B SG level will (1) unless operator actions are taken.

2) Per the EOP, the next method used to control 2B SG level will be by (2)

Which ONE of the following completes the statements above?

A. 1. decrease

2. aligning valves and throttling 2FDW-44 in the control room B. 1. decrease

2. throttling 2FDW-316 locally C. 1. increase

2. aligning valves and throttling 2FDW-44 in the control room D. 1. increase

2. throttling 2FDW-316 locally Page 44 of 75

Oconee Nuclear Station Question:

45 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Time = 0400

Reactor power = 100%

Both Main FDW pumps trip Current conditions:

Time = 0403

1A and lB MDEFDW Pumps operating

Power has been lost to the Moore Controller for 1FDW-316 Which ONE of the following describes the response of 1 B SG level?

ASSUME NO OPERATOR ACTION A. Decrease to dryout B. Automatically controlled at 30 C. Automatically controlled at 240 D. Increase to overflow into the steam lines Page 45 of 75

Oconee Nuclear Station Question:

46 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 3 conditions:

A voltage disturbance is occurring

AP/34 (Degraded Grid) initiated

Power Factor is lagging

Generator output = 700 Mwe

Generator Hydrogen pressure = 60 psig

Generator output voltage = 18.3 kV Which ONE of the following is the limit on MVARs in accordance with the Generator Capability Curve?

REFERENCE PROVIDED A. 325 B. 398 C. 460 D. 600 Page 46 of 75

Oconee Nuclear Station Question: 47 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 2 conditions:

Initial conditions:

Time = 0400

Reactor power = 100%

2B RPS Channel inadvertently placed in Shutdown Bypass Current conditions:

Time=0401

2DIA panel board is de-energized

1) (1) will cause the A CRD Trip Breaker to trip.

2) The EOP (2) be entered.

Which ONE of the following completes the statements above?

A. 1. BOTH the UV and the shunt trips

2. will B. 1. BOTHtheUVandtheshunttrips

2. will NOT C. 1. The UV but NOT the shunt trip

2. will D. 1. The UV but NOT the shunt trip

2. will NOT Page 47 of 75

Oconee Nuclear Station Question:

48 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

1A HWP breaker in the TEST position

1) The 1A HWP breaker (1) be closed remotely using the Control Room switch.

2) If the 1A HWP breaker DC control power fuses are removed, 1A HWP breaker (2) be closed locally using the pistol grip switch located on the front of the breaker cubicle.

Which ONE of the following completes the statements above?

A. 1. can

2. can B. 1. can

2. can NOT C. 1. can NOT

2. can D. 1. can NOT

2. can NOT Page 48 of 75

Oconee Nuclear Station Question: 49 1LT39 ONSRONRCExamination (1 point)

Given the following conditions:

Operators are preparing to synchronize KHU-2 to the grid in accordance with OP/0/A/1 106/019, (Keowee Hydro At Oconee)

The operator notes the following indications:

Grid Frequency = 59.9 cycles

Keowee Frequency = 60.3 cycles

Keowee 2 Line Volts = 13.7 kV

Keowee 2 Output Volts = 1 5.2 kV

1) (1) will be used to adjust the synchroscope indication.

2) If ACB-2 is closed with the above indications, generator MVARs will be (2) .

Which ONE of the following completes the statements above?

A. 1. UNIT2AUTOVOLTAGEADJUSTER

2. positive B. 1. UNIT 2 SPEED CHANGER MOTOR

2. positive C. 1. UNIT2AUTOVOLTAGEADJUSTER

2. negative D. 1. UNIT2SPEEDCHANGERMOTOR

2. negative Page 49 of 75

Oconee Nuclear Station Question:

50 1LT39 ONSRONRCExamination (1 point)

Given the following conditions:

Two Keowee Tailrace level instruments are OOS

1) Commercial operation of the Keowee Hydro Units (1) permitted by SLC 16.8.4 (Keowee Operational Restrictions).

2) Keowee operating head is normally calculated by using (2) from Oconee Control Room indications.

Which ONE of the following completes the statements above?

A. 1.is

2. Forebay Elevation PLUS Tailrace Elevation B. 1.is

2. Forebay Elevation MINUS Tailrace Elevation C. 1. is NOT

2. Forebay Elevation PLUS Tailrace Elevation D. 1. is NOT

2. Forebay Elevation MINUS Tailrace Elevation Page 50 of 75

Oconee Nuclear Station Question: 51 IL T39 ONS RO NRC Examination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Unit 1 in Mode 5

Unit I RB Purge release in progress Current conditions:

Loss of power to RM-80 skid of 1 RIA-45 (NORM Vent Gas)

I SA8/B9 RM PROCESS MONITOR RADIATION HIGH in alarm

ISA8/B1O RM PROCESS MONITOR FAULT in alarm

1) The RB Purge Fan will (I)

2) In accordance with OP/1/A111021014 (RB Purge System) the RB Purge release (2)

Which ONE of the following completes the statements above?

A. 1. remain running

2. may continue provided IRIA-45 is re-energized within one hour.

B. 1. automatically trip

2. may be re-initiated because IRIA-46 (Vent Gas HR) remains operable.

C. 1. remainrunning

2. must be secured immediately D. I. automatically trip

2. may be re-initiated only after IRIA-45 RM-80 skid is returned to service Page 51 of 75

Oconee Nuclear Station

1LT39 ONSRONRCExamination Question: 52 (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Timel200

Reactor power = 35%

lAsteamgeneratortubeleak2.1 gpd

RCS activity = 0.25 pCi/mi DEl increasing Current conditions:

Time=1400

Reactor power = 35%

1A steam generator tube leak = 2.1 gpd

RCS activity = 0.65 pCi/mI DEl and increasing

1) Between 1200 and 1400 1 RIA-16 indication will (1)

2) In accordance with AP/31 (Primary to Secondary Leakage), at 1400 I RIA-59 (2) be used to calculate SG tube leak size.

Which ONE of the following completes the statements above?

A. stay the same will B. stay the same will NOT C. increase will D. increase will NOT Page 52 of 75

Oconee Nuclear Station

53 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following Unit I conditions:

Initial conditions:

Reactor power = 1 % stable Current conditions:

LOCA occurs

RCS pressure 536 psig decreasing

RB pressure = 2.7 psig increasing

1) (1) LPSW pumps will be operating.

2) 1LPSW-l8will (2) ts above?

Which ONE of the following completes the statemen A. 1. two

2. NOT receive a signal to open B. 1. two

2. receive a signal to open C. 1. three

2. NOT receive a signal to open D. 1. three

2. receive a signal to open Page 53 of 75

Oconee Nuclear Station

54 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following Unit 2 conditions:

Reactor power = 100%

RB pressure = 12.8 psia ure will be increased to within the Which ONE of the following describes how RB press eillance)?

limits per PT/2/A/0600/001 (Periodic Instrument Surv ed and this alignment is A. 2PR-42 (RB Purge Disch to Unit Vent) will be open limited to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

ed and this alignment is B. 2PR-42 (RB Purge Disch to Unit Vent) will be open limited to 4 hours0.167 days 0.0238 weeks 0.00548 months .

alignment is limited to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

C. 21A-90 (IA Pent Isolation) will be opened and this alignment is limited to 4 D. 21A-90 (IA Pent Isolation) will be opened and this hours Page 54 of 75

Oconee Nuclear Station

55 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following Unit 1 conditions:

Reactor is shutdown following a transient

RCS temperature = 180°F decreasing ing valves Which ONE of the following will prevent opening ALL of the follow 1PR-1, 2,3,4,5,6?

A. 1RIA-46 HIGH alarm actuates B. Reactor Building pressure at 3.5 psig C. Statalarm SA9IB3, RB Purge Inlet Temperature Low water D. Vacuum on suction piping of the Main Purge Fan at 10 inches of Page 55 of 75

Oconee Nuclear Station

56 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following Unit 1 conditions:

Time 0900

Reactor power = 100%

lCSin MANUAL

CR group 2 rod 3 dropped into the core

AP/1 (Unit Runback) initiated In accordance with AP/1, the maximum reactor power

1) reactor power is required to be reduced less than allowed byTech Specby (1)

2) adequate SDM must be verified by (2) above?

Which ONE of the following completes the statements A. 1.1000

2. 1000 B. 1.1000

2. 1100 C. 1. 1100

2. 1000 D. 1. 1100

2. 1100 Page 56 of 75

Oconee Nuclear Station

57 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following on Unit 1:

Initial conditions

Reactor Power = 100%

Current conditions:

e actuator

The air line breaks off of the 1HP-120 valv

1) 1HP-120 will (1)

Control Room Pressurizer level

2) Assuming no operator action, the resulting will (2 .

ments above?

Which ONE of the following completes the state A. 1. close

2. de-energize the Pzr heaters at 80 inches B. 1. close

2. de-energize the Pzr heaters at 85 inches C. 1. open

2. cause the Pzr spray valve to open at 2205 psig D. 1. open

2. cause the Pzr spray valve to open at 2255 psig Page 57 of 75

Oconee Nuclear Station

58 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following Unit 1 conditions:

Initial conditions:

OP/I /Nl 105/019 (Control Rod Drive System) initiated l

Enclosure 4.15 (Recovery Of Dropped/Misaligned Safety Or Regulating Contro Rod With Diamond in Automatic) in progress P1

Step 2.3. states: IF affected rod is fully inserted, perform Auto Latch and Alignment, as follows:

2.3.1 Select LATCH AUTO.

1) When LATCH AUTO is selected RPI (1) automatically reset to match API.

2) During this control rod recovery, the (2)

Which ONE of the following completes the statements above?

A. 1. will NOT

2. Controlling CRD Group will maintain Rx power constant B. 1. will NOT e

2. Reactor Operator will insert the regulating rods to stop the power increas C. 1. will

2. Controlling CRD Group will maintain Rx power constant D. 1. will e

2. Reactor Operator will insert the regulating rods to stop the power increas Page 58 of 75

Oconee Nuclear Station Question:

59 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

MSLB in 1 B Steam Generator occurs

Rule 5 (Main Steam Line Break) in progress

CETCs being used to stabilize RCS temperature Current condition:

A single CETC indicates 0°F stable

The remaining CETCs indicate approximately 460°F stable Which ONE of the following:

1) states the range (°F) of the CETCs being used to stabilize RCS temperature?

2) describes the status of the CETC with the unique reading (0°F) in accordance with OPIOIAJ1 108/001 (Curves and General Information) Enclosure 4.45 (RCS Instrumentation)?

A. 1.0-700

2. Open Circuit B. 1. 0-700

2. Short toground C. 1. 0-2500

2. Open Circuit D. 1. 0-2500

2. Short toground Page 59 of 75

Oconee Nuclear Station Question:

60 IL T39 ONS RO NRC Examination (1 point)

Given the following conditions:

Loading of the Spent Fuel Cask is in progress in Unit 1&2 SF Pool

The Spent Fuel Cask is dropped on the fuel racks

1RIA-41 (SFP Gas) HIGH alarm actuates

1RIA-6 (SFP Area Monitor) HIGH alarm actuates

1) 1 RIA-41 send a trip signal to the Unit 2 Main Purge Fan.

2) 1 RIA-6 sound a local evacuation alarm.

Which ONE of the following completes the statements above?

A. 1.will

2. will B. 1. will

2. will NOT C. 1. will NOT

2. will D. 1. will NOT

2. will NOT Page 60 of 75

Oconee Nuclear Station Question: 61 1LT39 ONS RO NRC Examination (1 point)

Given the two pictures below:

MS-I 9 1ATURBINE BYPA VALES Meas Picture II Picture Y

OPEN OSEO 1MS-1S & 2 IA TURBINE BYPASS VALVES ItS S SB 012A

1) Assuming NO operator actions, picture (1) would be the expected indication five minutes following a spurious Unit 1 Reactor trip from 100% if the 1A TBVs mechanically stuck OPEN immediately following the trip.

2) The (2) tab will be used to mitigate this failure.

Which ONE of the following completes the statements above?

A. 1.X

2. Subsequent Actions B. 1.X

2. EHT C. 1.Y

2. Subsequent Actions D. 1.Y

2. EHT Page 61 of 75

Oconee Nuclear Station Question:

62 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Reactor power = 1 00%

Which ONE of the following will have resulted in a trip of the Main Turbine/Generator?

A. Turbine speed = 1940 RPM B. Bearing Oil Pressure 7.5 psig C. EITHER Steam Generator level = 90% OR D. EHC Discharge Header Pressure = 1300 psig Page 62 of 75

Oconee Nuclear Station Question:

63 1LT39 ONSRONRCExamination (1 poEnt)

Given the following Unit 1 condftions:

Reactor power = 100%

1RIA-40 (CSAE Off-Gas Monitor) reading is rising slowly

1RIA-54 (Turbine Building (TB) Sump Monitor) is inoperable

TB Sump sample result activity is 1.3 EC

The operating crew has just entered AP/31 (Primary To Secondary Leakage) due to a 6 gpm leak in the IA SG

1) In accordance with AP/31 an NEO is required to (2) .

2) Emergency Dose Limits (1) in affect.

A. 1. open and white tag the TB Sump Pump breakers

2. are B. 1. open and white tag the TB Sump Pump breakers

2. are NOT C. 1. align the TB Sump to the TB Sump Monitor Tanks

2. are D. 1. align the TB Sump to the TB Sump Monitor Tanks

2. are NOT Page 63 of 75

Oconee Nuclear Station Question: 64 1LT39 ONS RO NRC Examination (1 point)

The C LPSW Pump is normally powered from (1) and it (2J have an alternate supply from another unit.

A. 1. 1TC

2. does B. 1. ITC

2. does NOT C. 1. 2TC

2. does D. 1. 2TC

2. does NOT Page 64 of 75

Oconee Nuclear Station Question: 65 1LT39 ONSRONRCExamination (1 point)

Which ONE of the following is a function of HPSW-25, (EWST altitude valve)?

A. Automatically closes when the base HPSW pump stops.

B. Maintain HPSW system pressure when EWST level decreases.

C. Allows continuous HPSW pump operation without EWST overflow.

D. Allows continuous operation of the HPSW Jockey pump without EWST overflow.

Page 65 of 75

Oconee Nuclear Station Question:

66 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 3 conditions:

Reactor in MODE 6

Refueling in progress Which ONE of the following describes the source range NI requirements while refueling the reactor in accordance with OPI3/A115021007 (Operations Defueling/Refueling Responsibilities)?

A. Reactor Operator can use any two source range Nis B. Reactor Engineering will specify the one required source range NI C. Reactor Operator can use any one source range NI D. Reactor Engineering will specify the two required source range NIs Page 66 of 75

Oconee Nuclear Station

67 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor power = 100%

BOTH Main Feedwater Pumps trip Current conditions:

Reactor power = 57% slowly decreasing to

1) The correct sequence of activities directed by Rule I (ATWS) is _(1) to (2) Arc

2) The direction given to the operator opening the CRD breaker is Flash PPE.

Which ONE of the following completes the statements above?

open the A. 1. align HPI injection from the BWST THEN dispatch an operator to CRD breakers

2. wear open the B. 1. align HPI injection from the BWST THEN dispatch an operator to CRD breakers

2. NOT wear on C. 1. dispatch an operator to open the CRD breakers THEN align HPI injecti from the BWST

2. wear on D. 1. dispatch an operator to open the CRD breakers THEN align HPI injecti from the BWST

2. NOT wear Page 67 of 75

Oconee Nuclear Station

68 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following Unit 1 conditions:

MODE3

RCS pressure = 2755 psig restore The Technical Specification MINIMUM required action is to RCS pressure within limits within (I)

Which ONE of the following completes the statement above?

A. 5 minutes B. 15 minutes C. 30 minutes D. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Page 68 of 75

Oconee Nuclear Station 69 1LT39 ONSRONRCExamination Question:

(1 point) that have pre-planned Which ONE of the following describes two (2) evolutions or tests ently Performed Tests pre-job briefs per NSD 213 (Risk Management Process), Infrequ or Evolutions?

A. Unit 2 Mid-Loop Operations and approach to criticality r

B. Unit 2 Mid-Loop Operations and sluicing a purification demineralize ent Test C. Sluicing a purification demineralizer and Turbine Stop Valve Movem D. Turbine Stop Valve Movement Test and approach to criticality Page 69 of 75

Oconee Nuclear Station

70 1LT39 ONSRONRCExamination Question:

(1 point)

Given the following Unit 3 conditions:

3A GWD gas tank release in progress

Release is at 2/3 Station Limit

1) 1 RIA-45 High and Alert setpoints will be set at (1) the normal 1/3 Station limit as listed in PT/O/A/230/OO1 (Radiation Monitor Check).

tank release (2)

2) If I RIA-45 High alarm setpoint is reached, the 3A GWD gas

.

Which ONE of the following completes the statements above?

A. 1. double

2. will automatically terminate B. 1. double

2. must be manually terminated C. 1. half

2. will automatically terminate D. 1. half

2. must be manually terminated Page 70 of 75

I Oconee Nuclear Station Question:

71 1LT39 ONSRONRCExamiiiation (1 point)

Given the following Unit 1 conditions:

Initial conditions:

Reactor in MODE 6 Current conditions:

1 RIA-49A switchover acceptance range setpoint is exceeded

I RIA-49A HIGH alarm actuates

1) 1RIA-49willread (1)

2) As a result of the 1 RIA-49A HIGH alarm, (2)

Which ONE of the following completes the statements above?

A. 1. Zero

2. 1 LWD-1 will receive a close signal B. 1. Zero

2. the RB Evacuation Alarm will sound C. 1. offscale high

2. 1 LWD-1 will receive a close signal D. 1. offscale high

2. the RB Evacuation Alarm will sound Page 71 of75

Oconee Nuclear Station Question: 72 1LT39 ONSRONRCExamination (1 point)

1) The required response by an NEC performing Primary rounds to an Electronic Dosimeter dose rate alarm is to (1)

2) It is acceptable to deviate from the above requirements _(2)

Which ONE of the following completes the statements above?

A. 1. exit the area immediately and contact RP

2. with RP permission B. 1. exit the area immediately and contact RP

2. when emergency dose limits are in effect C. 1. move away from the area until alarm clears

2. with RP permission D. 1. move away from the area until alarm clears

2. when emergency dose limits are in effect Page 72 of 75

Oconee Nuclear Station Question: 73 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 3 conditions:

Initial conditions:

Reactor power = 100%

Current conditions:

Chlorine gas is entering the Control Room due to an accidentally dropped cylinder.

The SRO has implemented AP/08 (Loss of Control Room).

1) The RO will go to the (1)

2) Bank 2 Groups (2) Pzr heaters will be used to control RCS pressure from this location.

Which ONE of the following completes the statements above?

A. Standby Shutdown Facility B and D B. Standby Shutdown Facility B and C C. Unit 3 Auxiliary Shutdown Panel B and D D. Unit 3 Auxiliary Shutdown Panel B and C Page 73 of 75

Oconee Nuclear Station Question: 74 IL T39 ONS RO NRC Examination (1 point)

Given the following Unit 1 conditions:

Reactor power 100%

AP/8 (Loss of Control Room) initiated due to a fire in the Control Room

1) Per AP/8 the Unit I Reactor Operators will relocate to the (1)

2) A method used in RP/1 000/029 (Fire Brigade Response) to dispatch the fire brigade is (2)

Which ONE of the following completes the statements above?

A. 1. Auxiliary Shutdown Panel

2. by using the plant paging system B. 1. Auxiliary Shutdown Panel

2. having Security dispatch fire brigade C. 1. Standby Shutdown Facility

2. by using the plant paging system D. 1. Standby Shutdown Facility

2. having Security dispatch fire brigade Page 74 of 75

Oconee Nuclear Station Question:

75 1LT39 ONSRONRCExamination (1 point)

Given the following Unit 1 conditions:

Initial Conditions:

Reactor power = 100%

Current conditions:

2SA-18/A-11 (Turbine BSMT Water Level Emergency High) actuates

Turbine Building flood in progress

1) After the reactor is tripped this event will be mitigated by (1)

2) If ALL Main and EFDW is lost the preferred method to remove decay heat is (2).

Which ONE of the following completes the statements above?

A. 1. AP/lO (Turbine Building Flood) and the EOP

2. initiating HPI Forced Cooling B. 1. AP/1 0 (Turbine Building Flood) and the EOP

2. feeding with SSF or Station ASW C. 1. theEOP(AP/loisnotrequired tobe used)

2. initiating HPI Forced Cooling D. 1. theEOP(AP/loisnotrequired tobe used)

2. feeding with SSF or Station ASW Page 75 of 75

I 2 rJ C

z C

ONET-0400-50 Rev 31 Page 6 of 33 Oconee 1 Cycle 26 Steady State Operating Band Rod Index APSR %WD EFPD Mm Max Mm Max 0 to 452 292 +/- 5 300 30 40 452 to OC 292+/-5 300 100 100 Quadrant Power Tilt Setpoints Steady State Transient Maximum Core Power Level, %FP 30- 100 0- 30 30- 100 0-30 0- 100 Full Incoro 4.00 7.63 7.13 9.42 16.58 OutolCore 2.78 6.09 5.63 7.72 14.22 Backup lr.core 2.40 3.87 3.63 4.81 10.07 Referred to by TS 3.2.3 Correlation Slope (CS) 1.15 Referred to by TS 3.3.1 (SR 3.3.1.3).

_____ _____ _________________________

_____ _____

_____

__

_____

____

NSD 703 (R0810)

Duke Energy (I)IDNo. API3/A117001034 PROCEDURE PROCESS RECORD Revision No. 008 PREPARATION (2) Station OCONEE NUCLEAR STATION OT 0 4 L (3) Procedure Title (4)

Degraded Grid Prepared By* Tommy A. Loflin FILE (Si Date 09/21/10 (5) Requires NSD 228 Applicability Determinati LI Yes (New procedure or revision with major changes) Attach NSD 228 docum

-

entation.

No (Revision with minor changes)

(6) Reviewed By* 4 L) 00 L4 L (QR)(KI) Date ? L2 I Cross-Disciplinary Review By*

(QR)(K1) NAIate .__2 ? (

Reactivity Mgmt Review By*

NADate ?- -

Mgmt Involvement Review By* (Ops. Supt.) NA5ate

i (7) Additional Reviews Reviewed By*

Date Reviewed By*

Date (8) Approved By*

RFORMANCE X4L Co44

)

(Compare with control copy every 14 calendar days while work Date ° is being performed.)

, Compared with Control Copy*_______________________________________________

Date Compared with Control Copy*_____________________________________________

____ Date Compared with Control Copy*_____________________________________________

____ Date (10) Date(s) Performed Work Order Number (WO#)

COMPLETION (11) Procedure Completion Verification:

LI Unit 0 LI Unit I El Unit 2 El Unit 3 Procedure performed on what unit?

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

El Yes LI NA Required enclosures attached?

El Yes LI NA Charts, graphs, data sheets, etc. attached, dated, identified, and marked

?

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

El Yes LI NA Procedure requirements met?

Verified By*

Date (12) Procedure Completion Appro ved Date

Printed Name and Signature (13) Remarks (Attach additional pages, fncessary)

Degraded Grid AP/3/iV1 700/034 Carryover Steps Page 1 of I IFATANYTIME:

(4.6) Rx power is 100 % FP (decrease the CTPD Set Window as needed to prevent Hi flux

...

trip)

(4.11) generator output CANNOT be maintained with in appropriate capability curve (take generator off line) ...

(4.16) the Maximum Allowable Time for a given frequ ency is reached AND turbine is still on line ... (take generator off line)

(4.24) TCC/SOC directs unit separation from the grid

... (decrease power to 50 % and perform a load rejection)

(4.25) notified by TCC that Real Time Contingency Analysis indicates that switchyard voltage would be inadequate (ensure OP/0/A/11071

...

016 Enclosure performed)

(4.35) notified by TCC that Real Time Contingency Analysis indicates that switchyard voltage would be inadequate (ensure OPIOIA/11071

...

016 Enclosure performed)

(4.50) switchyard voltage or frequency alarms are recei ved, AND RTCA is out of service (contact System Engineering)

API3IAII 700/034 Page 1 of 25

1. Entry Conditions {1){2) 1.1 Grid Voltage or Frequency alanns NOTE The RTCA (Real Time Contingency Analysis) predicts the adequacy of switchyard voltage to allow proper ECCS operation during a LOCA for different grid conditions.

The analysis has two low voltage alanns associated with it. The first alarm is the Normal Low Alarm that alerts the TCC to take actions to raise voltage. The second is an Emergency Low Alarm that requires entry into this AP.

1.2 Notification from the SOC/TCC of py of the following:

Actual or predicted low MW reserve

Actual or suspected grid voltage or frequency alarms

NERC Alert 2 or 3 declaration

RTCA indicates Switchyard voltage will be Below the Emergency Low Limit

RTCA NOT working

2. Automatic Systems Actions None

3. Immediate Manual Actions None

AP/31A11 700/03 4 Page 3 of 25

4. Subsequent Actions ACTIONJEXPECTED RESPONSE RESPONSE NOT OBTAINED 4.1 Verify y of the following: GO TO Step 4.42.

Voltage or frequency alarm RTCA (Real Time Contingency Analysis) indicates switchyard voltage would be inadequate for an Oconee

.

4.2 Record time of first alarm or notification from TCC:

Time:

4.3 Verify Unit 1 and Unit 2 SROs are Notify the following of grid alarms or aware of grid alarms or notification

-

notification from TCC:

from TCC.

UI SRO U2 SRO 4.4 Verify Unit I is performing AP/1/34 Notify the following:

(Degraded Grid).

OSM to reference OMP 1-14 (Notifications)

STA 4.5 Verify Unit 3 generator on line. GO TO Step 4.33.

NOTE A large grid disturbance at 100 % FP operation may cause Nis to approa ch the Hi flux trip.

4.6 IAAT Rx power is 100 % FP, THEN decrease the CTPD Set Window as needed to prevent Hi Flux trip.

4.7 Verify Unit I is performing AP/1/34 Notify TCC that the RTCA (Real Time (Degraded Grid). Contingency Analysis) needs to be

-

performed.

4.8 Notify TCC of the status of U3 generator VOLTAGE REGULATOR MODE (Auto / Manual).

AP/3/A/l 700/034 Page 5 of 25 ACTION[EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.9 Verify Unit 2 is performing Notify Keowee Operator of the following:

AP/2/34 (Degraded Grid).

Monitor Keowee Generator Voltage when y Keowee unit is generating to the grid.

Trip y Keowee unit generating to the grid with Keowee Generator Voltage 13.2 kV. (3) 4.10 Verify generator output within limits I - Adjust MVARs to maintain generator of the appropriate capability curve output within limits of the appropriate based on generator voltage: capability curve.

, Generator 2. IF generator output CANNOT be Enclosure b3 Voltage maintained within limits by adjusting

>18.05kV MVARs 5.1 THEN reduce MWs as required.

1805kV. 5.2

1

API3IA/1 700/034 Page 7 of 25 r ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.11 IAAT generator output CANNOT be GO TO Step 4.15.

maintained within appropriate capability curve, THEN perform Steps 4.12 4.14.

-

4.12 Verif reactor> 50% power. GO TO Step 4.14.

4.13 Perform the following:

A. Manually trip reactor B. GO TO Unit 3 EOP.

4.14 Perform the following: {2)

A. Open the following:

PCB 58 PCB59 B. GO TO AP/1 (Load Rejection).

1

AP/3/AJ1 700/034 Page 9 of 25 F ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.15 Monitor frequency using UNDERFREQUENCY MONITOR screen on the EHC HMI Panel and compare to Maximum Allowable Time:

Frequency Maximum Limit Allowable Time 59.5 Hz Unlimited

< 59.5 Hz 48 mm

< 58.6 Hz 8 mm

<58.1Hz 48sec

< 57.6 Hz 0 sec 4.16 IAAT the Maximum Allowable Time GO TO Step 4.20.

for a given frequency band is reached, AND the turbine is still on line, THEN perform Steps 4.17 4.19.

-

4.17 Verify reactor is> 50% power. GOTO Step 419.

4.18 Perform the following:

A. Manually trip reactor.

B. GO TO Unit 3 EOP.

4.19 Perform the following:

A. Open the following:

PCB58 PCB 59 B. GO TO AP/1 (Load Rejection).

AP/3/AIl 700/034 Page 11 of25 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.20 Verify generator MVARs oscillating GO TO Step 4.24.

> +/- 100 MVARs from steady state.

4.21 Place VOLTAGE REGULATOR MODE in manual.

4.22 Verify generator output within limits I. Adjust MVARs using VOLTAGE of the appropriate capability curve ADJUST to maintain generator output based on generator voltage: within limits of the appropriate capability curve.

Generator Enclosure 2 IF generator output CANNOT be Voltage maintained within limits by adjusting

> 18.05 kV 5.1 MVARs, 18.05 kV 5.2 THEN reduce MWs as required.

4.23 Notify TCC that VOLTAGE REGULATOR MODE is in manual.

4.24 IAAT TCC/SOC directs unit separation from the grid, THEN perform the following:

A. PERFORM a rapid power decrease to 50 % using AP/29 (Rapid Unit Shutdown).

B. Open the following:

PCB 58 PCB59 C. GO TO AP/l (Load Rejection).

l

AP/3/AJl 700/034 Page 13 of25 ACTION[EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE OPIO/AIl 107/016 (Removal And Restoration of Switchyard Electrical Equipment) Enclosure (Grid Low Voltage Response) will give guidance for sliding links. Once links are slid, all Units will no longer be in TS 3.03, due to being in unanalyzed condition due to effect of post-trip voltage on ECCS systems.

4.25 IAAT notified by TCC that Real Time GO TO Step 4.27.

Contingency Analysis indicates that switchyard voltage would be inadequate for an Oconee Rx trip, THEN perform Step 4.26.

4.26 Verify Unit I is performing Initiate OP/0/A/1107/016 (Removal And OP/U/All 107/0 16 (Removal And Restoration of Switchyard Electrical Restoration of Switchyard Electrical Equipment) Enclosure (Grid Low Voltage Equipment) Enclosure (Grid Low Response). (4>

Voltage Response) per AP/1134 (Degraded Grid). (4) 4.27 Verify Unit 1 is performing API1/34 Notify WCC SRO to enter risk code (Degraded Grid). SSA_GRID into the Plant Risk Evaluation Program and evaluate the results. (5) 4.28 WHEN the grid is stable, as determined by the TCC, THEN continue.

4.29 Verify Unit 2 is performing AP12134 Notify Keowee Operator that Keowee (Degraded Grid). Generator Voltage monitoring is no longer required. (3)

AP/3/AJl 700/034 Page 15 of25 T ACTIONJEXPECTED RESPONSE RESPONSE NOT OBTAINED 4.30 Verify OP/0/AJ1 107/0 16 (Removal GO TO Step 4.32.

And Restoration of Switchyard Electrical Equipment) Enclosure (Grid Low Voltage Response) in progress or complete. -

4.31 Verify Unit 1 is performing Initiate OP/0/A/l 107/016 (Removal And OP/0/A/1 107/016 (Removal And Restoration of Switchyard Electrical Restoration of Switchyard Electrical Equipment) Enclosure (Recovery From Equipment) Enclosure (Recovery Grid Low Voltage). 4}

From Grid Low Voltage). {4) 4.32 WHEN CR SRO directs, THEN EXIT this procedure.

AP/3/A/l 700/034 Page 17 of25 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.33 Verify Unit 1 is performing AP/l/34 Notify TCC that the RTCA (Real Time (Degraded Grid). Contingency Analysis) needs to be performed. -

4.34 Verify Unit 2 is performing Notify Keowee Operator of the following:

AP/2/34 (Degraded Grid).

Monitor Keowee Generator Voltage when y Keowee unit is generating to the grid.

Trip py Keowee unit generating to the grid with Keowee Generator Voltage 13.2 kV. {3}

NOTE OPJOJA/1 107/016 (Removal And Restoration of Switchyard Electrical Equipment) Enclosure (Grid Low Voltage Response) will give guidance for sliding links. Once links are slid, all Units will no longer be in TS 3.0.3, due to being in unanalyzed condition due to effect of post-trip voltage on ECCS systems.

4.35 IAAT notified by TCC that Real Time GO TO Step 4.37.

Contingency Analysis indicates that switchyard voltage would be inadequate for an Oconee Rx trip, THEN perform Step 4.36.

4.36 Verify Unit 1 is performing Initiate OP/OIAI1 107/0 16 (Removal And OP/0/A/l 107/016 (Removal And Restoration of Switchyard Electrical Restoration of Switchyard Electrical Equipment) Enclosure (Grid Low Voltage Equipment) Enclosure (Grid Low Response). {4)

Voltage Response) per AP/1/34 (Degraded Grid). {4).

4.37 WHEN the grid is stable, as determined by the TCC, THEN continue.

API3IAII 700/03 4 Page 19 of25

[ ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.38 Verify Unit 2 is performing API2/34 Notify Keowee Operator that Keowee (Degraded Grid). Generator Voltage monitoring is no longer required._(3) 4.39 Verify OP/0/A/l 107/016 (Removal GO TO Step 4.41.

And Restoration of Switchyard Electrical Equipment) Enclosure (Grid Low Voltage Response) in progress or complete.

4A0 Verify Unit 1 is performing Initiate OP/0/A/l 107/016 (Removal And OP/0/A/l 107/016 (Removal And Restoration of Switchyard Electrical Restoration of Switchyard Electrical Equipment) Enclosure (Recovery From Equipment) Enclosure (Recovery Grid Low Voltage). 4}

From Grid Low Voltage).

4.41 WHEN CR SRO directs, THEN EXIT this procedure.

.

END .. .

AP/3/AJ1 700/034 Page 21 of25 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.42 Verify y of the following: GO TO Step 4.48.

Actual predicted Megawatt reserves < 500 MWe.

NERC (National Electric Reliability Commission) Alert 2 or 3 declaration.

RTCA (Real Time Contingency Analysis) indicates that 230 kV switchyard voltage would be inadequate if further grid degradation occurs. 6}

4.43 Verify that RTCA indicates that GO TO Step 4.45.

230 kV switchyard voltage would be inadequate if further grid degradation oCcurs. {6)

NOTE

TS 3.8.1 J should be entered if one more failure would cause 230 kV voltage to be degraded.

OP/U/A/i 107/016 (Removal And Restoration of Switchyard Electri cal Equipment) is performed per steps 4.25 or 4.35 if an Oconee Rx trip could cause the 230 kV switchyard degradation.

OP/U/A/i 107/016 will direct the TS 3.8.1. J entry for these cases.

4.44 Enter TS 3.8.1 Required Action J.

API3 IA/I 700/03 4 Page 23 of 25 L ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.45 Verif the following equipment is Initiate action to restore out of service available: (6) equipment.

. KHU underground and overhead power paths

. Lee Combustion Turbines and associated power path

. Control and Power Batteries

. SSF

TDEFWP 4.46 Notify WCC that the following equipment should remain in service until this AP is exited: {6)

KHU underground and overhead power paths

Lee Combustion Turbines and associated power path

. Control and Power Batteries

SSF

TDEFWP

API3/A11 700/034 Page 25 of 25 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 4.47 Notify WCC SRO to enter risk code SSA GRID into the Plant Risk Evaluation Program and evaluate the results. {6) 4.48 Verify TCC reports RTCA program GO TO Step 4.50.

out of service. {6}

4.49 Monitor switchyard voltage and frequency on OAC. {6) 4.50 IAAT switchyard voltage or frequency alarms are received, AND RTCA is out of service, THEN contact System Engineering to perform an Operability evaluation on off site power soUrces. {6}

4.51 WHEN conditions permit, THEN EXIT.

LEAD -* 1000 KILO VARS .- LAG C.fl . C.. r.3 -. - N3 C3 .. CJ C) C) C) rn rn rn C,

r rn rn rn

> >,,

m rn -

c rn rn Z rn

1 9

Enclosure 5.1 AP/31A117001034 Generator Capability Page 3 of 3 Curve

1. Instructions for use of End 5.1 (Generator Capability Curve) are as follows:

A. Locate Unit Megawatts on the horizontal axis. (1000 kilowatts = 1 megawatt)

B. Depending on whether power factor is leading or lagging. Move perpendicular away from the 1000 KILOWATTS axis until intersecting actual generator hydrogen pressure. If between two pressures curves, visually interpolate generator hydrogen pressure.

C. From this point of intersection with generator pressure, move horizontally to the left to intersect the 1000 KILO VARS axis. This point determines the generator MVAR limit. (1000 KILOVARS = I MVAR)

k sure 5.2 AP/3/A/1 700/03 4 Generator Reduced Capability Curve Page 1 of 5 Figure 5.2A Generator Capahuliy at Reduced Vollage with Hydrogen Pressure > 55 MVkRS I

inoj 2O0 L300I Oi 500! cooi 700! rsool 9001!i000!L1100J11200j MW

Ii sure 5.2 AP/3/A/1 700/03 4 Generator Reduced Capability Curve Page 3 of 5 Figure 5.2B Generator C 1 bfflty at Rethiced Voitige with Hyd.roeii Pressure 3055 psig 800 I 700 600 500 MVAJEth1 F4°° I 1300 I I 200 II 11001 LJ I 0 I loot 12.001 3001 400 15001 6001 7001 soot 9001 [i000]liioot 112001 rIw I

sure 5.2 AP/3/A/1700/034 Generator Reduced Capability Curve Page 5 of 5 Instructions for use of End 5.2 (Generator Reduced Capability Curve) are as follows:

A. Select appropriate Figure based on Generator Hydrogen pressure. If Generator Hydrogen pressure> 55 psig, use Figure 5.2A. If Qenerator

-

Hydrogen pressure is 30 55 psig, use Figure 5.2B.

B. Locate Unit Megawatts on the horizontal axis on appropriate Figure.

C. Move perpendicular up from Megawatts until intersecting actual generator voltage. If between two voltage curves, drop to the next lowest voltage curve.

