Text

Initial 2013-301 Final SRO Written Exam
	ML13191A879
Person / Time
Site:	Browns Ferry
Issue date:	07/09/2013
From:	; NRC/RGN-II
To:	;
References
	Download: ML13191A879 (149)
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NRC Exam Site-Specific SRO Written Examination Applicant Information Name:

Date: June 28th, 2013 Facility/Unit: Browns Ferry Region: I II III IV Reactor Type: W CE 8W 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 overall, with 70.00 percent or better on the SRO-only items if given in conjunction with the RO exam; SRO-only exams given alone require a final grade of 80.00 percent to pass. You have 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to complete the combined examination, and 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months if you are only taking the SRO portion.

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

Applicants Signature Results RO/SRO-Only/Total Examination Values 75 / 25 / 100 Points Applicants Scores / / Points Applicants Grade / / Percent

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QUESTION 76 th 27 At 0900 on April offsite power was lost resulting in the following conditions:

All 500 KV lines are DE-ENERGIZED

Athens 16 1KV line is DE-ENERGIZED

Trinity 161KV line is ENERGIZED

B and D Emergency Diesel Generators failed to start and can NOT be manually started At 1000, power has been restored to the Browns Ferry transmission yard via 500KV lines (Limestone and Union).

Which ONE of the following is the LATEST date & time Units I and 2 are required to be in Mode 4 in accordance with Technical Specification 3.8.1, AC Sources- Operating?

[REFERENCE PRO VIDEDI

th A. April27 at 2200 th 27 B. April at 2300 th 28 C. April at 2200 th 28 D April at 2300

QUESTION 77 Given the following conditions:

Unit 3 is operating at 40% power when a loss of drywell control air (DWCA) occurs

DRYWELL CONTROL AIR PRESS LOW (Panel 9-3E, Window 35) is in Alarm

MAIN STEAM RELIEF VLV ACCUM PRESS LOW (Panel 9-3D, Window 18) is in Alarm

DWCA has been cross tied to the Containment Atmospheric Dilution (CAD) System in accordance with 3-AOI-32A- 1, Loss of Drywell Control Air Which ONE of the following completes both statements below?

In accordance with the Tech Spec Bases for SR 3.5.1.3, the minimum required pneumatic pressure for the ADS valves to remain operable is j1)_ psig.

The CAD subsystem _(2)_ required to be declared inoperable when crosstied with the DWCA System.

A. (1)81 (2) is B. (1)81 (2) is NOT C. (1) 87 (2) is D (1)87 (2) is NOT

QUESTION 78 Given the following conditions:

Unit 2 is in a Refueling Outage

Movement of irradiated fuel is in progress

Refueling personnel report that a grapple failure has caused a fuel bundle to drop, resulting in the following alarms/indications:

FUEL POOL FLOOR AREA RADIATION HIGH, (2-9-3A, Window 1)

2-RlvI-90-1A, Fuel Pool Area Radiation Monitor is reading 1000 mremlhr Which one of the following completes the statements below?

Based on the above conditions, the required immediate actions in accordance with 2-AOI 1, Fuel Damage During Refueling, for the SRO is to direct evacuation of non essential personnel from the (1).

In accordance with EPIP-l, Emergency Plan Implementing Procedure, the HIGHEST required emergency action level classification for these conditions is a (an) _(2)_.

[REFERENCE PROVIDEDj A. (1) Refuel Floor ONLY (2) Unusual Event B. (1) Refuel Floor ONLY (2) Alert C. (1) Drywell AND Refuel Floor (2) Unusual Event D. (1) Drywell AND Refuel Floor (2) Alert

QUESTION 79 Which ONE of the following completes both statements below?

In accordance with EOI-2, Step PC/P-13, (1) is required to be implemented to control suppression chamber pressure less than 55 psig.

In accordance with EPIP-l, Emergency Classification Technical Basis, Section 2.1-G (general Emergency: Primary containment pressure at 55 psig), at this point, _(2) is (are) potentially threatened due to direction in the EOIs to Spray Primary Containment.

A. (1) Appendix 12, Primary Containment Venting (2) fuel cladding integrity B. (1) Appendix 12, Primary Containment Venting (2) offsite release limits C. (1) Appendix 13, Emergency Venting Primary Containment (2) fuel cladding integrity D. (1) Appendix 13, Emergency Venting Primary Containment (2) offsite release limits

QUESTION 80 Given the following conditions:

Unit 2 was operating at 100% power

At time 0805 a scram occurred due to a loss of both RPS Bus A and RPS Bus B

NO control rods initially inserted

Following the manual scram and ART, several rods failed to fully insert At 0815, the following conditions exist:

Reactor power is UNKNOWN

Reactor pressure is being maintained 800 to 1000 psig with two (2) SRVs OPEN and a third being manually cycled

Reactor water level is (-)75 inches and steady, being maintained using HPCI

Suppression pool temperature is 136°F and rising At 0817, the Shift Manager, as the Site Emergency Director, made an Emergency Plan event declaration in accordance with EPIP-1, EMERGENCY CLASSIFICATION PROCEDURE Which ONE of the following completes the statement below?

At 0817, the highest required classification is (l)_ and the State of Alabama is required to be notified no later than (2).

(REFERENCE PRO VIDEDI A. (1) General Emergency (2) 0832 B. (1) General Emergency (2) 0835 C. (1) Site Area Emergency (2) 0835 D. (1) Site Area Emergency (2) 0832

QUESTION 81 Given the following conditions:

All three units are operating at 100% power

A fire is reported in the 4KV Shutdown Board C

RHR Pump 2B automatically started and then tripped with no operator action Note:

l(3)-AOI-lOO-l, Manual Scram

0-SSI-9, Unit 2 Reactor Building Fire 4KV Electrical Board Room 2A Which ONE of the following completes the statements below?

The Shift Manager has entered the SSIs (1 )_, and _(2)_.

A. (1) solely based on the location of the fire (2) all three Units will implement 0-SSI-9 B. (1) due to RHR Pump 2B starting and tripping (2) Units 1 and 3 will implement 1(3)-AOI-lOO-1, and Unit 2 will implement 0-SSI-9 C. (1) due to RHR Pump 2B starting and tripping (2) all three Units will implement 0-SSI-9 D. (1) solely based on the location of the fire (2) Units 1 and 3 will implement 1(3)-AOI-l00-l, and Unit 2 will implement 0-SSI-9

QUESTION 82 Given the following conditions:

Unit 1 is at 90% power

Unit 2 is in MODE 5 performing a refueling outage

Unit 3 is at 100% power

Severe weather in the area causes grid instabilities The following conditions exist on Unit 1:

Incoming Mvars are 150 MVAR

Grid voltage is 505 kV on the 500kV bus

Grid voltage is 161kV on the 161kV bus

Grid frequency is fluctuating from 59.97Hz to 60.03Hz The grid conditions are RED for the 500kV system and YELLOW for the 161kV system.

Which ONE of the following completes the statements below?

The required action per 0-AOI-57-1E, Grid Instability, is to (1).

In accordance with TRO-TO-SOP-30.128, Browns Ferry Nuclear Plant (BFN) Grid Operating Guide, the 161KV circuits _(2)_.

A. (1) RAISE reactive load to restore system voltage (2) must be declared inoperable B. (1) RAISE turbine load to restore system frequency (2) remain operable C. (1) RAISE reactive load to restore system voltage (2) remain operable D. (1) RAISE turbine load to restore system frequency (2) must be declared inoperable

QUESTION 83 Given the following conditions:

Unit 2 was operating at 90%

An unisolable Main Steam Line break in the Steam Tunnel occurred

A manual reactor scram was inserted At time T0, the following conditions exist:

o Stack Noble gas (WRGERMS) release rate is 6.1X 1010 iiCi/sec

Actual Site Boundary Dose rate is 950 mRlhr gamma

The projected Iodine-i 31 Site Boundary measurement is 3.8 X 1 3 tCi/cm Which ONE of the following completes the statements below?

At time T=0, WRGERMS data (l)_ be used to make an emergency declaration.

The highest required emergency classification for this event is _(2)_.

[REFERENCE PROVIDEDj A. (1) should NOT (2) Site Area Emergency B. (l)shouldNOT (2) General Emergency C. (1) should (2) Site Area Emergency D. (1) should (2) General Emergency

QUESTION 84 Unit 2 was operating at 100% power when a LOCA occurred.

Current conditions are as follows:

RPV water level is (-) 135 inches and steady

RPV pressure is 275 psig and steady

Core Spray Loop I is injecting at 7000 gpm, and is the ONLY makeup source

Drywell pressure is 32 psig

Suppression Chamber Pressure is 30 psig

Suppression Pool Water level is 19.5 feet and slowly rising Based on these conditions, which ONE of the following procedures is required to be entered by the Unit Supervisor?