D. From this point of intersection with generator voltage curve move horizontally to the left to intersect the MVARs vertical axis, This point determins the generator MVAR limit. Acceptable MVA is below and to the left of the generator voltage curve.

Appendix AP/3/A11700/034 Page 1 of I

1. SOER 99-01/PIP 0-00-00354 Corrective Action #15 Created a procedure

-

to mitigate degraded grid conditions.

2. PIP-O-0l-01864 Corrective Action #1 states to use switchyard PCBs instead

-

of generator output breakers. These are actually one in the same and no change is require d.

3. PIP-O-00-00354 Corrective Action #27-Added guidance to notify Keowee Operator to monitor Keowee Generator Voltage on Keowee units generating to the grid and trip them if Keowee Generator Voltage is 13.2 kV.

4. PIP-O-03-4351 OP/0/AJ1 107/016 provides guidance to allow ONS to exit TS conditions associated with Degraded Grid and is not required to mitigate a Degraded Grid event. Thus, it is not considered an AP Support Procedure.

5. PIP-0-04-6469 Risk codes added to AP/6 and AP/34 to evaluate work and OOS equipment.

6. PIP-G-07-76 1. Guidance added per request from NGD Duty Engineering Group. Guidance tells ONS proper actions to take based on various grid problems.

PAM Instrumentation 3.3.8 3.3 INSTRUMENTATION 3.3.8 Post Accident Monitoring (PAM) Instrumentation LCO 3.3.8 The PAM instrumentation for each Function in Table 3.3.8-1 shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS NOTES----

1. LCO 3.0.4 is not applicable.

2. Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. NOTE A.1 Restore required 30 days Not applicable to channel to OPERABLE Functions 14, 18, 19, status.

and 22.

One or more Functions with one required channel inoperable.

B. Required Action and B.1 Initiate action in Immediately associated Completion accordance with Time of Condition A not Specification 5.6.6.

met.

(continued)

OCONEE UNITS 1, 2, & 3 3.3.8-1 Amendment Nos. 350, 352, & 351

PAM Instrumentation 3.3.8 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. NOTE C.1 Restore one channel to 7 days Not applicable to OPERABLE status.

Functions 14, 18, 19, and 22.

One or more Functions with two required channels inoperable.

D. Not Used D.1 Not Used Not Used E. NOTE E.1 Restore required 24 hours1 days 0.143 weeks 0.0329 months Only applicable to channel to OPERABLE Function 14. status.

One required channel inoperable.

(continued)

OCONEE UNITS 1, 2, & 3 3.3.8-2 Amendment Nos. 350, 352, & 351 I

PAM Instrumentation 3.3.8 ACTIONS (conUnued)

CONDITION REQUIRED ACTION COMPLETION TIME F. NOTE F.1 Declare the affected Immediately Only applicable to train inoperable.

Functions 18, 19, and 22.

One or more Functions with required channel inoperable.

G. Required Action and G.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C or Table 3.3.8-1 for the E not met. channel.

H. As required by H.1 Be in MODE 3. 12 hours0.5 days 0.0714 weeks 0.0164 months Required Action G.1 and referenced in AND Table 3.3.8-1.

H.2 Be in MODE 4. 18 hours0.75 days 0.107 weeks 0.0247 months As required by 1.1 Initiate action in Immediately Required Action G.1 accordance with and referenced in Specification 5.6.6.

Table 3.3.8-1.

OCONEE UNITS 1, 2, & 3 3.3.8-3 Amendment Nos. 350, 352, & 351 I

PAM Instrumentation 3.3.8 SURVEILLANCE REQUIREMENTS

-NOTE-These SRs apply to each PAM instrumentation Function in Table 3.3.8-1 except where indicated.

SURVEILLANCE FREQUENCY SR 3.3.8.1 Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized.

SR 3.3.8.2 NOTE Only applicable to PAM Functions 7 and 22.

Perform CHANNEL CALIBRATION. 12 months SR 3.3.8.3 NOTES

1. Neutron detectors are excluded from CHANNEL CALIBRATION.

2. Not applicable to PAM Functions 7 and 22.

Perform CHANNEL CALIBRATION. 18 months OCONEE UNITS 1,2, & 3 3.3.8-4 Amendment Nos. 344, 346, & 345

PAM Instrumentation 3.3.8 Table 3.3.8-1 (page 1 of 1)

Post Accident Monitoring Instrumentation CONDITIONS REFERENCED FROM FUNCTION REQUIRED CHANNELS REQUIRED ACTION G.1

1. Wide Range Neutron Flux 2 H

2. RCS Hot Leg Temperature 2 H

3. RCS Hot Leg Level 2 I

4. RCS Pressure (Wide Range) 2 H

5. Reactor Vessel Head Level 2

6. Containment Sump Water Level (Wide Range) 2 H

7. Containment Pressure (Wide Range) 2 H

8. Containment Isolation Valve Position 2 per penetration flow path H

9. Containment Area Radiation (High Range) 2

10. Not Used

11. Pressurizer Level 2 H

12. Steam Generator Water Level 2 per SG H

13. Steam Generator Pressure 2 per SG H

14. Borated Water Storage Tank Water Level 2 H

15. Upper Surge Tank Level 2 H

16. Core Exit Temperature (d) 5 2 independent sets of H

17. Subcooling Monitor 2 H

18. HPI System Flow 1 per train NA

19. LPI System Flow 1 per train NA

20. Not used

21. Emergency Feedwater Flow 2 per SG H

22. Low Pressure Service Water Flow to LPI Coolers 1 per train NA (a) Not required for isolation valves whose associated penetration is isolated by at least one closed and deactivated automatic valve, dosed manual valve, blind flange, or check valve with flow through the valve secured.

(b) Only one position indication channel is required for penetration flow paths with only one installed control room indication channel.

(C) Position indication requirements apply only to containment isolation valves that are electrically controlled.

(d) The subcooling margin monitor takes the average of the five highest CETs for each of the ICCM trains.

OCONEE UNITS 1, 2, & 3 3.3.8-5 Amendment Nos. 350, 352, & 351

LPSW System 3.7.7 3.7 PLANT SYSTEMS 3.7.7 Low Pressure Service Water (LPSW) System LCO 3.7.7 For Unit 1 or Unit 2, three LPSW pumps and one flow path shall be OPERABLE.

For Unit 3, two LPSW pumps and one flow path shall be OPERABLE.

The LPSW Waterhammer Prevention System (WPS) shall be OPERABLE on Units where the LPSW RB Waterhammer modification is installed.

NOTE With either Unit 1 or Unit 2 defueled and appropriate LPSW loads secured on the defueled Unit, such that one LPSW pump is capable of mitigating the consequences of a design basis accident on the remaining Unit, only two LPSW pumps for Unit 1 or Unit 2 are required.

APPLICABILITY: MODES 1,2, 3, and 4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required LPSW A.1 Restore required 72 hours3 days 0.429 weeks 0.0986 months pump inoperable. LPSW pump to OPERABLE status.

B. LPSW WPS inoperable B.1 Restore the LPSW 7 days on Units with LPSW WPS to OPERABLE RB Waterhammer status.

modification installed.

C. Required Action and C.1 Be in MODE 3. 12 hours0.5 days 0.0714 weeks 0.0164 months associated Completion Time of Condition A AND and B not met.

C.2 Be in MODE 5. 60 hours2.5 days 0.357 weeks 0.0822 months OCONEE UNITS 1, 2, & 3 3.7.7-1 Amendment Nos. 363, 365, & 364

LPSW System 3.7.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 Verify LPSW leakage accumulator level is within 12 hours0.5 days 0.0714 weeks 0.0164 months Water levels between 20.5 to 41 for Units with LPSW RB Waterhammer modification installed.

During LPSW testing, accumulator level > 41 is acceptable.

SR 3.7.7.2 NOTE Isolation of LPSW flow to individual components does not render the LPSW System inoperable.

Verify each LPSW manual, and non- 31 days automatic power operated valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.7.3 Verify each LPSW automatic valve in the flow 18 months path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.7.7.4 Verify each LPSW pump starts automatically 18 months on an actual or simulated actuation signal.

SR 3.7.7.5 Verify LPSW leakage accumulator is able to 18 months provide makeup flow lost due to boundary valve leakage on Units with LPSW RB Waterhammer modification installed.

(continued)

OCONEE UNITS 1, 2, & 3 3.7.7-2 Amendment Nos. 363, 365, & 364

LPSW System 3.7.7 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.7.7.6 Verify LPSW WPS boundary valve leakage is 18 months 20 gpm for Units with LPSW RB Waterhammer modification installed.

OCONEE UNITS 1, 2, & 3 3.7.7-3 Amendment Nos. 363, 365, & 364

Procedure No.

Duke Energy Oconee Nuclear Station RP/O/B/l000/oo1 Emergency Classification Revision No.

028 Electronic Reference No.

OXOO2WOS Reference Use PERFORMANCE

* * * * * * * * *

* * * * * * * *

UNCONTROLLED FOR PRINT (ISSUED) PDF Format

-

RP/0/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 classifi 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 Definitions and Acronyms are italicized throughout procedure for easy recognition. The definitions are in Enclosure 4.10 (Definitions/Acronyms).

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

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

1.4.4 j 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. hiformation relating to the problem(s) on the other unit(s) will be captured on the Emergency Notification Form as shown in RP/0/B/l000/015A, (Offsite Communications From The Control Room),

RP/0/B/1000/015B, (Offsite Communications From The Technical Support Center) or SRIO/B/2000/004, (Notification to States and Counties from the Emergency Operations Facility).

1.4.5 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/0/B/ 1000/001 Page 3 of 6 1.4.6 The Fission Product Barrier Matrix is applicable only to those events that occur at Mode 4 (Hot Shutdown) or higher.

A. An event that is recognized at Mode 5 (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 A transient event should occur, THEN Review the following guidance:

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

condition cam-iot be reasonably corrected before the duration elapses),

THEN Classify the event.

1.5.2 IF 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 10CFR5O.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 j 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)

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

Refer to NSD 202 for reportability 3

RP/0/B/ 1000/001 Page 4 of 6 1.5.4 j 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.

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.

4

RP/0/B/ 1000/001 Page 5 of6

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 Mode 4 (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).

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 Classif the event as required.

2.4 IF The condition requires an emergency classification, THEN Initiate the following:

for Control Room RP/0/B/1000/002, (Control Room

-

Emergency Coordinator Procedure)

for TSC RP/0/B/1000/019, (Technical Support Center

-

Emergency Coordinator Procedure)

for EOF SR/0/B/2000/003, (Activation of the Emergency

-

Operations Facility) 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/B/ 1000/001 Page 6 of 6 4.0 Enclosures Enclosures Page Number 4.1 Fission Product Barrier Matrix 7 4.2 System Malfunctions 8 4.3 Abnormal Rad Levels/Radiological Effluents 10 4.4 Loss Of Shutdown Functions 12 4.5 Loss of Power 14 4.6 Fires/Explosions And Security Actions 15 4.7 Natural Disasters, Hazards, And Other Conditions Affecting Plant Safety 18 4.8 Radiation Monitor Readings For Emergency Classification 21 4.9 Unexpected/Unplanned Increase In Area Monitor Readings 22 4.10 Definitions 23 4.11 Operating Modes Defined In Improved Technical Specifications 27 4.12 Instructions For Using Enclosure 4.1 28 4.13 References 30 6

Enclosure 4.1 RP/0/B/1 000/001 Fission Product Barrier Matrix Page 1 of 1 DETERMINE THE APPROPRIATE CLASSIFICATION USING THE TABLE BELOW:

ADD POINTS TO CLASSIFY. SEE NOTE BELOW RCS BARRIERS (BD 5-7) FUEL CLAD BARRIERS (BD 8-9) CONTAINMENT BARRIERS (BD 10-13)

Potential Loss (4 Points) Loss (5 Points) Potential Loss (4 Points) Loss (5 Points) Potential Loss (1 Point) Loss (3 Points)

RCS Leakrate 160 gpm RCS Leak rate that results in a loss Average of the 5 highest Average of the 5 highest CETC CETC 1200° F iS minutes Rapid unexplained containment of subcooling. CETC 1200° F OR pressure decrease after increase 700° F CETC 700° F 15 minutes with a valid RVLS reading o containment pressure or sump level not consistent with LOCA SGTR 160 gpm Valid RVLS reading of 0 Coolant activity 300 pCi/mI DEl RB pressure 59 psig Failure of secondary side of SG OR results in a direct opening to the RB pressure 10 psig and no environment with SO Tube Leak NOTE: RVLS is NOT RBCUorRBS l0gpmintheSG valid if one or more Entry into thc PTS (Pressurized RCPs are running Q, if IRIA 57 or 58 reading 1.0 RJhr Hours RIA 57 OR RJA 58 Hours Thermal Shock) Operation LPI pump(s) are RIA 57 OR RIA 58 SG Tube Leak 10 m exists in running taking Since SD R/hr RJhr Since SD RIhr ft/hr one SG.

NOTE: PTS is entered under 2 RIA 57 reading 1.6 RIhr suction from the LPI D either of the following: 2 RIA 58 reading 1.0 R/hr drop line. 0 <0.5 300 150 0 0.5 the other 50 has secondary side

- - < ? 1800 860

A cooldown below 400°F @ failure that results in a direct

> 100°F/hr. has occurred, 3RIA 57 or 58 reading 1.0 RIhr 0.5 opening to the environment

- < 2.0 80 40 0.5 - < 2.0 400 195 is being fed from the affected unit.

. HPI has operated in the injection mode while NO 2.0- 8.0 ? 32 16 2.0- 8.0 > 280 130 RCP5 were operating.

HPI Forced Cooling RCS pressure spike 2750 psig Hydrogen concentration 9% Containment isolation is incomplete and a release path to the environment exists Emergency Coordinator/EOF Emergency Coordinator/EOF Emergency CoordinatorIEOF Emergency CoordinatorfEOF Director Emergency Coordinator/EOF Emergency Coordinator/EOF Director judgment Director judgment Director judgment judgment Director judgment Director judgment UNUSUAL EVENT (1-3 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 4.1 .U. 1 Any potential loss of Containment 4.1 A. I Any potential loss or loss of the RCS 4.1 .S. 1 Loss of any two barriers 4.1G. 1 Loss of any two barriers and potential loss of 4.1 .U.2 Any loss of containment the third barrier 4.1 .A.2 Any potential loss or loss of the Fuel 4.1 S.2 Loss of one barrier and potential loss of either Clad 4.1.0.2 Loss of all three barriers RCS or Fuel Clad Barriers 4.1.S.3 Potential loss of both the RCS and Fuel Clad Barriers NOTE: An event with multiple events could occur which would result in the conclusion that exceeding the loss or potential loss threshold is IMMINENT (i.e., within 1-3 hours0.125 days 0.0179 weeks 0.00411 months ). In this IMMINENT LOSS situation, use judgment and classify as if the thresholds are exceeded.

7

Enclosure 4.2 RP/0/B/1 000/001 System Malfunctions Page 1 of2 UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY

1. RCSLEAKAGE(BD 15)

OPERATING MODE: 1,2,3,4 A. Unidentified leakage 10 gpm B. Pressure boundary leakage 10 gpm C. Identified leakage 25 gpm

. Includes SO tube leakage

2. UNPLANNED LOSS OF MOST OR ALL I. UNPLANNED LOSS OF MOST OR ALL SAFETY SYSTEM ANNUNCIATION! SAFETY SYSTEM ANNUNCIATION! 1. INABILITY TO MONITOR A INDICATION IN CONTROL ROOM INDICATION IN CONTROL ROOM SIGNIFICANT TRANSIENT IN FOR> 15 MINUTES (RD 16) (BD 20) PROGRESS (BD 22)

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

Units 1 & 3 Units I & 3 Units 1 & 3 I SAl, 2,3,4,5,6,7,8,9, 14, 15, 16, & 18 I SAI,2,3,4,S,6,7,8,9, 14,15, 16,&18 1 SAl, 2,3,4,5,6,7,8,9, 14, 15, 16, & 18 3 SAl, 2,3,4,5,6,7,8,9, 14, 15, 16, & 18 3 SAl, 2,3,4,5,6,7,8,9, 14, 15, 16, & 18 3 SAl, 2,3,4,5,6, 7, 8,9, 14, 15, 16, & 18 Unit 2 Unit 2 Unit 2 2 SAl, 2,3,4, 5,6, 7, 8,9, 14, 15, & 16 2 SAl, 2,3,4,5,6,7,8,9, 14, 15, & 16 2 SAl, 2,3,4,5,6, 7, 8, 9, 14, 15, & 16 AND AND AND A.2 Loss of annunciators or indicators requires A.2 Loss of annunciators or indicators requires A.2 A sign ficant transient is in progress additional personnel (beyond normal shift additional personnel (beyond normal shift complement) to safely operate the unit complement) to safely operate the unit AND AND A.3 Loss of the OAC and ALL PAM indications (CONTINUED)

A.3 Sign/icant plant transient in progress AND OR A.4 Inability to directly ,nonitor any one of the following functions:

A.4 Loss of the OAC and ALL PAM indications 1. Subcriticality

2. Core Cooling (END) 3. Heat Sink

4. RCS Integrity

5. Containment Integrity

6. RCS Inventory (END) 8

Enclosure 4.2 RP/O/B/1000/OO1 System Malfunctions Page 2 of 2 UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY

3. INABILITY TO REACH REQUIRED SHUTDOWN WITHIN LIMITS (BD 17)

OPERATING MODE: 1,2,3,4 A. Required operating mode not reached within TS LCO action statement time

4. UNPLANNED LOSS OF ALL ONSITE OR OFFSITE COMMUNICATIONS (ED 18)

OPERATING MODE: All A. Loss of all onsite communications capability (Plant phone system, PA system, Pager system, Onsite Radio system) affecting ability to perform Routine operations B. Lass 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 (BO 19)

OPERATING MODE: All:

A. DEl >5lICi/ml

-

(END) 9

Enclosure 4.3 RP/0/B/1 000/001 Abnormal Rad Levels/Radiological Effluent Page 1 of2 UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY 1 ANY UNPLANNED RELEASE OF I. ANY UNPLANNED RELEASE OF 1. BOUNDARY DOSE RESULTING FROM 1. BOUNDARY DOSE RESULTING FROM GASEOUS OR LIQUID RADIOACTIVITY GASEOUS OR LIQUID RADIOACTIVITY ACTUAL/IMMINENT RELEASE OF ACTUAL! IMMINENT RELEASE OF TO THE ENVIRONMENT THAT TO THE ENVIRONMENT THAT GASEOUS ACTIVITY (BD 33) GASEOUS ACTIVITY (BD 37)

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 24) MINUTES OR LONGER (BD 29)

A. Valid reading on RIA 46 of 2.09E+05 cpm A. Valid reading on RIA 46 of 2.09 E+06 cpm OPERATING MODE: All OPERATING MODE: All for l5 minutes (See Note 3) for>15 minutes (See Note 2)

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 RLk 57 or 58as shown on of 4.06E+06 cpm for >60 minutes for>I5 minutes (See Note I) Enclosure 4.8 (See Note 2) Enclosure 4.8 (See Note 3)

(See Note 1)

B 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 45 the site boundary of: the site boundary of:

of 9.35E+05 cpm for> 60 minutes AND (See Note 1) 1000 mRem TEDE 100 mRem TEDE or 500 mRem CDE adult Liquid effluent being released exceeds 200 thyroid C. Liquid effluent being released exceeds two times the level of SLC 16.11.1 for> 15 minutes OR times SLC 16.11.1 for>60 minutes as as determined by Chemistry Procedure determined by Chemistry Procedure D. Field survey results indicate Site boundary dose 5000 mRem CDE adult thyroid C. Gaseous effluent being released exceeds 200 rates exceeding 100 mRadlhr 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 l 000 mRad!hr expected to determined by RP Procedure OR continue for more than one hour Analyses of field survey samples indicate adult NOTE 1: If monitor reading is sustained OR thyroid dose commitment of 500 mRem for the time period indicated in the EAL (CONTINUED)

AND the required assessments (procedure CDE (3.84 E 7 iCi/ml) for one hour of Analyses of field survey samples indicate adult calculations) cannot be completed within inhalation thyroid dose commitment of 5000 mRem this period, declaration must be made on the CDE for one hour of inhalation valid Radiation Monitor reading. NOTE 2: If actual Dose Assessment cannot be completed within 15 minutes, then the valid radiation monitor reading should be NOTE 3: If actual Dose Assessment cannot used for emergency classification. be completed within 15 minutes, then the valid radiation monitor reading should be used for emergency classification.

(CONTINUED)

(END) 10

Enclosure 4.3 RP/0/B/ 1000/001 Abnormal Rad Levels/Radiological Effluent Page 2 of 2 UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY 2 UNEXPECTED INCREASE IN PLANT 2. RELEASE OF RADIOACTIVE 2. LOSS OF WATER LEVEL IN THE RADIATION OR AIRBORNE MATERIAL OR INCREASES IN REACTOR VESSEL THAT HAS OR CONCENTRATION (RD 26) RADIATION LEVELS THAT IMPEDES WILL UNCOVER FUEL IN THE OPERATION OF SYSTEMS REQUIRED REACTOR VESSEL (BD 36)

OPERATING MODE: All TO MAINTAIN SAFE OPERATION OR TO ESTABLISH OR MAINTAIN COLD SHUTDOWN (BD 31) OPERATING MODE: 5,6 A. LT 5 reading 14 and decreasing with makeup not keeprng up with leakage )JJI fuel in the OPERATING MODE: All A.I Failure of heat sink causes loss of Mode 5 core (Cold Shutdown) condition A. Valid radiation reading 15 mRad/hr in CR, B. Valid indication of uncontrolled water decrease AND CAS, or Radwaste CR in the SFP or fuel transfer canal with all fuel astemblies remaining covered by water B. Unplanned/unexpected valid area monitor LT 5 indicates 0 inches after initiation of RCS readings exceed limits stated in Enclosure 4.9 makeup AND B. Failure of heat sink causes loss of Mode 5 Unplanned Valid RLk 3, 6 or Portable Area 3. MAJOR DAMAGE TO IRRADIATED (Cold Shutdown) condition Monitor readings increase. FUEL OR LOSS OF WATER LEVEL THAT HAS OR WILL RESULT IN THE C. 1 Rlhr radiation reading at one foot away from UNCOVERING OF iRRADIATED FUEl. AND a damaged storage cask located at the ISFSI OUTSIDE THE REACTOR VESSEL (RD 32)

Either train ultrasonic level indication less than D. Valid area monitor readings exceeds limits O inches and decreasing after initiation of RCS stated in Enclosure 4.9. OPERATING MODE: All makeup A. Valid RIA 3*, 6,41, OR 49* HIGH Alarm NOTE: This Initiating Condition is also located NOTE: This Initiating Condition is also in Enclosure 4.4., (Loss of Shutdown Functions).

located in Enclosure 4.4., (Loss of Shutdown High radiation levels will also be seen with this - Applies to Mode 6 and No Mode Only Functions). High radiation levels will also be condition. seen with this condition.

B. HIGH Alarm for portable area monitors on the main bridge or SFP bridge C Report of visual observation of irradiated fuel uncovered (END))

D. Operators determine water level drop in either (END) the SFP or fuel transfer canal will exceed makeup capacity such that irradiated fuel will be uncovered 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) 11

Enclosure 4.4 RP/O/B/1000/OO1 Loss of Shutdown Functions Page 1 of 2 UNUSUAL EVENT

[ ALERT FAILURE OF RPS TO COMPLETE OR 1.

SITE AREA EMERGENCY FAILURE OF RPS TO COMPLETE OR

[ GENERAL EMERGENCY I. FAILURE OF RPS To COMPLETE INITIATE A Rx SCRAM (I3D 42) INITIATE A Rx SCRAM (BD 46) AUTOMATIC SCRAM AND MANUAL SCRAM NOT SUCCESSFUL WITH OPERATING MODE 1,2,3 OPERATING MODE: 1,2 INDICATION OF CORE DAMAGE (CONTINUE TO NEXT PAGE) (BD 49)

A Valid reactor trip signal received or required A. 1 Valid reactor trip signal received or required WITHOUT automatic scram WITHOUT automatic scram OPERATING MODE: 1,2 AND AND A. I Valid Rx trip signal received or required A.l.I DSS has inserted Control Rods WITHOUT automatic scram A.2 DSS has NOT inserted Control Rods

A.l.2 Manual trip from the Control Room is successful and reactor power is less A.2 Manual trip from the Control Room was AND than 5% and decreasing successful in reducing reactor power to < 5%

A.3 Manual trip from the Control Room was NOT and decreasing successful in reducing reactor power to less than 5% and decreasing A.3 Average of the 5 highest CETCs 1200° F on ICCM

2. INABILITY TO MAINTAIN PLANT IN 2. COMPLETE LOSS OF FUNCTION (END)

COLD SHUTDOWN (BD 44) NEEDED TO ACHIEVE OR MAINTAIN HOT SHUTDOWN (BD 47)

OPERATING MODE: 5,6 OPERATING MODE: 1,2,3,4 A.l Loss of LPI and/or LPSW A. Average of the 5 highest CETC5 l2000 F shown on ICCM A.2 Inability to maintain RCS temperature B. Unable to maintain reactor subcritical below 2000 F as indicated by either of the following:

C. EOP directs feeding SG from SSF ASWP or A.2. I RCS temperature at the LPI Pump station ASWP Suction (CONTINUED)

A.2.2 Average of the 5 highest CETC5 as indicated by ICCM display A.2.3 Visual observation (CONTINUED) 12

Enclosure 4.4 RP/0/B/1 000/001 Loss of Shutdown Functions Page 2 of 2 UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY

1. UNEXPECTED INCREASE IN PLANT 3. MAJOR DAMAGE TO IRRADIATED 3. LOSS OF WATER LEVEL IN THE RADIATION OR AIRBORNE FUEL OR LOSS OF WATER LEVEL REACTOR VESSEL THAT HAS OR CONCENTRATION (BD 40) THAT HAS OR WILL RESULT IN THE WILL UNCOVER FUEL IN THE OPERATING MODE: All UNCOVERING OF IRRADIATED FUEL REACTOR VESSEL (BD 48)

OUTSIDE THE REACTOR VESSEL (BD 45)

A. LT 5 reading 14 and decreasing with makeup OPERATING MODE: 5,6 not keeping up with leakage WITH fuel in the core OPERATING MODE: All A.l Failure of heat sink causes loss of Mode 5 (Cold Shutdown) conditions B. Valid indication of uncontrolled water decrease A. Valid RIA 3*, 6, 41, 0R49* HIGH Alarm in the SFP or fuel transfer canal with all fuel AND assemblies remaining covered by Water *App lies to Mode 6 and No Mode Only A.2 LT-5 indicates 0 rnches after initiation of RCS AND B. HIGH Alarm for portable area monitors on the Makeup main bridge or SFP bridge Unplanned Valid RIA 3, 6 or Portable Area B.l Failure of heat sink causes loss of ModeS Monitor readings increase. C Report of visual observation of irradiated fuel (Cold Shutdown) conditions uncovered AND C. I RIhr radiation reading at one foot away from a damaged storage cask located at the ISFSI 0. Operators determine water level drop in either B.2 Either train ultrasonic level indication less than the SFP or fuel transfer canal wilt exceed O inches and decreasing after initiation of RCS

0. Valid area monitor readings exceeds limits makeup capacity such that irradiated fuel will makeup stated in Enclosure 4.9. be uncovered 1F NOTE: This Initiating Condition is also located NOTE: This Initiating Condition is also located in Enclosure 4.3, (Abnormal Rad NOTE: This Initiating Condition is also located in Enclosure 4.3., (Abnormal Rad Levels/Radiological Effluent). High radiation in Enclosure 4.3, (Abnormal Rad Levels/Radiological Effluent). High radiation levels will also be seen with this condition. Levels/Radiological Effluent). High radiation levels will also be seen with this condition. levels will also be seen with this condition.

(END)

(END) 13

Enclosure 4.5 RP/O/B/1000/OO1 Loss of Power {4} Page 1 of 1 UNUSUAL EVENT

1. LOSS OF ALL OFFSITE POWER TO 1.

ALERT LOSS OF ALL OFFSITE AC POWER AND

[ 1.

SITE AREA EMERGENCY LOSS OF ALL OFFSITE AC POWER AND 1.

GENERAL EMERGENCY PROLONGED LOSS OF ALL OFFSITE ESSENTIAL BUSSES FOR GREATER LOSS OF ALL ONSITE AC POWER TO LOSS OF ALL ONSITE AC POWER TO POWER AND ONSITE AC POWER TI-IAN 15 MINUTES (BD 51) ESSENTIAL BUSSES (BD 53) ESSENTIAL BUSSES (BD 55) (BD 58)

OPERATING MODE: All OPERATING MODE: 5,6 OPERATING MODE: 1,2, 3,4 OPERATING MODE: I, 2,3,4 Defueled A. 1 Unit auxiliaries are being supplied from A. I MFB I and 2 de-energized A. I MFB I and 2 de-energized Keowee or CTS A. I MFB I and 2 dc-energized AND AND A.2 Failure to restore power to at least one MFB A.2 SSF fails to maintain Mode 3 A.2 Failure to restore power to at least one MFB A.2 within 15 minutes from the time of loss of (Hot Standby) {1 Inability to energize either MFB from an offsite within 15 minutes from the time of loss of both both offsite and onsite AC power source (either switchyard) within 15 minutes. offsite and onsite AC power AND A.3 At least one of the following conditions exist:

2. AC POWER CAPABILITY TO 2. LOSS OF ALL VITAL DC POWER

2. UNPLANNED LOSS OF REQUIRED DC ESSENTIAL BUSSES REDUCED TO A IBD 56) A.3.l Restoration of power to at least one POWER FOR GREATER THAN 15 SINGLE SOURCE FOR GREATER THAN MFB within 4 hours0.167 days 0.0238 weeks 0.00548 months is likely MINUTES (BD 52) 15 MINUTES (BD 54) OPERATING MODE: 1,2,3,4 OPERATING MODE: 5, 6 OPERATING MODE: 1,2,3,4 A.1 Unplanned loss of viral DC power to required DC busses as indicated by bus voltage less than A 3.2 Indications of continuing A. Unplanned loss of vital DC power to required degradation of core cooling based A. AC power capability has been degraded to a 110 VDC DC busses as indicated by bus voltage less on Fission Product Barrier single power source for> 15 minutes due to the than 110 VDC monitoring loss of all but one of the following: AND AND Unit Normal Transformer (backcharged) (END)

A.2 Failure to restore power to st least one required A. Unit SU Transformer DC bus within 15 minutes from the time of loss Failure to restore power to at least one required DC bus within 15 minutes from the time of lots Another Unit SU Transformer (aligned)

CT4 CT5 (END)

(END)

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 thcj1ant is the same as if both MFBs were de-enerized.

14

Enclosure 4.6 RP/0/B/1 000/001 Fire/Explosions and Security Actions {2} {3} Page 1 of2 UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY FIRES/EXPLOSIONS WITHIN THE FIRE/EXPLOSION AFFECTING (CONTINUE TO NEXT PAGE) (CONTINUE TO NEXT PAGE)

PLANT (BD6I)

OPERABILITY OF PLANT SAFETY SYSTEMS REQUIRED TO ESTABLISHJMAINTAIN SAFE OPERATING MODE: All SHUTDOWN (BD 65)

NOTE: Within the plant means:

Turbine Building Auxiliary Building NOTE: Only one train of a system needs to Reactor Building be affected or damaged in order to satisfy this Keowee Hydro condition.

Transformer Yard B3T B4T Service Air Diesel Compressors Keowee Hydro & associated A. Fire/explosions transformers AND A. 1.1 Affected safety-related system parameter indications show degraded performance OR A. Fire within the plant not extinguished within A. 1.2 Plant personnel report visible damage to 15 minutes of Control Room notification or permanent structures or equipment verification of a Control Room alarm required for safe shutdown B. Unanticipated explosion within the plant (Continued) resulting in visible damage to permanent structures/equipment includes steam line break and FDW line break (Continued) 15

Enclosure 4.6 RP/0/B/ 1000/001 Fire/Explosions and Security Actions {2} {3) Page 2 of 2 UNUSUAL EVENT ALERT

[ SITE AREA EMERGENCY GENERAL EMERGENCY

2. CONFIRMED SECURITY CONDITION 2 HOSTILE ACTION WITHIN THE HOLTILE ACTION within the PROTECTED A HOSTILE ACTION RESULTING IN OR THREAT WHICH INDICATES A OWNER CONTROLLED AREA OR AREA (RD 69) LOSS OF PHYSICAL CONTROL OF POTENTIAL DEGRADATION IN THE AIRBORNE THREAT. (RD 66)

LEVEL OF SAFETY OF THE PLANT THE FACILITY (BD 71)

(BD 62)

A. A HOSTILE ACTION is occurring or has OPERATING MODE: All OPERATING MODE: All occurred within the OWNER CONTROLLED OPERATING MODE: All AREA as reported by the Security Shift A. A HOSTILE ACTION is occurring or has A. A HOSTILE ACTION has occurred such that Supervisor. occurred within the PORTECTED AREA as A. Security condition that does not involve a plant personnel are unable to operate HOSTILE ACTION as reported by the reported by the Site Security force. equipment required to maintain safety B. A validated notification from the NRC of an Security Shift Supervisor functions AIRLINER LARGE AIRCRAFT attack threat 2. OTHER CONDITIONS EXIST WHICH IN within 30 minutes of the site. THE JUDGEMENT OF THE EMERGENCY B. A credible site-spccific sceurity threat B. A HOSTILE ACTION has caused failure of notification DIRECTOR VARRANT DECLARATION Spent Fuel Cooling Systems and OF A SiTE AREA EMERGENCY. (BD 70) IMMINENT fuel damage is likely for a C. A validated notification from NRC providing 3. OTHER CONDITIONS EXIST WHICH IN freshly off-loaded reactor core in pool.

information of an aircraft threat THE JUDGEMENT OF THE EMERGENCY DIRECTOR WARRANT DECLARATION OF AN ALERT (BD 68) OPERATING MODE: All 2. OTHER CONDITIONS EXIST WHICH

3. OTHER CONDITIONS EXIST WHICH IN THE JUDGMENT OF THE A. Other conditions exist which in the judgment of EMERGENCY DIRECTOR WARRANT IN THE JUDGEMENT OF THE the Emergency Director indicate that events are in DECLARATION OF A GENERAL EMERGENCY DIRECTOR WARRANT progress or have occurred which involve actual or EMERGENCY. (BD 72)

DECLARATION OF A NOUE. (RD 64) OPERATING MODE: All likely major failures of plant functions needed for A. Other conditions exist which in the judgment protection of the public or HOSTILE ACTION of the Emergency Director indicate that events that results in intentional damage or malicious are in progress or have occurred which involve acts; (1) toward site personnel or equipment that OPERATING MODE: All an actual or potential substantial degradation of could lead to the likely failure of or; (2) that OPERATING MODE: All the level of safety of the plant or a security prevent effective access to equipment needed for A. Other conditions exist which in the judgment event that involves probable life threatening the protection of the public. Any releases are not A. Other conditions exist which in the judgment of the Emergency Director indicate that risk to site personnel or damage to site expected to result in exposure levels which of the Emergency Director indicate that events are in progress or have occurred which equipment because of HOSTILE ACTION. exceed EPA Protective Action Guideline events are in progress or have occurred indicate a potential degradation of the level of safety of the plant or indicate a security threat Any releases are expected to be limited to small exposure levels beyond the site boundary. which involve actual or IMMINENT to facility protection has been initiated. No fractions of the EPA Protective Action substantial core degradation or melting with releases of radioactive material requiring off- Guideline exposure levels. potential for loss of containment integrity or site response or monitoring are expected HOSTILE ACTION that results in an actual unless further degradation of safety systems (END) loss of physical control of the facility.

occurs. (END) Releases can be reasonably expected to exceed EPA Protective Action Guideline (END) exposure levels off-site for more than the immediate site area.

(END) 16

Enclosure 4.7 RP/O/B/1000/OO1 Natural Disasters, Hazards and Other Conditions Affecting Plant Safety Page 1 of 3 UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY

1. NATURAL AND DESTRUCTIVE 1. NATURAL AND DESTRUCTIVE PHENOMENA AFFECTING THE PHENOMENA AFFECTING THE PLANT (CONTINUE TO NEXT PAGE)

PROTECTED AREA (ED 74) (CONTINUE TO NEXT PAGE)

VITAL AREA (BD 79)

OPERATING MODE: All OPERATING MODE: All A. Tremor felt and seismic trigger actuates (O.05g)

A. Tremor felt and valid alarm on the strong motion accelero graph NOTE: Only one train of a safety-related B Tornado striking within Pro tected Area system needs to be affected or damaged in Boundary order to satisf these conditions.

C. Vehicle crash into plant structures/systems B. Tornado, high winds, missiles resulting from within the Protected Area Boundary turbine failure, vehicle crashes, or other catastrophic event.

D. Turbine failure resulting in casing penetration or damage to turbine or generator seals AND B. I Visible damage to permanent (CONTINUED) structures or equipment required for safe shutdown of the unit.

OR B.2 Affected safety system parameter indications show degraded performance.

(CONTINUED) 17

Enclosure 4.7 RP/O/B/1000/OO1 Natural Disasters, Hazards and Other Conditions Affecting Plant Safety Page 2 of 3 UNUSUAL EVENT ALERT SITE AREA EMERGENCY GENERAL EMERGENCY

2. NATURAL AND DESTRUCTIVE 2. RELEASE OF TOXIC/FLAMMABLE I. CONTROL ROOM EVACUATION AND PHENOMENA AFFECTING KEOWEE GASES JEOPARDIZING SYSTEMS PLANT CONTROL CANNOT BE HYDRO CONDITION B (BD 75) REQUIRED TO MAINTAIN SAFE ESTABLISHED (BD 85)

OPERATION OR ESTABLISH! (CONTINUE TO NEXT PAGE)

OPERATING MODE: All MAINTAIN COLD SHUTDOWN (BD 81)

A. Reservoir elevation 807.0 feet with all OPERATING MODE: All OPERATING MODE: All spiliway gates open and the lake elevation A. Report/detection of toxic gases in Continues to rise concentrations that will be life-threatening to plant personnel A. 1 Control Room evacuation has been initiated B. Seepage readings increase or decrease greatly or seepage Water is carrying a significant B. Report/detection of flammable gases in AND amount of soil particles concentrations that will affect the safe operation of the plant: A2 Control of the plant cannot be established from C New area of seepage or wetness, with large

Reactor Building the Aux Shutdown Panel or the SSF within 15 amounts of seepage water observed on dam,

Auxiliary Building minutes dam toe, or the abutments

Turbine Building

Control Room D. Slide or other movement of the dam or 2. ICEO WEE HYDRO DAM FAILURE abutments which could develop into a failure (RD 86)

3. TURBINE BUILDING FLOOD (BD 82)

E. Developing failure involving the powerhouse or OPERATING MODE: All appurtenant structures and the operator believes thc safety of the structure is questionable A. Imminent/actual dam failure exists involving OPERATING MODE: All any of the following:

A. Turbine Building flood requiring use of

Keowee Hydro Dam

3. NATURAL AND DESTRUCTIVE AP!I,2,3/A1l700/l0, (Turbine Building Flood)

Little River Dam PHENOMENA AFFECTING JOCASSEE

Dikes A, B, C, or D HYDRO CONDITION B (RD 76)

Intake Canal Dike

4. CONTROL ROOM EVACUATION HAS

Jocassee Dam Condition A

-

BEEN INITIATED (BD 83)

OPERATING MODE: All (CONTINUED)

A. Condition B has been declared for the Jocassee OPERATING MODE: All Dam A.l Evacuation of Control Room (CONTINUED) AND ONE OF THE FOLLOWING:

AND A. 1.1 Plant control IS established from the Aux shutdown Panel or the SSF A. 1.2 Plant control IS BEING established from the Aux Shutdown Panel or SSF (CONTINUED) 18

Enclosure 4.7 RP/O/B/1000/OO1 Natural Disasters, Hazards and Other Conditions Affecting Plant Safety Page 3 of 3 UNUSUAL EVENT 4 RELEASE OF TOXIC OR FLAMMABLE GASES DEEMED DETRIMENTAL TO SAFE 5.

ALERT OTHER CONDITIONS WARRANT CLASSIFICATION OF AN ALERT j 3.

SITE AREA EMERGENCY OTHER CONDITIONS WRRANT

[ I.

GENERAL EMERGENCY OTHER CONDITIONS WARRANT DECLARATION OF SITE AREA DECLARATION OF GENERAL OPERATION OF THE PLANT (BD 77) (BD 84) EMERGENCY (RD 87) EMERGENCY (BD 88)

OPERATING MODE: All OPERATING MODE: All OPERATING MODE: All OPERATING MODE: All A. Report/detection of toxic or flammable gases A. I Emergency Coordinator judgment indicates A. Emergency Coordinator/EOF Director A. 1 Emergency Coordinator/EOF Director that could enter within the site area boundary in that:

judgment judgment indicates:

amounts that can affect normal operation of the plant A. 1. 1 Plant safety may be degraded A. 1.1 Actual/imminent substantial core (END) degradation with potential for loss of B. Report by local, county, state officials for Ai containment potential evacuation of site personnel based on offsite event A.I.2 Increased monitoring of plant functions OR is warranted A. 1.2 Potential for uncontrolled (END) radionuclide releases that would

5. OTHER CONDITIONS EXIST WHICH result in a dose projection at the WARRANT DECLARATION OF AN site boundary greater than 1000 mRem UNUSUAL EVENT (BD 78) TEDE or 5000 mRem CDE Adult Thyroid OPERATING MODE: All (END)

A. Emergency Coordinator determines potential degradation of level of safety has occurred (END) 19

Enclosure 4.8 Rp/0/B/1 000/001 Radiation Monitor Readings for Emergency Classification Page 1 of 1 All RIA values are considered GREATER THAN or EQUAL TO J

HOURS SINCE RIA 57 RIhr RIA 58 RIhr*

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 1.1E+003 1.IE+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

-

4.4E+003

RIA 58 is partially shielded 20

Enclosure 4.9 RP/0/B/l000/00l Unexpected/Unplanned Increase In Area Monitor Readings 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 mRADIHR mRAD/HR RIA 7, Hot Machine Shop Elevation 796 150 RIA 8, Hot Chemistry Lab 5000 Elevation 796 4200 5000 RIA 10, Primary Sample Hood Elevation 796 830 5000 RIA 11, Change Room Elevation 796 210 5000 RIA 12, Chem Mix Tank Elevation 783 800 5000 RIA 13, Waste Disposal Sink Elevation 771 650 5000 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 mRadlhr just for an Unusual Event. For this reason, an Unusual Event will NOT be declared for a reading less than 5000 mRadlhr.

21

Enclosure 4.10 RP/0/B/l000/00l Definitions/Acronyms Page 1 of 5

1. List of Definitions and Acronyms 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 or a security event that involves probable life threatening risk to site personnel or damage to site equipment because of HOSTILE ACTION. Any releases are expected to be limited to small fractions of the EPA Protective Action Guideline exposure levels.

1.2 BOMB Refers to an explosive device suspected of having sufficient force to damage plant

systems or structures.

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 persons violently protesting station operations or

-

activities at the site.

1.6 EXPLOSION A rapid, violent, unconfined combustion, or catastrophic failure of

-

pressurizedlenergized equipment that imparts energy of sufficient force to potentially damage permanent structures, systems, or components.

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

-

1.8 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.

1.9 FRESHLY OFF-LOADED CORE The complete removal and relocation of all fuel

-

assemblies from the reactor core and placed in the spent fuel pool. (Typical of a No Mode operation during a refuel outage that allows safety system maintenance to occur and results in maximum decay heat load in the spent fuel pool system).

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 or HOSTILE ACTION that results in an actual loss of physical control of the facility.

Releases can be reasonably expected to exceed EPA Protective Action Guidelines exposure levels outside the Exclusion Area Boundary.

1.11 HOSTAGE A person(s) held as leverage against the station to ensure demands will be met

-

by the station.

22

Enclosure 4.10 RP/O/B/1000/OO1 Definitions/Acronyms Page 2 of 5 1.12 HOSTILE ACTION An act toward an NPP or its personnel that includes the use of violent

-

force to destroy equipment, takes HOSTAGES, andlor intimidates the licensee to achieve an end. This includes attack by air, land, or water using guns, explosives, PROJECTILES, vehicles, or other devices used to deliver destructive force. Other acts that satisfy the overall intent may be included. HOSTILE ACTION should not be construed to include acts of civil disobedience or felonious acts that are not part of a concerted attack on the NPP. Non-terrorism-based EALs should be used to address such activities, (e.g., violent acts between individuals in the owner controlled area.)

1.13 HOSTILE FORCE One or more individuals who are engaged in a determined assault,

-

overtly or by stealth and deception, equipped with suitable weapons capable of killing, maiming, or causing destruction.

1.14 IMMINENT Mitigation actions have been ineffective, additional actions are not expected to

-

be successful, and trended information indicates that the event or condition will occur. Where IMMINENT timeframes are specified, they shall apply.

1.15 INTRUSION A person(s) present in a specified area without authorization. Discovery of a

BOMB in a specified area is indication of INTRUSION into that area by a HOSTILE FORCE.

1.16 INABILITY TO DIRECTLY MONITOR Operational Aid Computer data points are

-

unavailable or gauges/panel indications are NOT readily available to the operator.

1.17 LOSS OF POWER Emergency Action Levels (EAL5) apply to the ability of electrical

energy to perform its intended function, reach its intended equipment. Ex. If both MFBs,

are energized but all 41 60v 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.

1.18 PROJECTILE An object directed toward a NPP that could cause concern for its continued

operability, reliability, or personnel safety.

1.19 PROTECTED AREA Typically the site specific area which normally encompasses all

controlled areas within the security PROTECTED AREA fence.

23

Enclosure 4.10 RP/0/B/1000/001 Definitions/Acronyms Page 3 of 5 1.20 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): 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 primary to secondary LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall or vessel wall.

1.21 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.

1.22 SABOTAGE Deliberate damage, mis-alignment, or mis-operation of plant equipment with

-

the intent to render the equipment inoperable. Equipment found tampered with or damaged due to malicious mischief may not meet the definition of SABOTAGE until this determination is made by security supervision.

1.23 SECURITY CONDITION Any Security Event as listed in the approved security

contingency plan that constitutes a threat/compromise to site security, threat/risk to site personnel, or a potential degradation to the level of safety of the plant. A SECURITY CONDITION does not involve a HOSTILE ACTION.

1.24 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.

24

Enclosure 4.10 RP/0/B/1000/001 Definitions/Acronyms Page 4 of 5 1.25 SELECTED LICENSEE COMMITMENT (SLC) -Chapter 16 of the FSAR 1.26 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 1.27 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, or HOSTILE ACTION that results in intentional damage or malicious act; (1) toward site personnel or equipment that could lead to the likely failure of or; (2) that prevents effective access to equipment 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.

1.28 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).\

1.29 TOXIC GAS A gas that is dangerous to life or health by reason of inhalation or skin contact

-

(e.g.; Chlorine).

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

1.31 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.

1.32 UNUSUAL EVENT Events are in process or have occurred which indicate a potential

-

degradation of the level of safety of the plant or indicate a security threat to facility protection has been initiated. No releases of radioactive material requiring offsite response or monitoring are expected unless further degradation of safety systems occurs.

1.33 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 instruments operability, the conditions existence, or the reports accuracy is removed. Implicit with this definition is the need for timely assessment.

25

Enclosure 4.10 RP/O/B/l000/OOl Definitions/Acronyms Page 5 of 5 1.34 VIOLENT Force has been used in an attempt to injure site personnel or damage plant

-

property.

1.35 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.

1.36 VITAL AREA An area within the protected area where an individual is required to badge in

-

to gain access to the area and that houses equipment important for nuclear safety. The failure or destruction of this equipment could directly or indirectly endanger the public health and safety by exposure to radiation.

26

Enclosure 4.11 /O/B/looo/oo1 Operating Modes Defined In Improved Page 1 of 1 Technical Specifications MODES REACTIVITY % RATED AVERAGE CONDITION THERMAL REACTOR COOLANT MODE TITLE POWER (a) TEMPERATURE (cii) (°F)

I Power Operation 0.99 > 5 NA 2 Startup 0.99 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 27

Enclosure 4.12 RP/O/B/l000lool Instructions For Using Enclosure 4.1 Page 1 of 2

1. Instructions For Using Enclosure 4.1 Fission Product Barrier Matrix 1.1 If the unit was at Hot SID 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.

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 hours0.125 days 0.0179 weeks 0.00411 months ). 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.

28

Enclosure 4.12 RP!OIB/l000/ool Instructions For Using Enclosure 4.1 Page 2 of 2 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 S/G tubes.

RCS leakage through the S/G 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 normal 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.

29

Enclosure 4.13 /O/B/1ooo/oo1 References Page 1 of 1

References:

1. PIP 0-05-02980

2. PIP 0-05-4697

3. PIP 0-06-0404

4. PIP 0-06-03347

5. PIP 0-09-00234

6. PIP 0-10-1055

7. PIP 0-10-01750 30

I //Q3 ?2NU2O VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Duke fEnergy NUCLEAR POLICY MANUAL Nuclear System Directive: 202. Reportability Process/Program Owner: Regulatory Compliance Managers BEST REVISION NUMBER ISSUE DATE 0 11/01/92 1 02/28/94 2 06/09/94 3 08/22/94 4 12/12/94 5 06/14/95 6 06/13/96 7 03/12/97 8 06/16/97 9 06/16/98 10 12/20/98 11 04/30/99 12 02/23/00 13 12/28/00 14 01/23/01 15 11/13/01 16 01/27/03 17 05/03/04 18 02/08/05 19 07/21/05 20 11/30/05 21 11/28/06 CATAWBA MCGUIRE OCONEE Approved By/Date Approved By/Date Approved By/Date RD. Hart/I 1-08-06 C.J. Thomas/i 1-08-06 B.G. Davenport/I 1-08-06 Regulatory Compliance Regulatory Compliance Regulatory Compliance Manager Manager Manager Effective Date: Effective Date: Effective Date:

11/28/06 11/28/06 11/28/06 Issued By: R.L. Gill, Jr.

Manager, Nuclear Regulatory Issues & Industry Affairs VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2

II VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2

NSD 202 DOCUMENT REVISION DESCRIPTION REVISION NO. PAGES or SECTIONS REVISED AND DESCRIPTION 10 Section 202.3 is being revised to reflect the approved version of NUREG 1022, Rev. I.

Section 202.6.1 is being revised to reflect changes made by the NRC to Part 21.

Section 202.7.1, reportable example a and b are being revised to reflect implementation of the ITS at MNS.

Section 202.7.2 is being revised to include information on the reportability policy regarding missed ASME Section XI required visual inspections after maintenance, to reflect a new philosophy concerning plants that have a delay of up to 24 hours1 days 0.143 weeks 0.0329 months in declari ng an LCO or Tech Spec not being met (this philosophy resulted from the approval by the NRC of NUREG 1022, Rev. 1), to reflect new ITS section numbers for MNS, deletion of non-re portable example j and a new example concerning multiple test failures was added under the Repo rtable Examples.

Section 202.8.2 is being revised to add a Non-Reportable example regard ing Oconees Emergency Feedwater system.

Section 202.10 is being revised to add Fire Protection Program reporti ng information and more guidance on the reporting of Tech Spec Safety Limits violation.

Appendix A, item #12 is being revised to reflect the new ITS section numbe r for MNS.

11 Revised Section 202.4, entitled it, Roles and Responsibilities and renum bered remaining sections of NSD. Revised Section 202.6.4 to reflect that Tech Spec 3.03 is generic to all three sites. This is due to the implementation of the ITS. Added guidance on Past Operability in Section 202.6.4.1. Section 202.7.2 was also revised to reflect that Tech Spec 3.0.3 applies to all three sites. This is due to the implementation of the ITS at all three sites.

Example e was also revised to reflect to pressurizer heatup and cooldown rates no longer being in Tech Specs and Tech Specs no longer requiring DIG Special Reports. Items k and d were reused. Section 202.7.3 was revised to clarify what is considered a deviation and Report able example b was deleted. Section 202.7.4, item, #2 was revised to reflect renumbering of NSD sections. Section 202.8.1 was revised to reflect the new CNS ITS numbers governing tube plugging and examples that referenced these sections were also revised. Section 202.10

, Tech Spec Safety Limit, was revised to reflect the change from 14 to 30 days for the submis sion of a written report. This is due to the implementation of the ITS. Throughout the directive, TS was changed to Tech Spec.

12 Revised Section 202.6.4.1, 6 th paragraph, inserted the phrase have to in the discussion How far back do I look; inserted the phrase is generally sufficient in place ofago in the sentence; added the phrase however, is there is reason to believe that the SSC was inoperable

deleted the sentence addressing an exception at the end of the l sentence, replacing it with the phrase or until an inoperability in excess of the Tech Spec CT is discovered; replaced the phrase are not appropriate with are not necessary in the last senten ce of the paragraph.

13 NSD 202 is being revised in its entirety due to changes to 10 CFR 50.72 and 50.73. 10 CFR 50.73 reports are now required to be submitted within 60 days. The follow ing sections are affected by this revision:

TOC: The TOC was revised to reflect the new section numbering based on criteria being deleted/added.

Section 202.2 (Purpose) is being revised to reflect the new eight hour reporting requirement.

Section 202.3 (References) was revised to reflect approval of NURE G 1022, NSD 201 was added and the BWR Owners Group LERJJCO Committee Conso lidated Event Reporting Guidance document was deleted due to the approval of NUREG 1022, which is the primary III VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2

REVISION NO. PAGES or SECTIONS REVISED AND DESCRIPTION guidance document.

Table 202-1 was added to enhance the user-friendliness of the directive.

Section 202.5 (General Considerations) was revised to add NSD 201 as an additio nal reporting references.

Section 202.6.1 (Part 21 Reporting) was revised for clarification.

Section 202.6.3 (Emergency Notification System Reporting) was revised to reflect the new 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months reporting requirement.

Section 202.6.3.2 (Reporting Multiple Events in a Single Report) was added for clarification of 60 day LER reporting.

Section 202.6.3.4 (ENS Notification Retractions) was revised due to PIP 0-99-03952.

Section 202.6.4 (Specific Reporting Guidance to 50.72 and 50.73) was revised to delete the requirement to make an ENS notification upon entry into Tech Spec 3.0.3.

Section 202.6.4.1 (Past Operability Determinations) was renamed Evalu ations in Support of Reportability and clarification was added to this section to assist the user in making these determinations.

Section 202.8.1 (Plant Shutdown Required by Technical Specifications) was deleted from the 1-hour reporting requirement and added to the 4-hour reporting requirement.

Section 202.9 (8-hour ENS Notifications and LERs) was revised to reflect the new 8-hour reporting requirement and the reports that are reported under this require ment.

Section 202.9.1 (Technical Specification Prohibited Operation or Condit ion) was revised to reflect that entry into Tech Spec 3.0.3 is not necessarily reportable and missed surveillances are reportable when the equipment is tested and found to be inoperable. Missed surveillances are also reportable when there is a programmatic breakdown (a reportable examp le was added to assist with this interpretation). Clarifying information was also added to the reporting requirement. Examples for this section was revised to reflect the change s in reporting.

Section 202.9.2 (Degraded or Unanalyzed Condition) was revised to reflect deletion of the Outside Design Bases and Conditions not covered by the plants operati ng and emergency procedures. The operating and shutdown qualifiers for this criterio n was also deleted.

Additionally, examples were revised to reflect these deletions.

Section 202.9.3 (Natural Phenomenon or Condition Threatening Safety (Extern al Threat)) was revised by deleting the ENS reporting requirement. Examples were revise to reflect this deletion.

Section 202.9.4 (Loss of Emergency assessment, Response, or Comm unications) was revised to add clarification regarding what constitutes a major loss of communicatio n capability.

Section 202.9.5 (Internal Threat to Plant Safety) was revised by deletin g the ENS reporting requirement. Examples were revised to reflect the deletion.

Section 202.9.6 (System Actuations) was revised by deleting the referen ces to ESFs and instead, the NRC provided a list of systems that are to be reporte d RPS actuations when the

.

Reactor is critical are still 4-hour notifications; however, all other RPS actuations are to be made within 8-hours. Invalid system actuations are reportable per an LER only. Examples and Appendix A were revised to reflect these changes.

Section 202.9.7 (Event or Condition that Could have Prevented the Fulfill ment of a Safety Function) was revised to remove the term alone and the ENS notific ation requirement was revised to duplicate the LER reporting requirement. Clarifying inform ation was also added to iv VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2

NSD 202 REVISION NO. PAGES or SECTIONS REVISED AND DESCRIPTION this section to assist the user in making reportability determinations. Examp les were revised accordingly.

Section 202.9.9 (Airborne or Liquid Effluent Release exceeding Appen dix B) was revised to delete the ENS reporting requirement.

Section 202.9.11 (Single Cause that could have Prevented Fulfillment of the Safety Functions of Trains or Channels in Different Systems) is a new reporting requirement.

Section 202.10 (Followup Notification) was clarified.

Section 202.11 (Other Events Requiring Immediate Notification) was revised by deleting the reports of Loss of one working week or more of the operation of any unit and Damage to property in excess of $200,000). These two reporting requirements were required by Dukes Nuclear Insurer (NEIL) and they are no longer required per NEIL. The Basis

/Background for Engineered Safety Features and Associated Systems was deleted since this information is obsolete.

14 202.9.4: Changed 50.72(b)(1)(v) to 50.72(b)(3)(xiii) 202.9.7: Changed 50.72(b)(2)(iii) to 50.72(b)(3)(v) 202.9.10: Changed 50.72(b)(2)(v) to 50.72(b)(3)(xii) 15 Section 202.2 (Purpose) is being revised to indicate limited reporting of 10 CFR 20 events.

Section 202.4.3 (Engineering) is being revised to define SSC and typos were corrected.

Additionally, any references to Past Operability Evaluations were change d to Engineering Evaluations. This change is also applicable to Sections 202.6.3.1 and 202.6.

4.1. Section 202.7.1 is being revised for clarity. Section 202.9.1 is being revised to remov e the statement regarding missed surveillances being reportable due to programatic breakd owns. Example g in this section is being removed to reflect this change. Section 202.9.6 (Syste m Actuations),

example d is being revised to change spurious to invalid in order to be more in-line with industry terminology, example f is being revised to add clarification for ONS in relation to actuations of the EFW with regards to the Steam Generator Dry-out Protec tion circuit.

Additionally, clarification is added to this section in relation to VALID signals versus instrument drift or mis-calibration. Section 202.9.9 is being revised to remov e the reference to Part 20.2202. The reporting requirements are in Part 20.2203. Section 202.11 is being revised to add ONS to the S/G Tube Plugging requirement. Appendix A is being revised to add the ONS actuation signals to the Containment Isolation Systems, to delete the Hydrogen Igniters from item #3, Combustible Gas Control in Containment. Additi onally, in item #5, Auxiliary/Emergency Feedwater System, the tornado pump was re-nam ed the Station- ASW pump.

16 Section 202.3: Added NT.JREG-302, Rev. 1 and a Regulatory Position on the Reportability Requirements for a Single Train System Section 202.6.1: This section is being updated based on guidance provid ed in NUREG 302.

Revised to correctly reflect regulatory requirements for the comple tion of evaluations of deviations and failures to comply, and the regulatory guidance provid ed by NUREG-302, Rev.

1. (PIP #G-02-00291).

Section 202 .9.4: Revised this section and associated examples to reflect that Duke no longer uses the FTS-2000 telecommunication system and added clarification to the Loss of Offsite Response Capability section that emphasized the lost capability to alert a large segment of the population for more than an hour would warrant an immediate notific ation.

Section 202.9.6: In the section relative to Valid signals the word not had been omitted.

Section 202.9.7: Added guidance to this section to clarif when reporti ng of single-train V

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2

REVISION NO. PAGES or SECTIONS REVISED AND DESCRIPTION systems is required. This guidance is based on information provided in the Regula tory Position on the Reportability Requirements for a Single Train System.

Appendix A: Added Essential or Non-Essential Isolation to item #1 for clarific ation.

17 Section 202.3: Part 21 was deleted from this section and added the Federa l Register Notice that amended 10 CFR 72 Event Notification Requirements; Section 202.5: Deleted Part 21 from this section; Section 202.6.1: Deleted the Part 21 guidance from this section and referen ced the new Part 21 directive (NSD 229);

Section 202.12: Revised the reporting requirements for 10 CFR 72.75 based on Event Notification Requirements Rule revision Table 202-1: Deleted the 50.73 reporting requirement for the transport ofa contam inated person and added the 50.72 reporting requirement. There is not a 50.73 reporting requirement associated with this criteria.

18 Section 202.9.2: Added a reportable example regarding serious degradation of Steam generator tubes based on clarification published in the errata to NUREG 1022, Revisi on 2.

Section 202.9.7: Deleted the reportable example regarding both trains of the VC system being inoperable based on new guidance provided by the NRC. Reference PIP

C-04-05549.

19 Change made to table 202-1 to correct the entry on transport of a contam inated person to be 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months (mistakenly placed in the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months column in the previous revision).

20 Section 202.8.4.2: Corrected the spelling of raised under item h (non-re portable examples, last line).

Section 202.9.6: Added clarification regarding which signals are includ ed in general containment isolation signals. Reference PIP M-03-05 104 Section 202.9.7: Moved this section heading to the next page Section 202.9.11: Corrected the spelling of reasonable under item a (Reportable Examples, second paragraph, sixth line down).

21 Section 202.8.4: Added clarifying information regarding formal and informal communications with local, state and other federal agencies with respect to notification to the NRC.

Additionally, reformatted this section for clarity.

Section 202.9.1: Added clarifying information to this section in response to a condition that occurred at MNS (reference PIP M-06-3281). Additionally, a Non-R eportable example k was added for clarification.

Section 202.9.2: Information regarding the Fire Protection Program was removed from Section 202.11 and added to this section based on approved Amendments 230/22 6.

Section 202.9.6 Clarified Reportable Examples section by adding to the NOTE that precedes the examples that you are to assume that actuations are the result of Valid signals. Under Reportable Example d, removed valid or invalid. Editorial change s were made to Reportable Examples f, g, j and k.

Section 202.12: Revised this section to expand ISFSI reporting to all three sites.

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NSD 202 Table Of Contents 202. REPORTABILITY 1

2

02.1 INTRODUCTION

202.2 I PURPOSE 202.3 1 REFERENCES 202.4 1 ROLES AND RESPONSIBILITIES 202.4.1 3 OPERATIONS 202.4.2 3 REGULATORY COMPLIANCE 202.4.3 3 ENGINEERING 202.5 3 GENERAL CONSIDERATIONS 202.6 3 SPECIFIC GUIDANCE 202.6.1 4 PART 21 REPORTING 202.6.2 4 IOCFR 50.9 REPORTING 202.6.3 4 EMERGENCY NOTIFICATION SYSTEMREPORTING 202.6.4 5 SPECIFIC REPORTING GUIDANCE TO 50.72 AND 50.73 202.7 I-HOUR ENS NOTIFICATIONS AND LERS 6 202.7.1 7 TECH SPEC DE VIA TION PER IOCFR 50.54(X) 202.8 7 4-HOUR ENS NOTIFICATIONS AND LERS 202.8.1 8 PLANTSHUTDOWNREQUIRED BY TECHNICAL SPECIFICATIONS 202.8.2 8 ECCS DISCHARGE INTO THE REA CTOR COOLANT SYSTEM 202.8.3 9 REA CTOR PROTECTION SYSTEM ACTUATION 202.8.4 10 NEWS RELEASE OR OTHER GOVERNMENTNOTIFICA TIONS 202.9 10 8-HOUR ENS NOTIFICATIONS AND LERS 202.9.1 13 TECHNICAL SPECIFICATION PROHIBITED OPERATION OR CONDITION 202.9.2 13 DEGRADED OR UNANALYZED CONDITION 202.9.3 16 NA TURAL PHENOMENON OR CONDITION THREA TENING PLANT SAFETY (EXTERNAL THREAT) 202.9.4 19 LOSS OF EMERGENCYASSESSMENT RESPONSE, OR COMMUNICATIONS 202.9.5 20 JNTERNAL THREAT TO PLANTSAFETY 202.9.6 21 SYSTEMACTUATIONS 202.9.7 22 EVENT OR CONDITION THAT COULD HAVE PREVENTED THE FULFILLME NT OF SAFETYFUNCTIONOFSYSTEMS OR STRUCTURES 202.9.8 COMMON-MODE FAILURES OF INDEPENDENT TRAINS OR CHANNELS 26 202.9.9 28 AIRBORNE OR LIQUID EFFLUENT RELEASE EXCEEDING 20 TIMES APPEND IXB 29 202.9.10 CONTAMINATED PERSON REQUIRING TRANSPORT TO OFFSITE MEDICAL FACILITY 30 202.9.11 SINGLE CA USE THAT COULD HAVE PREVENTED FULFILLMENT OF THE SAFETY FUNCTIONS OF TRAINS OR CHANNELS INDIFFERENT SYSTEMS 30 202.10 FOLLOWUP NOTIFICATION 202.11 OTHER EVENTS REQUIRING IMMEDIATE NOTIFICATION 35 202.12 INDEPENDENT SPENT FUEL STORAGE INSTALLATION (ISFSI) 35 REPORTING REQUIREMENTS 36 APPENDIX A. 202. SYSTEM ACTUATIONS 39 vu VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

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NSD 202 List Of Tables TABLE 202-I REPORTABLE EVENTS 2 ix VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

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202. REPORTABILITY 2

02.1 INTRODUCTION

The NRCs regulations set forth in Title 10, Chapter 1, Code of Federal Regula tions requires the reporting of various events or conditions in connection with licensee activities. This directive is presented to ensure nuclear station compliance and consistency with the reporting regulations of the 1 OCFR.

202.2 PURPOSE The purpose of the directive is to provide guidance for use in determining reporta bility of station events or conditions under the provisions of the Immediate Notification Requirements of Significant Events (IOCFR 50.72),

the Licensee Event Reporting System (10CFR 50.73), IOCFR Part 21, Report ing of Defects and Noncompliance, 1 OCFR 50.9, Completeness and Accuracy of Information, to ensure proper and consistent reporting. Security event notifications are addressed in the Duke Nuclear Security Manual, a limited number of 10CFR 20 radiological notification requirements and 10CFR 72, ISFSI, notification requirements are included in the NSD. For Part 50.72 reporting, this directive only addresses [50.72(b)] one/four/eight hour notific ations for non-emergency events, since adequate guidance currently exists in each stations Emergency Plans implem enting response procedures for emergency events [50.72(a)] and their classifications.

2

02.3 REFERENCES

1. 10 Code of Federal Regulations 50.72, 50.73, Part 20,72 and 50.9

2. Federal Register; Vol. 48, No. 144 and 168; July 26, 1983/August 29, 1983; Licensee Report System and Immediate Notification Requirements of Significant Events; final rule

3. NUREG 1397, Feb. 91, An Assessment of Design Control Practices and Design Reconstitution Practices in the Nuclear Industry

4. Generic Letter 91-18, Operable/Operability: Ensuring the Functional Capab ility of a System or Component

5. Standard Review Plan (NUREG 800)

6. Federal Register (56 FR 36081); July 31, 1991; 10 Code ofFederal Regula tions Parts 21 and 50.55(e)

7. NUREG 1022, Revision 2.

8. NSD 201 (Reporting Requirements)

9. NUREG-0302, Rev. 1

10. Regulatory Position on the Reportability Requirements for a Single Train System, dated June 28, 2002

11. Federal Register; Vol 68, No. 108; June 5,2003; 10 CFR Parts 72 and 73, Events Notification Requirements; final rule REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 Event or Condition ENS notification within ENS notification ENS notification 60-day LER NSD 202 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months within 4 hours0.167 days 0.0238 weeks 0.00548 months within 8 hours0.333 days 0.0476 weeks 0.011 months Section Deviation from Tech Deviation from TS Specs Authorized under § 50.73 (a)(2)(i)(c) 202.7.1 authorized by 50,54 (x) 50.54 (a) [50.72 (b)(l)J Plant shutdown (SID) Initiation of S/D required required by Tech Specs Completion of a S/D 202.8.1 by Tech Specs [50.72 required by Tech Specs (b)(2)(i)) [50.73 (a)(2)(i)(A)

Operation or Condition Prohibited by Tech Specs 50.73 (a)(2)(i)(b) 202.9.1 Degraded or Unanalyzed 50.72 (b)(3)(ii) 50.73 (a)(2)(ii) 202.9.2 Condition External Threat or Hampering 50.73 (a)(2)(iii) 202.9.3 System Actuationn Valid ECCS discharges 50.73 (a)(2)(iv)(A) 202.8.2 into Reactor Coolant system [50.72 (b)(2)(iv)(A)]

RPS Actaations when Reactor is critical [50.72 202 8 3 (b)(2)(iv)(B)J Valid actuation of NRC 202,9.6 listed systems Event or Condition that 50.72 (b)(3)(v) 50,73 (a)(2)(v) 202.9.7 could have prevented fulfillment of a safety 50.72 (b)(3)(vi) 50.73 (a)(2)(vi) function Common Cause lnoperability of 50.73 (a)(2)(vii) 202.9.8 independent trains or channels Radioactive Releases Airborne radioactive 202.9.9 release [50.73 (a)(2)(viii)(A)[

Liquid Effluent release

[50.73 (a)(2)(viii)(B)J Internal Threat or Hampering 50.73 (a)(2)(x) 202.9.5 Transport of a 50.72 (b)(3)(xii) 202.9.10 Contaminated Person Offsite News Release or 50,72 (b)(2)(xi)

Notification of other 202.8.4 Government Agency Loss of Emergency 50.72 (b)(3)(xiii) 202,9.4 Preparedness Capabilities Single Cause that could have prevented fulfillment 50.73 (a)(2)(ix)(A) 202.9.11 of the Safety Functions of 50.73 2(a)(

) (ix)(B) trains or channels in different systems Table 202-1 Reportable Events 2

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VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 202.4 ROLES AND RESPONSIBILITIES 202.4.1 OPERATIONS

1. Responsible for reportability timeliness

2. Makes reportability determination (i.e., knowledgeable of issue, performs reasonableness review, ensures license requirements are met)

3. Makes notification to NRC and other required parties (Note: Regulatory Compliance may perform this function for some issues: e.g., design basis issues)

4. Ensures license and NRC requirements are met 202.4.2 REGULATORY COMPLIANCE

1. Reviews PIPs on front end (screening meeting) for potential reportability issues; follows up on screened PIPS that are unclear with respect to reportability

2. Independently assures timeliness is in accordance with NRC requirements

3. Provides lead role in making reportability recommendations to Operations Shift Manager (OSM) (For engineering related reportability evaluations, works closely with engineering to ensure the right questions are being asked and performs QV & V to ensure licensing basis assumptions are valid and proper)

4. Notifies OSM immediately when sufficient evidence exists that indicates an item is reportable

5. Provides support to the OSM as needed for NRC notification (may make NRC notification for some issues: e.g.,

design basis issues)

6. Ensures NSD conformance with NRC requirements

7. Ensures process is implemented in accordance with NSD 202.4.3 ENGINEERING

1. Notifies OSM and Regulatory Compliance immediately when sufficient evidence exists that indicates an item is reportable. (Note: Engineering scope for reportability also includes SSC (Structure, System, Subsystem, Component or Device) engineering evaluations (50.72 and 50.73), and Part 21 evaluations)

2. Keeps OSM and Regulatory Compliance informed of status of reportability evaluation and timeline to complete

3. Ensures engineering analysis and calculations assure SSCs can perform required functions

4. Determines if component failures meet 10 CFR 21 reporting criteria 202.5 GENERAL CONSIDERATIONS Guidance is presented in this directive in order to ensure nuclear station compliance and consistency with the reporting regulations of 10CFR 50.72, 50.73, and 50.9. Other routine reports are outlined in NSD 201 (Reporting Requirements). Additionally, refer to NSD 201 when evaluating for reportability.

The purpose of the emergency notification requirements in 10CFR 50.72 is to inform the NRC of deficient conditions or events that have immediate safety significance or that may require NRC awareness or action in response to potential public interest. The purpose of the LER Rule in IOCFR 50.73 is to identif the types of deficient conditions or events that are significant to the NRC so that the NRC may perform engineering studies of REVISION 21 3 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 operational anomalies, trends and pattern analyses of operational occurrences. In general, many of the conditions and events that require immediate notification will also require an LER, as is reflected by the many parallel requirements specified in 50.72 and 50.73. Therefore, the event reporting guidance is arranged in the sequence of the Emergency Notification Rule, along with the corresponding sections of the LER Rule.

In some cases, such as discovery of an existing but previously unrecognized condition, it may be necessary to undertake an evaluation to determine if an event or condition is reportable. An evaluation should generally proceed on a schedule commensurate with the safety significance of the question. Plant operation may continue provided there is reasonable expectation that the equipment in question is operable. Whenever this reasonable expectation no longer exists, or significant doubts begin to arise, the equipment should be considered inoperable and appropriate actions, including reporting, should be taken promptly (Refer to NSD 203, Operability for more guidance on operable/inoperable equipment).

In evaluating a potentially reportable item, this document should be reviewed to identify all possible sections of the event reporting rules that might be applicable. It should be noted that an item can be reportable under several criteria and, in accordance with 50.72 and 50.73, a reportable item must be reported under all applicable criteria. In this directive, an example in a specific section is only evaluated for reportability under that specific criterion. In actual application, that same example might be reportable under other criteria. For ENS calls, the report should be made in accordance with the most stringent criterion that applies in order to fulfill all 50.72 requirements (e.g. an event that falls under a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months notification should be reported within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , which also satisfies the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months requirement). For LERs that are reportable under more than 1 criterion, all applicable blocks should be marked on the LER form.

202.6 SPECIFIC GUIDANCE 202.6.1 PART 21 REPORTING NOTE: Part 21 Reporting guidance has been relocated to NSD 229 (Evaluation and Reporting of Potential Defects and Non-compliance).

202.6.2 IOCFR 50.9 REPORTING The stated intent for 10CFR 50.9(a) is that information provided to the NRC be complete and accurate in all material respects. Sections 50.72 and 50.73 contain provisions for updating and revising reports that should be used to correct material incompleteness or inaccuracies that are discovered. For example, submitting a revised LER would be appropriate to correct any previously submitted inaccuracies of a material nature.

10CFR 50.9(b) states that any licensee information with significant public health and safety, or common defense and security implications be reported to the NRC, except where a specific reporting requirement exists. The Statements of Consideration for 50.9 refer to such information as residual information that could affect licensed activities.

The provisions of 50.9 should not be used to report information that is required to be reported under other reporting rules such as 50.72, 50.73, and Part 21.

If a condition is determined to be reportable under Part 50.9, the station shall notify the Region within 2 working days of the discovery of the information. A special report shall be written and submitted to the Region within 30 days of discovery of the event. The report should contain all relevant information pertaining to the circumstance s

involved, as well as, any planned corrective actions to be taken to prevent recurrence.