A. 2-EOI Appendix 12, Primary Contaimrient Venting B. EOI C-2, RPV-Emergency Depressurization C. 2-EO1 Appendix 13, Emergency Venting Primary Containment D. EOI C-i, Alternate Level Control

QUESTION 85 Given the following conditions:

A loss of coolant accident (LOCA) has occurred on Unit 1

Suppression Pool level is 16 feet

/0 concentrations are as indicated below:

H 2

Which ONE of the following completes the statements below?

In accordance with 1 -EOI-Appendix- 19, 2 /0 Analyzer Operation, readings from 1 -XR 110 H

/0 Concentration H

2 Recorder (Panel 1-9-54) or from 1-MON-76-1 10, 2/O Analyzer H

(Panel 1-9-55) (1).

Based on the current H/O readings and in accordance with 1 -EOI-2, PC/H leg, enter_(2)_.

2 A. (1) are valid as soon as the analyzer is placed in service (2) 1-EOI-Appendix l4A, N2 MAKEUP TO PRIMARY CONTAINMENT B. (1) are valid as soon as the analyzer is placed in service (2) 1-EOI-Appendix 14B, CAD OPERATION C. (1) are NOT valid until ten minutes after the analyzer is placed in service (2) 1-EOI Appendix 14A, N2 MAKEUP TO PRIMARY CONTAINMENT D. (1) are NOT valid until ten minutes after the analyzer is placed in service (2) 1EOI-Appendix 14B, CAD OPERATION

QUESTION 86 Given the following conditions:

Unit 2 is operating at 100% Reactor power

Core Spray Loop II has been inoperable since June 15 at 0800 The following Core Spray discharge pipe pressures were reported on June 18 at 0830:

2-PI-75-20, CS Loop I Discharge Pressure, 43 psig

2-PI-75-48, CS Loop II Discharge Pressure, 0 psig Assuming no further operator action, which ONE of the following identifies the EARLIEST time that Unit 2 is required to be in Mode 3, in accordance with Tech Specs?

IREFERENCE PROVIDED]

A. June 18 at2130 B. June 18 at2230 C. June22 at 0800 D. June 22 at2000

QUESTION 87 Given the following conditions:

th 26

At 0900 on March Unit 1 scrammed from rated conditions and all rods filly inserted At 1300:

RPV Pressure is 500 psig

Annunciator 9-5B window #13, SLC TEMP ABNORMAL alarms 530

The AUO reports that local tank temperature is F and the breakers for the heaters are tripped

SLC storage tank boron concentration is 12.0%

The SLC storage tank temperature continues to drop while troubleshooting the tripped breakers Which ONE of the following completes the statements below?

At _(1)_ reactor coolant temperature must be less than 212 degrees.

In accordance with Tech Spec Bases 3.1.7, the reason why SLC is required to remain operable in Mode 3 is to ensure (2).

[REFERENCE PRO VIDEDI A. (1) 2100 on March 27th (2) offsite doses remain within 10CFR5O.67 limits following a LOCA B. (1) 0900 on March 28th (2) shutdown capability exists for the subsequent plant cooldown C. (l)2l00onMarch27th (2) shutdown capability exists for the subsequent plant cooldown D. (1) 0900 on March 28th (2) offsite doses remain within 10CFR5O.67 limits following a LOCA

QUESTION 88 Given the following conditions:

Unit 1 is in MODE 2 withdrawing control rods for a startup

IRM D has failed and has been bypassed on Panel 9-5

All IRM DOWNSCALE alarms have cleared on the operable IRMs

All IRMs are on range 1

SRMs are inserted and indicate between 9 x iO cps and 5 x iO cps and are trending higher Subsequently:

IRM H fails downscale due to a degraded power supply Which ONE of the following completes the statements below?

The shortest required completion time for a Tech Spec or Technical Requirements Manual, LCO Required Action is _(l)_ hour(s).

Source Range Monitors (SRMs) _(2)_ be withdrawn at this time.

IREFERENCE PROVIDEDj A. (l)one (2) can NOT B. (1)one (2) can C. (l)twelve (2) can NOT D. (1) twelve (2) can

QUESTION 89 Given the following conditions:

Unit 3 is operating at 100% power

A loss of 25OVDC RMOV Board 3B occurs Which ONE of the following identifies the required action statement(s), if any, in accordance with Technical Specification 3.5.1, ECCS Operating?

IREFERENCE PROVIDED]

A. Action statements G. 1 and G.2 are required to be entered B. Action statement E. 1 is required to be entered C. No action statement in LCO 3.5.1 is required to be entered because LCO 3.0.6 applies D. Action statement H. 1 is required to be entered

QUESTION 90 Which ONE of the following completes the statements below in accordance with 2-SR-3.4.3.2, Main Steam Relief Valves Manual Cycle Test, acceptance criteria?

Each relief valve shall be manually opened and confirmed OPEN by acoustic monitors

_( 1)_thermocouples.

The green CLOSED valve indicating light must be confirmed by no acoustic monitor response

_(2)_ no steam flow indicated on thermocouples downstream of each relief valve.

A. (1)OR (2) AND B. (1)AND (2) AND C. (l)OR (2) OR D. (1)AND (2) OR

QUESTION 91 Unit 2 has entered 2-AOI-85-4, Loss of RPIS due problems with control rod 10-27 position indication.

Which ONE of the following completes the statement below?

In accordance with TRM TR 3.3.5, Surveillance Instrumentation, the (1) and

_(2) are considered redundant to each other for the parameter of control rod motion.

A. (1) control rod position indicators (2) neutron monitoring instruments B. (1) control rod position indicators (2) rod drift alarm feature C. (1) rod drift alarm feature (2) neutron monitoring instruments D. (1) RPIS iNOPERABLE annunciator (Panel 2-9-5A Window 35)

(2) rod drift alarm feature

QUESTION 92 Unit 3 is operating at 100% power when the following occurs:

Main steam line flow increases rapidly

All Main Steam Line Isolation Valves close, except MSIV LINE A INBOARD, 3-FCV-1-14A, which indicates intermediate.

Main Steam Line Leak Detection High (Panel 9-3D-Window 24) is in alarm and TIS- 1 -60A reached 240° F and is slowly lowering Which ONE of the following completes the statements below?

In accordance with the bases for Tech Spec 3.6.1.3, PCIVs, the reason why an additional 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is allowed in the required completion time for Condition A (due to an inoperable MSIV) is to

_(1).

The TSC is _(2)_ to be staffed.

[REFERENCE PRO VIDEDI A. (1) restore the MSIV to Operable before having to reduce power or shutdown the unit (2) required B. (1) restore the MSIV to Operable before having to reduce power or shutdown the unit (2) NOT required C. (1) implement administrative controls for the Operable in-series valve (2) required D. (1) implement administrative controls for the Operable in-series valve (2) NOT required

QUESTION 93 Unit 3 is operating at 100% power when the following occurs:

Annunciator CONDENSATE DEMIN ABNORMAL (9-6B, W6) is received

Hotwell Level is lowering

Reactor vessel water conductivity is slowly rising Further investigation reveals that DRAIN VLV (U), 3-FCV-002-0213J for the 3J Condensate Demineralizer has failed OPEN.

Which ONE of the following completes both statements below?

The failure of the Condensate Demineralizer U valve will cause a (1).

In accordance with 3-AOI-2-1, Reactor Coolant High Conductivity, if reactor vessel water conductivity is rising towards 10 imhos, then _(2)_ is required to be implemented.

NOTE: 3-AOI-100-1 Reactor Scram 3-GOI-100-12A Unit Shutdown from Power Operation to Cold Shutdown and Reductions in Power During Power Operations A. (1) Backwash receiver tank high level and overflow to the backwash receiver pit sump (2) 3-AOI-100-1 B. (1) Phase separator high level and overflow to the waste collector tank (2) 3-GOI-100-12A C. (1) Phase separator high level and overflow to the waste collector tank (2) 3-AOI-100-l D. (1) Backwash receiver tank high level and overflow to the backwash receiver pit sump (2) 3-GOI-100-12A

QUESTION 94 In accordance with O-GOI-lOO-3C, Fuel Movement Operations During Refueling, which ONE of the following identifies where the OFFICIAL Fuel Assembly Transfer Form (FATF) is required to be located during fuel handling?

A. The Fuel Handling Superviso?s desk B. At the refuel floor tag board C. On the refuel platform D. In the Control Room on the Unit Supervisors desk

QUESTION 95 Unit 1 is operating at 100% power when the following occurs:

An inadvertent closure of l-FCV-005-0005, HTR Al EXTR ISOL VLV

Core thermal power exceeded 3458 MWth for an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period (8 hr average)

NO operator actions have been taken per l-AOI-6-1A, High Pressure Feedwater Heater String/Extraction Steam Isolation Which ONE of the following completes the statements below?