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NSD 202 202.6.3 EMERGENCY NOTIFICATION SYSTEM REPORTING 202.6.3.1 Reporting Timeliness The timing for ENS reporting is described in 10CFR 50.72 as immediate and as soon as practical and in all cases within one! four/eight hour(s) of the occurrence of an event (depending on its significance)

. The intent is to require reportability decisions to be made in a timely manner so that ENS notifications are made to the NRC as soon as practical, keeping in mind the safety of the plant comes first. The event reportability time clock generally starts at the time of the event or the discovery of the condition. For example, the reportability time clock would start at the time of a Reactor trip or initiation of plant shutdown in accordance with Tech Specs.

In come cases, such as discovery of an existing but previously unrecognized condition, it may be necessary to undertake an evaluation in order to determine if an event or condition is reportable. This evaluation should generally proceed on a schedule commensurate with the safety significance of the question. When evaluating more complex issues such as design basis questions, the clock should start once appropriate station management makes a decision with respect to the operability of the system or component. For example, the reportability time clock begins for an engineering evaluation once the evaluation concludes that the associated system was inoperable.

When evaluating an event for reportability, consideration should be given to the requirements contained in section 202.10, Follow-up Notifications.

It is recognized that in the short time frame between the event and the ENS notification, there may not be enough time for an evaluation of the cause, effect, or compensatory measures taken. It is more important that the NRC be quickly made aware of the situation than it is for the station to answer every NRC question at the time of the initial notification. In other words, when evaluating a potentially reportable item, and there is doubt regarding whether to report or not, the NRCs policy is that licensees should make the report. Update ENS notifications should be made to provide additional information or analysis as it becomes available as appropriate.

Revisions to LERs should be submitted in a manner commensurate with its safety significance.

202.6.3.2 Reporting Multiple Events in a Single Report More than one failure or event may be reported in a single ENS notification or LER if(l) the failures or events are related (i.e., they have the same general cause or consequences) and (2) they occurred during a single activity (e.g., a test program) over a reasonably short time (e.g., within 4 hours0.167 days 0.0238 weeks 0.00548 months or 8 hours0.333 days 0.0476 weeks 0.011 months for ENS notifications, or within 60 days LER reporting).

Unrelated failures or events should be reported as separate ENS notifications to be given unique ENS numbers by the NRC. However, multiple ENS notifications may be addressed in a single telephone call.

202.6.3.3 VoluntarylCourtesy Notifications The station may make voluntary or courtesy ENS notifications about events or conditions the NRC may be interested in. The NRC will evaluate and respond to any voluntary notification of an event or condition, as its safety significance warrants, regardless of the reporting classification of the reporting requirement.

If it is determined later that the event is reportable, then another ENS notification should be made under the appropriate 50.72 criterion.

202.6.3.4 ENS Notification Retractions If the station makes a 50.72 notification and later determines that the event or condition was not reportable, the appropriate station personnel should contact the NRC Operations Center to retract the previous notification and explain the rationale for the decision. Sound, logical bases for the withdrawal should be communicated with the retraction.

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VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 The retraction should receive a level of review commensurate with that of the initial notification.

A retracted ENS report is retained in the NRC ENS database, along with the retraction.

202.6.4 SPECIFIC REPORTING GUIDANCE TO 50.72 AND 50.73 The sections that follow will address guidelines for reporting one, four and eight hour non-emergency events and LERs. Specific guidance for reporting Emergency classifications will not be provided in this directive since adequate guidance currently exists under the Emergency Plan implementing response procedures.

If guidance is needed with respect to the reportability of an environmental event, Environmental Management should be contacted for assistance.

In addition to the specific guidelines given under each section, a descriptive list of examples, some of which have occurred, of nuclear station events and conditions that have been determined either reportable or non-reportable pursuant to 10CFR 50.72 and 50.73 are provided. A single event may fall under several reporting criteria. Although this list will not reflect all reporting sections applicable to a specific example, the example will be included under its most immediate reporting requirement, with the exception of those events that may also be reported under an Emergency Class declaration.

202.6.4.1 Engineering Evaluations in Support of Reportability A Reportability Determination should first ask Is the event or condition under consideration reportable if it is assumed that the event occurred or that the condition made an SSC inoperable for an extended period? At a minimum, the reporting criteria that are most applicable for Reportability determinatio ns of historical conditions should be consulted. These are: operations prohibited by Tech Specs {50.73 (a)(2)(i)(B)},

common-mode failures of independent trains or channels {50.73 (a)(2)(vii)}, events or conditions that could have prevented the fulfillment of a safety function {50.72 (b)(3)(v)}, single cause that could have prevented fulfillment of the safety functions of trains or channels in different systems {50.73 (a)(2)(ix)} and the plant in a degraded or unanalyzed condition {50.72 (b)(3)(ii)}.

However, in order to answer the above question, an Engineering Evaluation may be needed to determine the effect of a components inoperability with respect to Tech Spec LCOs, the impact on the operability of any associated SSCs, and the ability to perform safety functions. Because the Tech Specs do not directly specify an LCO for many items that perform supporting functions, a knowledge of the plant design basis is essential to determine which support systems can affect operability.

Also, if the answer to the above question is Yes, then an Engineering Evaluation may be needed to determine if the event/condition actually occurred, if the SSC was actually inoperable in the past due to the condition, and, if so, for how long.

Although there is no attendant duty of protecting the public, such Engineering evaluations should be completed in a timely manner. For example, there are one hour, four hours, eight hours and 60 day reporting requirements associated with past conditions, issues, or events. An event or condition may meet ENS and LER reporting criteria even though the event or condition under evaluation may have existed for years, or only minutes, or may have been corrected prior to discovery.

In most cases, it is expected that these evaluations can be made promptly (e.g.,

there is firm evidence that Tech Spec Completion Time has been exceeded, etc.). In other cases, additional information regarding the event or condition may be needed to complete the reportability determination. For these cases, it is expected that the required information can be obtained and the reportability determination completed within thirty days. Some few exceptional cases may take longer.

Also, in most cases, engineering judgement by a technically qualified individual is all that is needed to support the evaluation. A documented engineering analysis is not a requirement as a basis for an engineering judgement for all events or conditions its only necessary for particularly complex situations requiring

in-depth analysis. When exercising engineering judgement, however, the NRC recommends that licensees record in writing that ajudgement 6

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was exercised by identifying the individual making the judgement and the date made, and briefly documenting the basis for the judgement.

For these evaluations, actual environmental conditions, instrument toleran ce, etc., can be used rather then bounding conditions assumed in the design basis.

In general, for the purpose of evaluating the reportability of situations found during surveillance tests, it should be assumed that the situation occurred at the time of discovery, unless there is firm evidence to believe otherwise. For example, if a standby component with a seven day Tech Spec Action Statem ent is found to be inoperable because it was assembled improperly during maintenance conducted thirty days previo usly, then there is firm evidence that it had been inoperable for the entire thirty days, and the event would be reporta ble.

A common question when performing Reportability determinations is How far back do I have to look? If the SSC could have been inoperable in excess of its Tech Spec Action Statement in the past, a look back of three years is sufficient. The intent is to perform a reasonable search for a condition that could be reportable. In general, exhaustive searches or in-depth analyses are not necessary.

[NOTE: These Engineering Evaluations in Support of Reportability are generally in the Past Operability section of the associated PIP.]

202.7 1-HOUR ENS NOTIFICATIONS AND LERS This section addresses 50.72(b)(1) 1-hour notifications for non-emergenc y events and the associated LER. If not reported as a declaration of an emergency class under 50.72(a), the station is required to notify the NRC as soon as practical and in all cases within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of the discovery of the event specifi ed.

In addition to similar reporting criteria under both I0CFR 50.72 and 50.73, several requirements for only 50.72 notifications or only LERs are included in this section because of the sequen tial numbering scheme used.

202.7.1 TECH SPEC DEVIATION PER IOCFR 50.54(X)

§50.72(b)(1) §50.73(a)(2)(i)(C)

Licensees shall report: Any deviation from the plants Licensees shall report: Any deviation from the plants Technical Specifications authorized pursuant to Technical Specifications authorized pursuant to

§50.54(x) of this part. §50.54(x) of this part.

General I OCFR 50.54(x) generally allows the station to take reasonable action in an emergency even though the action is in violation of the License Condition or Tech Specs provided: (1) the action is immediately needed to protect the health and safety of the public (including station personnel), and (2) no action consistent with the License Conditions and Tech Specs is obvious that can immediately provide adequate protection. In accordance with 50.54(y), such action requires, as a minimum, prior approval by a license d Senior Reactor Operator.

Deviation from an Emergency Procedure that alters the intent of the procedure without prior approval may also be a violation of Tech Specs and should be evaluated to determ ine if it would require reporting under this section.

EXAMPLES Reportable

a. With the unit at 100% power, the upper containment airlock inner door was opened to allow a technician to exit from the containment while the upper door was inoperable, resultin g in a loss of containment integrity.

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VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 The Technician was inside containment when the lower airlock failed, requiring exit through the upper door.

The decision to open the upper containment airlock inner door exercised an allowable option under 1 0CFR 50.54(x). Immediate action was considered necessary for the technician to exit the containment for his personal safety. An ENS call was made within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of the breech of containment.

202.8 4-HOUR ENS NOTIFICATIONS AND LERS This section addresses 50.72(b)(2) 4-hour notifications for non-emergency events and the associated LER. If not reported as a declaration of an emergency class under 50.72(a) or as a non-emergency 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months report under 50.72(b)(I), the station is required to notify the NRC as soon as practical and in all cases within 4 hours0.167 days 0.0238 weeks 0.00548 months of the discovery of any of the events specified.

In addition to similar reporting criteria under both 1 OCFR 50.72 and 50.73, several requirements for only 50.72 notifications or only LERs are included in this section because of the sequential numbering scheme used.

202.8.1 PLANT SHUTDOWN REQUIRED BY TECHNICAL SPECIFICATIONS

§50.72(b)( 2)(i) 50.73(a)(2)(i)(A)

Licensees shall pt: The initiation of any nuclear Licensees shall submit a Licensee Event Report on:

plant shutdown required by the plants Technical The completion of any nuclear plant shutdown Specifications. required by the plants Technical Specifications.

50.72 The 50.72 reporting requirement is intended to capture those events for which Tech Specs require the initiation of reactor shutdown to provide the NRC with early warning of safety significant conditions.

Initiation is the performance of any action to start reducing reactor power to achieve an operational condition or mode that requires the reactor to be subcritical, as a result of a Tech Spec requirement. This includes any means of power reductions such as control rod insertion or boron concentration changes.

2. 50.73 For 50.73 reporting purposes, the phrase completion of any nuclear plant shutdown is defined as the point in time during a Tech Spec required shutdown when the plant enters Mode 3. Therefore, if a failure can be corrected before the unit is required to be in Mode 3 an LER is not required. This

,

includes a situation where the plant is shutdown, the problem is fixed and the unit is returned to power before the completion of shutdown was required by Tech Specs. The shutdown is reportable, however, if the failure cannot be corrected before the unit was required to be shutdown.

EXAMPLES Reportable

a. Two out of three channels for a certain function failed. Tech Specs require the unit to be placed in Mode 3 within 6 hours0.25 days 0.0357 weeks 0.00822 months with less than the minimum required channels operable. After 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , the station began a load reduction from full power at 20% per hour. Within 15 minutes of the initial load reduction, an ENS notification was made. The station made an update ENS call 3 hours0.125 days 0.0179 weeks 0.00411 months later after the equipment was repaired, the channels were declared operable, and the power reduction was stopped before completion of the shutdown.

An ENS notification per 50.72 was required because the power reduction was an initiation of plant shutdown. {Note, however, an LER was not required because the shutdown was never completed (i.e.,

Mode 3 was not entered).}

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b. When leakage around the primary containment ventilation exhaust dampers exceeded the maximum allowable combined secondary bypass leakage rate, the plant Tech Specs required the plant to be in Hot Shutdown within 12 hours0.5 days 0.0714 weeks 0.0164 months . The station commenced a reactor shutdown at 10% per hour and made an ENS call within 10 minutes of entering the LCD Action. Hot Shutdown was reached 10 hours0.417 days 0.0595 weeks 0.0137 months later.

c. While the unit was at 100%, the units nuclear service water pump discharge valve failed its monthly periodic test. Because the station knew repairs could not be made during the remaining time allowed by Tech Specs (72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Action), the unit was placed in Cold Shutdown within 1 day. The ENS call was made 30 minutes after the initial load decrease (even though there were 50 hours2.083 days 0.298 weeks 0.0685 months left on the Tech Spec clock).

Non-Reportable

d. Two out of three channels for a certain function failed. Tech Specs require the unit to be placed in Mode 3 within 6 hours0.25 days 0.0357 weeks 0.00822 months with less than the minimum required channels operable. Since IAE personnel felt the repairs could be made within 3 hours0.125 days 0.0179 weeks 0.00411 months , the Shift Supervisor decided to hold power for 3 hours0.125 days 0.0179 weeks 0.00411 months . The equipment was repaired and the station declared the failed channels operable 4 hours0.167 days 0.0238 weeks 0.00548 months later. No ENS call was made since there was no shutdown initiated.

e. While the unit was at 100%, the units nuclear service water pump discharge valve failed its monthly periodic test. Because the station thought repairs could be made during the remaining time allowed by Tech Specs (72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Action), the unit held at full power. The ENS call was not required since the valve work took only 40 of the remaining 50 hours2.083 days 0.298 weeks 0.0685 months left on the Tech Spec clock, and no power reduction had begun.

202.8.2 ECCS DISCHARGE INTO THE REACTOR COOLANT SYSTEM

§50.72(b)(2)(iv)(A) 10 CFR 50.73d Licensees shall report: Any event that results or should [ECCS discharge is a subset of50.73(a)(2)(iv) (See have resulted in Emergency Core Cooling System Section 202.9.6). Therefore, an LER is required.]

(ECCS) discharge into the reactor coolant system as a result of a valid signal.

1. General Those events that result in either automatic or manual actuation of the ECCS, or should have resulted in ECCS discharge into the reactor coolant system if some component had not failed or an operator action had not been taken, are reportable. Reporting exceptions include preplanned actuations and the ECCS is properly removed from service and not required to be operable.

2. Valid Signal Valid signal refers to those signals that are automatically initiated by the measurement of an actual physical system parameter that was within the established set point band of the sensor that provides the signal to the protection systems logic, or manually initiated in response to plant conditions. Valid signals should also include those passive system actuations that occur as a function of system conditions like differential pressure (i.e., cold leg accumulators) whereby no SSPS or other electrical signal is involved. The validity of an ECCS signal may not be determined within 4 hours0.167 days 0.0238 weeks 0.00548 months , ECCS signals that result or should have resulted in injections should be considered valid until firm evidence proves otherwise. Invalid ECCS injections should be evaluated under Section 202.9.6 (50.73 (a)(2)(iv)).

EXAMPLES Reportable

a. While in Mode 3, valve 2NC-29 stuck open resulting in a rapid decrease in reactor coolant (NC) system pressure. This caused the Cold Leg Accumulators to actuate and inject approximately 1100 gallons of REVISION 21 9 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 borated water into the reactor coolant system. An ENS call is required to be made within 4 hours0.167 days 0.0238 weeks 0.00548 months and an LER is required because of the actuation.

b. During a reactor vessel pressure test while in Cold Shutdown, a low pressure coolant injection pump (LPCI) automatically started when a reactor recirculation pump start caused a perturbation in reactor vessel level instrumentation readings. Because the reactor vessel pressure was above the LPCI pump shutoff head, no water was injected into the vessel. An ENS call is required because this was a valid ECCS signal that should have resulted in an ECCS discharge into the reactor vessel.

Non-Reportable

c. While surveillance testing containment isolation valves, a test pushbutton was inadvertently released, which initiated a B train containment isolation and safety injection. High pressure ECCS pumps injected 300 gallons of borated water from the RWST into the reactor before pumps were secured, while the reactor remained at 94% power. The event is not reportable as a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ENS call under this section, even though it was an ECCS injection. The signal that caused the injection was an inadvertent, manual signal (i.e., plant conditions did not require a manual safety injection), thus, not a valid signal. The event is reportable (ref.

Section 50.73 (a)(2)(iv).

202.8.3 REACTOR PROTECTION SYSTEM ACTUATION

§50.72(b)(2)(iv)(B) 10 CFR 50.73 Licensees shall report: Any event that results in the [RPS actuation is a subset of §50.73(a)(2)(iv) (See actuation of the reactor protection system (RPS) when Section 202.9.6). Therefore, an LER is required.]

the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation 202.8.4 NEWS RELEASE OR OTHER GOVERNMENT NOTIFICATIONS

§50.72(b)(2)(xi) 10 CFR 50.73 Licensees shall report: Any event or situation, related [No corresponding Part 50.73 requirement.]

to the health and safety of the public or on-site personnel, or protection of the environment, for which a news release is planned or notification to other government agencies has been or will be made. Such an event may include an on-site fatality or inadvertent release of radioactively contaminated materials.

General The purpose of this section is to ensure the NRC is made aware of issues that will cause heightened public or government concern related to radiological or environment events. The NRC Operations Center does not need to be made aware of every press release or offsite notification made. Only those issues that are perceived by the public to be related to the radiological health and safety of the public, onsite personnel, or protection of the environment, need be reported.

For reporting purposes, other government agencies refer to local, State or Federal agencies, including the FBI and local law enforcement. Notification to law enforcement agencies are governed by the Security Manual/Directive. If reportable under 50.72, they would also be reportable as one hour calls per 73.71.

10 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 If a licensee is notifying a local, state, or other federal agencies in accordance with an existing law, regulation or ordinance, then, the licensee should make its notification to the NRC under this criterion. However, if a licensee is informally communicating with a local, state, or other federal agencies (i.e., not under a specific law, regulation or ordinance), then, the licensee has discretion as to whether to informally communicate with the NRC (e.g., through the site resident inspector) or formally through the 50.72 notification process. If due to the site-specific circumstances or heightened sensitivity to the issue at the site, the issue is likely to produce strong media interest, then the licensee should consider notifiing NRC under the 50.72 requirement because this is actually the underlying intent of this criterion.

The 4-hour ENS notification clock starts at the time the decision is made to report to other agencies or to make a press release. In some cases, a decision to issue a press release may not be made until long after the specific event. In all cases, however, the notification to the NRC should be made before the press release is issued to the media Notifications to other Federal agencies does not relieve the station of the requirement to report to the NRC Operations Center via ENS. Likewise, if current procedures require reporting of events to other areas within the NRC, such as Region II, this too does not fulfill the reporting requirement of 50.72.

When in doubt, the ENS notification should be made by the station.

2. Generally, the following types of events require a report under 50.72:

Radiological

- inadvertent release of radioactively contaminated materials to public areas

- inadvertent public notification system operation for which a news release is planned

- inadvertent releases of radioactivity Environmental

- unanticipated non-radioactive releases\spills that would generate interest from local government agencies or the EPA

- onsite plant or animal disease outbreaks including fish kills, excessive bird impaction events, or mortality or unusual occurrence of any species protected by the Endangered Species Act of 1973.

- Release of a Reportable Quantity (RQ) of a Superfund Amendment Reauthorization Act (SARA) extremely hazardous substance

- increase in nuisance organisms or conditions causally related to station operation

3. Optional or discretionary reports For the following events, a report under 50.72 is left to the discretion of station management on a case by case basis. However, the NRC Resident inspector should be informed:

- groundwater contamination Informal communications made to government agencies as a result of the Industry Groundwater Protection Initiative (GPI). The NRC Regional RP Inspector should receive informal notification of the event.

- underground storage tank (UST) or UST piping leak

- brown scum on the waters of the state

- release of a dye to waters of the state

- any drinking water maximum contaminate level violation for which posting is required

4. Generally, the NRC does NOT need to be informed under this section of:

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- peaceful strikes or civil demonstrations Environmental

- minor deviations from permitted effluent limits

- routine reports of effluent releases to other agencies

- minor onsite chemical spills that would not generate interest from local agencies of the EPA OTHER EXAMPLES Reportable

a. A man fell into the discharge canal while fishing and failed to resurface. The station notified the sheriff, state police, and state emergency agencies. The local media was granted onsite access to cover the event.

An ENS call is required because of the fatality onsite, the other notifications made, and the media involvement.

b. The station informed the county government and other organizations of a spurious actuation of several alert sirens in a county. The station also planned a press release. An ENS notification is required within 4 hours0.167 days 0.0238 weeks 0.00548 months of the initial contact with any county agency regarding the inadvertent actuation of part of the public notification system.

c. The station transported 2 secondary side filters to the county dump as non-radioactive waste, but later determined that they were contaminated. The station notified appropriate state agency and NRC resident inspector. An ENS call is required.

d. The station notified its state environmental protection agency and the NRC resident of a fish kill involving several species in the circulating water discharge canal, possibly resulting from thermal water conditions.

An ENS call is required because of the state notification of a significant fish kill, which the media or public could perceive as an environmental or public hazard.

e. Oil spills to waters of the state require an ENS call.

f. A spill of 1 pound ( 50 ppm) of PCBs to the environment or any impervious surface requires an ENS call.

Non-Reportable

g. The station notified the state, EPA, and Dept. of Transportation that 5 gallons of diesel fuel oil had spilled onto gravel covered ground inside the protected area. The spill was cleaned up by removing the gravel and dirt. Such notifications to other agencies such as this do not require an ENS notification. These kind of events do not pertain to the radiological health and safety of the public, or protection of the environment.

h. As a result of a local newspaper article regarding the findings of an NRC regional inspection, a station representative was interviewed on local television and radio stations. The station also notified State officials and the NRC resident. An ENS call is not required in this case because the station was responding to findings raised by the NRC.

i. Notification of when a hazardous waste manifest is returned from an out-of-state facility does not require an ENS call.

j. A hazardous waste manifest not returned within the 45 day limit does not require an ENS call.

k. A licensee notified the U.S. EPA that the circulation water temperature rise exceeded the release permit allowable. This event was caused by the unexpected loss of a circulation water pump while operating at 92 percent power. The licensee reduced power to 73 percent so that the circulating water temperature would decrease to within the allowable limits until the pump could be repaired. An ENS notification is not needed because this event is routine and has little safety significance.

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VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 202.9 8-HOUR ENS NOTIFICATIONS AND LERS This section addresses 50.72(b)(3) 8-hour notifications for non-emergency events and the associated LER. If not reported as a declaration of an emergency class under 50.72(a) or as a non-emergency 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months report under 50.72(b)(l) or 50.72(b)(2),respectively, the station is required to notify the NRC as soon as practical and in all cases within 8 hours0.333 days 0.0476 weeks 0.011 months of the discovery of any of the events specified.

In addition to similar reporting criteria under both 10CFR 50.72 and 50.73, several requirements for only 50.72 notifications or only LERs are included in this section because of the sequential numbering scheme used.

202.9.1 TECHNICAL SPECIFICATION PROHIBITED OPERATION OR CONDITION 10 CFR 50.72 §50.73(a)(2)(i)(B)

[There is no corresponding Part 50.72 requirement. Licensees shall report: Any operation or condition which was prohibited by the plants Technical Specifications, except when:

(1) The Tech Spec is administrative in nature; (2) The event consists solely of a case of a late surveillance test where the oversight is corrected, the test is performed, and the equipment is found to be capable of performing its specified safety functions; or (3) The Tech Spec was revised prior to discovery of the event such that the operation or condition was no longer prohibited at the time of discovery of the event.

General An LER is required under this criterion if an LCO and associated Action statement are not met. The time constraints included in the associated Action statements are based on the safety significance of the component or system being removed from service. The NRC is interested in the frequency of occurrence and the Tech Spec involved in events which a shutdown did not occur within the given time constraint. The condition is reportable even if the condition was not discovered until later and was corrected upon discovery. Therefore, if an inoperable component or system is discovered, an investigation is required in order to determine how long the component has been in the degraded condition. Reportability per this section can be determined based upon the results of the investigation.

The LER rule does not address violations of License Conditions in documents other than Tech Specs. Such notifications are reportable as specified in a plants license or other applicable document.

2. Inoperable upon Discovery If, through the course of the investigation of the inoperable component or system, it cannot be determined how long it was in the as found condition, there are 2 different assumptions to be made in order to reach a reportability decision. If the inoperable condition was discovered during the course of a surveillance, maintenance, or inspection, the condition is assumed to have occurred at the time of discovery (same philosophy as operability), provided no firm evidence exists that would indicate when the failure occurred. If, however, the condition was discovered by chance (e.g., an operator discovers a mispositioned valve during a walkdown), and it is obvious that the degraded condition was caused by some personnel action, it is assumed that the condition has existed since the component (or system) was known to be operable. Once these determinations are made, the most stringent Action statement should be compared to the time the item was inoperable. If the most limiting time constraints of the LCO Action were exceeded, the condition is reportable REVISION 21 13 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 per this criterion. Since these determinations may be subjective at times, the evaluator should consider what is reasonable based upon the circumstances surrounding the as found condition.

3. Tech Spec LCO 3.0.3 Tech Spec LCO 3.0.3 establishes requirements for actions when (1) an LCO is not met and the associated Actions are not met; (2) an associated ACTION is not provided, or (3) as directed by the associated ACTIONS themselves.

Entry into LCO 3.0.3 is not necessarily reportable under this criterion. However, it should be considered reportable under this criterion if the condition is not corrected within an hour, such that it is necessary to initiate actions to shutdown, cool down, etc. If a licensee responsibly concludes that plant shutdown should be delayed or corrective action can be accomplished so that an unnecessary plant transient can be avoided, such a decision is permitted as long as the shutdown times specified by the Tech Specs are observed.

4. Missed Surveillance A missed or late surveillance test is reportable when it indicates that equipment (e.g., one train of a multiple train system) was not capable of performing its specified safety functions (and, thus, was inoperable) for a period of time longer than allowed by Tech Specs. Reporting is not required if an event consists solely of a case of a late surveillance test where the oversight is corrected, the test is performed, and the equipment is found to be capable of performing its specified safety functions.

For the purpose of evaluating the reportability of a discrepancy found during surveillance testing that is required by the Tech Specs:

(1) For testing that is conducted within the required time (i.e., the surveillance interval plus any allowed extension), it should be assumed that the discrepancy occurred at the time of its discovery unless there is firm evidence, based on a review of relevant information such as the equipment history and the cause of the failure, to indicate that the discrepancy existed previously.

(2) For testing that is conducted later than the required time, it should be assumed that the discrepancy occurred at the time the testing was required unless there is firm evidence to indicate that it occurred at a different time.

The purpose of this approach is two-fold. It rules out reporting of routine occurrences (i.e., occurrences where a timely surveillance test is performed, the results fall outside of acceptable limits, and the condition is corrected) unless there is firm evidence that equipment was incapable of performing its specified safety function longer than allowed. On the other hand, if the surveillance test is performed substantially late, and the equipment is not capable of performing its specified safety function, the occurrence is not routine. In this case the event is reportable unless there is firm evidence that the duration of the discrepancy was within allowed limits.

Tech Specs allow a delay of up to 24 hours1 days 0.143 weeks 0.0329 months in declaring an LCO or a Tech Spec requirement not met if it is found that a surveillance was not performed within its specified frequency or interval. However, this does not change the fact that the condition existed longer than allowed by Tech Specs. Failure to perform a surveillance within its frequency or interval is still reportable if it indicates that the equipment (i.e., one train of a multiple train system) was not capable of performing its specified safety functions and, thus, was inoperable for a period of time longer than allowed by Tech Specs. The delay merely specifies appropriate remedial action.

As specified previously, the event is not reportable if it consists solely of a case of a late surveillance test where the oversight is corrected, the test is performed, and the equipment is found to be capable of performing its specified safety functions. This type of event has not proven to be significant because the equipment remained functional.

5. Design and Analysis Defects and Deviations A design or analysis defect or deviation is reportable under this criterion if, as a result, equipment (e.g., one train of a multiple train system) was not capable of performing its specified safety functions (and thus was inoperable) for a period of time longer than allowed by Tech Specs. Since Design and analysis conditions are long-lasting, the essential question in this case is whether the equipment was capable of performing its specified safety functions.

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6. 1ST Requirements per Tech Spec 5.5 Tech Specs 5.5.8 covers 1ST requirements for ASME Class 1, 2, and 3 components. Missed or deficient IST/ASME surveillances are reportable when, as a result of the missed or deficient surveillance, a Tech Spec controlled system must be declared inoperable and the LCO action statement has been exceeded. The reportability evaluation should proceed per the guidance in Section 202.9.1, 1 through 4 (above), as applicable.

Failure to perform a visual inspection required by ASME Section XI does not in itself affect the operability of the component. As such, failure to perform visual inspections will not be reported as a condition prohibited by Technical Specifications. However, these missed inspections shall be reported to the NRC Resident Inspector for inclusion in any inspections as determined appropriate.

7. Administrative Requirements Tech Specs include administrative requirements that are required to be followed. Violation of a Tech Spec that is administrative in nature is not reportable. For example, a change in the plants organizational structure that has not yet been approved as a Tech Spec change would not be reportable.

An administrative procedure violation, or failure to implement a procedure, such as failure to lock a high radiation door, is generally not reportable under this criterion. Radiological conditions and events that are prohibited by Tech Specs should be evaluated for reportability under the requirements of 10CFR 20.2202 and 20.2203. Redundant reporting is not required.

EXAMPLES Reportable

a. Doghouse water level instrumentation functional test was not performed on 1 train of channels. Tech Specs require this surveillance to be performed once every refueling outage. The missed test was discovered 1 month later and the Action statement requires continuous level monitoring with 1 or more trains inoperable.

b. The IWV Program lists valve NV-iSO as a valve that requires a VST quarterly. With NV-iso inoperable, Train A of the Chemical and Volume Control (NV) system is inoperable. This valve has been tested only during Cold Shutdown.

c. Unit 1 operated at greater than 100% licensed thermal power for a period greater than the Tech Specs allow.

d. While preparing to perform a surveillance on an air operated valve, a technician discovered the instrument air line disconnected from the port. The inoperable valve renders its respective train inoperable. Upon investigation, it was determined that the line was most probably not connected properly after maintenance performed 2 weeks earlier. The Tech Spec Action for this train is 72 hours3 days 0.429 weeks 0.0986 months . The valve was not immediately retested following maintenance.

e. While performing surveillances on the main steam safety valves, of the 20 valves tested, 17 were out of tolerance (13 with set points above Tech Specs by as much as 4 percent). The existence of similar discrepancies in multiple valves is an indication that the discrepancies arose over a period of time and therefore reportable.

f. Operation with less than the required number of people on shift in excess of Tech Spec allowances would constitute operation prohibited by Tech Specs and therefore reportable.

Non-Reportable

g. The IWV Program lists valve NV-15 1 as a valve that requires a VST quarterly. With NV-is i closed and incapable of opening, Train A of the NV system is inoperable. This valve has not been tested in 9 months.

Upon this discovery Operations confirmed that the valve had been in the open position for the entire period, thus, in its safety position and train A NV was capable of performing its intended safety function.

Even though the 1ST program was violated, an LER is not required because the failure to test the valves movement did not render its associated system or train inoperable.

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h. Upon entering Mode 4, operators observed that the NC system (MNS and CNS) heatup rate had been exceeded during the removal of the A reactor coolant pump. The Tech Spec LCO Action requires the rate to be restored within 30 minutes (which it was) and an engineering evaluation performed on the integrity of the pressurizer. The evaluation was performed immediately and confirmed the structural integrity acceptable, thus complying with the Action statement.

i. A certain containment isolation valve failed to meet its stroke timing test of 5.0 seconds during an outage.

The subsequent investigation failed to reveal any evidence as to why the valve was slower for this surveillance. After maintenance, the valve tested in under 5.0 seconds and was declared operable.

j. Failure to perform a visual inspection after maintenance as required by ASME Section Xl does not in itself affect the operability of the component. As such, failure to perform visual inspections will not be reported as a condition prohibited by Tech Specs.

k. At MNS, Unit 1 entered the Containment Isolation LCO due to an inoperable containment isolation valve.

The affected penetration flow path was not isolated within the required time. This LCO also had an associated shutdown condition. Eleven minutes into the shutdown condition, the LCO was declared met.

There was no need to add negative reactivity to initiate a plant shutdown at the time the LCO was declared met and the plant remained within the range of limitations as defined by the LCO. Thus, it was concluded that this event did not constitute an operation or condition prohibited by Tech Specs.

202.9.2 DEGRADED OR UNANALYZED CONDITION

§50.72(b)(3)(ii) §50.73(a)(2)(ii)

Licensees shall report: Any event or condition that Licensees shall report: Any event or condition that results in: resulted in:

(A) The condition of the nuclear power plant, including (A) The condition of the nuclear power plant, including its principal safety barriers, being seriously its principal safety barriers, being seriously degraded; or degraded;

( B) The nuclear power plant being in an unanalyzed (B) The nuclear power plant being in an unanalyzed condition that significantly degrades plant safety. condition that significantly degraded plant safety.

1. Definitions

a. Principal Safety Barriers: The principal safety barriers involve the functionally controlling or bounding accident and transient analysis barriers:

- Fuel Cladding

- Reactor Coolant System (RCS) Pressure Boundary

- Primary and Secondary (MNS/CNS Annulus) Containment The specific safety function of these principal safety barriers is the protection of public health and safety through limiting the release of radioactive material. The controlling parameters for each of the principal safety barriers is contained in the UFSAR. Typical parameters include:

- Offsite Dose

- Fuel Clad Temperature

- Hydrogen Generation

- Core Geometry

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- Reactor Coolant Pressure Boundary Integrity The specific value or ranges of values chosen for each controlling parameter along with final verification of principal safety barrier performance is contained in the stations UFSAR.

b. Abnormal Degradation: Abnormal degradation is plant degradation beyond that analyzed for in the UFSAR. Abnormal degradation of a barrier may be indicated by the necessity of taking corrective action to restore the barriers capability.

c. Unanalyzed Condition: The current UFSAR transient and accident analyses define the limiting conditions for operation and confirms the ability of the stations systems, structures, and components to prevent or mitigate the consequences of postulated transients and accidents. An event or condition that places the plant outside the bounds of any of these analyses represents an unanalyzed condition. An example of an event reportable as an unanalyzed condition that significantly degraded plant safety would be discoveiy that a system required to meet the single failure criterion does not do so.

d. Significantly degrades Plant Safety: An unanalyzed condition significantly degrades plant safety if it results in abnormal degradation, or has the potential to result in abnormal degradation of one of the principal safety barriers. The level of significance of these cases generally corresponds to the inability to perform a required safety function.

2. General If the event or condition affects more than a single safety system or structure, or one of the principal safety barriers, reportability under this section should be reviewed. The stations are designed and licensed to adequately handle its Design Basis Accident along with its most limiting single failure. If an event occurs or condition exists that results in more equipment or systems being inoperable than covered by the plants safety analysis, it may be in an unanalyzed condition. The definitions provided in 202.9.2 for these concepts need to be applied to determine reportability.

It is not intended that this section apply to minor variations in individual parameters, or to problems concerning single pieces of equipment. Any failure, or minor error in performing surveillance tests could produce a situation in which two or more often unrelated, safety-related components are out of service. Technically, this is an unanalyzed condition. However, these events should be reported only if they involve functionally related components or if they significantly compromise plant safety. For instance, if an event occurred where there could have been a failure of a safety system to properly complete a safety function, Section 202.9.7 Event or Condition That Could Have Prevented the Fulfillment of Safety Function of Systems or Structures should be reviewed for reportability. If an event occurred where a single cause actually made a component or group of components inoperable in redundant or independent trains or channels, of one or more systems having a safety function, Section 202.9.8 Common-Mode Failures of Independent Trains or Channels should be reviewed for reportability.

Section 202.9.11 Single Cause that Could Have Prevented Fulfillment of the Safety Functions of Trains or Channels in Different Systems should also be reviewed.

Deficiencies in the Fire Protection and App. R program should be evaluated under this criterion. In general, only programmatic breakdowns of the Fire Protection Program need to be reported. Programmatic breakdowns do not include failures to execute the program. Individual problems with Fire Protection Program Remedial Actions (e.g., fire watches) or fire protectionldetection equipment should be evaluated with respect to actual cause. If the cause is related to a failure to put in place an element or elements of the Fire Protection Program, then this would be reportable. If however, the problem is related to isolated failures to execute due to human performance problems or isolated equipment failures, these conditions would not be reportable as programmatic breakdowns.

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VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 EXAMPLES Reportable

a. Three studs were discovered missing on the horizontal missile shields located over the reactor vessel.

Engineering analysis determined that the remaining studs were not sufficient to hold the shields during a

postulated accident, thus, putting a principal safety barrier in a potentially degraded position.

b. Two weeks after painting the Diesel Generators, an operability test was performed and neither DIG was capable of starting since paint had been applied to key D/G components, preventing any movement.

Upon discovery, the D/G components had to be scraped clean before the D/Gs were able to start and load, The Unit had been at full power during the entire period.

c. Engineering determined that instrument loop inaccuracies could result in safety injection initiation on low pressurizer pressure at a lower RCS pressure than assumed in the accident analysis.

d. Fire barriers were found to be missing such that the required degree of separation for redundant safe shutdown trains is lacking. This event is reportable as an unanalyzed condition that significantly degraded plant safety.

e. With the unit in Mode 6, ultrasonic testing revealed a number of failed fuel rods (233 were identified in 88 of 109 fuel assemblies scheduled for reinsertion) that far exceed the anticipated number of failures.

An ENS call is required because a principal safety barrier (fuel cladding) was found seriously degraded.

f. Steam Generator tube degradation is considered serious and reportable if the tubing fails to meet either of the following two performance criteria:

1) Steam generator tubing shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, cooldown and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a margin of 3.0 against burst under normal steady state full power operation and a margin of 1.4 against burst under the limiting design basis accident concurrent with a safe shutdown earthquake.

2) The primary to secondary accident induced leakage rate for the limiting design basis accident, other than a steam generator tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all steam generators and leakage rate for an individual steam generator. The licensing basis accident analyses typically assume a 1 gpm. primary to secondary leak rate per steam generator, except for specific types of degradation at specific locations where the tubes are confined, as approved by the NCR and enumerated in conjunction with the list of approved repair criteria in the licensees design basis documents.

Non-Reportable

g. A main steam isolation valve closed while the plant was at 100% power as a result of a solenoid failure.

Operations personnel reduced reactor power because of asymmetric power tilt and feedwater oscillations.

No procedure existed for operating the unit in these conditions while the solenoid was being replaced.

The event is not reportable because this condition would not have significantly degraded plant safety.

h. Upon review of historical test data on the 2A and 2B Component Cooling (KC) heat exchangers, both HXs were unknowingly inoperable during the same time period due to excessive fouling. {Note, although not reportable under these criteria, the condition is reportable as a loss of safety function for the KC system under Section 202.7.3 Event or Condition That Could Have Prevented the Fulfillment of Safety Function of Systems or Structures.}

i. While in Cold Shutdown and mid-loop operation, the 2A Containment Spray (NS) pump suction valve was opened for VST with ND-l and 2 open. This subjected the 2A NS train to Reactor Coolant pressure conditions. Overpressurization of the NS heat exchanger and a 10,000 gallon spill resulted.

j. A fire wrap, to which the licensee had committed, was missing from a safe shutdown train but another safe shutdown train was available in a different fire area, protected such that the required separation for safe shutdown is still provided, the event would not be reportable.

18 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 202.9.3 NATURAL PHENOMENON OR CONDITION THREATENING PLANT SAFETY (EXTERNAL THREAT)

§50.72 §50.73(a)(2)(iii)

There is no 50.72 requirement. Refer to the plants Licensees shall report: Any natural phenomenon or Emergency Plan regarding declaration of an Emergency other external condition that posed an actual threat to the Class, safety of the nuclear power plant or significantly hampered site personnel in the performance of duties necessary for the safe operation of the nuclear power plant.

General This section applies only to acts of nature (e.g., tornadoes, earthquakes, fires, hurricanes, and floods) and external hazards (e.g., industrial and transportation accidents). This section requires events to be reported if the threat or actual damage challenges the ability of plant personnel to continue to operate in a safe manner, including the orderly shutdown and maintenance of safe shutdown conditions.

2. Actual Threat Judgment should be used to determine if a condition actually threatens the plant. For example, a small brush fire in a remote area of the site that was quickly controlled and did not present a threat to the plant need not be reported. However, a major forest fire or hurricane moving in the direction of the plant and thus threatened plant equipment may be reportable. There are no prescribed limits, but in general, situations involving only monitoring by the plants staff are not reportable. But when preventative actions are taken or if there are serious concerns, then the situation should be carefully reviewed for reportability.

3. Significantly Hampers Personnel To be reportable, an event need not prevent station personnel from performing their duties. It is only necessary that they be significantly hampered, hindered, or interfered with in the performance of safety-related activities.

If the condition makes performing routine safety-related functions significantly more difficult, it is reportable.

For example, in a snowstorm, judgment may be based on the amount of snow, the extent to which additional assistance could have been available in an emergency, and the length of time the condition existed. If station management decides to allow all non-essential personnel to go home early as a conservative, precautionary step, considering the safety of the employees during their travel, the condition is not reportable.

EXAMPLES Reportable

a. The National Weather Service issued a Tornado Warning for York County. A tornado was spotted approaching the Catawba Nuclear Station. The tornado touched down within the plant protected area boundary. Operations declared an Unusual Event. The tornado continued on and struck the SSF and inflicted significant damage. Operations upgraded to an Alert. The tornado left the site and after assessing damage, the Alert was terminated. An LER is also required since a safety-related structure (SSF) was significantly damaged.

Non-Reportable

b. Hurricane Hugo was within 150 miles of the plant and appeared to be heading toward the direction of the plant. Since the force of the hurricane had diminished significantly by the time it neared the station and an insignificant amount of damage was done, an LER was not required.

c. One day in February it began snowing considerably. When the accumulation reached 4 inches, station management made a decision to allow non-essential plant personnel to leave early that afternoon since the REVISION 21 19 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 snow was expected to continue into the night and decreasing temperatures would make traveling home especially hazardous in the evening.

d. A Tornado warning 202.9.4 LOSS OF EMERGENCY ASSESSMENT, RESPONSE, OR COMMUNICATIONS

§50.72(b)(3)(xiii) 10 CFR 50.73 Licensees shall report: Any event that results in a major [No corresponding Part 50.73 requirement.]

loss of emergency assessment capability, offsite response capability, or offsite communications capability (e.g., significant portion of control room indication, Emergency Notification System, or offsite notification system).

Loss of Emergency Assessment Capability Emergency assessment capability is defined in the station Emergency Plan and implementing procedures. A major loss of emergency assessment capability would include those events or conditions that significantly impair the operators ability to determine the status of the key station parameters and take the proper course of actions in the event of an emergency. Engineering judgment may be needed to determine the significance of the loss in terms of the equipment and the length of time involved. For example, the unavailability of 1 redundant component or train such as a radiation monitor or OAC, for a period of time as permitted by Tech Specs or administrative procedures, generally is not reportable.

2. Loss of Offsite Response Capability A major loss of offsite response capability includes those events that would significantly impair the fulfillment of the stations Emergency Plan. Loss of offsite response capability may typically include the loss of plant access, emergency offsite response facilities, or public prompt notification system (a loss of more than 25% of the stations total sirens, other alerting systems (e.g., tone alert radios), or more importantly, the lost capability to alert a large segment of the population (for more than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ) would be considered a major loss and, therefore, reportable per this section).

3. Loss of Communications Capability A major loss of communications capability would include the loss of ENS and commercial telephone lines.

The loss of the following is considered reportable: a significant amount of control room annunciators or monitors (such as an annunciator panel, a number of annunciators on various panels, or all plant vent stack radiation monitors), Control Room or shutdown panel habitability (from complete loss to using self-contained breath apparatus), or loss of multiple independent safety assessment equipment or systems concurrently.

A loss of the Safety Parameter Display System (SPDS) required by Three Mile Island Action Plan [Ref.

NUREG-0737], is not necessarily reportable under this criterion if other (safety-related) indication(s) is (are) available for use by the operators (or Emergency Response Organization) to adequately monitor plant safety parameters. Extended losses of SPDS and related plant computer capabilities; e.g., > 4 hours0.167 days 0.0238 weeks 0.00548 months , should be considered for reporting if, coincident with other adverse conditions, such a loss would significantly hamper the plants ability to deal with an accident or emergency.

EXAMPLES Reportable

a. More than 25% of the stations total alert sirens were disabled because of loss of power as a result of severe weather.

20 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202

b. ENS and commercial phone lines were discovered to have been cut while crews were digging.

c. The local sheriff notified the station that all roads to and from the plant were closed because of a heavy snow storm. The station had 2 full shift crews on site to support plant operations and no emergency declaration was made. An ENS call is required because the road closing may prevent the plant staff from adequately staffing the TSC, or from fully responding to some emergencies.

Non-Reportable

d. It was observed during siren testing that 5 of 52 alert sirens around the EPZ failed to function. This was not considered to be a major loss of the offsite response capability.

e. York County was performing a scheduled quarterly full cycle siren test and as they were performing the procedure there was a step requiring the turning of a key in order to make the sirens sound. The sirens did not sound; however, within minutes the individual realized an improper arming configuration, rearmed the siren, turned the key, and the sirens function properly. This event would not be reportable because the sirens were only disabled during the quarterly test.

202.9.5 INTERNAL THREAT TO PLANT SAFETY

§50.72 §50.73(a)(2)(x)

There is no 50.72 requirement. Licensees shall report: Any event that posed an actual Refer to the plants Emergency Plan regarding threat to the safety of the nuclear power plant or declaration of an Emergency Class. significantly hamper site personnel in the performance of duties necessary for the safe operation of the nuclear power plant including fires, toxic gas releases, or radioactive releases.

General This section pertains to threats internal to the station. Fires, toxic gas releases, and radioactive releases are not the only threats that may require reporting under these provisions. The criterion to be applied in each case is whether the event poses an actual threat to the safety of the plant or significantly hampers personnel in the performance of duties necessary for the safe operation of the plant. The significant hampering criterion is pertinent to the performance of duties necessary for safe operation of the nuclear power plant. One way to evaluate this is to ask if one could seal the room in question (or disable the function in question) for a substantial period of time and still operate the plant safely. Actions such as room evacuations that are purely precautionary would not constitute significant hampering if the performance of duties necessary for the safe operation of the plant can still be performed in a timely manner. Refer to Section 202.9.3, Natural Phenomenon or Condition Threatening Plant Safety (External Threat) of this directive for additional discussion on actual threats and significantly hampering personnel.

EXAMPLES Reportable

a. A turbine building evacuation was ordered when a large area of the floor was contaminated. Condensate demineralizer resin was being transferred through a cleaner to a mix-and-hold tank. As the tank was being pressurized, a mispositioned inlet valve allowed 50 to 100 gallons of water/resin to blow out into the turbine building. The ventilation system spread loose surface contamination through various turbine building locations. Eight operators and construction workers were contaminated.

An LER is required because plant operators were significantly hampered in the performance of their duties because they were evacuated from areas containing safety-related equipment and would have been delayed in their duties during an emergency.

REVISION 21 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 Non-Reportable

b. A small hydrazine leak occurred in the yard as a result of transporting a drum that was inadvertently punctured. An ENS notification is not required under this reporting section since the toxic gas leak posed no threat to the safety of the plant, nor did it significantly hamper personnel in the performance of their duties necessary for plant safety. However, depending on the circumstances, this event may be reportable under other 50.72 criteria such as Section 202.8.4, News Release or Other Government Notifications (notification to outside agencies) if not an emergency class declaration.

202.9.6 SYSTEM ACTUATIONS

§50.72(b)(3 )(iv) §50.73(a)(2)(iv)

Licensees shall report: Licensees shall report:

(A) Any event or condition that results in valid (A) Any event or condition that resulted in manual or actuation of any of the systems listed in paragraph automatic actuation of any of the systems listed in (b)(3)(iv)(B) of this section except when the paragraph (a) (2) (iv) (B) of this section, except actuation results from and is part of a pre-planned when:

sequence during testing or reactor operation.

(I) The actuation resulted from and was part of a (B) The systems to which the requirements of paragraph pre-planned sequence during testing or reactor (b)(3)(iv)(A) of this section apply are: operation; or

1. Reactor protection system (RPS) including:

(2) The actuation was invalid and; reactor scram and reactor trip.

5

2. General containment isolation signals affecting (i) Occurred while the system was properly containment isolation valves in more than one removed from service; or (ii) Occurred after the safety function had system or multiple main steam isolation valves been completed.

(MSIVs).

(B) The systems to which the requirements of paragraph

3. Emergency core cooling systems(ECCS) for (a)(2)(iv)(A) of this section apply are:

pressurized water reactors (PWRs) including:

high-head, intermediate-head, and low-head 1. Reactor protection system (RPS) including: reactor scram and reactor trip.

5 injection systems and the low pressure injection function of residual (decay) heat removal systems 2. General containment isolation signals affecting

4. PWR auxiliary or emergency feedwater system. containment isolation valves in more than one system or multiple main steam isolation valves

5. Containment heat removal and depressurization (MSIVs).

systems, including containment spray and fan cooler systems. 3. Emergency core cooling systems (ECCS) for pressurized water reactors (PWRs) including:

6. Emergency ac electrical power systems, including:

emergency diesel generators (EDGs); high-head, intermediate- head, and low-head hydroelectric facilities used in lieu of EDGs at the injection systems and the low pressure injection Oconee Station. function of residual (decay) heat removal systems.

4. PWR auxiliary or emergency feedwater system.

5. Containment heat removal and depressurization Actuation of the RPS when the reactor is critical is systems, including containment spray and fan cooler reportable under paragraph (b)(2)(iv) of this section. systems.

6. Emergency ac electrical power systems, including:

emergency diesel generators (EDGs); hydroelectric facilities used in lieu of EDGs at the Oconee Station.

7. Emergency service water systems that do not normally run and that serve as ultimate heat sinks.

22 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 Definitions

a. Valid actuations are those actuations that result from valid signals or from intentional manual initiation, unless it is part of a preplanned test. Valid signals are those signals that are initiated in response to actual plant conditions or parameters satisfying the requirements for initiation of the safety function of the system.

They do not include those that are the result of other signals

b. Invalid actuations are, by definition, those that do not meet the criteria for being valid. Thus, invalid actuations include actuations that are not the result of valid signals and are not intentional manual actuations.

Some invalid actuations are still reportable (see examples).

These systems specific to each station are listed in Appendix A.

c. RPS Actuation: (1) Receipt of a Solid State Protection System (SSPS) signal(s) necessary to activate the RPS system, or (2) manual or automatic actions that activate the RPS system without the presence of an SSPS signal(s).

d. Actuation of multichannel systems is defined as actuation of enough channels to complete the minimum actuation logic. Therefore, single channel actuations, whether caused by failures or otherwise, are not reportable if they do not complete the minimum actuation logic. Note, however, that if only a single logic channel actuates when, in fact, the system should have actuated in response to plant parameters, this would be reportable under these paragraphs as well as under 10 CFR 50.72(b)(3)(v) and 10 CFR 50.73(a)(2)(v)

(event or condition that could have prevented the fulfillment of the safety function of....

).

e. Preplanned Actuation: A preplanned system actuation is the initiation of a particular system as called for by an approved operating or testing procedure.

f. Properly Removed From Service: The component or system is intentionally mechanically or electrically disabled such that it is not capable of performing its intended safety function, and station procedures for removing equipment from service have been implemented (e.g., required clearance documentation, equipment and control board tagging, etc.).

g. General Containment Isolation Signals: General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves do not include the containment ventilation isolation (SH). The referenced signals include those signals that are provided to systems that mitigate the consequences of a significant event and are credited in the Chapter 15 of the UFSAR. The SH is not credited in Chapter 15 of the UFSAR nor is it credited as an engineered safety feature.

2. Reportability These paragraphs require events to be reported whenever one of the specified systems actuates either manually or automatically.

These systems are provided to mitigate the consequences of a significant event and, therefore:

a. they should work properly when called upon, and

b. they should not be challenged frequently or unnecessarily.

The NRC is interested both in events where a system was needed to mitigate the consequences (whether or not the equipment performed properly) and events where a system operated unnecessarily. Generally, the NRC would not consider this to include single component actuations because single components of complex systems, by themselves, usually do not mitigate the consequences of significant events. However, in some cases a component would be sufficient to mitigate the event (i.e., perform the safety function) and its actuation would then be reportable.

Since single trains do mitigate the consequences of significant events, train level actuations are reportable. In this regard, actuation of a diesel-generator is considered to be an actuation of a train and not an actuation of a single component because a diesel generator is needed to mitigate the event (performs the safety function)

REVISION 21 23 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 The ECCS contains systems that have no other operating function as well as systems that are shared with other systems. Actuations of ECCS systems which are shared with other systems is reportable only when they are performing their safety function.

An actuation of any of the systems named in § 50.73(a)(2)(iv)(B) is reportable under §50.73(a)(2)(iv)(A) [a 60-day report] unless the actuation resulted from and was part of a preplanned sequence during testing or reactor operation or the actuation was invalid and occurred while the system was properly removed from service or occurred after the safety function had been already completed. As indicated in 50.73(a)(l), in the case of an invalid actuation reported under 50.73(a)(2)(iv)(A) other than actuation of the reactor protection system (RPS) when the reactor is critical the licensee may. at its option, provide a telephone notification to the NRC Operations Center within 60 days after discovery of the event instead of submitting a written LER. In these cases the telephone report:

(I) Is not considered an LER.

(2) Should identify that the report is being made under 50.73(a)(2)(iv)(A).

(3) Should provide the following information:

(a) The specific train(s) and system(s) that were actuated.

(b) Whether each train actuation was complete or partial.

(c) Whether or not the system started and functioned successfully.

VALID Signals versus instrument drift or mis-calibration: If a transient is in progress such that a plant parameter approaches an actuation setpoint. and an actuation of a listed system occurs sooner than expected, (i.e., outside of the allowed tolerances), the signal should initially be considered VALID and reported per 50.72 (This position assumes that the transient would have reached the actuation setpoint if not terminated or mitigated by the actuation. The 50.72 notification can be retracted if subsequent analysis concludes that the transient could not have reached the setpoint if the actuation were assumed not to occur.

It is not expected that such an analysis could be completed within the 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months notification requirement.).

Conversely, if a listed system is operating at essentially steady-state (i.e. ,within normal operating range) and is apparently actuated due to calibration drift of the instrumentation outside of the allowed tolerances, then, the signal should be treated as iNVALID.

3. Reporting Exceptions Except for critical scrams, invalid actuations are not reportable by telephone under 50.72. In addition, invalid actuations are not reportable under § 50.73 in any of the following circumstances:

(A) The invalid actuation occurred when the system is already properly removed from service. This means all requirements of plant procedures for removing equipment from service have been met. It includes required clearance documentation, equipment and control board tagging, and properly positioned valves and power supply breakers.

(B) The invalid actuation occurred after the safety function has already been completed. An example would be RPS actuation after the control rods have already been inserted into the core.

However, if one of the specified systems actuate during the planned operation or test in a way that is not part of the planned procedure, such as at the wrong step, that event is reportable.

EXAMPLES Reportable Note: {For the reportable examples provided, assume the actuation is the result of a valid signal, is not part of a pre-planned sequence in a procedure and the system has not been removed from service.} This note applies to examples a-k.

a. Any manual or automatic actuation of the reactor trip switchgear is reportable.

24 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202

b. Initiation of a containment isolation signal constitutes an actuation whether or not the containment isolation valve actually repositions.

c. The opening of a Hydrogen Skimmer fan header isolation valve and the subsequent starting of a Hydrogen Skimmer fan is an actuation.

d. The starting or speed change of a Reactor Building Cooling Unit fan, as a result of an ES Channel 5 or 6 signal, is reportable. (ONS)

e. The starting of any of the ECCS pumps to mitigate the consequences of a significant event is an activation.

f. Any manual or automatic actuation of the Auxiliary (CA)/Emergency Feedwater( EFW) system is reportable. At ONS, The Steam Generator Dry-out Protection Circuit does not perform a credited safety function. By definition, it is an INVALID signal so EFW actuations due to it are NOT reportable under 50.72 but are reportable under 50.73.

g. Unplanned Diesel Generator starts, and Keowee starts resulting from ES Channel 1 or 2 signals, are reportable.

h. Emergency power switching logic actuations of4l6OV breakers which result from ES 1 or 2 signals are reportable. (ONS)

i. During a significant operational transient, an ice condenser door open alarm was received in the Control Room. This is a reportable event because if the Ice Condenser doors are off their seals, the equipment is considered actuated.

j. Swaps of Nuclear Service Water pumps suction from the lake to the Standby Nuclear Service Water pond are reportable under 50.73. However, they are NOT reportable to the NRC Operations Center under 10 CFR 50.72(b)(3)(iv).

k. Actuation of the SSF- ASW pump is reportable under 50.73. However, it is NOT reportable to the NRC Operations Center under 10 CFR 50.72(b)(3)(iv). (ONS)

Non-Reportable

a. Equipment actuation because of a signal generated by EMFs (radiation monitors) is not reportable.

b. RPS actuates after all control rods and banks have already been inserted in the core.

c. During surveillance testing of the main steam isolation valves (MSIVs), an operator incorrectly closed MSIV D when the procedure specified closing MSIV C. This event is not reportable because the event is an inadvertent actuation of a component of a system.

d. Movement of a single valve swapped the suction of the Nuclear Service Water System to the Auxiliary Feedwater pump suction. Since only a single component was actuated and the valve could not mitigate the consequences of an event by itself, the valve movement is not reportable as an actuation.

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VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 202.9.7 EVENT OR CONDITION THAT COULD HAVE PREVENTED THE FULFILLMENT OF SAFETY FUNCTION OF SYSTEMS OR STRUCTURES

§50.72(b)(3)(v) §50.73(a)(2)(v)

Licensees shall report: Any event or condition that at Licensees shall report: Any event or condition that the time of discovery could have prevented the could have prevented the fulfillment of the safety fulfillment of the safety function of structures or systems function of structures or systems that are needed to:

that are needed to: a. Shut down the reactor and maintain it in a safe

a. Shut down the reactor and maintain it in a safe shutdown condition; shutdown condition; b. Remove residual heat;

b. Remove residual heat; Control the release of radioactive material; or c.

c. Control the release of radioactive material; or Mitigate the consequences of an accident.

d.

d. Mitigate the consequences of an accident. §5O.73(a)(2)(vi)

§50.72(b)(3)(vi) Events covered in paragraph (a)(2)(v) of this section Events covered in paragraph (b)(3)(v) of this section may include one or more procedural errors, equipment may include one or more procedural errors, equipment failures, and/or discovery of design, analysis, failures, and/or discovery of design, analysis, fabrication, construction, and/or procedural fabrication, construction, and/or procedural inadequacies. However, individual component failures inadequacies. However, individual component failures need not be reported pursuant to paragraph (a)(2)(v) of need not be reported pursuant to paragraph (b)(3)(v) of this section if redundant equipment in the same system this section if redundant equipment in the same system was operable and available to perform the required was operable and available to perform the required safety function.

safety function.

Note: This reporting criterion shall be reviewed for applicability to any plant condition that caused both trains to be inoperable.

1. General The intent of this section is to capture those events where there could have been a failure of a safety system to properly complete a safety function, regardless of when the failures were discovered or whether the system was needed at the time. The event must be reported regardless of the situation or condition that caused the system to be unavailable, and regardless of whether or not an alternate safety system could have been used to perform the safety function.

The level ofjudgement for reporting an event or condition under this criteria is a reasonable expectation of preventing fulfillment of safety function.

If the event or condition could have prevented fulfillment of the safety function at the time of discovery an ENS notification is required. If it could have prevented fulfillment of the safety function at any time within 3 years of the date of discovery an LER is required.

The applicability of this section includes those safety systems designed to mitigate the consequences of an accident (e.g., containment isolation). Hence, minor operational events involving a specific component such as valve packing leaks, which could be considered a lack of control of radioactive material, should not be reported under this section.

In determining the reportability of an event or condition that affects a system, it is not necessary to assume an additional random single failure in that system; however, it is necessary to consider other existing plant conditions.

It should be noted that a reportable condition does not exist if you knowingly disable a safety function by removing all trains of a safety system from service provided this is done within a Tech Spec action statement time limit and within an approved procedure (Which is presumed to have properly evaluated the risk and need 26 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 for compensatory actions or controls.). However, it appears that it is the intent of the NRC to report any failure, or discovery of a procedure deficiency, that unexpectedly prevented the fulfillment of the safety function (In such a case the approved procedure was NOT approved with the thought in mind that it defeated a safety function.).

This logic is extended to the situation where one train of a system is removed from service for maintenance or testing (in accordance with Tech Specs) and the redundant train fails or is discovered to be inoperable. The resulting condition is an unplanned loss of safety function and the event is reportable. Again, planned removal would not be reportable.

In regards to single-train systems, there are a limited number of single-train systems that perform safety functions. At Duke, specifically at ONS, the single-train system is the Standby Shutdown Facility (SSF). The SSF is included in ONS Tech Specs but is not credited in Chapter 15 of the plants safety analysis. Existing guidance in NUREG 1022 specifies that a loss of a single-train system is reportable even though the plants Tech Specs may allow such a condition to exist for a limited length of time. The guidance was modified and clarified by specifying that the inclusion of the system in the plants Tech Specs indicated that the system was needed to perform one of the designated safety functions and was therefore subject to the reporting requirement. The reference to the Tech Specs was based on an assumption that if a system was included in the Tech Specs, then credit for the system was taken in the UFSAR. However, the NRC has reconsidered this position and now concludes that in order for the failure of a single-train system to be reportable as a loss of safety function, the system must be credited in mitigating design basis accidents described in Chapter 15 of the plants safety analysis.

Therefore, failure of the SSF at ONS is not reportable per the criterion of this section simply because it is in the plants Tech Specs. In order for the failure to be reportable as a loss of safety function, the system must be credited in the plants safety analysis.

2. Single Train/Common-Mode Failure These reporting criteria are not meant to require reporting of a single, independent component failure that makes only one functionally redundant train inoperable. The following conditions, however, are reportable:

- an actual single event or condition that disabled multiple trains of a safety-related system

- an actual event or condition that disabled one train of a safety-related system and could have affected a redundant train

- a condition or potential single event that could have disabled multiple trains of a safety-related system Engineering judgement should be used when these criteria are applied to those few systems with more than 2 redundant trains (e.g., MNS/CNS CA system).

3. Non-Reportable Events or Conditions

- failures that affect inputs or services to systems that have no safety function

- defective component(s) that has not been installed

- unrelated component failures in several different safety systems

- a single stuck control rod that alone would not have prevented the fulfillment of a reactor shutdown

- removal of a system or part of a system from service as part of a planned evolution for maintenance or surveillance testing when done in accordance with an approved procedure and the plants Tech Specs (unless a condition is discovered that could have prevented the system from performing its function)

A design or analysis defect or deviation is reportable under this criterion if it could have prevented fulfillment of the safety function of structures or systems defined in the rules. Reportability of a design or analysis defect or deviation under this criterion should be judged on the same basis that is used for other conditions, such as operator errors and equipment failures. That is, the condition is reportable if there is a reasonable expectation of preventing fulfillment of the safety function. Alternately stated, the condition is reportable if there was reasonable doubt that the safety function would have been fulfilled if the structure or system had been called upon to perform it.

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VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 OTHER EXAMPLES Reportable

a. During a refueling outage, the equipment hatch was discovered open 1/4 after containment integrity had been established.

b. While train A VC/YC was inoperable due to maintenance, the B train YC chiller tripped and could not be restarted. Tech Spec 3.0.3 was entered for 90 minutes because both trains of the VC system were inoperable. There was no load reduction since operators felt that 1 of the trains would be back in service within 2 hours0.0833 days 0.0119 weeks 0.00274 months . This event is reportable as a loss of safety function.

Non-Reportable

c. While performing a main steam line Pressure Instrument Functional Test and Calibration, a switch was found to actuate at 853 psig. The Tech Spec limit is 825 + 15 psig head correction. The redundant switches were operable. The cause of the occurrence was setpoint drift. The switch was recalibrated, tested successfully per procedure and returned to service. The event is not reportable due to the drift of a single pressure switch unless it could have caused a system to fail to fulfill its safety function.

202.9.8 COMMON-MODE FAILURES OF INDEPENDENT TRAINS OR CHANNELS 10 CFR 50.72 §50.73(a)(2)(vii)

[ No corresponding Part 50.72 requirement.] Licensees shall report: Any event where a single cause or condition caused at least one independent train or channel to become inoperable in multiple systems or two independent trains or channels to become inoperable in a single system designed to:

a. Shut down the reactor and maintain it in a safe shutdown condition;

b. Remove residual heat;

c. Control the release of radioactive material; or

d. Mitigate the consequences of an accident.

General This section requires those events to be reported where a single cause made a component or group of components to become inoperable in redundant or independent trains or channels, of one or more systems having a safety function (common-mode failures). Failures reported under this part of the rule should be actual failures, not potential ones.

Such failures can be simultaneous which occur from a single initiating cause, or sequential (i.e., cascade failures), such as the case where a single component failure results in the failure of one or more additional components.

To be reportable, however, the event or failure must result in or involve the failure of independent portions of more than one train or channel in the same or different systems. For example, if a single cause or condition resulted in inoperable components in Train A of the KC System and Train B of the Nuclear Service Water (RN) system (i.e., train that is assumed in the safety analysis to be independent) the event is reportable.

Additionally, one function of the B train of the RN system is to provide cooling for the B train of the KC System, and since B train of the RN system cannot perform its cooling function, then B train of the KC 28 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 system is also inoperable. Thus, both trains of the KC system are inoperable and unable to perform their safety function.

EXAMPLES Reportable

a. Events reportable under Section 202.9. 7, Event or Condition That Could Have Prevented the Fulfillment of Safety Function of Systems or Structures of this directive are also reportable per this section provided:

(1) the system involved has 2 or more trains or channels, and (2) the inoperable condition is as a result of actual failures.

b. The station found 11 inoperable snubbers during periodic testing. All the snubbers failed to lock up when required. These failures rendered trains in 3 systems inoperable. This condition is reportable because the condition indicated a generic common-mode problem that caused numerous multiple independent trains in one or more safety systems to become inoperable.

Non-Reportable

c. Design investigation indicated that electrical power feed to the VE filter train heaters can be postulated to drop to a sustained voltage that would place power dissipation outside the required range. Both trains of VE were considered inoperable. This condition is not reportable under this section because the condition was not an actual failure of both trains, but a postulated event that could have prevented the fulfillment of the safety function of the VE system, and is reportable under Section 202. 9. 7, Event or Condition That Could Have Prevented the Fulfillment of Safety Function of Systems or Structures, ref. Example 2.

202.9.9 AIRBORNE OR LIQUID EFFLUENT RELEASE EXCEEDING 20 TIMES APPENDIX B

§50.72 50.73(a)(2)(viii)

There is no 50.72 requirement. Licensees shall report:

Refer to the plants Emergency Plan regarding a. Any airborne radioactivjly release that when declaration of an Emergency Class. averaged over a time period of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , resulted in airborne radionuclide concentrations in an Refer to § 50.72(b)(2)(xi) below regarding a news unrestricted area that exceeded 20 times the release or notification of another agency. . . .

applicable concentration limits specified in Refer to § 20.2202 regarding events reportable under Appendix B, to Part 20, Table 2, Column 1.

that section. ,,

Any liquid effluent release that, when averaged over a time period of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , exceed 20 times the applicable concentrations specified in Appendix B to Part 20, Table 2, Column 2, at the point of entry into the receiving waters (i.e., unrestricted area) for all radionuclides except tritium and dissolved noble gases.

1. General This section is similar to Part 20.2203, but places a lower threshold for reporting events at commercial power reactors. The lower threshold is based on the significance of the breakdown of the stations program necessary to have a release of this size, rather than on the significance of the impact of the actual release. For a release that takes less than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , normalize the release to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (e.g., release of 15 minutes, multiply by 4). For releases that last more than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , use the highest release for any continuous 60 minute period. It often takes a period of time to assess the magnitude of a radioactive release EXAMPLE Reportable REVISION 21 29 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2

a. During routine maintenance on a pressure actuated valve in the waste gas system, an unplanned radioactive release to the environment was detected by a radiation alarm. The release occurred when an isolation valve, required to be closed, was inadvertently left open. This allowed radioactive gas from the waste gas decay tank to escape through a pressure gage connection that had been opened to vent the system. The concentration at the site boundary, averaged over 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , was estimated by the station to exceed the limits specified in §50.73 (a)(2)(viii).

202.9.10 CONTAMINATED PERSON REQUIRING TRANSPORT TO OFFSITE MEDICAL FACILITY

§50.72(b)(3)(xii) 10 CFR 50.73 Licensees shall report: Any event requiring the [No corresponding Part 50.73 requirement.]

transport of a radioactively contaminated person to an offsite medical facility for treatment.

1. General Contaminated, in this case, refers to either contaminated clothing, the person, or both. If the initial onsite survey is incomplete and there is a potential for contamination, the station should assume the individual is contaminated and make the ENS notification. Often the full extent of radioactive contamination on an injured individual may not be known until after arrival at the hospital. If no potential for contamination is present, reporting of the transport to offsite medical facilities is not required.

EXAMPLES Reportable

a. A contract worker experienced a back injury lifting a tool while working in the reactor building and was considered to be potentially contaminated because his back could not be surveyed. An ENS call was made immediately. The individual was later found not to be contaminated and an update ENS notification was made.

Non-Reportable

b. The station transported a high school student from its PAP to a medical office because the student had stomach pains. This event is not reportable because no potential for contamination was present.

c. An employee cut his head in the containment pipe chase. RP reported that the individual was not contaminated but was being transported to the hospital. The event is not reportable because no potential for contamination was present.

202.9.11 SINGLE CAUSE THAT COULD HAVE PREVENTED FULFILLMENT OF THE SAFETY FUNCTIONS OF TRAINS OR CHANNELS IN DIFFERENT SYSTEMS

§50.72 § 50.73 (a)(2)(ix)

There is no corresponding requirement in (A) Any event or condition that as a result of a single cause could have prevented the fulfillment of a safety

§ 50. 72.

. .

requirement in . .

function for two or more trains or channels in different systems that are needed to:

1) Shut down the reactor and maintain it in a safe shutdown condition;

2) Remove residual heat;

3) Control the release of radioactive material; or 30 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202

4) Mitigate the consequences of an accident.

(B) Events covered in paragraph (ix)(A) of this section may include cases of procedural error, equipment failure, and/or discovery of a design, analysis, fabrication, construction, andlor procedural inadequacy. However, licensees are not required to report an event pursuant to paragraph (ix)(A) of this section if the event results from:

1) A shared dependency among trains or channels that is a natural or expected consequence of the approved plant design; or

2) Normal and expected wear or degradation.

General Subject to the two exclusions stated in the rule, this criterion captures those events where a single cause could have prevented the fulfillment of the safety function of multiple trains or channels, but the event:

(1) Would not be captured by § 50.73(a)(2)(v) and 50.72(b)(3)(v) [event or condition that could have prevented fulfillment of the safety function of structures and systems needed to ] because the affected

...

trains or channels are in different systems; and (2) Would not be captured by § 50.73(a)(2)(vii) [common cause inoperability of independent trains or channels]

because the affected trains or channels are either:

(a) Not assumed to be independent in the plants safety analysis; or (b) Not both considered to be inoperable.

This criterion is closely related to § 50.73(a)(2)(v) and 50.72(b)(3)(v) [event or condition that could have prevented fulfillment of the safety function of structures and systems needed to: shut down the reactor and maintain it in a safe shutdown condition; remove residual heat; control the release of radioactive material; or mitigate the consequences of an accident]. Specifically:

The meaning of the term could have prevented the fulfillment of the safety function is essentially the same for this criterion as it is for § 50.73(a)(2)(v) and 50.72(b)(3)(v) [i.e., there was a reasonable expectation of preventing the fulfillment of the safety function(s) involved]. However, in contrast to § 50.73(a)(2)(v) and 50.72(b)(3)(v), reporting under this criterion applies to trains or channels in different systems. Thus, for this criterion, the safety function that is affected may be different in different trains or channels.

In contrast to § 50.73(a)(2)(v) and 50.72(b)(3)(v), reporting under this criterion applies only to a single cause.

Also, in contrast to § 50.73(a)(2)(v) and 50.72(b)(3)(v), this criterion does not apply to an event that results from a shared dependency among trains or channels that is a natural or expected consequence of the approved plant design. For example, this criterion does not capture failure of a common electrical power supply that disables Train A of AFW and Train A of HPSI, because their shared dependency on the single power supply is a natural or expected consequence of the approved plant design.

Similar to § 50.73(a)(2)(v) and 50.72(b)(3)(v), this criterion does not capture events or conditions that result from normal and expected wear or degradation. For example, consider pump bearing wear that is within the normal and expected range. In the case of two pumps in different systems, this criterion categorically excludes normal and expected wear. In the case of two pumps in the same system, normal and expected wear should be adequately addressed by normal plant operating and maintenance practices and thus should not indicate a reasonable expectation of preventing fulfillment of the safety function of the system.

The level ofjudgment for reporting an event or condition under this criterion is a reasonable expectation of preventing fulfillment of a safety function. In the discussions that follow, several different expressions such as would have, could have, alone could have, and reasonable doubt are used to characterize this standard. In the staffs view, all of these should be judged on the basis of a reasonable expectation of preventing fulfillment of REVISION 21 31 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 the safety function.

The intent of this criterion is to capture those events where, as a result of a single cause, there would have been a failure of two or more trains or channels to properly complete their safety function, regardless of whether there was an actual demand. For example if, as a result of a single cause, a train of the high pressure safety injection system and a train of the auxiliary feedwater system failed, the event would be reportable even if there was no demand for the systems safety functions.

Examples of a single cause responsible for a reportable event may include cases of procedural error, equipment failure, and/or discovery of a design, analysis, fabrication, construction, and/or procedural inadequacy. They may also include such factors as high ambient temperatures, heat up from energization, inadequate preventive maintenance, oil contamination of air systems, incorrect lubrication, or use of non-qualified components.

The event is reportable if, as a result of a single cause, there would have been a failure of two or more trains or channels to properly complete their safety function, regardless of whether the problem was discovered in both trains at the same time.

Trains or channels for reportability purposes are defined as those trains or channels designed to provide protection against single failures. Many systems containing active components are designed as at least a two-train system. Each train in a two-train system can normally satisfy all the system functions.

This criterion does not include those cases where trains or channels are removed from service as part of a planned evolution, in accordance with the plants Tech Specs. For example, if a licensee removes two trains from service to perform maintenance, and the Tech Specs permit the resulting configuration, and the trains are returned to service within the time limits specified in the Tech Specs, the action need not be reported under this paragraph. However, if, while the trains or channels are out of service, the licensee identifies a single cause that could have prevented the trains from performing their safety functions (e.g., the licensee finds a set of relays that is wired incorrectly), that condition must be reported.

The definition of the systems included in the scope of this criterion is provided in the rule itself. It includes systems required by the Tech Specs to be operable to perform one of the four functions specified in the rule. It is not determined by the phrases safety- related, important to safety, or ESF.

Trains or channels must operate long enough to complete their intended safety functions as defined in the safety analysis report.