Reactor power will rise and generator output will _(1)_ slightly.

Per NPG-SPP-03.5, Regulatory Reporting Requirements, the Shift Manager must make a report to the NRC within _(2)_.

[REFERENCE PROVIDEDj A. (1) rise (2) 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months B. (1) rise (2) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months C. (1) lower (2) 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months D. (1) lower (2) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

QUESTION 96 Which ONE of the following completes the statements below?

Tech Spec LCO 3.0.4(b) allows entry into a mode with the LCO NOT met ONLY if _(1)_.

In accordance with NPG-SPP-09. 11.2, Risk Assessment Methods for Tech Specs, the Tech Spec 3.0.4(b) provision should ONLY be used when (2) once the mode is entered.

A. (1) a risk assessment is performed (2) there is reasonable likelihood that the inoperable equipment will be made operable within the applicable completion time B. (1) the associated actions to be entered permit continued operation in the higher mode for an unlimited period of time (2) the risk management actions do not prevent the completion of other Tech Spec required actions C. (1) a risk assessment is performed (2) the risk management actions do not prevent the completion of other Tech Spec required actions D. (1) the associated actions to be entered permit continued operation in the higher mode for an unlimited period of time (2) there is reasonable likelihood that the inoperable equipment will be made operable within the applicable completion time

QUESTION 97 Which ONE of the following completes the statements below?

Consider each statement separately.

An Emergency Paging System (EPS) touch screen CRT _(l)_ located in the Unit 3 Control Room.

In accordance with the Technical Bases for EPIP-l, EMERGENCY CLASSIFICATION PROCEDURE, the reason the threshold value for the General Emergency classification on drywell radiation is different for the 2-RE-90-272A rad monitor on Unit 2 (when compared to the other units) is because of _(2)_.

TABLE 2.3-GI DRYWELL RADIATION LEVELS WITH RCS BARRIER NOT INTACT INSIDE PRIMARY CONTAINMENT UNIT I UNIT 2 UNIT 3 RAD MONITOR RIHR RAD MONITOR R/HR RAD MONITOR R/HR 1-RE-90-272A 90091 2-RE-90-272A 68405 3-RE-90-272A 90091 A. (1) is (2) fuel loading pattern B. (1)isNOT (2) fuel loading pattern C. (l)isNOT (2) detector geometry and relative shielding D. (1) is (2) detector geometry and relative shielding

QUESTION 98 Which ONE of the following completes the statements below in accordance with EPIP-15, Emergency Exposures?

The (1) shall provide authorization for all emergency radiation doses that may exceed 10 CFR 20.120 1 entitled Occupational Dose Limits for Adults.

Potassium Iodide (KI) should be issued if a projected dose to the thyroid is expected to exceed a MiNIMUM of(2) REM during emergency conditions.

A. (1) Site Emergency Director (2) 10 B. (1) Radiation Protection Manager (2) 10 C. (1) Site Emergency Director (2) 25 D. (1) Radiation Protection Manager (2) 25

QUESTION 99 Which ONE of the following completes the both statements regarding, C-5, Level/Power Control, below?

In accordance with 0-EOIPM SECTION 0-V-K, CONTIGENCY #5, LEVEL/POWER CONTROL BASES, the lower limit of the RPV water level control band is Minimum Steam Cooling RPV Water Level (MSCRWL), WHICH is the lowest RPV water level at which the covered portion of the reactor core will generate sufficient steam to prevent any clad temperature in the uncovered part of the core from exceeding _( 1 )_.

In C-5, Level/Power Control, if RPV level cannot be restored and maintained above _(2)_,

then SAMG entry is required.

A. (1) 1500 (2) Minimum Steam Cooling RPV Water Level B. (1) 1800 (2) Minimum Zero-Injection RPV Water Level C. (1) 1800 (2) Minimum Steam Cooling RPV Water Level D. (1) 1500 (2) Minimum Zero-Injection RPV Water Level

QUESTION 100 During the implementation of EOIs, the Unit Supervisor reaches the step Cl-17 shown below.

For step Ci -17, which ONE of the following identifies 1) the generic name of this EOI symbol AND 2) the point in C-i at which the exit arrow C originated?

Cl-27 MAXIMIZE RPV injection with all available sources L

WHEN RPV water lvi CANNOT be restored and maintained above -180 in.

L C1-16 SAMG ENTRY IS REQUIRED (Ed-i. RC-1; EOl-2, PcC-2: EOl-3, ScC-i; EOl-4, RR-i; C2-i)

A. Action Step Symbol; in the Primary Containment Flooding portion of C-i B. Signal Step Symbol; in the Primary Containment Flooding portion of C-i C. Action Step Symbol; in the Steam Cooling portion of C-i D. Signal Step Symbol; in the Steam Cooling portion of C-i

SRO Reference Table of Contents

13. EOI Curve 2 NPSH Limits (c2$)

29. 2-SR-3.4.9.1 (1)Table2

76. Unit 2 Tech Spec 3.8.1

78. EPIP-1

80. EPIP-1

83. EPIP-1

86. UnIt2TS3.5.1

87. Unit 1 Tech Spec 3.1.7

88. Unit 1 TS 3.3.1.1 pages 3.3-1 through 3.3-6 only, TRM 3.3.4 pages 30-36 only

89. Unit 3 Tech Spec 3.5.1

92. Unit 3 Tech Spec 3.6.1.3, EPIP-1

95. NPG-SPP-03.5, Regulatory Reporting Requirements, Appendix A

AC Sources Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources - Operating LCO 3.8.1 The following AC electrical power sources shall be OPERABLE:

a. Two qualified circuits between the offsite transmission network and the onsite Class I E AC Electrical Power Distribution System:

b. Unit 1 and 2 diesel generators (DGs) with two divisions of 480 V load shed logic and common accident signal logic OPERABLE: and

c. Unit 3 DG(s) capable of supplying the Unit 3 4.16 kV shutdown board(s) required by LCO 3.8.7, Distribution Systems -

Operating.

APPLICABILITY: MODES 1,2, and 3.

ACTIONS NOTE*

LCO 3.0.4.b is not applicable to DG5.

CONDITION REQUIRED ACTION COMPLETION TIME A. One required offsite A.1 Verify power availability 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months circuit inoperable, from the remaining OPERABLE offsite AND transmission network.

Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter AND (continued)

BFN-UNIT 1 3.8-1 Amendment No. 34 249 December 1, 2003

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2 Evaluate availability of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months both temporary diesel generators (TDGs).

AND AND Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter B.3 Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from feature(s), supported by discovery of the inoperable Unit 1 and Condition B 2 DG. inoperable when concurrent with the redundant required inoperability of feature(s) are inoperable. redundant required feature(s)

AND B.4.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Unit 1 and 2 DG(s) are not inoperable due to common cause failure.

OR B.4.2 PerrormSR3.8.1.1 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE Unit 1 and 2 DG(s).

AND (continued)

AC Sources Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) 8.5 Restore Unit 1 and 2 DG 7 days from to OPERABLE status. discovery of unavailability of TDG(s)

AND 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from discovery of Condition B entry

>6 days concurrent with unavailability of TDG(s)

AND 14 days AND 21 days from discovery of failure to meet LCO (continued)

AC Sources Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One division of 480 V 0.1 Restore required division 7 days load shed logic of 480 V load shed logic inoperable, to OPERABLE status.

D. One division of common D.1 Restore required division 7 days accident signal logic of common accident inoperable, signal logic to OPERABLE status.

E. Two required offsite E.1 Declare required 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from circuits inoperable, feature(s) inoperable discovery of when the redundant Condition E required feature(s) are concurrent with inoperable. inoperability of redundant required feature(s)

AND E.2 Restore one required 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months offsite circuit to OPERABLE status.

(continued)

AC Sources Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME NOTE NOTE Only applicable when more Enter applicable Conditions and than one 4.16 kV shutdown Required Actions of LCD 3.8.7, board is affected. Distribution Systems -

Operating, when Condition F is entered with no AC power source F. One required offsite to any 4.16 kV shutdown board.

circuit inoperable.

AND F.1 Restore required offsite 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months circuit to OPERABLE One Unit 1 and 2 DG status.

inoperable.

OR F.2 Restore Unit 1 and 2 DG 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to OPERABLE status.

NOTE Applicable when only one 4.16 kV shutdown board is affected.

G. One required offsite G.1 Declare the affected Immediately circuit inoperable. 4.16 kV shutdown board inoperable.

AND One Unit 1 and 2 DG inoperable.