Generic Letter 9 1-18 provides guidance on determining whether a system is operable.

The application of this reporting criterion and other reporting criteria involves the use of engineering judgment. In the case of this criterion, a technical judgment must be made as to whether a failure or operator action that did actually disable one train or channel, could have, but did not, disable another train or channel. If so, this would constitute an event that could have prevented the fulfillment of the safety function of multiple trains or channels, and, accordingly, must be reported.

Reporting is required if one train or channel fails and, as a result of a single cause, there is reasonable doubt that another train or channel would remain operational until it completed its safety function or is repaired. For example, if a pump fails because of improper lubrication, and engineering judgment indicates that there is a reasonable expectation that another pump in a different system, which was also improperly lubricated, would have also failed before it completed its safety function, then the event is reportable under this criterion.

Reportable conditions under this criterion include the following:

- an event or condition that disabled multiple trains because of a single cause

- an event or condition where one train is disabled; in addition, (1) the underlying cause that disabled one train of a system could have failed another train and (2) there is reasonable expectation that the second train would not complete its safety function if it were called upon to do so

- an observed or identified event or condition that could have prevented fulfillment of the safety function of multiple trains or channels as a result of a single cause The following types of events or conditions generally are not reportable under this criterion:

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- failures that affect inputs or services to systems that have no safety function (unless it could have prevented the performance of a safety function of an adjacent or interfacing system)

- a defective component that was delivered, but not installed

- removal of trains or channels from service as part of a planned evolution for maintenance or surveillance testing when done in accordance with the plants Technical Specifications (unless a condition is discovered that could have prevented multiple trains or channels from performing their safety functions)

- independent failure of a single component (unless it is indicative of a generic problem, which could have caused failure of multiple trains or channels)

- a procedure error that could have resulted in defeating the safety function of multiple trains or channels but was discovered before procedure approval

- a failure of a system used only to warn the operator where no credit is taken for it in any safety analysis and it does not directly control any of the four safety functions in the rule

- a single stuck control rod that would not have prevented the fulfillment of a reactor shutdown

- unrelated component failures in different trains or channels Minor operational events involving a specific component such as valve packing leaks, which could be considered a lack of control of radioactive material, should not be reported under this criterion.

A design or analysis defect or deviation is reportable under this criterion if it could have prevented fulfillment of the safety function of multiple trains or channels. Reportability of a design or analysis defect or deviation under this criterion should be judged on the same basis that is used for other conditions, such as operator errors and equipment failures. That is, the condition is reportable if there is a reasonable expectation of preventing fulfillment of the safety function(s) of multiple trains or channels. Alternatively stated, the condition is reportable if there was reasonable doubt that the safety functions of multiple trains or channels would have been fulfilled if there were demands for them.

EXAMPLES Reportable a) Solenoid Operated Valve Deficiency During testing, two containment isolation valves failed to function as a result of improper air gaps in the solenoid operated valves that controlled the supply of instrument air to the containment isolation valves.

The valves were powered from the same electrical division. Thus, § 50.73(a)(2)(vii) [common cause inoperability of independent trains or channels] would not apply. The two valves isolated fluid process lines in two different systems. Thus § 50.73(a)(2)(v) [condition that could have prevented fulfillment of the safety function of a structure or system] would apply only if engineering judgment indicates there was a reasonable expectation of preventing fulfillment of the safety function for redundant valves within the same system. Or, alternatively, there was reasonable doubt that the safety function would have been fulfilled if the affected trains had been called upon to perform them. However, this criterion would certainly apply if a single cause (such as a design inadequacy) induced the improper air gaps, thus preventing fulfillment of the safety function of two trains or channels in different systems.

b) Degraded Valve Stems A motor operated valve in one train of a system was found with a crack 75 percent through the stem. Although the valve stem did not fail, engineering evaluation indicated that further cracking would occur which could have prevented fulfillment of its safety function. As a result, the train was not considered capable of performing its specified safety function. The valve stem was replaced with a new one.

The root cause was determined to be environmentally assisted stress corrosion cracking which resulted from installation of an inadequate material some years earlier. The same inadequate material had been installed in a similar valve in a different system at the same time. The similar valve was exposed to similar environmental conditions as the first valve.

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c) Overpressure due to Thermal Expansion It was determined that a number of liquid-filled and isolated containment penetration lines in multiple safety systems were not adequately designed to accommodate the internal pressure buildup that could occur because of thermal expansion caused by heatup after a design basis accident. The problem existed because the original design failed to consider this effect following a postulated accident.

The condition is reportable under this criterion because there was a reasonable expectation of preventing fulfillment of the safety function of multiple trains or channels as a result of a single cause.

d) Cable Degradation One of three component cooling water pumps tripped due to a ground fault on a power cable leading to the pump. The likely cause was determined to be moisture permeation into the cable insulation over time in a section of cable that was exposed to water.

e) Overstressed Valve Yokes The event is reportable under this criterion if engineering judgment indicates that there was a reasonable expectation of preventing fulfillment of the safety function of an additional train in a different system as a result of the same cause. For example, if cable testing indicates that another cable to safety related equipment was likely to fail as a result of the same cause the event is reportable.

It was determined that numerous motor operated valve yokes experienced over thrusting that exceeded design basis stress levels.

The cause was lack of knowledge that resulted in inadequate design engineering at the time the designs were performed.

Some of the motor operated valve yokes, in different systems, were being over stressed enough during routine operations that, although they were currently capable of performing their specified safety functions, the over stressing would, with the passage of time, render them incapable of performing those functions. The condition is reportable under this criterion if engineering judgment indicates there was a reasonable expectation of preventing fulfillment of the safety function of trains or channels in two or more different systems.

Non-Reportable f) Heat Exchanger Fouling Periodic monitoring of heat exchanger performance indicated that two heat exchangers in two different systems required cleaning in order to ensure they would remain operable. The degree of fouling was within the range of normal expectations upon which the monitoring and maintenance procedures were based.

The event is not reportable under this criterion because there was not a reasonable expectation of preventing the fulfillment of the safety function of the heat exchangers.

g) Pump Vibration Based on increasing vibration trends, identified by routine vibration monitoring, it was determined that a pumps bearings required replacement. Other pumps in different systems with similar designs and service histories experience similar bearing degradation. However, it is expected that the degradation will be detected and corrected before failure occurs. Such bearing degradation is not reportable under this criterion because it is normal and expected.

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VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 202.10 FOLLOWUP NOTIFICATION

§ 50.72 (c) § 50.73 Followup Notification. With respect to the telephone There is no corresponding requirement in § 50.73.

notifications made under paragraphs (a) and (b) of this section, in addition to making the required initial notification, each licensee shall, during the course of the event:

(1) Immediately report (i) any further degradation in the level of safety of the plant or other worsening plant conditions, including those that require the declaration of any of the Emergency Classes, if such a declaration has not been previously made, or (ii) any change from one Emergency Class to another, or (iii) a termination of the Emergency Class.

(2) Immediately report (i) the results of ensuing evaluations or assessments of plant conditions, (ii) the effectiveness of response or protective measures taken, and (iii) information related to plant behavior that is not understood.

(3) Maintain an open, continuous communication channel with the NRC Operations Center upon request by the NRC.

General 10CFR 50.72(c), Followup Notification, is in addition to making the required initial ENS notification under 50.72(a) or (b). Reporting under this section is intended to provide the NRC with timely notification when an event becomes more serious or additional information or new analysis clarify the event.

It is important that the station record the NRC 50.72 Report number in the appropriate procedure for the initial ENS phone call, so when notifications are made per this section, the station can provide the NRC the proper report number. Any new information to be given will be recorded as such on the NRCs original 50.72 report as an update.

The followup notification is required for data or analysis results that clarifS the plant conditions. Anytime a determination is made that a followup notification is required under 10CFR 50.72c, a formal notification shall be made using the ENS phone. Notification to the NRC Resident, other NRC representatives on site, or informally communicating on the open ENS line during an event is not a substitute for a 50.72 notification.

Since this criterion primarily deals with changes in plant status or analyses associated with emergency events, no discussion on the specific parts of the rule will be included in this directive, since current Emergency Plan implementing procedures provide adequate guidance (as stated in the Purpose of this directive).

202.11 OTHER EVENTS REQUIRING IMMEDIATE NOTIFICATION This section addresses immediate notification requirements for sections other than 50.72. The station is required to notify the NRC as soon as practical and in all cases within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of the occurrence of any of the events specified.

There are no examples available for these reporting sections.

REVISION 21 35 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 10CFR 20.2202a Each Licensee shall immediately report any incident involving byproduct, source or special nuclear material that may have caused or threatens to cause the following:

1. Individual Exposure Greater than or equal to 25 Rem total effective dose equivalent (TEDE) or Greater than or equal to 75 Rem eye dose equivalent (EDE) or Greater than or equal to 250 Rads shallow dose equivalent to the skin or extremities (SDE)

2. Release of radioactive material, inside or outside of a restricted area, so that, had an individual been present for 24 hours1 days 0.143 weeks 0.0329 months , the individual could have received an intake five times the annual limit on intake (the provisions of this paragraph do not apply to locations where personnel are not normally stationed during routine operations, such as hot cells or process enclosures).

10CFR2O.1906(d)(1) and (d)(2)

Notification to the NRC Regional Office, Region II, Atlanta, GA. following receipt of a package of radioactive materials where:

Removable radioactive surface contamination exceeds the limits of 10 CFR 71.87 (i) or External radiation levels exceed the limits of 10 CFR 71.47 Steam Generator Tube Plugging Catawba Tech Spec 5.5.9 and ONS Tech Spec Table 5.5.10-1 delineates the requirements for the SG tube surveillance program. If the results of the SG tube inspection requires a SG to be classified as Category C-3, prompt notification to the NRC pursuant to 10 CFR 50.72 is required.

Tech Spec Safety Limit Violation The station is required to notifi the NRC as soon as practical and in all cases within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of the occurrence of a Safety Limit violation. A follow-up written report is to be submitted within 30 days of the event.

202.12 INDEPENDENT SPENT FUEL STORAGE INSTALLATION (ISFSI)

REPORTING REQUIREMENTS Reporting Requirements Independent Spent Fuel Storage Installation (ISFSI) 10CFR72.75 (a) Emergency Notifications Adequate guidance currently exist in each sites Emergency Plans implementing response procedures for emergency events and their classifications. For an ISFSI that is located on the site of a nuclear power reactor licensed for operation by the Commission, the emergency plan required by 10CFR5O.47 shall be deemed to satis the requirements of this section.

The sections that follow address guidelines for reporting four and twenty-four hour notifications for non-emergency events and the associated event report. There are no examples available for these sections.

36 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 IOCFR72.75 (b) Four hour reports The station is required to notify the NRC as soon as practical and in all cases within 4 hours0.167 days 0.0238 weeks 0.00548 months of the occurrence of any of the following events or conditions involving spent fuel or high-level radioactive waste:

1. An action taken in an emergency that departs from a condition or a technical specification contained in a license or certificate of compliance issued under this part when the action is immediately needed to protect the public health and safety and no action consistent with license or certificate of compliance conditions or technical specifications that can provide adequate or equivalent protection is immediately apparent.

2. An event or situation, related to the health and safety of the public or on-site personnel, or protection of the environment, for which a news release is planned or notification to other government agencies has been or will be made.

10CFR72.75 (c) Eight hour reports I. A defect in any spent fuel, high-level radioactive waste, or reactor-related Greater then Class C (GTCC) waste storage structure, system, or component important to safety.

2. A significant reduction in the effectiveness of any spent fuel, high-level radioactive waste, or reactor-related GTCC storage confinement system during use.

3. An event that requires the transport of a radioactively contaminated person to an offsite medical facility for treatment.

10CFR72.75 (d) Twenty-four hour reports The station is required to notify the NRC as soon as practical and in all cases within 24 hours1 days 0.143 weeks 0.0329 months of the occurrence of any of the following events or conditions involving spent fuel or high-level radioactive waste:

I. An event in which safety equipment is disabled or fails to function as designed when:

a. The equipment is required by regulation, license condition, or certificate of compliance to be available and operable to prevent releases that could exceed regulatory limits, to prevent exposures to radiation or radioactive materials that could exceed regulatory limits, or to mitigate the consequences of an accident; and

b. No redundant equipment was available and operable to perform the required safety function.

IOCFR72.75(g) Written report The station is required to submit a written followup report within 60 days of an initial report required by paragraph (b) or (c) of this section. A written followup report is required for (b)(2) and (c)(3). The reports and copies that licensees are required to submit to the Commission under the provisions of this section must be of sufficient quality to permit legible reproduction and micrographic processing. Written reports prepared pursuant to other regulations may be submitted to fulfill this requirement if the reports contain all of the necessary information and the appropriate distribution is made.

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38 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE Nuclear Policy Manual Volume 2 NSD 202 APPENDIX A.202. SYSTEM ACTUATIONS System Actuations CNS MNS ONS

1. Containment Isolation Systems

a. Phase A/ES Chl I & 2 (Non-Essential Isolation) X X X

b. Phase B/ES ChI 5 & 6 (Essential Isolation) X X X

c. NW X

2. Containment Heat Removal

a. Ice Condenser X X

b. Air Return Fans X X

c. Containment/Reactor Building Spray X X X

d. Reactor Building Cooling Units X

3. Combustible Gas Control in Containment

a. Hydrogen Recornbiners X X

b. Air Return and Skimmer Fans X X

c. Hydrogen Purge X X

4. Emergency Core Cooling System

a. NV/HPI X X X

b. NI X X

c. ND/LPI X X X

d. CLAICFT X X X

e. FWST/BWST X X X I. Containment Sump Swapover X X

5. Auxiliary/Emergency Fccdwatcr System X X X

a. Station- ASW Pump (10 CFR 50.73 only) X

b. SSF-ASW Pump (10 CFR 50.73 only) X

6. Diesel Generator starts X X

7. Keowee starts (see Section 202.9.6, example g) X

8. Reactor Protection System X X X

9. Nuclear Service Water System Suction Transfer - (10 X X CFR 50.73 only)

10. Steam Line Isolation X X II. 4KVUndcrvoltagc X X X REVISION 21 39 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE NSD 202 Nuclear Policy Manual Volume 2 THIS PAGE LEFT BLANK INTENTIONALLY.

40 REVISION 21 VERIFY HARD COPY AGAINST WEB SITE IMMEDIATELY PRIOR TO EACH USE

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss Of DHR Time To Boil Page 1 of 51

1. Instructions For Use Of Tables In This Enclosure 1.1 Table Total Loss Of DHR Time To Boil With Filled Fuel Transfer Canal (Page 3) may be used to evaluate time to core boil when FTC is filled.

1.2 Prior to Refueling tables assume all fuel assemblies in the core have experienced operation at power.

NOTE: Curves with expanded time scales that measure time since Rx S/D in hours vs. days for Prior to Refueling initial temperatures of 80, 90, 100, and 110°F have been added to this enclosure. These curves must be used for the first 5 days (120 hours5 days 0.714 weeks 0.164 months ) after Rx S/D.

1.3 After Refueling tables assume approximately one third of the core is new fuel.

1.4 If RCS level is at some point between the columns provided, use the column for the next lower level.

Interpolation between provided levels shall NOT be attempted.

1.5 For tables that have time since Rx was shut down measured in hours, select the most recent whole hour.

1.6 For tables that have time since Rx was shut down measured in days, select the most recent whole day.

1.7 If Initial Temperature is between temperatures listed for each table, use table with the next highest temperature.

1.8 Indications to use for Initial Temperature (listed in order of preference for each mode):

1.8.1 If LPI is in High Pressure Mode, Series Mode, or Switchover Mode, use CETCs (avg. of five highest).

1.8.2 If LPI is in Normal DHR Mode, use CETCs (if available, avg. of five highest), OAC point OxA 1322 (LPI DHR / RBES A SUCTION HDR TEMP), or LPI Pump Suct. Temp. Line A Gauge.

2. Example Of Time To Boil Calculation 2.1 Given plant conditions:

Rx shutdown was 3/1/09 at 2200.

RV head removed, CETCs withdrawn in preparation for fuel removal from core.

For Example 1, calculation will be performed for 3/5/09 at 0300.

For Example 2, calculation will be performed for 3/8/09 at 0300.

RCS Level (LT-5) is +63.

RCS temperature is 83°F on OAC point OxA 1322 (LPI DHR / RBES A SUCTION HDR TEMP).

2.2 Calculation Steps (example I- calculation is within 5 days of Rx S/D) 2.2.1 Determine which page of Enclosure will be used for calculation:

A. Since fuel has not yet been removed from core (Prior to Refueling), one of the Time to Core Boil Prior to Refueling tables will be used.

B. RCS temperature is 83°F as read from OAC point OxA 1322. Since Initial Temperature is between temperatures listed for the 80°F table and the 90°F table, use table where Initial Temperature = 90°F (see Step 1.6 above).

EncLosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 2 of 51 2.2.2 Determine time to core boiling:

A. On table Time to Core Boil (Minutes)- Prior to Refueling Initial Temp.

-

= 90°F, (Hours Since S/D), perform the following:

1. The given time for the Rx shutdown is 3/1/09 at 2200. Calculate the number of hours that have passed since Rx shutdown, and note this in the Hours since S/D column.

Assume the calculation date is 3/5/09 at 0300; or 77 hours3.208 days 0.458 weeks 0.105 months after the Rx shutdown.

2. The given RCS Level is +63. On the table, choose the +60 column (See Step 1.3 above).

3. On the table, find the intersection of the +60 column and the 77 hour8.912037e-4 days 0.0214 hours 1.273148e-4 weeks 2.92985e-5 months row; the time to core boiling is shown to be 23.6 minutes in this example.

2.3 Calculation Steps (example 2- calculation is >5 days after Rx S/D) 2.3.1 Determine which page of Enclosure will be used for calculation:

A. Since fuel has not yet been removed from core (Prior to Refueling), one of the Time to Core Boil Prior to Refueling tables will be used.

B. RCS temperature is 83°F as read from OAC point OxA 1322. Since Initial Temperature is between temperatures listed for the 80°F table and the 90°F table, use table where Initial Temperature = 90°F (see Step 1.6 above).

2.3.2 Determine time to core boiling:

A. On table Time to Core Boiling Prior to Refueling Initial Temperature = 90°F,

-

perform the following:

1. The given time for the Rx shutdown is 3/1/09 at 2200. For this example, assume the calculation date is 3/8/09 at 0300. Calculate the number of full 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months days that have passed since Rx shutdown, and note this in the Time (Days) column. The S/D date falls on the 7th day after the Rx shutdown, but since it is only a partial day, Day 6 (most recent whole day; see Step 1.5 above) will be used.

2. The given RCS Level is +63. On the table, choose the +60 column (See Step 1.3 above).

3. On the table, find the intersection of the +60 column and the Day 6 row; the time to core boiling is shown to be 30.5 minutes in this example.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss Of DHR Time To Boil With Filled Page 3 of 51 Fuel Transfer Canal

1. Table below assumes the following conditions:

Initial conditions inside containment 140°F and containment vented to atmosphere

Initial RCS water temperature 140°F

Initial FTC level> 21.34 feet above reactor vessel flange

Core cycle length 24 months 1.1 Time-to-core saturation times with the fuel transfer canal filled are as follows:

Time After Shutdown Time-to-Saturation (hrs) 3 days 4.0 5 days 4.9 10 days 6.6 15 days 7.8 10 days with reloaded core 8.1 20 days with reloaded core 1 1.0

Enclosure 4.46 OP/O/A/1 108/00 1 Total Loss Of DHR Time To Boil Page 4 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =80°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since i Pressurizer S/D level 24 13.3 13.7 14.0 14.2 15.1 16.2 16.9 17.6 18.3 19.0 21.6 25 13.5 13.8 14.1 14.3 15.3 16.4 17.0 17.8 18.5 19.2 21.8 26 13.6 14.0 14.3 14.5 15.4 16.5 17.2 17.9 18.6 19.4 22.0 27 13.7 14.1 14.4 14.6 15.6 16.7 17.4 18.1 18.8 19.5 22.2 28 13.9 14.2 14.6 14.8 15.7 16.8 17.5 18.3 19.0 19.7 22.4 29 14.0 14.4 14.7 14.9 15.8 17.0 17.7 18.5 19.2 19.9 22.6 30 14.1 14.5 14.8 15.0 16.0 17.2 17.9 18.6 19.3 20.1 22.8 31 14.2 14.6 15.0 15.2 16.1 17.3 18.0 18.8 19.5 20.3 23.0 32 14.4 14.8 15.1 15.3 16.3 17.5 18.2 19.0 19.7 20.4 23.2 33 14.5 14.9 15.2 15.4 16.4 17.6 18.3 19.1 19.9 20.6 23.4 34 14.6 15.0 15.3 15.5 16.6 17.8 18.5 19.3 20.0 20.8 23.6 35 14.7 15.1 15.5 15.7 16.7 17.9 18.6 19.5 20.2 21.0 23.8 36 14.9 15.3 15.6 15.8 16.8 18.1 18.8 19.6 20.4 21.2 24.0 37 15.0 15.4 15.7 15.9 17.0 18.2 19.0 19.8 20.5 21.3 24.2 38 15.1 15.5 15.9 16.1 17.1 18.4 19.1 19.9 20.7 21.5 24.4 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/1108Ioo1 Total Loss OF DHR Time To Boil Page 5 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =80°F (Hours Since SID)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since I Pressurizer S/D level 39 15.2 15.6 16.0 16.2 17.3 18.5 19.3 20.1 20.9 21.7 24.6 40 15.4 15.8 16.1 16.3 17.4 18.7 19.4 20.3 21.0 21.9 24.8 41 15.5 15.9 16.2 16.4 17.5 18.8 19.6 20.4 21.2 22.0 25.0 42 15.6 16.0 16.4 16.6 17.7 19.0 19.7 20.6 21.4 22.2 25.2 43 15.7 16.1 16.5 16.7 17.8 19.1 19.9 20.7 21.5 22.4 25.4 44 15.8 16.2 16.6 16.8 18.0 19.3 20.0 20.9 21.7 22.5 25.6 45 16.0 16.4 16.7 16.9 18.1 19.4 20.2 21.1 21.9 22.7 25.8 46 16.1 16.5 16.9 17.1 18.2 19.6 20.3 21.2 22.0 22.9 26.0 47 16.2 16.6 17.0 17.2 18.4 19.7 20.5 21.4 22.2 23.0 26.2 48 16.3 16.7 17.1 17.3 18.5 19.8 20.6 21.5 22.3 23.2 26.4 49 16.4 16.8 17.2 17.4 18.6 20.0 20.7 21.7 22.5 23.4 26.5 50 16.5 17.0 17.4 17.5 18.7 20.1 20.9 21.8 22.6 23.5 26.7 51 16.7 17.1 17.5 17.7 18.9 20.3 21.0 22.0 22.8 23.7 26.9 52 16.8 17.2 17.6 17.8 19.0 20.4 21.2 22.1 23.0 23.8 27.1 53 16.9 17.3 17.7 17.9 19.1 20.5 21.3 22.3 23.1 24.0 27.3 54 17.0 17.4 17.8 18.0 19.3 20.7 21.5 22.4 23.3 24.2 27.5 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are J full JJ RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 oP/O/AI1 108/00 1 Total Loss OF DHR Time To Boil Page 6 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. 80°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since I Pressurizer S/D level 55 17.1 17.5 17.9 18.1 19.4 20.8 21.6 22.6 23.4 24.3 27.6 56 17.2 17.6 18.1 18.3 19.5 20.9 21.7 22.7 23.6 24.5 27.8 57 17.3 17.7 18.2 18.4 19.6 21.1 21.9 22.9 23.7 24.6 28.0 58 17.4 17.9 18.3 18.5 19.8 21.2 22.0 23.0 23.9 24.8 28.2 59 17.6 18.0 18.4 18.6 19.9 21.3 22.1 23.2 24.0 24.9 28.3 60 17.7 18.1 18.5 18.7 20.0 21.5 22.3 23.3 24.2 25.1 28.5 61 17.8 18.2 18.6 18.8 20.1 21.6 22.4 23.4 24.3 25.3 28.7 62 17.9 18.3 18.7 18.9 20.3 21.7 22.6 23.6 24.5 25.4 28.9 63 18.0 18.4 18.9 19.0 20.4 21.9 22.7 23.7 24.6 25.6 29.0 64 18.1 18.5 19.0 19.2 20.5 22.0 22.8 23.9 24.7 25.7 29.2 65 18.2 18.6 19.1 19.3 20.6 22.1 23.0 24.0 24.9 25.9 29.4 66 18.3 18.7 19.2 19.4 20.7 22.3 23.1 24.1 25.0 26.0 29.5 67 18.4 18.8 19.3 19.5 20.9 22.4 23.2 24.3 25.2 26.2 29.7 68 18.5 18.9 19.4 19.6 21.0 22.5 23.3 24.4 25.3 26.3 29.9 69 18.6 19.0 19.5 19.7 21.1 22.6 23.5 24.5 25.5 26.4 30.0 70 18.7 19.2 19.6 19.8 21.2 22.7 23.6 24.7 25.6 26.6 30.2 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs QI available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are QI full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 7 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =80°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since I Pressurizer S/D level 71 18.8 19.3 19.7 19.9 21.3 22.9 23.7 24.8 25.7 26.7 30.4 72 18.9 19.4 19.8 20.0 21.4 23.0 23.9 24.9 25.9 26.9 30.5 73 19.0 19.5 19.9 20.1 21.5 23.1 24.0 25.1 26.0 27.0 30.7 74 19.1 19.6 20.0 20.2 21.7 23.2 24.1 25.2 26.1 27.2 30.8 75 19.2 19.7 20.1 20.3 21.8 23.4 24.2 25.3 26.3 27.3 31.0 76 19.3 19.8 20.2 20.4 21.9 23.5 24.3 25.5 26.4 27.4 31.2 77 19.4 19.9 20.3 20.5 22.0 23.6 24.5 25.6 26.5 27.6 31.3 78 19.5 20.0 20.4 20.6 22.1 23.7 24.6 25.7 26.7 27.7 31.5 79 19.6 20.1 20.5 20.7 22.2 23.8 24.7 25.9 26.8 27.8 31.6 80 19.7 20.2 20.6 20.8 22.3 23.9 24.8 26.0 26.9 28.0 31.8 81 19.8 20.3 20.7 20.9 22.4 24.1 25.0 26.1 27.1 28.1 31.9 82 19.9 20.3 20.8 21.0 22.5 24.2 25.1 26.2 27.2 28.2 32.1 83 20.0 20.4 20.9 21.1 22.6 24.3 25.2 26.4 27.3 28.4 32.2 84 20.1 20.5 21.0 21.2 22.7 24.4 25.3 26.5 27.5 28.5 32.4 85 20.1 20.6 21.1 21.3 22.8 24.5 25.4 26.6 27.6 28.6 32.5 86 20.2 20.7 21.2 21.4 22.9 24.6 25.5 26.7 27.7 28.8 32.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 8 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. 80°F (Hours Since SID)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since I Pressurizer I S/D level 87 20.3 20.8 21.3 21.5 23.0 24.7 25.6 26.8 27.8 28.9 32.8 88 20.4 20.9 21.4 21.6 23.1 24.8 25.8 27.0 28.0 29.0 33.0 89 20.5 21.0 21.5 21.7 23.2 24.9 25.9 27.1 28.1 29.1 33.1 90 20.6 21.1 21.6 21.8 23.3 25.0 26.0 27.2 28.2 29.3 33.3 91 20.7 21.2 21.7 21.9 23.4 25.1 26.1 27.3 28.3 29.4 33.4 92 20.8 21.3 21.8 22.0 23.5 25.3 26.2 27.4 28.4 29.5 33.5 93 20.9 21.4 21.9 22.1 23.6 25.4 26.3 27.5 28.6 29.6 33.7 94 20.9 21.5 22.0 22.2 23.7 25.5 26.4 27.7 28.7 29.8 33.8 95 21.0 21.5 22.1 22.3 23.8 25.6 26.5 27.8 28.8 29.9 34.0 96 21.1 21.6 22.2 22.4 23.9 25.7 26.6 27.9 28.9 30.0 34.1 97 21.2 21.7 22.2 22.4 24.0 25.8 26.7 28.0 29.0 30.1 34.2 98 21.3 21.8 22.3 22.5 24.1 25.9 26.8 28.1 29.1 30.2 34.4 99 21.4 21.9 22.4 22.6 24.2 26.0 27.0 28.2 29.2 30.4 34.5 100 21.4 22.0 22.5 22.7 24.3 26.1 27.1 28.3 29.4 30.5 34.6 101 21.5 22.1 22.6 22.8 24.4 26.2 27.2 28.4 29.5 30.6 34.8 102 21.6 22.1 22.7 22.9 24.5 26.3 27.3 28.5 29.6 30.7 34.9 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 9 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =80°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since I Pressurizer I S/D level 103 21.7 22.2 22.8 23.0 24.6 26.4 27.4 28.6 29.7 30.8 35.0 104 21.8 22.3 22.9 23.0 24.7 26.4 27.5 28.7 29.8 30.9 35.1 105 21.8 22.4 22.9 23.1 24.8 26.5 27.6 28.8 29.9 31.0 35.3 106 21.9 22.5 23.0 23.2 24.8 26.6 27.7 29.0 30.0 31.2 35.4 107 22.0 22.5 23.1 23.3 24.9 26.7 27.8 29.1 30.1 31.3 35.5 108 22.1 22.6 23.2 23.4 25.0 26.8 27.9 29.2 30.2 31.4 35.6 109 22.1 22.7 23.3 23.5 25.1 26.9 28.0 29.3 30.3 31.5 35.8 110 22.2 22.8 23.3 23.5 25.2 27.0 28.0 29.4 30.4 31.6 35.9 111 22.3 22.9 23.4 23.6 25.3 27.1 28.1 29.5 30.5 31.7 36.0 112 22.4 22.9 23.5 23.7 25.4 27.2 28.2 29.6 30.6 31.8 36.1 113 22.4 23.0 23.6 23.8 25.4 27.3 28.3 29.7 30.7 31.9 36.3 (See next page)

Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oiOi&ii 108/00 1 Total Loss OF DHR Time To Boil Page 10 of5l Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =80°F (Hours Since S/fl)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since I Pressurizer I SID Ieve 114 22.5 23.1 23.7 23.9 25.5 27.3 28.4 29.8 30.8 32.0 36.4 115 22.6 23.2 23.7 23.9 25.6 27.4 28.5 29.8 30.9 32.1 36.5 116 22.6 23.2 23.8 24.0 25.7 27.5 28.6 29.9 31.0 32.2 36.6 117 22.7 23.3 23.9 24.1 25.8 27.6 28.7 30.0 31.1 32.3 36.7 118 22.8 23.4 24.0 24.2 25.8 27.7 28.8 30.1 31.2 32.4 36.8 119 22.8 23.5 24.0 24.2 25.9 27.8 28.9 30.2 31.3 32.5 36.9 120 22.9 23.5 24.1 24.3 26.0 27.9 29.0 30.3 31.4 32.6 37.1 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 11 of 51 Time to Core Boil Prior to Refueling Initial Temperature =80°F

(Days Since S/D)

Time Level (LT-5) minutes (Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 6 23.5 25.0 25.7 26.3 26.6 28.4 30.4 31.6 33.1 34.3 35.6 7 25.1 26.7 27.4 28.0 28.4 30.3 32.5 33.7 35.3 36.6 38.0 8 26.6 28.3 29.0 29.6 30.0 32.0 34.3 35.7 37.3 38.7 40.2 9 28.0 29.8 30.5 31.2 31.6 33.7 36.2 37.6 39.3 40.7 42.3 10 29.2 31.1 31.8 32.6 33.0 35.2 37.8 39.2 41.0 42.5 44.2 11 30.4 32.4 33.2 34.0 34.4 36.7 39.4 40.9 42.7 44.3 46.0 12 31.5 33.6 34.4 35.2 35.6 38.0 40.8 42.3 44.3 45.9 47.7 13 32.7 34.8 35.7 36.5 36.9 39.5 42.3 43.9 45.9 47.6 49.5 14 33.7 35.8 36.7 37.6 38.0 40.6 43.6 45.2 47.3 49.0 50.9 15 34.7 36.9 37.8 38.7 39.2 41.9 44.9 46.6 48.7 50.5 52.5 16 35.8 38.1 39.0 40.0 40.4 43.2 46.3 48.1 50.3 52.1 54.2 17 36.6 39.0 39.9 40.9 41.4 44.2 47.4 49.2 51.5 53.4 55.4 18 37.7 40.1 41.1 42.0 42.5 45.5 48.7 50.6 52.9 54.9 57.0 19 38.6 41.1 42.1 43.1 43.6 46.6 49.9 51.8 54.2 56.2 58.4 20 39.4 41.9 42.9 43.9 44.4 47.5 50.9 52.9 55.3 57.3 59.5 21 40.4 43.0 44.0 45.0 45.6 48.7 52.2 54.2 56.7 58.8 61.1 22 41.2 43.9 44.9 46.0 46.5 49.7 53.3 55.4 57.9 60.0 62.3 23 41.9 44.6 45.7 46.7 47.3 50.5 54.2 56.2 58.8 61.0 63.3 24 42.8 45.5 46.6 47.7 48.3 51.6 55.3 57.4 60.1 62.3 64.7 25 43.5 46.3 47.4 48.5 49.1 52.5 56.2 58.4 61.1 63.3 65.8 26 44.5 47.3 48.5 49.6 50.2 53.6 57.5 59.7 62.4 64.7 67.2 27 45.2 48.1 49.3 50.5 51.0 54.6 58.5 60.7 63.5 65.9 68.4 28 46.0 49.0 50.2 51.3 51.9 55.5 59.5 61.8 64.6 67.0 69.6 29 46.8 49.8 51.1 52.2 52.9 56.5 60.6 62.9 65.8 68.2 70.8 30 47.4 50.4 51.7 52.9 53.5 57.2 61.3 63.6 66.5 69.0 71.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 12 of5l Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =90F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 since Pressurizer I level 24 12.3 12.6 12.9 13.1 14.0 15.0 15.6 16.3 16.9 17.5 19.9 25 12.4 12.8 13.1 13.2 14.2 15.2 15.8 16.5 17.1 17.7 20.1 26 12.6 12.9 13.2 13.4 14.3 15.3 15.9 16.6 17.2 17.8 20.3 27 12.7 13.0 13.3 13.5 14.4 15.4 16.0 16.8 17.4 18.0 20.5 28 12.8 13.1 13.4 13.6 14.6 15.6 16.2 16.9 17.6 18.2 20.7 29 12.9 13.2 13.6 13.7 14.7 15.7 16.3 17.1 17.7 18.4 20.9 30 13.0 13.4 13.7 13.9 14.8 15.9 16.5 17.2 17.9 18.5 21.1 31 13.2 13.5 13.8 14.0 15.0 16.0 16.6 17.4 18.0 18.7 21.2 32 13.3 13.6 13.9 14.1 15.1 16.1 16.8 17.5 18.2 18.9 21.4 33 13.4 13.7 14.1 14.2 15.2 16.3 16.9 17.7 18.4 19.0 21.6 34 13.5 13.8 14.2 14.3 15.4 16.4 17.1 17.8 18.5 19.2 21.8 35 13.6 13.9 14.3 14.5 15.5 16.6 17.2 18.0 18.7 19.4 22.0 36 13.7 14.1 14.4 14.6 15.6 16.7 17.3 18.1 18.8 19.5 22.2 37 13.8 14.2 14.5 14.7 15.7 16.8 17.5 18.3 19.0 19.7 22.4 38 14.0 14.3 14.7 14.8 15.9 17.0 17.6 18.4 19.1 19.8 22.5 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/i 108/00 1 Total Loss OF DHR Time To Boil Page 13 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =90°F (Hours Since S[D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since i Pressurizer i S/D level 39 14.1 14.4 14.8 14.9 16.0 17.1 17.8 18.6 19.3 20.0 22.7 40 14.2 14.5 14.9 15.1 16.1 17.2 17.9 18.7 19.4 20.2 22.9 41 14.3 14.6 15.0 15.2 16.2 17.4 18.0 18.9 19.6 20.3 23.1 42 14.4 14.8 15.1 15.3 16.4 17.5 18.2 19.0 19.7 20.5 23.3 43 14.5 14.9 15.3 15.4 16.5 17.6 18.3 19.2 19.9 20.6 23.4 44 14.6 15.0 15.4 15.5 16.6 17.8 18.5 19.3 20.0 20.8 23.6 45 14.7 15.1 15.5 15.6 16.7 17.9 18.6 19.4 20.2 20.9 23.8 46 14.8 15.2 15.6 15.7 16.9 18.0 18.7 19.6 20.3 21.1 24.0 47 14.9 15.3 15.7 15.9 17.0 18.2 18.9 19.7 20.5 21.3 24.1 48 15.1 15.4 15.8 16.0 17.1 18.3 19.0 19.9 20.6 21.4 24.3 49 15.2 15.5 15.9 16.1 17.2 18.4 19.1 20.0 20.8 21.6 24.5 50 15.3 15.6 16.0 16.2 17.3 18.6 19.3 20.1 20.9 21.7 24.7 51 15.4 15.7 16.2 16.3 17.5 18.7 19.4 20.3 21.1 21.9 24.8 52 15.5 15.8 16.3 16.4 17.6 18.8 19.5 20.4 21.2 22.0 25.0 53 15.6 16.0 16.4 16.5 17.7 18.9 19.6 20.6 21.4 22.2 25.2 54 15.7 16.1 16.5 16.6 17.8 19.1 19.8 20.7 21.5 22.3 25.3 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs jQJ available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 oP/O/A11 108/00 1 Total Loss OF DHR Time To Boil Page 14 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =90°F (Hours Since S)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer i S/D level 55 15.8 16.2 16.6 16.7 17.9 19.2 19.9 20.8 21.6 22.4 25.5 56 15.9 16.3 16.7 16.9 18.0 19.3 20.0 21.0 21.8 22.6 25.7 57 16.0 16.4 16.8 17.0 18.2 19.4 20.2 21.1 21.9 22.7 25.8 58 16.1 16.5 16.9 17.1 18.3 19.5 20.3 21.2 22.0 22.9 26.0 59 16.2 16.6 17.0 17.2 18.4 19.7 20.4 21.4 22.2 23.0 26.2 60 16.3 16.7 17.1 17.3 18.5 19.8 20.5 21.5 22.3 23.2 26.3 61 16.4 16.8 17.2 17.4 18.6 19.9 20.7 21.6 22.5 23.3 26.5 62 16.5 16.9 17.3 17.5 18.7 20.0 20.8 21.8 22.6 23.5 26.6 63 16.6 17.0 17.4 17.6 18.8 20.1 20.9 21.9 22.7 23.6 26.8 64 16.7 17.1 17.5 17.7 18.9 20.3 21.0 22.0 22.9 23.7 27.0 65 16.8 17.2 17.6 17.8 19.1 20.4 21.1 22.1 23.0 23.9 27.1 66 16.9 17.3 17.7 17.9 19.2 20.5 21.3 22.3 23.1 24.0 27.3 67 17.0 17.4 17.8 18.0 19.3 20.6 21.4 22.4 23.2 24.1 27.4 68 17.1 17.5 17.9 18.1 19.4 20.7 21.5 22.5 23.4 24.3 27.6 69 17.2 17.6 18.0 18.2 19.5 20.8 21.6 22.6 23.5 24.4 27.7 70 17.3 17.7 18.1 18.3 19.6 21.0 21.7 22.8 23.6 24.5 27.9 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 15 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =90°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer I level 71 17.3 17.8 18.2 18.4 19.7 21.1 21.9 22.9 23.8 24.7 28.0 72 17.4 17.9 18.3 18.5 19.8 21.2 22.0 23.0 23.9 24.8 28.2 73 17.5 18.0 18.4 18.6 19.9 21.3 22.1 23.1 24.0 24.9 28.3 74 17.6 18.1 18.5 18.7 20.0 21.4 22.2 23.3 24.1 25.1 28.5 75 17.7 18.1 18.6 18.8 20.1 21.5 22.3 23.4 24.3 25.2 28.6 76 17.8 18.2 18.7 18.9 20.2 21.6 22.4 23.5 24.4 25.3 28.8 77 17.9 18.3 18.8 19.0 20.3 21.7 22.6 23.6 24.5 25.5 28.9 78 18.0 18.4 18.9 19.1 20.4 21.8 22.7 23.7 24.6 25.6 29.1 79 18.1 18.5 19.0 19.2 20.5 22.0 22.8 23.8 24.7 25.7 29.2 80 18.2 18.6 19.1 19.3 20.6 22.1 22.9 24.0 24.9 25.8 29.4 81 18.2 18.7 19.2 19.4 20.7 22.2 23.0 24.1 25.0 26.0 29.5 82 18.3 18.8 19.3 19.4 20.8 22.3 23.1 24.2 25.1 26.1 29.6 83 18.4 18.9 19.4 19.5 20.9 22.4 23.2 24.3 25.2 26.2 29.8 84 18.5 19.0 19.5 19.6 21.0 22.5 23.3 24.4 25.3 26.3 29.9 85 18.6 19.0 19.5 19.7 21.1 22.6 23.4 24.5 25.4 26.4 30.1 86 18.7 19.1 19.6 19.8 21.2 22.7 23.5 24.6 25.6 26.6 30.2 Notes:

Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are 2I full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oiOivi 108/00 1 Total Loss OF DHR Time To Boil Page 16 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =90°F (Hours Since S)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer I SiD level 87 18.8 19.2 19.7 19.9 21.3 22.8 23.6 24.8 25.7 26.7 30.3 88 18.8 19.3 19.8 20.0 21.4 22.9 23.8 24.9 25.8 26.8 30.5 89 18.9 19.4 19.9 20.1 21.5 23.0 23.9 25.0 25.9 26.9 30.6 90 19.0 19.5 20.0 20.2 21.6 23.1 24.0 25.1 26.0 27.0 30.7 91 19.1 19.6 20.1 20.3 21.7 23.2 24.1 25.2 26.1 27.2 30.9 92 19.2 19.6 20.1 20.3 21.7 23.3 24.2 25.3 26.2 27.3 31.0 93 19.2 19.7 20.2 20.4 21.8 23.4 24.3 25.4 26.3 27.4 31.1 94 19.3 19.8 20.3 20.5 21.9 23.5 24.4 25.5 26.4 27.5 31.3 95 19.4 19.9 20.4 20.6 22.0 23.6 24.5 25.6 26.5 27.6 31.4 96 19.5 20.0 20.5 20.7 22.1 23.7 24.6 25.7 26.7 27.7 31.5 97 19.5 20.1 20.6 20.8 22.2 23.8 24.7 25.8 26.8 27.8 31.6 98 19.6 20.1 20.6 20.8 22.3 23.9 24.8 25.9 26.9 27.9 31.8 99 19.7 20.2 20.7 20.9 22.4 24.0 24.9 26.0 27.0 28.0 31.9 100 19.8 20.3 20.8 21.0 22.4 24.1 25.0 26.1 27.1 28.2 32.0 101 19.8 20.4 20.9 21.1 22.5 24.2 25.1 26.2 27.2 28.3 32.1 102 19.9 20.4 20.9 21.2 22.6 24.2 25.2 26.3 27.3 28.4 32.3 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are J full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/001 Total Loss OF DHR Time To Boil Page 17 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =90°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours I since I Pressurizer I S/D level 103 20.0 20.5 21.0 21.3 22.7 24.3 25.3 26.4 27.4 28.5 32.4 104 20.1 20.6 21.1 21.3 22.8 24.4 25.3 26.5 27.5 28.6 32.5 105 20.1 20.7 21.2 21.4 22.9 24.5 25.4 26.6 27.6 28.7 32.6 106 20.2 20.7 21.3 21.5 22.9 24.6 25.5 26.7 27.7 28.8 32.7 107 20.3 20.8 21.3 21.6 23.0 24.7 25.6 26.8 27.8 28.9 32.8 108 20.4 20.9 21.4 21.6 23.1 24.8 25.7 26.9 27.9 29.0 33.0 109 20.4 21.0 21.5 21.7 23.2 24.9 25.8 27.0 28.0 29.1 33.1 110 20.5 21.0 21.5 21.8 23.3 25.0 25.9 27.1 28.0 29.2 33.2 111 20.6 21.1 21.6 21.9 23.3 25.0 26.0 27.2 28.1 29.3 33.3 112 20.6 21.2 21.7 22.0 23.4 25.1 26.1 27.3 28.2 29.4 33.4 113 20.7 21.3 21.8 22.0 23.5 25.2 26.2 27.4 28.3 29.5 33.5 114 20.8 21.3 21.8 22.1 23.6 25.3 26.3 27.5 28.4 29.6 33.6 115 20.8 21.4 21.9 22.2 23.6 25.4 26.3 27.5 28.5 29.7 33.7 116 20.9 21.5 22.0 22.2 23.7 25.5 26.4 27.6 28.6 29.8 33.9 117 21.0 21.5 22.0 22.3 23.8 25.5 26.5 27.7 28.7 29.9 34.0 (See next page)

Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/AJ1 108/00 1 Total Loss OF DHR Time To Boil Page 18 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =90°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours I I since Pressurizer S/D level 118 21.0 21.6 22.1 22.4 23.9 25.6 26.6 27.8 28.8 30.0 34.1 119 21.1 21.7 22.2 22.5 23.9 25.7 26.7 27.9 28.9 30.0 34.2 120 21.1 21.7 22.2 22.5 24.0 25.8 26.8 28.0 28.9 30.1 34.3 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A11 108/00 1 Total Loss OF DHR Time To Boil Page 19 of 51 Time to Core Boil Prior to Refueling Initial Temperature =90°F

(Days Since S/D)

Time RCS Level (LT-5) minutes______

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 6 21.7 23.1 23.7 24.2 24.5 26.2 28.1 29.2 30.5 31.6 32.9 7 23.2 24.7 25.3 25.9 26.2 28.0 30.0 31.1 32.6 33.8 35.1 8 24.5 26.1 26.7 27.4 27.7 29.6 31.7 32.9 34.4 35.7 37.1 9 25.8 27.5 28.2 28.8 29.1 31.2 33.4 34.7 36.3 37.6 39.0 10 27.0 28.7 29.4 30.1 30.4 32.5 34.9 36.2 37.9 39.3 40.8 11 28.1 29.9 30.6 31.4 31.7 33.9 36.3 37.7 39.5 40.9 42.5 12 29.1 31.0 31.7 32.5 32.9 35.1 37.6 39.1 40.9 42.4 44.0 13 30.2 32.1 32.9 33.7 34.1 36.4 39.0 40.5 42.4 44.0 45.7 14 31.1 33.1 33.9 34.7 35.1 37.5 40.2 41.8 43.7 45.3 47.0 15 32.1 34.1 34.9 35.8 36.2 38.7 41.4 43.0 45.0 46.7 48.5 16 33.1 35.2 36.1 36.9 37.3 39.9 42.8 44.4 46.4 48.1 50.0 17 33.8 36.0 36.9 37.7 38.2 40.8 43.7 45.4 47.5 49.3 51.2 18 34.8 37.0 37.9 38.8 39.3 42.0 45.0 46.7 48.9 50.7 52.6 19 35.7 37.9 38.9 39.8 40.2 43.0 46.1 47.9 50.1 51.9 53.9 20 36.4 38.7 39.6 40.6 41.0 43.9 47.0 48.8 51.0 52.9 55.0 21 37.3 39.7 40.7 41.6 42.1 45.0 48.2 50.1 52.4 54.3 56.4 22 38.1 40.5 41.5 42.5 43.0 45.9 49.2 51.1 53.4 55.4 57.5 23 38.7 41.1 42.2 43.1 43.6 46.7 50.0 51.9 54.3 56.3 58.5 24 39.5 42.0 43.1 44.1 44.6 47.7 51.1 53.0 55.5 57.5 59.7 25 40.2 42.7 43.8 44.8 45.3 48.4 51.9 53.9 56.4 58.5 60.7 26 41.1 43.7 44.8 45.8 46.3 49.5 53.1 55.1 57.6 59.8 62.1 27 41.8 44.4 45.5 46.6 47.1 50.4 54.0 56.1 58.6 60.8 63.1 28 42.5 45.2 46.3 47.4 48.0 51.3 54.9 57.0 59.7 61.9 64.2 29 43.2 46.0 47.1 48.2 48.8 52.2 55.9 58.1 60.7 63.0 65.4 30 43.8 46.6 47.7 48.8 49.4 52.8 56.6 58.8 61.4 63.7 66.2 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 oP/O/AJ1 108/00 1 Total Loss OF DHR Time To Boil Page 20 of5l Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =100°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer S/D level 24 11.3 11.6 11.8 12.0 12.8 13.7 14.3 14.9 15.5 16.1 18.3 25 11.4 11.7 11.9 12.1 12.9 13.9 14.4 15.0 15.6 16.3 18.5 26 11.5 11.9 12.1 12.3 13.1 14.0 14.6 15.2 15.8 16.4 18.6 27 11.6 12.0 12.2 12.4 13.2 14.1 14.7 15.3 15.9 16.6 18.8 28 11.8 12.1 12.3 12.5 13.3 14.3 14.8 15.5 16.1 16.7 19.0 29 11.9 12.2 12.4 12.6 13.4 14.4 15.0 15.6 16.2 16.9 19.2 30 12.0 12.3 12.5 12.7 13.6 14.5 15.1 15.8 16.4 17.0 19.3 31 12.1 12.4 12.6 12.8 13.7 14.7 15.3 15.9 16.5 17.2 19.5 32 12.2 12.5 12.7 12.9 13.8 14.8 15.4 16.1 16.7 17.3 19.7 33 12.3 12.6 12.9 13.0 13.9 14.9 15.5 16.2 16.8 17.5 19.9 34 12.4 12.7 13.0 13.2 14.0 15.0 15.7 16.3 17.0 17.6 20.0 35 12.5 12.8 13.1 13.3 14.2 15.2 15.8 16.5 17.1 17.8 20.2 36 12.6 12.9 13.2 13.4 14.3 15.3 15.9 16.6 17.3 17.9 20.4 37 12.7 13.0 13.3 13.5 14.4 15.4 16.1 16.7 17.4 18.1 20.5 38 12.8 13.1 13.4 13.6 14.5 15.6 16.2 16.9 17.5 18.2 20.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 21 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =1OO°F (Hours Since SIP)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since i Pressurizer I sir) level 39 12.9 13.2 13.5 13.7 14.6 15.7 16.3 17.0 17.7 18.4 20.9 40 13.0 13.3 13.6 13.8 14.7 15.8 16.4 17.2 17.8 18.5 21.0 41 13.1 13.4 13.7 13.9 14.9 15.9 16.6 17.3 18.0 18.7 21.2 42 13.2 13.5 13.8 14.0 15.0 16.1 16.7 17.4 18.1 18.8 21.4 43 13.3 13.6 13.9 14.1 15.1 16.2 16.8 17.6 18.2 18.9 21.5 44 13.4 13.7 14.0 14.2 15.2 16.3 16.9 17.7 18.4 19.1 21.7 45 13.5 13.8 14.2 14.3 15.3 16.4 17.1 17.8 18.5 19.2 21.9 46 13.6 13.9 14.3 14.4 15.4 16.5 17.2 18.0 18.6 19.4 22.0 47 13.7 14.0 14.4 14.5 15.5 16.7 17.3 18.1 18.8 19.5 22.2 48 13.8 14.1 14.5 14.6 15.7 16.8 17.4 18.2 18.9 19.6 22.3 49 13.9 14.2 14.6 14.8 15.8 16.9 17.6 18.3 19.0 19.8 22.5 50 14.0 14.3 14.7 14.9 15.9 17.0 17.7 18.5 19.2 19.9 22.6 51 14.1 14.4 14.8 15.0 16.0 17.1 17.8 18.6 19.3 20.0 22.8 52 14.2 14.5 14.9 15.1 16.1 17.3 17.9 18.7 19.4 20.2 23.0 53 14.3 14.6 15.0 15.2 16.2 17.4 18.0 18.8 19.6 20.3 23.1 54 14.4 14.7 15.1 15.3 16.3 17.5 18.2 19.0 19.7 20.4 23.3 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are QJ full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/AJ1 108/00 1 Total Loss OF DHR Time To Boil Page 22 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =100°F (Hours Since S/fl)

LT-5 I (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since I Pressurizer si : level 55 14.4 14.8 15.2 15.4 16.4 17.6 18.3 19.1 19.8 20.6 23.4 56 14.5 14.9 15.3 15.5 16.5 17.7 18.4 19.2 19.9 20.7 23.6 57 14.6 15.0 15.4 15.6 16.6 17.8 18.5 19.3 20.1 20.8 23.7 58 14.7 15.1 15.5 15.7 16.7 18.0 18.6 19.5 20.2 21.0 23.9 59 14.8 15.2 15.6 15.7 16.8 18.1 18.8 19.6 20.3 21.1 24.0 60 14.9 15.3 15.7 15.8 16.9 18.2 18.9 19.7 20.4 21.2 24.2 61 15.0 15.4 15.8 15.9 17.0 18.3 19.0 19.8 20.6 21.4 24.3 62 15.1 15.5 15.9 16.0 17.1 18.4 19.1 19.9 20.7 21.5 24.5 63 15.2 15.6 15.9 16.1 17.2 18.5 19.2 20.1 20.8 21.6 24.6 64 15.3 15.7 16.0 16.2 17.3 18.6 19.3 20.2 20.9 21.7 24.7 65 15.4 15.7 16.1 16.3 17.4 18.7 19.4 20.3 21.1 21.9 24.9 66 15.4 15.8 16.2 16.4 17.5 18.8 19.5 20.4 21.2 22.0 25.0 67 15.5 15.9 16.3 16.5 17.6 18.9 19.7 20.5 21.3 22.1 25.2 68 15.6 16.0 16.4 16.6 17.7 19.0 19.8 20.6 21.4 22.2 25.3 69 15.7 16.1 16.5 16.7 17.8 19.2 19.9 20.8 21.5 22.4 25.5 70 15.8 16.2 16.6 16.8 17.9 19.3 20.0 20.9 21.7 22.5 25.6 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oiOivi 108/00 1 Total Loss OF DHR Time To Boil Page 23 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. 1OO°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer SID level 71 15.9 16.3 16.7 16.9 18.0 19.4 20.1 21.0 21.8 22.6 25.7 72 16.0 16.4 16.8 17.0 18.1 19.5 20.2 21.1 21.9 22.7 25.9 73 16.0 16.4 16.9 17.1 18.2 19.6 20.3 21.2 22.0 22.8 26.0 74 16.1 16.5 17.0 17.1 18.3 19.7 20.4 21.3 22.1 23.0 26.1 75 16.2 16.6 17.0 17.2 18.4 19.8 20.5 21.4 22.2 23.1 26.3 76 16.3 16.7 17.1 17.3 18.5 19.9 20.6 21.5 22.3 23.2 26.4 77 16.4 16.8 17.2 17.4 18.6 20.0 20.7 21.6 22.5 23.3 26.5 78 16.5 16.9 17.3 17.5 18.7 20.1 20.8 21.8 22.6 23.4 26.7 79 16.5 17.0 17.4 17.6 18.8 20.2 20.9 21.9 22.7 23.5 26.8 80 16.6 17.0 17.5 17.7 18.9 20.3 21.0 22.0 22.8 23.6 26.9 81 16.7 17.1 17.6 17.8 19.0 20.4 21.1 22.1 22.9 23.8 27.1 82 16.8 17.2 17.6 17.8 19.1 20.5 21.2 22.2 23.0 23.9 27.2 83 16.9 17.3 17.7 17.9 19.2 20.6 21.3 22.3 23.1 24.0 27.3 84 16.9 17.4 17.8 18.0 19.2 20.7 21.4 22.4 23.2 24.1 27.5 85 17.0 17.4 17.9 18.1 19.3 20.7 21.5 22.5 23.3 24.2 27.6 86 17.1 17.5 18.0 18.2 19.4 20.8 21.6 22.6 23.4 24.3 27.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs J available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 24 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =100°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since i Pressurizer level 87 17.2 17.6 18.0 18.3 19.5 20.9 21.7 22.7 23.5 24.4 27.8 88 17.3 17.7 18.1 18.3 19.6 21.0 21.8 22.8 23.6 24.5 28.0 89 17.3 17.8 18.2 18.4 19.7 21.1 21.9 22.9 23.7 24.6 28.1 90 17.4 17.8 18.3 18.5 19.8 21.2 22.0 23.0 23.8 24.7 28.2 91 17.5 17.9 18.4 18.6 19.8 21.3 22.1 23.1 23.9 24.8 28.3 92 17.6 18.0 18.4 18.7 19.9 21.4 22.2 23.2 24.0 24.9 28.4 93 17.6 18.1 18.5 18.7 20.0 21.5 22.3 23.3 24.2 25.0 28.6 94 17.7 18.1 18.6 18.8 20.1 21.6 22.4 23.4 24.2 25.2 28.7 95 17.8 18.2 18.7 18.9 20.2 21.7 22.5 23.5 24.3 25.3 28.8 96 17.9 18.3 18.7 19.0 20.3 21.7 22.6 23.6 24.4 25.4 28.9 97 17.9 18.4 18.8 19.0 20.3 21.8 22.6 23.6 24.5 25.5 29.0 98 18.0 18.4 18.9 19.1 20.4 21.9 22.7 23.7 24.6 25.6 29.1 99 18.1 18.5 19.0 19.2 20.5 22.0 22.8 23.8 24.7 25.7 29.2 100 18.2 18.6 19.0 19.3 20.6 22.1 22.9 23.9 24.8 25.8 29.4 101 18.2 18.7 19.1 19.3 20.7 22.2 23.0 24.0 24.9 25.9 29.5 102 18.3 18.7 19.2 19.4 20.7 22.2 23.1 24.1 25.0 25.9 29.6 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs J available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 25 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =100°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer I S/D level 103 18.4 18.8 19.3 19.5 20.8 22.3 23.2 24.2 25.1 26.0 29.7 104 18.4 18.9 19.3 19.6 20.9 22.4 23.2 24.3 25.2 26.1 29.8 105 18.5 19.0 19.4 19.6 21.0 22.5 23.3 24.4 25.3 26.2 29.9 106 18.6 19.0 19.5 19.7 21.0 22.6 23.4 24.5 25.4 26.3 30.0 107 18.6 19.1 19.5 19.8 21.1 22.7 23.5 24.5 25.5 26.4 30.1 108 18.7 19.2 19.6 19.9 21.2 22.7 23.6 24.6 25.6 26.5 30.2 109 18.8 19.2 19.7 19.9 21.3 22.8 23.7 24.7 25.7 26.6 30.3 110 18.8 19.3 19.7 20.0 21.3 22.9 23.7 24.8 25.7 26.7 30.4 111 18.9 19.4 19.8 20.1 21.4 23.0 23.8 24.9 25.8 26.8 30.5 112 19.0 19.4 19.9 20.1 21.5 23.0 23.9 25.0 25.9 26.9 30.6 113 19.0 19.5 19.9 20.2 21.6 23.1 24.0 25.0 26.0 27.0 30.7 114 19.1 19.6 20.0 20.3 21.6 23.2 24.1 25.1 26.1 27.0 30.8 115 19.2 19.6 20.1 20.3 21.7 23.3 24.1 25.2 26.2 27.1 30.9 116 19.2 19.7 20.1 20.4 21.8 23.3 24.2 25.3 26.3 27.2 31.0 117 19.3 19.8 20.2 20.5 21.8 23.4 24.3 25.4 26.3 27.3 31.1 (See next page)

Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 26 of 51 Time to Core Boil (Minutes)- Prior to Refueling- Initial Temp. =100°F (Hours Since S/D)

LT-5 (in) 10? 14 181? 20 28 42 50 60 70 80 100 I I Hours since Pressurizer S/D level 118 19.4 19.8 20.2 20.5 21.9 23.5 24.4 25.4 26.4 27.4 31.2 119 19.4 19.9 20.3 20.6 22.0 23.6 24.4 25.5 26.5 27.5 31.3 120 19.5 20.0 20.4 20.7 22.0 23.6 24.5 25.6 26.6 27.6 31.4 Notes:

Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs fl available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full JjJ RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 27 of 51 Time to Core Boil Prior to Refueling Initial Temperature =100°F Time Level (LT-5) minutes

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 6 19.9 21.2 21.7 22.2 22.5 24.0 25.8 26.8 28.0 29.0 30.1 7 21.3 22.6 23.2 23.7 24.0 25.7 27.5 28.6 29.9 31.0 32.2 8 22.5 23.9 24.5 25.1 25.4 27.1 29.1 30.2 31.6 32.7 34.0 9 23.7 25.2 25.8 26.4 26.7 28.6 30.6 31.8 33.2 34.5 35.8 10 24.7 26.3 27.0 27.6 27.9 29.8 32.0 33.2 34.7 36.0 37.4 11 25.8 27.4 28.1 28.8 29.1 31.1 33.3 34.6 36.2 37.5 39.0 12 26.7 28.4 29.1 29.8 30.1 32.2 34.5 35.8 37.5 38.9 40.4 13 27.7 29.5 30.2 30.9 31.3 33.4 35.8 37.2 38.9 40.3 41.9 14 28.5 30.3 31.1 31.8 32.2 34.4 36.9 38.3 40.0 41.5 43.1 15 29.4 31.3 32.0 32.8 33.2 35.5 38.0 39.5 41.3 42.8 44.4 16 30.3 32.3 33.1 33.8 34.2 36.6 39.2 40.7 42.6 44.1 45.8 17 31.0 33.0 33.8 34.6 35.0 37.4 40.1 41.7 43.6 45.2 46.9 18 31.9 34.0 34.8 35.6 36.0 38.5 41.3 42.8 44.8 46.5 48.2 19 32.7 34.8 35.6 36.5 36.9 39.4 42.3 43.9 45.9 47.6 49.4 20 33.3 35.5 36.4 37.2 37.6 40.2 43.1 44.8 46.8 48.5 50.4 21 34.2 36.4 37.3 38.1 38.6 41.3 44.2 45.9 48.0 49.8 51.7 22 34.9 37.1 38.1 38.9 39.4 42.1 45.1 46.9 49.0 50.8 52.8 23 35.5 37.7 38.7 39.6 40.0 42.8 45.8 47.6 49.8 51.6 53.6 24 36.2 38.5 39.5 40.4 40.9 43.7 46.8 48.6 50.9 52.7 54.8 25 36.8 39.2 40.1 41.1 41.6 44.4 47.6 49.4 51.7 53.6 55.7 26 37.7 40.1 41.0 42.0 42.5 45.4 48.7 50.5 52.9 54.8 56.9 27 38.3 40.7 41.8 42.7 43.2 46.2 49.5 51.4 53.8 55.7 57.9 28 39.0 41.5 42.5 43.5 44.0 47.0 50.4 52.3 54.7 56.7 58.9 29 39.7 42.2 43.2 44.2 44.8 47.8 51.3 53.2 55.7 57.7 59.9 30 40.1 42.7 43.8 44.8 45.3 48.4 51.9 53.9 56.3 58.4 60.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are QJ full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oOii 108/00 1 Total Loss OF DHR Time To Boil Page 28 of 51 Time to Core Boil (Minutes)- Prior to Refueling-Initial Temp. =110°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100

.-----------.---.-------.---.-.-.-----.---.-----.-.--------------4 Hours since Pressurizer SID p level 24 10.2 10.5 10.8 10.9 11.6 12.5 13.0 13.6 14.1 14.6 16.6 25 10.3 10.6 10.9 11.0 11.8 12.6 13.1 13.7 14.2 14.7 16.8 26 10.4 10.7 11.0 11.1 11.9 12.8 13.3 13.9 14.4 14.9 16.9 27 10.6 10.8 11.1 11.3 12.0 12.9 13.4 14.0 14.5 15.0 17.1 28 10.7 10.9 11.2 11.4 12.1 13.0 13.5 14.1 14.7 15.2 17.2 29 10.8 11.0 11.3 11.5 12.2 13.1 13.6 14.3 14.8 15.3 17.4 30 10.9 11.1 11.4 11.6 12.3 13.2 13.8 14.4 14.9 15.4 17.6 31 11.0 11.2 11.5 11.7 12.4 13.3 13.9 14.5 15.1 15.6 17.7 32 11.1 11.3 11.6 11.8 12.5 13.5 14.0 14.7 15.2 15.7 17.9 33 11.2 11.4 11.7 11.9 12.6 13.6 14.1 14.8 15.3 15.9 18.0 34 11.3 11.5 11.8 12.0 12.8 13.7 14.2 14.9 15.4 16.0 18.2 35 11.3 11.6 11.9 12.1 12.9 13.8 14.4 15.0 15.6 16.1 18.3 36 11.4 11.7 12.0 12.2 13.0 13.9 14.5 15.2 15.7 16.3 18.5 37 11.5 11.8 12.1 12.3 13.1 14.0 14.6 15.3 15.8 16.4 18.6 38 11.6 11.9 12.2 12.4 13.2 14.2 14.7 15.4 16.0 16.5 18.8 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs Qf available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full jJ RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 29 of 51 Time to Core Boil (Minutes)- Prior to Refueling-Initial Temp. =110°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours

since Pressurizer level 39 11.7 12.0 12.3 12.5 13.3 14.3 14.8 15.5 16.1 16.7 18.9 40 11.8 12.1 12.4 12.6 13.4 14.4 14.9 15.7 16.2 16.8 19.1 41 11.9 12.2 12.5 12.7 13.5 14.5 15.0 15.8 16.3 16.9 19.2 42 12.0 12.3 12.6 12.8 13.6 14.6 15.2 15.9 16.5 17.1 19.4 43 12.1 12.4 12.7 12.9 13.7 14.7 15.3 16.0 16.6 17.2 19.5 44 12.2 12.5 12.8 13.0 13.8 14.8 15.4 16.1 16.7 17.3 19.7 45 12.3 12.6 12.9 13.1 13.9 14.9 15.5 16.3 16.8 17.5 19.8 46 12.4 12.7 13.0 13.2 14.0 15.0 15.6 16.4 17.0 17.6 20.0 47 12.5 12.8 13.1 13.3 14.1 15.1 15.7 16.5 17.1 17.7 20.1 48 12.6 12.9 13.2 13.4 14.2 15.3 15.8 16.6 17.2 17.8 20.3 49 12.7 13.0 13.3 13.5 14.3 15.4 15.9 16.7 17.3 18.0 20.4 50 12.8 13.1 13.4 13.6 14.4 15.5 16.1 16.8 17.4 18.1 20.5 51 12.8 13.1 13.4 13.6 14.5 15.6 16.2 17.0 17.6 18.2 20.7 52 12.9 13.2 13.5 13.7 14.6 15.7 16.3 17.1 17.7 18.3 20.8 53 13.0 13.3 13.6 13.8 14.7 15.8 16.4 17.2 17.8 18.5 21.0 54 13.1 13.4 13.7 13.9 14.8 15.9 16.5 17.3 17.9 18.6 21.1 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/AJ1 108/00 1 Total Loss OF DHR Time To Boil Page 30 of 51 Time to Core Boil (Minutes)- Prior to Refueling-Initial Temp. =110°F (Hours Since S/D)

(in) 10 14 18 20 28 42 50 60 70 80 100

.-.-.-.-.-.-.-.-.-.-.---.--------.---.-.---.-.-.----.-.-.---.-.-.-.-.---.-1 I

-i since Pressurizer S,D level 55 13.2 13.5 13.8 14.0 14.9 16.0 16.6 17.4 18.0 18.7 21.2 56 13.3 13.6 13.9 14.1 15.0 16.1 16.7 17.5 18.2 18.8 21.4 57 13.4 13.7 14.0 14.2 15.1 16.2 16.8 17.6 18.3 18.9 21.5 58 13.4 13.8 14.1 14.3 15.2 16.3 16.9 17.8 18.4 19.1 21.7 59 13.5 13.8 14.2 14.4 15.3 16.4 17.0 17.9 18.5 19.2 21.8 60 13.6 13.9 14.2 14.5 15.4 16.5 17.1 18.0 18.6 19.3 21.9 61 13.7 14.0 14.3 14.5 15.5 16.6 17.2 18.1 18.7 19.4 22.1 62 13.8 14.1 14.4 14.6 15.6 16.7 17.3 18.2 18.8 19.5 22.2 63 13.9 14.2 14.5 14.7 15.7 16.8 17.4 18.3 19.0 19.7 22.3 64 13.9 14.3 14.6 14.8 15.8 16.9 17.5 18.4 19.1 19.8 22.5 65 14.0 14.3 14.7 14.9 15.8 17.0 17.6 18.5 19.2 19.9 22.6 66 14.1 14.4 14.7 15.0 15.9 17.1 17.7 18.6 19.3 20.0 22.7 67 14.2 14.5 14.8 15.1 16.0 17.2 17.8 18.7 19.4 20.1 22.8 68 14.3 14.6 14.9 15.1 16.1 17.3 17.9 18.8 19.5 20.2 23.0 69 14.4 14.7 15.0 15.2 16.2 17.4 18.0 18.9 19.6 20.3 23.1 70 14.4 14.8 15.1 15.3 16.3 17.5 18.1 19.0 19.7 20.4 23.2 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs J available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 31 of 51 Time to Core Boil (Minutes)- Prior to Refueling-Initial Temp. 110°F (Hours Since S/D)

(in) 10 14 18 20 28 42 50 60 70 80 100

__{iJ_

since Pressurizer S/D level 71 14.5 14.8 15.2 15.4 16.4 17.6 18.2 19.1 19.8 20.6 23.4 72 14.6 14.9 15.2 15.5 16.5 17.7 18.3 19.2 19.9 20.7 23.5 73 14.7 15.0 15.3 15.6 16.6 17.8 18.4 19.3 20.0 20.8 23.6 74 14.7 15.1 15.4 15.6 16.6 17.9 18.5 19.4 20.1 20.9 23.7 75 14.8 15.1 15.5 15.7 16.7 17.9 18.6 19.5 20.2 21.0 23.8 76 14.9 15.2 15.6 15.8 16.8 18.0 18.7 19.6 20.3 21.1 24.0 77 15.0 15.3 15.6 15.9 16.9 18.1 18.8 19.7 20.4 21.2 24.1 78 15.0 15.4 15.7 16.0 17.0 18.2 18.9 19.8 20.5 21.3 24.2 79 15.1 15.4 15.8 16.0 17.1 18.3 19.0 19.9 20.6 21.4 24.3 80 15.2 15.5 15.9 16.1 17.2 18.4 19.1 20.0 20.7 21.5 24.5 81 15.3 15.6 15.9 16.2 17.2 18.5 19.2 20.1 20.8 21.6 24.6 82 15.3 15.7 16.0 16.3 17.3 18.6 19.3 20.2 20.9 21.7 24.7 83 15.4 15.7 16.1 16.3 17.4 18.7 19.4 20.3 21.0 21.8 24.8 84 15.5 15.8 16.2 16.4 17.5 18.7 19.4 20.4 21.1 21.9 24.9 85 15.6 15.9 16.2 16.5 17.6 18.8 19.5 20.5 21.2 22.0 25.0 86 15.6 16.0 16.3 16.6 17.6 18.9 19.6 20.6 21.3 22.1 25.1 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs j available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are QJ full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 opiOii.i 108/00 1 Total Loss OF DHR Time To Boil Page 32 of 51 Time to Core Boil (Minutes)- Prior to Refueling-Initial Temp. =110°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer SID level 87 15.7 16.0 16.4 16.6 17.7 19.0 19.7 20.7 21.4 22.2 25.3 88 15.8 16.1 16.5 16.7 17.8 19.1 19.8 20.8 21.5 22.3 25.4 89 15.8 16.2 16.5 16.8 17.9 19.2 19.9 20.9 21.6 22.4 25.5 90 15.9 16.2 16.6 16.9 18.0 19.2 20.0 20.9 21.7 22.5 25.6 91 16.0 16.3 16.7 16.9 18.0 19.3 20.1 21.0 21.8 22.6 25.7 92 16.0 16.4 16.8 17.0 18.1 19.4 20.1 21.1 21.9 22.7 25.8 93 16.1 16.5 16.8 17.1 18.2 19.5 20.2 21.2 22.0 22.8 25.9 94 16.2 16.5 16.9 17.1 18.3 19.6 20.3 21.3 22.1 22.9 26.0 95 16.2 16.6 17.0 17.2 18.3 19.7 20.4 21.4 22.2 23.0 26.1 96 16.3 16.7 17.0 17.3 18.4 19.7 20.5 21.5 22.3 23.1 26.2 97 16.4 16.7 17.1 17.4 18.5 19.8 20.6 21.5 22.3 23.2 26.3 98 16.4 16.8 17.2 17.4 18.6 19.9 20.7 21.6 22.4 23.3 26.5 99 16.5 16.8 17.2 17.5 18.6 20.0 20.7 21.7 22.5 23.4 26.6 100 16.5 16.9 17.3 17.6 18.7 20.0 20.8 21.8 22.6 23.4 26.7 101 16.6 17.0 17.4 17.6 18.8 20.1 20.9 21.9 22.7 23.5 26.8 102 16.7 17.0 17.4 17.7 18.8 20.2 21.0 22.0 22.8 23.6 26.9 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs Qf available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/001 Total Loss OF DHR Time To Boil Page 33 of5l Time to Core Boil (Minutes)- Prior to Refueling-Initial Temp. =110°F (Hours Since S/D)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 since Pressurizer S/D level 103 16.7 17.1 17.5 17.8 18.9 20.3 21.1 22.0 22.9 23.7 27.0 104 16.8 17.2 17.6 17.8 19.0 20.3 21.1 22.1 23.0 23.8 27.1 105 16.9 17.2 17.6 17.9 19.1 20.4 21.2 22.2 23.0 23.9 27.2 106 16.9 17.3 17.7 17.9 19.1 20.5 21.3 22.3 23.1 24.0 27.3 107 17.0 17.4 17.8 18.0 19.2 20.6 21.4 22.4 23.2 24.1 27.4 108 17.0 17.4 17.8 18.1 19.3 20.6 21.4 22.4 23.3 24.1 27.5 109 17.1 17.5 17.9 18.1 19.3 20.7 21.5 22.5 23.4 24.2 27.6 110 17.1 17.5 18.0 18.2 19.4 20.8 21.6 22.6 23.4 24.3 27.6 111 17.2 17.6 18.0 18.3 19.5 20.9 21.7 22.7 23.5 24.4 27.7 112 17.3 17.6 18.1 18.3 19.5 20.9 21.7 22.7 23.6 24.5 27.8 113 17.3 17.7 18.1 18.4 19.6 21.0 21.8 22.8 23.7 24.6 27.9 114 17.4 17.8 18.2 18.4 19.7 21.1 21.9 22.9 23.8 24.6 28.0 115 17.4 17.8 18.3 18.5 19.7 21.1 22.0 23.0 23.8 24.7 28.1 116 17.5 17.9 18.3 18.5 19.8 21.2 22.0 23.0 23.9 24.8 28.2 117 17.5 17.9 18.4 18.6 19.9 21.3 22.1 23.1 24.0 24.9 28.3 (See next page)

Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 colunm for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 34 of 51 Time to Core Boil (Minutes)- Prior to Refueling-Initial Temp. =110°F (Hours Since SID)