(rrntir irf

AC Sources Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME H. Two or more Unit 1 H.1 Restore all but one Unit 1 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and 2 DGs and 2 DG to OPERABLE inoperable, status, Required Action and 1.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Associated Completion Time of LINP Condition A B, C, D, E, F. or H not met. 1.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months J. One or more required J.1 Enter LCO 3.0.3. Immediately offsite circuits and two or more Unit 1 and 2 DGs inoperable.

OR Two required offsite circuits and one or more Unit 1 and 2 DGs inoperable.

OR Two divisions of 480 V load shed logic inoperable.

OR Two divisions of common accident signal logic inoperable.

(continued)

BFN-UNIT 1 3.8-6 Amendment No. 234

I I BFN I EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 Rev. 0049 UnitO I PAGE 15 OF 205 6.0 EVENT CLASSIFICATION INDEX SECTION 1.0 REACTOR 1.1 WATER LEVEL 1.2 SCRAM FAILURE 1.3 REACTOR COOLANT ACTIVITY 1.4 MSLIOFFGAS RADIATION 1.5 LOSS OF DECAY HEAT REMOVAL SECTION 2.0 PRIMARY 2.1 PRIMARY CONTAINMENT PRESSURE CONTAINMENT 2.2 PRIMARY CONTAINMENT HYDROGEN 2.3 DRYWELL RADIATION 2.4 DRYWELL INTERNAL LEAKAGE 2.5 LOSS OF PRIMARY CONTAINMENT SECTION 3.0 SECONDARY 3.1 SECONDARY CONTAINMENT CONTAINMENT TEMPERATURE 3.2 SECONDARY CONTAINMENT RADIATION SECTION 4.0 RADIOACTIVITY 4.1 GASEOUS EFFLUENT RELEASES 4.2 MAIN STEAM LINE BREAK 4.3 LIQUID EFFLUENT SECTION 5.0 LOSS OF POWER 5.1 LOSS OF AC POWER 5.2 LOSS OF 250V DC POWER SECTION 6.0 HAZARDS 6.1 RADIOLOGICAL 6.2 CONTROL ROOM EVACUATION

. 6.3 TURBINE FAILURE 6.4 FIREIEXPLOSION 6.5 TOXIC GASES 6.6 FLAMMABLE GASES 6.7 SECURITY 6.8 VEHICLE CRASH 6.9 SPENT FUEL STORAGE SECTION 7.0 NATURAL EVENTS 7.1 EARTHQUAKE 7.2 TORNADO1HIGH WINDS 7.3 FLOOD SECTION 8.0 EMERGENCY 8.1 TECHNICAL SPECIFICATIONS DIRECTOR 8.2 LOSS OF COMMUNICATION JUDGMENT 8.3 LOSS OF ASSESSMENT CAPABILITY 8.4 OTHER LAST PAGE

I BFN EMERGENCY CLASSIFICATION PROCEDURE I

I EPIP-1 Rev. 0049 II Unito I PAGE 16 OF 205 I THIS PAGE INTENTIONALLY BLANK

I J

EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 17 OF 205 REACTOR 10

BFN EMERGENCY CLASSIFICATION PROCEDURE R0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 18 OF 205 NOTES 1 .1-U 111.1 -Al Applicable when the Reactor Head is removed and the Reactor Cavity is flooded.

1.1-SI Applicable in Mode 5 when the Reactor Head is installed.

1 .1-G2 The reactor will remain subcritical under all conditions without boron when:

Any 19 control rods are inserted to position 02, with all other control rods fully inserted.

All control rods except one are inserted to or beyond position 00.

Determined by Reactor Engineeiing.

CURVESITABLES:

TABLE 1.1 -G2 MINIMUM ALTERNATE RPV FLOODING PRESS (MARFP)

NUMBER OF OPEN MSRVs MARFP (PSIG) 6orMore 190 5 230 4 290

I I BFN Unit 0 EMERGENCY CLASSIFICATION PROCEDURE EVENT CLASSIFICATION MATRIX I

EPIP-1 Rev. 0049 I PAGE 19 OF 205 WATER LEVEL Description Description 1.1-oil I NOTE I 1.1-1121 I Uncontrolled water level decrease in Reactor Uncontrolled water level decrease in Spent Fuel Cavity with irradiated fuel assemblies expected to Pool with irradiated fuel assemblies expected to z remain covered by water. remain covered by water.

C I-OPERATING CONDITION: OPERATING CONDITION Mode 5 ALL 1.1-All INOTEI i.i-A21 Uncontrolled water level decrease in Reactor Uncontrolled water level decrease in Spent Fuel Cavity expected to result in irradiated fuel Storage Pool expected to result in irradiated fuel assemblies being uncovered, assemblies being uncovered.

OPERATING CONDITION: OPERATING CONDITION: -.4 Mode 5 ALL 1.1-SI I INOTEI I 1.1-521 I Reactor water level can NOT be maintained Reactor water level can NOT be determined.

above -162 inches. (TAF) m m

J 0

m OPERATING CONDITION: OPERATING CONDITION:

ALL Model or2or3 -<

l.1-G1 I I 1.1-G2 I I NOTE I TABLE I Reactor water level can NOT be restored and Reactor water level can NOT be determined maintained above -180 inches. AND Either of the following exists:

. The reactor will remain subcritical without boron under all conditions, and Less than 4 MSRVs can be opened, or Z Reactor pressure can NOT be restored and maintained above Suppression Chamber pressure by at least 70 psi.

. It has NOT been determined that the reactor will remain subcritical without boron under all ni conditions and unable to restore and maintain MARFP in Table l.l-G2.

z OPERATING CONDITION: 0 Modelor2or3 OPERATING CONDITION:

Model or2or3

BFN I EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 20 OF 205 NOTES 1.2 Subcritical is defined as reactor power below the heating range and not trending upward.

CURVESITABLES:

CURVE t.2-G HEAT CAPACITY TEMP LIMIT RXfFESS

3BtLOWTOP.>5 UI UI SUPPR P. LVL T)

ACTONREQUIRDIAUI3..UR Oh STI(..A UI.

I BFN EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 21 OF 205 SCRAM FAILURE REACTOR COOLANT ACTIVITY E tion Descr I 1.3-UI I I I Reactor coolant activity exceeds 26 iCiIgm dose equivalent 1-131 (Technical Specification Limits) Z as determined by chemistry sample.

C I-OPERATING CONDITION ALL 1.2-Al INOTEI I 1.3-Al I I I Failure of RPS automatic scram functions to bring Reactor coolant activity exceeds 300 .tCiIgm dose the reactor subcritical equivalent lodine-131 as determined by chemistry AND sample.

I-Manual scram or ARI (automatic or manual) was m successful.

OPERATING CONDITION:

OPERATING CONDITION: Mode I or 2 or 3 Model or2 1.2-SI INOTEI I I Failure of automatic scram, manual scram, and ARI to bring the reactor subcritical.

m m

0 m

z OPERATING CONDITION:

Modelor2 -<

1.2-GICURVEI I I I I I Failure of automatic scram, manual scram, and ARI. Reactor power is above 3% 0 AND Either of the following conditions exists:

. Suppression Pool temp exceeds HCTL. in Refer to Curve 1.2-G.

. Reactor water level can NOT be restored and maintained at or above -180 inches.

m z

OPERATING CONDITION:

Mode 1 or 2

BFN I EMERGENCY CLASSIFICATION PROCEDURE 1 Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 22 OF 205 NOTES CURVES/TABLES:

CURVE 15S HEAT CAPACITY TEMP LIMIT U,

SLPR RL LVL FT)

I EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 23 OF 205 1.4U I I I I I I I I Valid MAIN STEAM LINE RADIATION HIGH-HIGH alarm, 1, 2, or 3-RA-90-135C OR Valid OG PRETREATMENT RADIATION HIGH alarm, 1, 2, or 3-RA-90-157A.

m OPERATING CONDITION: Z Modelor2or3 1.5A I I I I Reactor moderator temperature can NOT be maintained below 2120 F whenever Technical Specifications require Mode 4 conditions or during operations in Mode 5. r rn OPERATING CONDITION:

Mode 4 or 5 1.5-SICURVEI I I Suppression Pool temperature, level and RPV pressure can NOT be maintained in the safe area j of Curve 1.5-S. m m

C) m OPERATING CONDITION:

Modelor2or3 I I I C) m z

m m

z C)

I BFN I EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 Unit 0 EVENT CLASSIFICATION MATRIX I Rev. 0049 I PAGE 24 OF 205 THIS PAGE INTENTIONALLY BLANK

BFN Unit 0 I EMERGENCY CLASSIFICATION PROCEDURE EVENT CLASSIFICATION MATRIX I

EPIP-i Rev. 0049 I PAGE 25 OF 205 PRIMARY CONTAINMENT 2.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Unit 0 EVENT CLASSIFICATION MATRIX PAGE 26 OF 205 NOTES CURVESITABLES:

TABLE 2.1-Arn INDICATIONS OF PRIMARY SYSTEM LEAKAGE INTO PRIMARY CONTAINMENT Primary Containment Pressure High Alarm Drywell Ftoor Drain Sump Pump Excessive Operation Drywell CAM Activity Increasing Drywell Temperature High Alarm Chemistry Sample Radionuclide Comparison To Reactor Water

I EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 27 OF 205 PRIMARY CONTAINMENT PRIMARY CONTAINMENT PRESSURE HYDROGEN II )n [iIiJJ I I I I C

z C

0 C

I m

m z

-I 2.1-Al I ITABLEI I I Drywell pressure at or above 2.45 psig AND r

Indication of Primary System leakage into m Primary Containment. Refer to Table 2.1-A.

OPERATING CONDITION:

Model or2or3 2.1-S ICURVEI 2.2-S I I Suppression Chamber pressure can NOT be Drywell or Suppression Chamber maintained in the safe area of Curve 2.1-S. hydrogen concentration at or above 4%

m AND Drywell or Suppression Chamber oxygen concentration at or above 5%.

OPERATING CONDITION: OPERATING CONDITION:

Mode 1 or 2 or 3 Mode I or 2 or 3 -<

2.1GI 2.2-GI I Suppression Chamber pressure can NOT be Drywell or Suppression Chamber maintained below 55 psig. hydrogen concentration at or above 6%

AND Drywell or Suppression Chamber oxygen concentration at or above 5%. m m

m OPERATING CONDITION: OPERATING CONDITION:

Mode 1 or 2 or 3 Mode 1 or 2 or 3

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I BFN EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 29 OF 205 DRYWELL RADIATION Desci n LJescI ion I I I I I z

C C)

C I

m m

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-*1 2.3-Al ITABLEIUS I I Drywell radiation levels at or above the values listed in Table 2.3-A/2.3-S2, with the RCS barrier intact inside Primary Containment.

I m

-I OPERATING CONDITION:

Model or2or3 2.3-SI I I I TABLE I US 2.3-S2 I I I TABLE I US Drywell radiation levels at or above the values Drywell radiation levels at or above the values listed in Table 2.3-S112.3-G2 with the RCS barrier listed in Table 2.3-A12.3-S2, with the RCS barrier NOT intact inside Primary Containment, intact inside Primary Containment, AND m Either of the following exists: m

. Indications of loss of Primary Containment.

Refer to Table 2.312.5-U.

. Primary Containment integrity can NOT be G) maintained.

0 OPERATING CONDITION: OPERATING CONDITION: -<

Model or2or3 Model or2or3 2.3-GI I I TABLE I US 2.3-G2 I I TABLE I US Drywell radiation levels at or above the values Drywall radiation levels at or above the values C) listed in Table 2.3-G1 with the RCS barrier NOT listed in Table 2.3-S112.3-G2 with the RCS barrier m intact inside Primary Containment. NOT intact inside Primary Containment, Z AND rn Either of the following exists:

. Indications of loss of Primary Containment.

Refer to Table 2.3/2.5-U.

. Primary Containment integrity can NOT be m maintained.

OPERATING CONDITION: OPERATING CONDITION: C)

Mode I or 2 or 3 Mode 1 or 2 or 3

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I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 31 OF 205 DRYWELL INTERNAL LOSS OF PRIMARY LEAKAGE CONTAINMENT Description uescription 2.4-U I I I I 2.5-U I I ITABLEI Drywell unidentified leakage exceeds 10 gpm Inability to maintain Primary Containment pressure boundary. Refer to Table 2.3/2.5-U. z OR C

Drywell identified leakage exceeds 40 gpm.

OPERATING CONDITION: OPERATING CONDITION: m Mode 1 or 2 or 3 Mode 1 or 2 or 3 2.4A I I I I I I I Drywell unidentified leakage exceeds 50 gpm.

F m

-I OPERATING CONDITION:

Model or2or3 I I I I I I I Co

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in in C) in z

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in z

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EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 32 OF 205 THIS PAGE INTENTIONALLY BLANK

I EPIP-1 I I BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 I Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 33 OF 205 I SECONDARY CONTAINMENT 3.0

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I I BFN I EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 35 OF 205 SECONDARY CONTAINMENT TEMPERATURE uescnption I I I I I z

0)

I rn m

z

-I I I I I I I

m 3.1-SI I ITABLEIUSI Co An unisolable Primary System leak is discharging into Secondary Containment m

AND Any area temperature exceeds the Maximum Safe Operating Temperature limit listed in Table 3.1.

OPERATING CONDITION:

Modelor2or3 -<

3.1-GI I ITABLEIUSI An unisolable Primary System leak is discharging into Secondary Containment 0 AND Any area temperature exceeds the Maximum Safe Operating Temperature limit listed in Table 3.1 rn AND hi Any indication of potential or significant fuel cladding failure exists. Refer to Table 3.1-G13.2-G with RCS Barrier intact inside Primary Containment. rn z

OPERATING CONDITION Mode 1 or2or3

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I iI EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX i PAGE 37 OF 205 SECONDARY CONTAINMENT RADIATION uescnpuon I I I I I C

z C

0 C

I m

m z

-I 3.2-Al I I I I Any of the following high radiation alarms on Panel 9-3:

1, 2, or 3-RA-90-IA, Fuel Pool Floor Alarm

. 1, 2, or 3-RA-90-250A, Reactor, Turbine, Refuel Exhaust

. 1, 2, or 3-RA-90-142A, Reactor Refuel Exhaust

. 1 2, or 3-RA-90-140A, Refueling Zone Exhaust I

m AND

-I Confirmation by Refuel Floor personnel that irradiated fuel damage may have occurred.

OPERATING CONDITION:

ALL 3.2-S I I ITABLEI US I An unisolable Primary System leak is discharging into Secondary Containment

-4 AND m m

Any area radiation level at or above the Maximum Safe Operating Area radiation limit listed in Table 3.2.

0 OPERATING CONDITION:

Modelor2or3 3.2-G I ITABLEI US I An unisolable Primary System leak is discharging into Secondary Containment m

AND Z Fri Any area radiation level at or above the Maximum Safe Operating Area radiation limit listed in Table 3.2.

r AND Any indication of potential or significant fuel cladding failure exists. Refer to Table 3.1-G13.2-G with RCS Barrier intact inside Primary Containment.

OPERATING CONDITION Modelor2or3 -<

I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 UnIt 0 EVENT CLASSIFICATION MATRIX I PAGE 38 OF 205 THIS PAGE INTENTIONALLY BLANK

BFN EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 39 OF 205 RADIOACTIVITY RELEASES 4M

I BFN I EMERGENCY CLASSIFICATION PROCEDURE f EPIP-1 Rev. 0049 I

Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 40 OF 205 NOTES 4.1-U Pnorto making this emergency classification based upon the WRGERMS incficafion, assess the release by either of the following:

ifidual field measuremen ceed the limits intabte4.l-U 2.0-SI 4.8.B.1 .a.l release fraction exceeds 2.0 if neither assessment can be cendocted within 60 minutes then the declaration must be made on the valid WRGERMS reading.

4.1-A Prior to making this emergency classification based upon the WRGERMS indication, assess the release by either of the following:

1. Actual field measurements exceed the limits in table 4.1-A 2.0-SI 4.8.B.1.a.1 release fraction exceeds 200 If neither assessment can be conducted within 15 minutes then the declaration must be made on the valid WRGERMS reading.

4.1-S Prior to making this emergency classification based upon the gaseous release rate indication, assess the release by eHrer of the following methods:

1. Actual field measurements exceed the limits in table 4.1-S.

2. Prceded or actual dose assessments exceed 100 mrem TEDE or 500 mrem CDE.

If neither assessment can be conducted within 15 minutes then the declaration must be made based on the valid WRGERMS reading.

4.1-G Prior to making this emergency classification based upon the gaseous release rate indication, assess the release by either of the following methods:

1. Actual field measurements exceed the limits in table 4.1-G.

2. Pneded or actual dose assessments exceed 1000 mrem TEDE or 5000 mrem CDE.

If neither assessment can be conducted within 15 minutes then the declaration must be made based on the valid WRGERMS reading.