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer S/D level 118 17.6 18.0 18.4 18.7 19.9 21.3 22.2 23.2 24.1 24.9 28.4 119 17.6 18.0 18.5 18.7 20.0 21.4 22.3 23.2 24.1 25.0 28.5 120 17.7 18.1 18.6 18.8 20.0 21.5 22.3 23.3 24.2 25.1 28.6 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 35 of5l Time to Core Boil Prior to Refueling Initial Temperature 1 10°F Time RCS_Level (LT-5) minutes______

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 6 18.1 19.3 19.8 20.2 20.5 21.9 23.4 24.3 25.4 26.4 27.4 7 19.4 20.6 21.1 21.6 21.8 23.3 25.0 26.0 27.2 28.2 29.2 8 20.5 21.8 22.3 22.8 23.1 24.7 26.4 27.5 28.7 29.8 30.9 9 21.5 22.9 23.5 24.0 24.3 26.0 27.8 28.9 30.2 31.4 32.6 10 22.5 23.9 24.5 25.1 25.4 27.1 29.1 30.2 31.6 32.7 34.0 11 23.5_ 24.9 25.6 26.2 26.5 28.3 30.3 31.5 32.9 34.1 35.4 12 24.3 25.8 26.5 27.1 27.4 29.3 31.4 32.6 34.1 35.3 36.7 13 25.2 26.8 27.5 28.1 28.4 30.4 32.6 33.8 35.4 36.7 38.1 14 25.9 27.6 28.3 28.9 29.3 31.3 33.5 34.8 36.4 37.8 39.2 15 26.7 28.4 29.1 29.8 30.2 32.3 34.6 35.9 37.5 38.9 40.4 16 27.6 29.3 30.1 30.8 31.1 33.3 35.7 37.0 38.7 40.1 41.7 17 28.2 30.0 30.8 31.5 31.9 34.0 36.5 37.9 39.6 41.1 42.7 18 29.0 30.9 31.6 32.4 32.8 35.0 37.5 39.0 40.7 42.3 43.9 19 29.7 31.6 32.4 33.2 33.6 35.9 38.4 39.9 41.7 43.3 44.9 20 30.3 32. 33.1 33.8 34.2 36.6 39.2 40.7 42.6 44.1 45.8 21 31.1 33. 33.9 34.7 35.1 37.5 40.2 41.7 43.7 45.3 47.0 22 31.8 33.8 34.6 35.4 35.8 38.3 41.0 42.6 44.6 46.2 48.0 23 32.3 34. 35.2 36.0 36.4 38.9 41.7 43.3 45.3 46.9 48.7 24 33.0 35. 35.9 36.8 37.2 39.7 42.6 44.2 46.2 48.0 49.8 25 33.5 35.6 36.5 37.4 37.8 40.4 43.3 45.0 47.0 48.8 50.6 26 34.3 36.4 37.3 38.2 38.7 41.3 44.3 46.0 48.1 49.8 51.8 27 34.8 37.1 38.0 38.9 39.3 42.0 45.0 46.8 48.9 50.7 52.6 28 35.4 37.7 38.6 39.5 40.0 42.8 45.8 47.6 49.7 51.6 53.6 29 36.1 38.4 39.3 40.2 40.7 43.5 46.6 48.4 50.6 52.5 54.5 30 36.5 38.8 39.8 40.7 41.2 44.0 47.2 49.0 51.2 53.1 55.2 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs J available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are QJ full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 36 of5l Time to Core Boil Prior to Refueling Initial Temperature 420°F {21}

(in) 10 14 18 20 28 42? 50 60 70 80 100 H

Hours I since Pressurizer S/D p level 24 13.1 15.0 25 13.2 15.1 26 13.4 15.3 27 13.5 15.4 28 13.6 15.6 29 13.8 15.7 30 13.9 15.9 31 14.0 16.0 32 14.1 16.2 33 14.3 16.3 34 14.4 16.4 35 14.5 16.6 36 14.6 16.7 37 14.7 16.8 38 14.9 17.0 39 15.0 17.1 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/A/1 108/001 Total Loss OF DHR Time To Boil Page 37 of 51 Time to Core Boil Prior to Refueling Initial Temperature =120°F {21}

LT-5 I (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since I Pressurzer S/D level 40 15.1 17.3 41 15.2 17.4 42 15.3 17.5 43 15.5 17.7 44 15.6 17.8 45 15.7 17.9 46 15.8 18.0 47 15.9 18.2 48 16.0 18.3 49 16.2 18.4 50 16.3 18.6 51 16.4 18.7 52 16.5 18.8 53 16.6 18.9 54 16.7 19.1 55 16.8 19.2 56 16.9 19.3 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs QI available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are full jJ RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/v1 108/00 1 Total Loss OF DHR Time To Boil Page 38 of5l Time to Core Boil Prior to Refueling Initial Temperature =120°F {21}

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours since Pressurizer S/D level 57 17.0 19.4 58 17.2 19.6 59 17.3 19.7 60 17.4 19.8 61 17.5 19.9 62 17.6 20.0 63 17.7 20.2 64 17.8 20.3 65 17.9 20.4 66 18.0 20.5 67 18.1 20.6 68 18.2 20.7 69 18.3 20.9 70 18.4 21.0 71 18.5 21.1 72 18.6 21.2 73 18.7 21.3 Notes:

Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 OP/O IA/i 108/00 1 Total Loss OF DHR Time To Boil Page 39 of 51 Time to Core Boil Prior to Refueling Initial Temperature =120°F {21}

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 Hours I I Pressurizer I since I SID level 74 18.8 21.4 75 18.9 21.5 76 19.0 21.6 77 19.1 21.7 78 19.2 21.8 79 19.3 22.0 80 19.4 22.1 81 19.5 22.2 82 19.6 22.3 83 19.7 22.4 84 19.7 22.5 85 19.8 22.6 86 19.9 22.7 87 20.0 22.8 88 20.1 22.9 89 20.2 23.0 90 20.3 23.1 Notes:

Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs J available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level?? colunm (if available) for Time to Boil.

Enclosure 4.46 oiOii 108/00 1 Total Loss OF DHR Time To Boil Page 40 of 51 Time to Core Boll Prior to Refueling Initial Temperature =120°F {21}

(in) 10 14 18 20 28 42 50 60 70 80 100 Hours -

since I Pressurizer S/D level 91 20.4 23.2 92 20.5 23.3 93 20.5 23.4 94 20.6 23.5 95 20.7 23.6 96 20.8 23.7 97 20.9 23.7 98 21.0 23.8 99 21.0 23.9 100 21.1 24.0 101 21.2 24.1 102 21.3 24.2 103 21.4 24.3 104 21.4 24.4 105 21.5 24.5 106 21.6 24.6 107 21.7 24.6 Notes:

Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/001 Total Loss OF DHR Time To Boil Page 41 of 51 Time to Core Boil Prior to Refueling Initial Temperature =120°F {21}

LT-5 (in) 10 14 18 20 28 42 50 60 70 80 100 since i Pressurizer Sm level 108 21.8 24.7 109 21.8 24.8 110 21.9 24.9 111 22.0 25.0 112 22.1 25.1 113 22.1 25.1 114 22.2 25.2 115 22.3 25.3 116 22.3 25.4 117 22.4 25.5 118 22.5 25.5 119 22.6 25.6 120 22.6 25.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs QI available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 42 of 51 Time_to_Core_Boil_Prior_to_Refueling__Initial_Temperature_=120°F Time Level (LT-5) minutes

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 1 8.8 9.3 9.6 9.8 9.9 10.6 11.3 11.8 12.3 12.7 13.2 2 10.8 11.5 11.8 12.1 12.2 13.0 14.0 14.5 15.2 15.7 16.3 3 12.4 13.2 13.5 13.9 14.0 15.0 16.1 16.7 17.4 18.1 18.8 4 13.8 14.7 15.1 15.4 15.6 16.7 17.9 18.6 19.4 20.1 20.9 5 15.1 16.1 16.5 16.9 17.1 18.3 19.6 20.3 21.3 22.0 22.9 6 16.3 17.4 17.8 18.2 18.4 19.7 21.1 21.9 22.9 23.8 24.7 7 17.4 18.5 19.0 19.4 19.7 21.0 22.5 23.4 24.5 25.4 26.3 8 18.4 19.6 20.1 20.6 20.8 22.2 23.8 24.7 25.9 26.8 27.8 9 19.4 20.6 21.2 21.6 21.9 23.4 25.1 26.0 27.2 28.2 29.3 10 20.3 21.6 22.1 22.6 22.9 24.4 26.2 27.2 28.4 29.5 30.6 11 21.1 22.5 23.0 23.6 23.8 25.5 27.3 28.3 29.6 30.7 31.9 12 21.9 23.3 23.8 24.4 24.7 26.4 28.3 29.4 30.7 31.8 33.1 13 22.7 24.1 24.7 25.3 25.6 27.4 29.3 30.4 31.8 33.0 34.3 14 23.4 24.9 25.5 26.1 26.4 28.2 30.2 31.4 32.8 34.0 35.3 15 24.1 25.6 26.3 26.9 27.2 29.0 31.1 32.3 33.8 35.0 36.4 16 24.9 26.4 27.1 27.7 28.0 30.0 32.1 33.3 34.9 36.2 37.5 17 25.4 27.0 27.7 28.4 28.7 30.7 32.9 34.1 35.7 37.0 38.4 18 26.2 27.8 28.5 29.2 29.5 31.5 33.8 35.1 36.7 38.0 39.5 9 26.8 28.5 29.2 29.9 30.2 32.3 34.6 35.9 37.6 39.0 40.5 20 27.3 29.1 29.8 30.5 30.8 32.9 35.3 36.7 38.3 39.8 41.3 21 28.0 29.8 30.5 31.3 31.6 33.8 36.2 37.6 39.3 40.8 42.3 22 28.6 30.4 31.2 31.9 32.3 34.5 37.0 38.4 40.1 41.6 43.2 23 29.1 30.9 31.7 32.4 32.8 35.0 37.6 39.0 40.8 42.3 43.9 24 29.7 31.6 32.4 33.1 33.5 35.8 38.4 39.8 41.7 43.2 44.8 25 30.2 32.1 32.9 33.7 34.0 36.4 39.0 40.5 42.3 43.9 45.6 26 30.9 32.8 33.6 34.4 34.8 37.2 39.9 41.4 43.3 44.9 46.6 27 31.4 33.4 34.2 35.0 35.4 37.8 40.6 42.1 44.0 45.7 47.4 28 31.9 34.0 34.8 35.6 36.0 38.5 41.3 42.8 44.8 46.5 48.2 29 32.5 34.6 35.4 36.2 36.7 39.2 42.0 43.6 45.6 47.3 49.1 30 32.9 35.0 35.8 36.7 37.1 39.7 42.5 44.1 46.1 47.8 49.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs JQ available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 43 of 51 Time_to_Core_Boil_Prior_to_Refueling _Initial_Temperature_=130°F Time Level (LT-5) minutes

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 1 7.8 8.3 8.5 8.7 8.8 9.4 10.1 10.5 10.9 11.3 11.8 2 9.6 10.2 10.5 10.7 10.9 11.6 12.4 12.9 13.5 14.0 14.5 3 11.1 11.8 12.1 12.3 12.5 13.3 14.3 14.8 15.5 16.1 16.7 4 12.3 13.1 13.4 13.7 13.9 14.9 15.9 16.5 17.3 17.9 18.6 5 13.5 14.3 14.7 15.0 15.2 16.3 17.4 18.1 18.9 19.6 20.4 6 14*5 15.5 15.8 16.2 16.4 17.5 18.8 19.5 20.4 21.1 22.0 7 5.5 16.5 16.9 17.3 17.5 18.7 20.0 20.8 21.8 22.6 23.4 8 6.4 17.4 17.9 18.3 18.5 19.8 21.2 22.0 23.0 23.9 24.8 9 7.3 18.4 18.8 19.3 19.5 20.8 22.3 23.2 24.2 25. 26.1 10 8.0 19.2 19.7 20.1 20.3 21.7 23.3 24.2 25.3 26.2 27.2 11 18.8 20.0 20.5 21.0 21.2 22.7 24.3 25.2 26.4 27. 28.4 12 19.5 20.7 21.2 21.7 22.0 23.5 25.2 26.1 27.3 28. 29.4 13 20.2 21.5 22.0 22.5 22.8 24.4 26.1 27.1 28.3 29.4 30.5 14 20.8 22.1 22.7 23.2 23.5 25.1 26.9 27.9 29.2 30.3 31.4 15 21.4 22.8 23.4 23.9 24.2 25.8 27.7 28.8 30.1 31.2 32.4 16 22.1 23.5 24.1 24.7 25.0 26.7 28.6 29.7 31.0 32.2 33.4 17 22.6 24.1 24.7 25.2 25.5 27.3 29.2 30.4 31.7 32.9 34.2 18 23.3 24.8 25.4 26.0 26.3 28.1 30.1 31.2 32.6 33.9 35.2 19 23.8 25.4 26.0 26.6 26.9 28.7 30.8 32.0 33.4 34.7 36.0 20 24.3 25.9 26.5 27.1 27.4 29.3 31.4 32.6 34.1 35.4 36.7 21 24.9 26.5 27.2 27.8 28.1 30.1 32.2 33.5 35.0 36.3 37.7 22 25.5 27.1 27.7 28.4 28.7 30.7 32.9 34.2 35.7 37.0 38.4 23 25.9 27.5 28.2 28.8 29.2 31.2 33.4 34.7 36.3 37.6 39.1 24 26.4 28.1 28.8 29.5 29.8 31.9 34.1 35.4 37.1 38.4 39.9 25 26.9 28.6 29.3 29.9 30.3 32.4 34.7 36.0 37.7 39.1 40.6 26 27.5 29.2 29.9 30.6 31.0 33.1 35.5 36.8 38.5 39.9 41.5 27 27.9 29.7 30.4 31.1 31.5 33.7 36.1 37.5 39.2 40.6 42.2 28 28.4 30.2 31.0 31.7 32.1 34.3 36.7 38.1 39.9 41.3 42.9 29 28.9 30.8 31.5 32.3 32.6 34.9 37.4 38.8 40.6 42.1 43.7 30 29.3 31.1 31.9 32.6 33.0 35.3 37.8 39.3 41.1 42.6 44.2 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs QJ available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 44 of 51 Time_to_Core_Boil_Prior_to_Refueling Initial_Temperature_=140°F

Time Level (LT-5) minutes (Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 1 6.8 7.3 7.5 7.6 7.7 8.2 8.8 9.2 9.6 9.9 10.3 2 8.4 9.0 9.2 9.4 9.5 10.2 10.9 11.3 11.8 12.3 12.7 3 9.7 10.3 10.6 10.8 10.9 11.7 12.5 13.0 13.6 14.1 14.6 4 10.8 11.5 11.8 12.0 12.2 13.0 14.0 14.5 15.2 15.7 16.3 5 11.8 12.6 12.9 13.2 13.3 14.2 15.3 5.8 16.6 17.2 17.8 6 12.7 13.6 13.9 14.2 14.4 15.4 16.5 7.1 17.9 18.5 19.2 7 13.6 14.5 14.8 15.2 15.3 16.4 17.6 8.2 19.1 19.8 20.5 8 14.4 15.3 15.7 16.0 16.2 17.3 18.6 19.3 20.2 20.9 21.7 9 15.1 16.1 16.5 16.9 17.1 18.3 19.6 20.3 21.2 22.0 22.9 10 15.8 16.8 17.2 17.6 17.8 19.1 20.4 21.2 22.2 23.0 23.9 11 16.5 17.5 18.0 18.4 18.6 19.9 21.3 22.1 23.1 24.0 24.9 12 17.1 18.2 18.6 19.0 19.3 20.6 22.1 22.9 23.9 24.8 25.8 13 17.7 .8.8 19.3 19.7 20.0 21.3 22.9 23.7 24.8 25.7 26.7 14 18.2 19.4 19.9 20.3 20.6 22.0 23.6 24.5 25.6 26.5 27.5 15 18.8 20.0 20.5 21.0 21.2 22.7 24.3 25.2 26.4 27.3 28.4 16 19.4 20.6 21.1 21.6 21.9 23.4 25.0 26.0 27.2 28.2 29.3 17 19.8 21.1 21.6 22.1 22.4 23.9 25.6 26.6 27.8 28.8 29.9 18 20.4 21.7 22.2 22.8 23.0 24.6 26.4 27.4 28.6 29.7 30.8 19 20.9 22.2 22.8 23.3 23.6 25.2 27.0 28.0 29.3 30.4 31.6 20 21.3 22.7 23.2 23.8 24.0 25.7 27.5 28.6 29.9 31.0 32.2 21 21.9 23.3 23.8 24.4 24.7 26.4 28.2 29.3 0.7 31.8 33.0 22 22.3 23.7 24.3 24.9 25.2 26.9 28.8 29.9 1.3 32.5 33.7 23 22.7 24.1 24.7 25.3 25.6 27.3 29.3 30.4 1.8 33.0 34.2 24 23.2 24.6 25.2 25.8 26.1 27.9 29.9 31.1 i2.5 33.7 35.0 25 23.5 25.0 25.7 26.3 26.6 28.4 30.4 31.6 33.0 34.2 35.5 26 24.1 25.6 26.2 26.8 27.2 29.0 31.1 32.3 33.8 35.0 36.3 27 24.5 26.0 26.7 27.3 27.6 29.5 31.6 32.8 34.3 35.6 37.0 28 24.9 26.5 27.1 27.8 28.1 30.0 32.2 33.4 34.9 36.2 37.6 29 25.4 27.0 27.6 28.3 28.6 30.6 32.8 34.0 35.6 36.9 38.3 30 25.7 27.3 28.0 28.6 28.9 30.9 33.1 34.4 36.0 37.3 38.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs jQ available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/A/1108/OO1 Total Loss OF DHR Time To Boil Page 45 of 51 Time_to_Core_Boil_After_Refueling _Initial_Temperature_= 80°F Time Level (LT-5) minutes

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 10 36.1 38.4 39.3 40.2 40.7 43.5 46.6 48.4 50.6 52.5 54.6 11 37.6 40.0 41.0 41.9 42.4 45.3 48.6 50.5 52.8 54.7 56.9 12 38.9 41.4 42.4 43.4 43.9 47.0 50.3 52.3 54.7 56.7 58.9 13 40.4 43.0 44.0 45.0 45.6 48.7 52.2 54.2 56.7 58.8 61.1 14 41.6 44.2 45.3 46.4 46.9 50.2 53.8 55.8 58.4 60.5 62.9 15 42.9 45.6 46.7 47.8 48.4 51.7 55.4 57.5 60.2 62.4 64.8 16 44.2 47.0 48.2 49.3 49.9 53.3 57.2 59.4 62.1 64.4 66.9 17 45.2 48.1 49.3 50.5 51.1 54.6 58.5 60.7 63.5 65.9 68.4 18 46.5 49.5 50.7 51.9 52.5 56.1 60.2 62.5 65.3 67.8 70.4 19 47.7 50.7 52.0 53.2 53.8 57.5 61.6 64.0 66.9 69.4 72.1 20 48.6 51.7 53.0 54.2 54.9 58.7 62.9 65.3 68.3 70.8 73.6 21 49.9 53.0 54.3 55.6 56.3 60.1 64.5 66.9 70.0 72.6 75.4 22 50.9 54.1 55.5 56.8 57.4 61.4 65.8 68.3 71.5 74.1 77.0 23 51.7 55.0 56.4 57.7 58.4 62.4 66.9 69.4 72.6 75.3 78.2 24 52.8 56.2 57.6 58.9 59.6 63.7 68.3 70.9 74.2 76.9 79.9 25 53.7 57.1 58.5 59.9 60.6 64.8 69.4 72.1 75.4 78.2 81.2 26 54.9 58.4 59.8 61.2 62.0 66.2 71.0 73.7 77.1 79.9 83.1 27 55.8 59.4 60.9 62.3 63.0 67.4 72.2 75.0 78.4 81.3 84.5 28 56.8 60.4 61.9 63.4 64.1 68.5 73.5 76.3 79.8 82.7 86.0 29 57.8 61.5 63.0 64.5 65.3 69.8 74.8 77.6 81.2 84.2 87.5 30 58.5 62.3 63.8 65.3 66.0 70.6 75.7 78.6 82.2 85.2 88.5 35 63.0 67.1 68.7 70.3 71.2 76.1 81.5 84.6 88.5 91.8 95.4 40 67.4 71.7 73.5 75.2 76.1 81.3 87.1 90.5 94.6 98.1 102.0 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs I available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are full Q RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 46 of 51 Time_to_Core_Boil_After_Refueling _Initial_Temperature_= 90°F Time Level (LT-5) minutes

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 10 33.3 35.4 36.3 37.1 37.6 40.2 43.0 44.7 46.7 48.5 50.4 11 34.7 36.9 37.8 38.7 39.2 41.9 44.9 46.6 48.7 50.5 52.5 12 35.9 38.2 39.2 40.1 40.6 43.4 46.5 48.3 50.5 52.3 54.4 13 37.3 39.7 40.6 41.6 42.1 45.0 48.2 50.1 52.3 54.3 56.4 14 38.4 40.9 41.9 42.8 43.3 46.3 49.6 51.5 53.9 55.9 58.1 15 39.6 42.1 43.1 44.1 44.7 47.7 51.2 53.1 55.6 57.6 59.9 16 40.8 43.4 44.5 45.5 46.1 49.3 52.8 54.8 57.3 59.4 61.8 17 41.8 44.4 45.5 46.6 47.1 50.4 54.0 56.1 58.6 60.8 63.2 18 43.0 45.7 46.8 47.9 48.5 51. 55.6 57.7 60.3 62.6 65.0 19 44.0 46.8 48.0 49.1 49.7 53. 56.9 59.1 61.8 64.1 66.6 20 44.9 47.8 48.9 50.1 50.7 54.2 58.0 60.3 63.0 65.4 67.9 21 46.0 49.0 50.2 51.4 52.0 55.5 59.5 61.8 64.6 67.0 69.6 22 47.0 50.0 51.2 52.4 53.0 56.7 60.8 63.1 66.0 68.4 71.1 23 47.7 50.8 52.0 53.3 53.9 57.6 61.7 64.1 67.0 69.5 72.2 24 48.8 51.9 53.2 54.4 55.0 58.8 63.1 65.5 68.5 71.0 73.8 25 49.6 52.7 54.0 55.3 56.0 59.8 64.1 66.6 69.6 72.2 75.0 26 50.7 53.9 55.3 56.5 57.2 61.2 65.5 68.1 71.2 73.8 76.7 27 51.6 54.9 56.2 57.5 58.2 62.2 66.7 69.2 72.4 75.1 78.0 28 52.5 55.8 57.2 58.5 59.2 63.3 67.8 70.4 73.6 76.4 79.4 29 53.4 56.8 58.2 59.6 60.3 64.4 69.0 71.7 75.0 77.7 80.8 30 54.0 57.5 58.9 60.3 61.0 65.2 69.9 72.5 75.9 78.7 81.7 35 58.2 61.9 63.5 64.9 65.7 70.2 75.3 78.2 81.7 84.8 88.1 40 62.2 66.2 67.8 69.4 70.2 75.1 80.5 83.5 87.4 90.6 94.1 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 47 of 51 Time_to_Core_Boil_After_Refueling Initial_Temperature_= 100°F Time Level (LT-5) minutes

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 10 30.5 32.5 33.3 34.1 34.5 36.8 39.5 41.0 42.9 44.4 46.2 11 31.8 33.9 34.7 35.5 35.9 38.4 41.1 42.7 44.7 46.3 48.1 12 33.0 35.1 35.9 36.8 37.2 39.8 42.6 44.3 46.3 48.0 49.9 13 34.2 36.4 37.3 38.1 38.6 41.2 44.2 45.9 48.0 49.8 51.7 14 35.2 37.5 38.4 39.3 39.7 42.5 45.5 47.3 49.4 51.3 53.3 15 36.3 38.6 39.6 40.5 41.0 43.8 46.9 48.7 50.9 52.8 54.9 16 37.4 39.8 40.8 41.8 42.3 45.2 48.4 50.3 52.6 54.5 56.6 17 38.3 40.8 41.8 42.7 43.2 46.2 49.5 51.4 53.8 55.8 57.9 18 39.4 41.9 43.0 44.0 44.5 47.5 50.9 52.9 55.3 57.4 59.6 19 40.4 42.9 44.0 45.0 45.6 48.7 52.2 54.2 56.7 58.8 61.0 20 41.2 43.8 44.9 45.9 46.5 49.7 53.2 55.3 57.8 59.9 62.3 21 42.2 44.9 46.0 47.1 47.6 50.9 54.6 56.7 59.3 61.5 63.8 22 43.1 45.9 47.0 48.1 48.6 52.0 55.7 57.9 60.5 62.7 65.2 23 43.8 46.6 47.7 48.8 49.4 52.8 56.6 58.8 61. 63.7 66.2 24 44.7 47.6 48.8 49.9 50.5 54.0 57.8 60.0 62. 65.1 67.6 25 45.5 48.4 49.6 50.7 51.3 54.8 58.8 61.0 63. 66.2 68.8 26 46.5 49.5 50.7 51.9 52.5 56.1 60.1 62.4 65.3 67.7 70.3 27 47.3 50.3 51.5 52.7 53.4 57.0 61.1 63.5 66.4 68.8 71.5 28 48.1 51.2 52.4 53.7 54.3 58.0 62.2 64.6 67.5 70.0 72.8 29 49.0 52.1 53.4 54.6 55.3 59.1 63.3 65.7 68.7 71.3 74.0 30 49.6 52.7 54.0 55.3 55.9 59.8 64.1 66.5 69.6 72.1 74.9 35 53.4 56.8 58.2 59.6 60.3 64.4 69.0 71.7 74.9 77.7 80.7 40 57.1 60.7 62.2 63.7 64.4 68.8 73.8 76.6 80.1 83.1 86.3 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/AI1 108/00 1 Total Loss OF DHR Time To Boil Page 48 of 51 Time to Core Boil After Refueling Initial Temperature = 110°F Time RCS Level (LT-5) minutes (Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 10 27.8 29.5 30.3 31.0 31.3 33.5 35.9 37.3 39.0 40.4 42.0 11 29.0 30.8 31.6 32.3 32.7 34.9 37.4 38.9 40.6 42.1 43.8 12 30.0 31.9 32.7 33.4 33.8 36.2 38.8 40.2 42.1 43.6 45.3 13 31.1 33.1 33.9 34.7 35.1 37.5 40.2 41.7 43.6 45.3 47.0 14 32.0 34.1 34.9 35.7 36.1 38.6 41.4 43.0 44.9 46.6 48.4 15 33.0 35.1 36.0 36.8 37.3 39.8 42.7 44.3 46.3 48.0 49.9 16 34.1 36.2 37.1 38.0 38.4 41.1 44.0 45.7 47.8 49.6 51.5 17 34.8 37.1 38.0 38.9 39.3 42.0 45.0 46.8 48.9 50.7 52.7 18 35.8 38.1 39.1 40.0 40.4 43.2 46.3 48.1 50.3 52.2 54.2 19 36.7 39.1 40.0 41.0 41.4 44.3 47.5 49.3 51.5 53.4 55.5 20 37.4 39.8 40.8 41.8 42.3 45.2 48.4 50.3 52.6 54.5 56.6 21 38.4 40.9 41.9 42.8 43.3 46.3 49.6 51.5 53.9 55.9 58.1 22 39.2 41.7 42.7 43.7 44.2 47.3 50.7 52.6 55.0 57.1 59.3 23 39.8 42.4 43.4 44.4 44.9 48.0 51.5 53.4 55.9 58.0 60.2 24 40.7 43.3 44.3 45.4 45.9 49.1 52.6 54.6 57.1 59.2 61.5 25 41.4 44.0 45.1 46.1 46.7 49.9 53.5 55.5 58.0 60.2 62.5 26 42.3 45.0 46.1 47.2 47.7 51.0 54.7 56.8 59.3 61.5 63.9 27 43.0 45.8 46.9 48.0 48.5 51.9 55.6 57.7 60.4 62.6 65.0 28 43.8 46.6 47.7 48.8 49.4 52.8 56.6 58.7 61.4 63.7 66.2 29 44.5 47.4 48.5 49.7 50.3 53.7 57.6 59.8 62.5 64.8 67.3 30 45.1 48.0 49.1 50.3 50.9 54.4 58.3 60.5 63.3 65.6 68.1 35 48.6 51.7 52.9 54.2 54.8 58.6 62.8 65.2 68.1 70.7 73.4 40 51.9 55.2 56.6 57.9 58.6 62.6 67.1 69.7 72.8 75.5 78.5 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs rI available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

Enclosure 4.46 oiOii 108/00 1 Total Loss OF DHR Time To Boil Page 49 of 51 Time to Core Boil After Refueling Initial Temperature

120°F Time Level (LT-5) minutes

(Day)_ +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 10 25.0 26.6 27.3 27.9 28.2 30.2 32.3 33.6 35.1 36.4 37.8 1 26.1 27.7 28.4 29.1 29.4 31.4 33.7 35.0 36.6 37.9 39.4 12 27.0 28.7 29.4 30.1 30.5 32.6 34.9 36.2 37.9 39.3 40.8 13 28.0 29.8 30.5 31.2 31.6 33.8 36.2 37.6 39.3 40.8 42.3 14 28.9 30.7 31.4 32.2 32.6 34.8 37.3 38.7 40.5 42.0 43.6 5 29.7 31.6 32.4 33.2 33.6 35.9 38.4 39.9 41.7 43.3 44.9 6 30.7 32.6 33.4 34.2 34.6 37.0 39.6 41.2 43.0 44.6 46.4 17 31.4 33.4 34.2 35.0 35.4 37.9 40.6 42.1 44.0 45.7 47.4 18 32.3 34.3 35.2 36.0 36.4 38.9 41.7 43.3 45.3 47.0 48.8 19 33.1 35.2 36.0 36.9 37.3 39.9 42.7 44.4 46.4 48.1 50.0 20 33.7 35.9 36.8 37.6 38.1 40.7 43.6 45.3 47.3 49.1 51.0 21 34.6 36.8 37.7 38.6 39.0 41.7 44.7 46.4 48. 50.3 52.3 22 35.3 37.6 38.5 39.4 39.8 42.6 45.6 47.4 49. 51.4 53.4 23 35.9 38.2 39.1 40.0 40.5 43.3 46.4 48.1 50. 52.2 54.2 24 36.6 39.0 39.9 40.9 41.4 44.2 47.4 49.2 51.4 53.3 55.4 25 37.3 39.6 40.6 41.5 42.0 44.9 48.1 50.0 52.3 54.2 56.3 26 38.1 40.5 41.5 42.5 43.0 45.9 49.2 51.1 53.4 55.4 57.6 27 38.7 41.2 42.2 43.2 43.7 46.7 50.1 52.0 54.4 56.4 58.6 28 39.4 41.9 43.0 44.0 44.5 47.5 50.9 52.9 55.3 57.4 59.6 29 40.1 42.7 43.7 44.7 45.3 48.4 51.8 53.8 56.3 58.4 60.6 30 40.6 43.2 44.3 45.3 45.8 49.0 52.5 54.5 57.0 59.1 61.4 35 43.7 46.5 47.7 48.8 49.4 52.8 56.5 58.7 61.4 63.6 66.1 40 46.8 49.7 51.0 52.2 52.8 56.4 60.4 62.7 65.6 68.0 70.7 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are QI full Q RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 oP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 50 of 51 Time to Core_Boil_After_Refueling__Initial_Temperature_=_130°F Time Level (LT-5) minutes______

(Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 10 22.3 23.7 24.3 24.8 25.1 26.8 28.8 29.9 31.2 32.4 33.6 11 23.2 24.7 25.3 25.9 26.2 28.0 30.0 31.1 32.6 33.8 35.1 12 24.0 25.6 26.2 26.8 27.1 29.0 31.1 32.3 33.7 35.0 36.3 13 24.9 26.5 27.2 27.8 28.1 30.1 32.2 33.4 35.0 36.3 37.7 14 25.7 27.3 28.0 28.6 29.0 31.0 33.2 34.4 36.0 37.3 38.8 15 26.5 28.2 28.8 29.5 29.9 31.9 34.2 35.5 37.1 38.5 40.0 16 27.3 29.0 29.8 30.4 30.8 32.9 35.3 36.6 38.3 39.7 41.3 17 27.9 29.7 30.4 31.2 31.5 33.7 36.1 37.5 39.2 40.6 42.2 18 28.7 30.6 31.3 32.0 32.4 34.6 37.1 38.5 40.3 41.8 43.4 19 29.4 31.3 32.1 32.8 33.2 35.5 38.0 39.5 41.3 42.8 44.5 20 30.0 31.9 32.7 33.5 33.9 36.2 38.8 40.3 42.1 43.7 45.4 21 30.8 32.7 33.6 34.3 34.7 37.1 39.8 41.3 43.2 44.8 46.5 22 31.4 33.4 34.3 35.0 35.5 37.9 40.6 42.2 44.1 45.7 47.5 23 31.9 34.0 34.8 35.6 36.0 38.5 41.3 42.8 44.8 46.4 48.2 24 32.6 34.7 35.5 36.4 36.8 39.3 42.1 43.8 45.8 47.4 49.3 25 33.2 35.3 36.1 37.0 37.4 40.0 42.8 44.5 46.5 48.2 50.1 26 33.9 36.1 36.9 37.8 38.2 40.9 43.8 45.5 47.6 49.3 51.2 27 34.5 36.7 37.6 38.5 38.9 41.6 44.6 46.3 48.4 50.2 52.1 28 35.1 37.3 38.2 39.1 39.6 42.3 45.3 47.1 49.2 51.0 53.0 29 35.7 38.0 38.9 39.8 40.3 43.1 46.1 47.9 50.1 51.9 54.0 30 36.1 38.4 39.4 40.3 40.8 43.6 46.7 48.5 50.7 52.6 54.6 35 38.9 41.4 42.4 43.4 43.9 46.9 50.3 52.2 54.6 56.6 58.8 40 41.6 44.3 45.4 46.4 47.0 50.2 53.8 55.8 58.4 60.5 62.9 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs QI available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or p100 inch Pressurizer Level column (if available) for Time to Boil.

Enclosure 4.46 OP/O/A/1 108/00 1 Total Loss OF DHR Time To Boil Page 51 of5l Time to Core Boil After RefueHn Initial Temperature = 140°F Time RCS Level (LT-5) minutes (Days) +0 +10 +14 +18 +20 +28 +42 +50 +60 +70 +80 10 19.5 20.8 21.3 21.8 22.0 23.5 25.2 26.2 27.4 28.4 29.5 11 20.3 21.6 22.2 22.7 23.0 24.5 26.3 27.3 28.5 29.6 30.7 12 21.1 22.4 23.0 23.5 23.8 25.4 27.2 28.3 29.6 30.6 31.8 13 21.9 23.3 23.8 24.4 24.7 26.4 28.2 29.3 30.7 31.8 33.0 14 22.5 23.9 24.5 25.1 25.4 27.1 29.1 30.2 31.6 32.7 34.0 15 23.2 24.7 25.3 25.9 26.2 28.0 30.0 31.1 32.5 33.7 35.0 16 23.9 25.5 26.1 26.7 27.0 28.9 30.9 32.1 33.6 34.8 36.2 17 24.5 26.0 26.7 27.3 27.6 29.5 31.6 32.8 34.3 35.6 37.0 18 25.2 26.8 27.5 28.1 28.4 30.4 32.5 33.8 35.3 36.6 38.1 19 25.8 27.4 28.1 28.8 29.1 31.1 33.3 34.6 36.2 37.5 39.0 20 26.3 28.0 28.7 29.3 29.7 31.7 34.0 35.3 36.9 38.3 39.8 21 27.0 28.7 29.4 30.1 30.4 32.5 34.9 36.2 37.8 39.2 40.8 22 27.6 29.3 30.0 30.7 31.1 33.2 35.6 37.0 38.6 40.1 41.6 23 28.0 29.8 30.5 31.2 31.6 33.7 36.2 37.5 39.3 40.7 42.3 24 28.6 30.4 31.2 31.9 32.3 34.5 36.9 38.3 40.1 41.6 43.2 25 29.1 30.9 31.7 32.4 32.8 35.0 37.5 39.0 40.8 42.3 43.9 26 29.7 31.6 32.4 33.1 33.5 35.8 38.4 39.9 41.7 43.2 44.9 27 30.2 32.2 32.9 33.7 34.1 36.4 39.0 40.5 42.4 44.0 45.7 28 30.8 32.7 33.5 34.3 34.7 37.1 39.7 41.2 43.1 44.7 46.5 29 31.3 33.3 34.1 34.9 35.3 37.7 40.4 42.0 43.9 45.5 47.3 30 31.7 33.7 34.5 35.3 35.7 38.2 40.9 42.5 44.4 46.1 47.9 35 34.1 36.3 37.2 38.1 38.5 41.1 44.1 45.8 47.9 49.6 51.6 40 38.8 39.8 40.7 41.2 44.0 47.1 I 48.9 51.2 53.0 55.1 Notes:

1. Limited boiling may occur prior to the above times due to incomplete mixing of the coolant exiting the core.

2. RCS Loops full with SGs NOT available use 80 column for Time to Boil.

3. RCS Loops full with SGs available use 2 hours0.0833 days 0.0119 weeks 0.00274 months as Time to Boil.

4. If RCS Loops are NOT full AND RCS level is> 80 on LT-5, use 80 inch column or 100 inch Pressurizer Level colunm (if available) for Time to Boil.

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ML111380080: Difference between revisions

Revision as of 20:25, 12 November 2019

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02.1 INTRODUCTION

02.1 INTRODUCTION

02.3 REFERENCES

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ML111380080: Difference between revisions

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02.1 INTRODUCTION

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02.3 REFERENCES

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