CURVES!TABLES:

Table 4.1-U RELEASE LIMITS FOR UNUSUAL EVENT TYPE MONITORING METHOD LIMIT DURATION Gaseous Release Rate Stack Noble Gas (WRGERMS) 2.88 X pCi/sec 1 Hour Gaseous Release Rate 0-SI 4.8.B.1.a.1 Release Fraction 2.0 1 Hour Site Boundary Radiation Reading Field Assessment Team 0.10 MREMIHR Gamma 1 Hour Table 4.1-A RELEASE LIMITS FOR? LERT TYPE MONITORING METHOD LIMIT DURATION

° Gaseous Release Rate Stack Noble Gas (WRGERMS) 2.88 X 10 iiCi/sec 15 Minutes Gaseous Release Rate 0-SI 4.8.B.1.a.1 Release Fraction 200 15 Minutes Site Boundary Radiation Reading Field Assessment Team 10 MREM/HR Gamma 15 Minutes Table 4.1-S REI EASE LIMITS FOR SITE ARE EMERGENCY TYPE IVHJNI I JIII1I3 I I FIJU UMIT DURATION Gaseous Release Rate Stack Noble Gas (WRGERMS) 5.9 X 10 pCi/sec 15 Minutes Site Boundary Radiation Reading Field Assessment Team 100 MREM/HR Gamma 1 Hour Site Boundary Iodine-131 Field Assessment Team 3.9X 3jiCl/cm 7

lO 1 Hour Table 4.1-C RELEASE UMITS FOR GENERA EMERGENCY TYPE MONITORING METHOD LIMIT DURATION 10 Gaseous Release Rate Stack Noble Gas (WRGERMS) 5.9 X 10 pCi/sec 15 Minutes Site Boundary Radiation Reading Field Assessment Team 1000 MREM/HR Gamma 1 Hour Site Boundary Iodine-131 Field Assessment Team 3.9 X 10 pCI I cm 3 1 Hour

I BFN I EMERGENCY CLASSIFICATION PROCEDURE I EPIP-i Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 41 OF 205 GASEOUS EFFLUENT Description 4.1-U I I NOTE I TABLEI I a

Gaseous release exceeds ANY limit and duration in Table 4.1-U. z C

0 C

I m

OPERATING CONDITION: m ALL Z

-I 4.1-A I I NOTE ITABLEI I Gaseous release exceeds ANY limit and duration in Table 4.1-A.

I m

OPERATING CONDITION:

ALL 4.1-S I INOTEITABLEI I 0

EITHER of the following conditions exists:

. Gaseous release exceeds or is expected to exceed ANY limit and duration in Table 4.1-S.

. Dose assessment indicates actual or projected dose consequences above 100 rnrem TEDE or 500 mrem thyroid CDE.

OPERATING CONDITION:

ALL -<

4.1-GI INOTEITABLEI I EITHER of the following conditions exists:

. Gaseous release exceeds or is expected to exceed ANY limit and duration in Table 4.1-G.

. Dose assessment indicates actual or projected dose consequences above 1000 mrem TEDE or 5000 mrem thyroid CDE.

m OPERATING CONDITION ALL

-C

EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 BFN L Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 42 OF 205 NOTES CURVESITABLES:

I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 43 OF 205 MAIN STEAM LINE LIQUID EFFLUENT BREAK tion Description 4.2-U I I 4.3-UI I I I Liquid release rate exceeds 20 times ECL as Main Steam Line break outside determined by chemistry sample z Primary Containment with isolation.

AND c Release duration exceeds or will exceed 60 minutes.

m OPERATING CONDITION: OPERATING CONDITION: Z I

Model or2or3 ALL I I 4.3-Al I I Liquid release rate exceeds 2000 times ECL as determined by chemistry sample AND I-Release duration exceeds or will exceed 15 minutes.

OPERATING CONDITION:

ALL 4.2-SI I I I I I I Unisolable Main Steam Line break outside Primary Containment. m m

6) m OPERATING CONDITION:

Model or2or3 -<

I I I I I I 6) m z

ii I

m rTl 6) rTi z

C,

F BFN EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 Unit 0 EVENT CLASSIFICATION MATRIX I Rev. 0049 I PAGE 44 OF 205 THIS PAGE INTENTIONALLY BLANK

I EPIP-1 BFN I EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit EVENT CLASSIFICATION MATRIX I PAGE 45 OF 205 LOSS OF POWER 5.0

BFN EMERGENCY CLASSIFICATION PROCEDURE R0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 46 OF 205 NOTES 5.1-U Loss of normal and alternate supply voltage implies inability to restore voltage from any qualified source to normal or alternate feeder for at least one of the unit specific boards within 15 minutes. At least two boards must be energized from Diesel power to meet this classification. If only one board can be energized and that board has only one source of power then refer to EAL 5.1-Al or 5.1-A2.

5.1-Al Only one source of power (Diesel or Offsite) is available to any one of the listed unit specific 4KV Shutdown Boards. No power is available to the three remaining boards.

5.1 -A2 Loss of voltage to all unit specific 4KV Shutdown Boards applies to those boards which normally supply emergency AC power to the affected unit only. Determination of the event classification depends on the affected unit operating mode. For units in operation 5.1-S would apply.

5.1-S Loss of voltage to all unit specific 4KV Shutdown Boards applies to those boards which normally supply emergency AC power to the affected unit only. Determination of the event classification depends on the affected unit operating mode. For units in Shutdown or Refuel 5.l-A2 would apply.

5.1 -G Loss of voltage to all unit specific 4KV Shutdown Boards applies to those boards which normally supply emergency AC power to the affected unit only.

CURVESITABLES:

Table 5.1 UNIT 4KV SHUTDOWN BOARD APPLICABILITY APPLICABLE UNIT APPLICABLE 4KV SHUTDOWN BOARDS UNIT 1 A, B, C, and D UNIT2 A, B, C, andD UNIT 3 3A, 3B, 3C, and 3D

I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 47 OF 205 1 5.1-U I tITABLEI US I I I I Loss of normal and supply voltage to ALL unit specific 4KV shutdown boards from Table 5.1 z for greater than 15 minutes C AND C At least two Diesel Generators supplying power to unit specific 4KV shutdown boards listing in Table 5.1.

OPERATING CONDITION: m ALL 5.1-Al I I NOTE I TABLE I US 5.1-A2 I I I NOTE TABLE US I Loss of voltage to ANY THREE unit specific 4KV Loss of voltage to ALL unit specific 4KV shutdown shutdown boards from Table 5.1 for greater than boards from Table 5.1 for greater than 15 minutes.

15 minutes I-Only ONE source of power available to the m remaining board.

OPERATING CONDITION: OPERATING CONDITION:

Mode 1 or 2 or 3 Mode 4 or 5 or Defueled 5.1-S I I NOTE ITABLEI US I I I I Loss of voltage to ALL unit specific 4KV shutdown boards from Table 5.1 for greater than 15 minutes.

in m

G) in z

C)

OPERATING CONDITION: -<

Model or2or3 5.1-G I I NOTE ITABLEI US I I I Loss of voltage to ALL unit specific 4KV shutdown G) boards from Table 5.1 FR AND FR Either of the following conditions exists;

. Restoration of at least one 4KV shutdown board F.

is NOT likely within three hours. FR

. Adequate core cooling can NOT be assured.

FR m

z OPERATING CONDITION:

Mode 1 or 2 or 3

BFN EMERGENCY CLASSIFICATION PROCEDURE R0049

Unit 0 EVENT CLASSIFICATION MATRIX PAGE 48 OF 205 NOTES 52 250V DC power voltage below 248 volts constitutes a loss of DC power to the affected board. The voltage readings may be obtained at the 250V Shutdown Battery Board (or the 250V Plant Battery Board) that is feeding the affected board.

CURVES1TABLES:

Table 5.2-U UNIT 4KV SHUTDOWN BOARD APPLICABILITY APPLICABLE UNIT APPLICABLE 4KV SHUTDOWN BOARDS UNIT 1 A, B, C,ANDD UNIT2 A, B, C,ANDD

. UNIT 3 3A, 3B, 3C, AND 3D Table 5.2-S CRITICAL DC POWER AND ESSENTIAL SYSTEMS COMBINATION LOSS OF CRITICAL 250V DC POWER POTENTIALLY RESULTS (Unit Specific Unless Otherwise Noted) IN I Control Power for 4KV Unit Boards A, B, and C Loss of Main Condenser AND AND Control Power for 480V Unit Boards A and B Loss of Both EHC Pumps AND AND Power for Panel 9-9 Cabinet I Loss of All Reactor Feed Pumps II Power for 250V DC RMOV Board A Loss of HPCI III Power for 250V DC RMOV Board C Loss of RCIC IV Power for 250V DC RMOV Boards A, B, and C Less than 4 MSRVs AND AND Control Power for 4KV Shutdown Boards A, B, C, and D Loss of All RHR Pumps (4KV Shutdown Boards 3A, 3B, 3C, and 3D for Unit 3) And Core Spray Pumps

BFN I EMERGENCY CLASSIFICATION PROCEDURE I

I EPIP-1 Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 49 OF 205 L

5.2-U 1 ITABLEI US I I I I Unplanned loss of 2 .1 DC control power to ALL unit specific 4KV shutdown boards from z Table 5.2-U for greater than 15 minutes OR c Unplanned loss of 250V DC control power to unit specific 480V shutdown boards A and B I.

for greater than 15 minutes.

m OPERATING CONDITION: Z I

Modes4or5 I I I I I I I

)I I

m 5.2-S I I NOTE ITABLEI US I I I Loss of 250V DC power to ALL combinations (I, II, III, and IV) of essential systems from Table 5.2-S for greater than 15 minutes.

m 6) m z

C, OPERATING CONDITION:

Mode 1 or 2 or 3 I I I I I I 6) m z

rTi I

m m

6) ni C,

I EPIP-1 BFN I EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 50 OF 205 a THIS PAGE INTENTIONALLY BLANK

I EPIP.1 I BFN I EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 51 OF 205 HAZARDS

I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 52 OF 205 NOTES CURVESITABLES:

I I BFN EMERGENCY CLASSIFICATION PROCEDURE EPIP-1 Rev. 0049 UnIt 0 EVENT CLASSIFICATION MATRIX I PAGE 53 OF 205 RADIOLOGICAL uescription uescription 6.1U I I I I I I I I Valid, unexpected increase of ANY in-plant ARM reading to 1000 mrem/hr (except TIP room).

C I

I m

OPERATING CONDITION:

ALL Z 6.1-All I I 6.l-A21 I I I Valid, unexpected increase of ANY in-plant ARM Control Room radiation levels greater than reading to 1000 mrem/hr (except TIP room). 15 mrem/hr.

r Personnel required in the affected area(s). m

-I OPERATING CONDITION: OPERATING CONDITION:

ALL ALL I I I I C)

-I ii m

m G) m z

C)

I I G)

I, z

ii I

FT1 rn Ii z

C,

BFN I EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 54 OF 205 NOTES CURVESITABLES:

EPIP-1 I BFN I EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 55 OF 205 CONTROL ROOM TURBINE FAILURE EVACUATION Desci non I 6.3-U I I I Turbine failure resulting in casing penetration OR Significant damage to turbine or generator seals during operation.

I-OPERATING CONDITION:

Model,or2 6.2-Al I I 6.3-Al I I Control Room Abandonment from entry into Turbine failure resulting in visible structural 1, 2, or 3-AOl-I 00-2 or 0-SSI-l 6 for ANY Unit damage to or visible penetration of ANY of the Control Room. following structures from missles:

Reactor Building Diesel Generator Building r Intake Structure Control Bay m OPERATING CONDITION:

OPERATING CONDITION: Model or 2 ALL 6.2S I I I Control Room Abandonment from entry into 1, 2, or 3-AOI-l00-2 or 0-SSI-16 for ANY Unit Control Room AND m Control of reactor water level, reactor pressure, m and reactor power (for Modes 1, or 2, or 3) or m decay heat removal (for Modes 4, or 5) per 1, 2, or 3-AOl-i 00-2 or 0-SSI-l 6 as applicable, can G)

NOT be established within 20 minutes after evacuation is initiated. a OPERATING CONDITION: -<

ALL I I I G)

Ill z

m r

I1 m

rn z

C,

U, zoO W 0W LU wx 0-00 D

._J 0.

I_i 0 0.

(DO ZLIJ

> 0 Z E >OZ E <

o 0 -LLJa,o o u, o, LU 0 E oCC E° LU OOOEC<Ø 4-0 C Cl, LU (oCt, uoCv 0 a .- o** 0 cc C CD c C C Cl, C,, LU i. IL Z WI >

I-I ol D C.) ooi-.9roco

EPIP-1 I BFN I EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 57 OF 205 6.4-UI I I I TABLE I 6.4-U2 I I I I Confirmed fire in ANY plant area listed in Unanticipated explosion within the protected area Table 6.4-UI resulting in visible damage to ANY permanent AND structure or equipment.

NOT extinguished within 15 minutes.

m OPERATING CONDITION: OPERATING CONDITION:

ALL ALL.

6.4-Al I ITABLEI ..

I I Fire or explosion in ANY plant area listed in Table 6.4-A affecting safety system performance OR Fire or explosion causing visible damage to permanent structure of safety systems in ANY plant area listed in Table 6.4-A. 4 OPERATING CONDITION:

ALL I I I I I I Cl)

-I m

m 0

m z

C, I I I I I 0

ni z

m I

ni m

ni z

C)

BFN EMERGENCY CLASSIFICATION PROCEDURE R0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 58 OF 205 NOTES CURVESITABLES:

Table 6.516.6 APPLICABLE PLANT AREA Reactor Building Refuel Floor Control Bay Diesel Generator Buildings Turbine Building Intake Pumping Station Radwaste Building Cable Tunnel (Intake To Turbine Building)

Standby Gas Treatment Building

I I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 59 OF 205 TOXIC GASES uescription 6.5-U I I I TABLEI I EITHER of the following conditions exists:

. Normal operations impeded due to access restrictions caused by toxic gas concentrations within Z any building or structure listed in Table 6.5/6.6.

. Confirmed report by local, county, or state officials that a large offsite toxic gas release has c occurred within one mile of the site with potential to enter the site boundary in concentrations at or above the Permissible Exposure Limit (PEL) causing an evacuation of any site personnel.

OPERATING CONDITION: m Z

ALL -1 6.5-A I I I TABLEI I ALL of the following conditions exist:

. Plant personnel report toxic gas within any building or structure listed in Table 6.5/6.6.

. Plant personnel report severe adverse health reactions due to toxic gas (i.e., burning eyes, throat, or dizziness), or sampling results by Fire Protection or Industrial Safety personnel indicate levels above the Permissible Exposure Limit (PEL).

. Determination by the Site Emergency Director that plant personnel would be unable to perform actions necessary to establish and maintain cold shutdown conditions while utilizing appropriate personnel protective equipment.

OPERATING CONDITION:

ALL I I I I I Cl,

-I m

m m

D C) m z

C)

I I I I I C) m z

m I

BFN EMERGENCY CLASSIFICATION PROCEDURE R0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 60 OF 205 NOTES CURVESITABLES:

Table 6.5166 APPLICABLE PLANT AREA Reactor Building Refuel Floor Control Bay Diesel Generator Buildings Turbine Building Intake Pumping Station Radwaste Building Cable Tunnel (Intake To Turbine Building)

Standby Gas Treatment Building

I I BFN I EMERGENCY CLASSIFICATION PROCEDURE EPIP-1 Rev. 0049

[ Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 61 OF 205 FLAMMABLE GASES Description 6.6-U I I I TABLEI I EITHER of the following conditions exists:

. Release of flammable gas within the site boundary in concentrations at or above 25% of the Lower z Explosive Limit (LEL) for any three readings obtained in a 10 ft. triangular area as indicated by Fire C Protection or Industrial Safety personnel using appropriate monitoring instrumentation.

. Confirmed report by local, county, or state officials that a large offsite flammable gas release has occurred within one mile of the site with potential to enter the site boundary in concentrations at or above 25% of the Lower Explosive Limit (LEL).

m OPERATING CONDITION: Z ALL 6.6-A I ITABLEI I Release of flammable gases within any building or structure listed in Table 6.5/6.6 in concentrations at or above 25% of the Lower Explosive Limit (LEL) for any three readings obtained in a 10 ft. triangular area as indicated by Fire Protection or Industrial Safety personnel using appropriate monitoring instwmentation.

J

-I OPERATING CONDITION:

ALL I I I I I Ci)

-4 rn m

C) m z

C)

I I I I I C) rn z

m F

m rn C) ni z

C)

BFN EMERGENCY CLASSIFICATION PROCEDURE I

I Rev. 0049 I Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 62 OF 205 I NOTES CURVESITABLES:

I I BFN EMERGENCY CLASSIFICATION PROCEDURE I

EPIP-i Rev. 0049 UnIt 0 EVENT CLASSIFICATION MATRIX I PAGE 63 OF 205 SECURITY Description DescriptIon 6.7-U I 1 I I I I

1. A SECURITY CONDITION that does NOT involve a HOSTILE ACTION as reported by z the Security Shift Supervisor. c OR

2. A credible Browns Ferry threat notification OR

3. A validated notification from NRC providing information of an aircraft threat. m z

I OPERATING CONDITION:

ALL 6.7A I I I I I I I I

1. A HOSTILE ACTION is occurring or has occurred within the OWNER CONTROLED AREA as reported by the Security Shift Supervisor.

r m

u

2. A validated notification from NRC of an airliner attack threat within 30 minutes of the site.

OPERATING CONDITION:

ALL 6.7S I I I I I I I I Co A HOSTILE ACTION is occurring or has occurred within the PROTECTED AREA as reported by the m Security Shift Supervisor G)

OPERATING CONDITION: m ALL 6.7-GI I I I I I I I G)

1. A HOSTILE ACTION has occurred such that plant personnel are unable to operate equipment required to m:intain safety functions.

2. A HOSTILE ACTION has caused failure of Spent Fuel Cooling Systems and IMMINENT z fuel damage is likely for a freshly off-loaded reactor core in pool.

OPERATING CONDITION:

ALL

I EPIP-1 BFN I EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 64 OF 205 NOTES CURVESITABLES:

I EPIP-1 I BFN I EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 65 OF 205 VEHICLE CRASH Description 6.8-UI I I I Vehicle crash (for example; aircraft or barge) into plant structures or systems within the protected area boundary.

C I

r m

OPERATING CONDITION:

ALL 6.8-Al I I I Vehicle crash (for example; aircraft or barge) into ANY plant vital area.

I m

OPERATING CONDITION:

ALL I I I I C,)

-I m

m m

C) m z

C)

I I I I I C) ni z

rn I

ni F

C)

F 2

C,

I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 66 OF 205 NOTES CURVESITABLES:

EMERGENCY CLASSIFICATION PROCEDURE EPIP.1 BFN Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 67 OF 205 SPENT FUEL STORAGE Description 6.9-UI I I I I Damage to a loaded cask CONFINEMENT BOUNDARY from ANY of the following: C z

. Natural phenomena (e.g., seismic event, tornado, flood, lightning, snowlice accumulation, etc.)

. Accident (e.g., dropped cask, tipped over cask, explosion, missile damage, fire damage, burial under C debris, etc.).

. Judgement of the Site Emergency Director that the CONFINEMENT BOUNDARY damage is a m degradation in the level of safety of the ISFSI.

OPERATING CONDITION:

ALL I I I I I I

m

-I I I I I I 0

-I m

m m

6) m z

C)

I I I I I 6) rn z

rn I

m ni m

z C)

I BFN EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 68 OF 205 THIS PAGE INTENTIONALLY BLANK

EPIP-i I BFN I EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 69 OF 205 NATURAL EVENTS 7.0

1 EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 70 OF 205 NOTES CURVESITABLES:

I EPIP-1 l BFN I EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 71 OF 205 EARTHQUAKE Description 7.1-UI I I I I Valid annunciation in Unit I Control Room, Panel 1-XA-55-22C, Window 5, START OF STRONG MOTION ACCELEROGRAPH z AND Assessment by Unit One and Two Control Room personnel that an earthquake has occurred.

OPERATING CONDITION:

ALL 7.1-Al I Valid annunciation in the Unit 1 Control Room, Panel 1-XA-55-22C, Window 6, 12 SSE RESPONSE SPECTRUM EXCEEDED AND Assessment by Unit One and Two Control Room personnel that an earthquake has occurred.

-I OPERATING CONDITION:

ALL 0)

-4 m

m m

C) m z

a I I I C) m 2

rn I

m m

m 2

C)

I EPIP-i I BFN I EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 I UnIt 0 EVENT CLASSIFICATION MATRIX I PAGE 72 OF 205 I NOTES CURVESITABLES:

I I BFN Unit 0 I EMERGENCY CLASSIFICATION PROCEDURE EVENT CLASSIFICATION MATRIX I

EPIP-1 Rev. 0049 I PAGE 73 OF 205 TORNADO I HIGH WINDS Description 7.2-UI I I I I Report by plant personnel of tornado striking within the protected area boundary.

C C,

C I

m OPERATING CONDITION:

ALL 7.2-Al I I I Tornado striking plant vital area OR I

Onsite wind speed above 90 MPH as indicated using the meteorological data screen of the Integrated Computer System (ICS). 4 OPERATING CONDITION:

ALL I I C,

-I m

m 0

m z

C, I I I 0

m z

ii I

Ill m

m z

C,

I EPIP-1 BFN I EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 74 OF 205 NOTES CURVESITABLES:

I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 75 OF 205 FLOOD Description 7.3-UI I I I I Wheeler Lake level exceeds or is predicted to exceed elevation 565 feet. c z

Water entering permanent plant structures due to flooding.

OPERATING CONDITION:

ALL 7.3-Al I I I I Wheeler Lake level exceeds or is predicted to exceed elevation 565 feet.

AND I-EITHER of the following conditions exists: m

. Breech or failure of any water-tight structure is causing flooding of the structure

. Equipment required for safe shutdown is affected.

OPERATING CONDITION:

ALL I

0)

-I m

m 0

m z

C, I I I 0

m z

m I

I I BFN I EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 76 OF 205 THIS PAGE INTENTIONALLY BLANK

I EPIP-1 BFN I EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 UnIt 0 EVENT CLASSIFICATION MATRIX I PAGE 77 OF 205 EMERGENCY DIRECTOR JUDGMENT 8.0

EPIP-1 I I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 I Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 78 OF 205 I NOTES CURVES!TABLES:

(.

I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 79 OF 205 TECHNICAL SPECIFICATIONS Description 8.1-UI I I I I Inability to reach required shutdown condition (Mode 3 or Mode 4) within Technical Specification Limiting Conditions for Operation (LCO) Limits.

C m

OPERATING CONDITION:

Modelor2or3 I

I m

Co

-I m

m m

0 m

z C)

I 0

m z

Fri I

In zoO 0O WWW C,)

C 4

0.

z E

uJ 8z o

LIJX Ci- U) z o 2 U).

E d)

< G) E Q c z0r U

0 U)

U, 0

>- -J z C o

Ow Cl)

D 0 E v w 1;;

C,)

a,w

-J Cl) 0 >Z 0 0 D 0 W CLC)

LU >

H CI ZI C..)

j BFN I EMERGENCY CLASSIFICATION PROCEDURE I EPIP-1 Rev. 0049 Unit 0 f EVENT CLASSIFICATION MATRIX I PAGE 81 OF 205 LOSS OF COMMUNICATION uescription 8.2-U I I ITABLE I I Unplanned loss of onsite communication listed in Table 8.2-U that defeats the Plant Operations Staffs ability to perform routine operations CI, OR Unplanned loss of ALL off-site communication listed in Table 8.2-U.

m OPERATING CONDITOIN:

ALL I

I m

I 0)

-4 m

m m

0 m

z C)

II 0

m z

rTi I

rn F,

0 m

z C,

BFN EMERGENCY CLASSIFICATION PROCEDURE R

Unit 0 EVENT CLASSIFICATION MATRIX PAGE 82 OF 205 NOTES 8.3 Significant Transient is an unplanned event involving one or more of the following:

(I) Automatic turbine runback greater than 25% thermal reactor power, or (2) Electrical load reduction greater than 25% full electrical load, or (3) Thermal power oscillations greater than 10%, or (4) Reactor scram, or (5) Valid ECCS initiation.

CURVESITABLES:

. Table 8.3-S APPLICABLE SAFETY FUNCTIONS Reactor Power Reactor Pressure Reactor Level Subcriticality Drywell Temperature Drywell Pressure Suppression Chamber Pressure Suppression Pool Temperature Suppression Pool Level

(.

I EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 83 OF 205 LOSS OF ASSESSMENT CAPABILITY Uescflption 8.3-UI I I I I Unplanned loss of most or all safety system annunciators or indicators which causes a significant loss of plant assessment capability for greater than 15 minutes z AND Compensatory non-alarming safety system indications are available (SPDS, ICS)

AND In the opinion of the Shift Manager, increased surveillance is required to safely operate the plant.

OPERATING CONDITION:

MODE1,or2,or3 8.3-Al INOTEI I I Unplanned loss of most or all safety system annunciators or indicators which causes a significant loss of plant assessment capability for greater than 15 minutes AND In the opinion of the Shift Manager, increased surveillance is required to safely operate the plant AND EITHER of the following conditions exists: m

Compensatory non-alarming safety system indications are NOT available (SPDS, ICS)

A significant transient is in progress.

OPERATING CONDITION:

r.

MODE 1,or2,or3 8.3-S I I NOTE I TABLEI I Loss of most or all annunciators associated with safety systems AND Compensatory non-alarming safety system indications are NOT available (SPDS, ICS) m AND In Indications needed to monitor safety functions are NOT available (Refer to Table 8.3-S)

AND A significant transient is in progress. 0 OPERATING CONDITION:

MODE1,or2,or3 I I C)

In z

In r

In In C) m z

C)

I EPIP-1 I BFN I EMERGENCY CLASSIFICATION PROCEDURE I Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 84 OF 205 NOTES 8.4-U Table 8.4-U contains only example events that may justify Unusual Event classification. This event classification is intended to address unanticipated conditions not explicitly addressed elsewhere, but warrant declaration of an emergency because conditions exists which the Emergency Director believes to fall under the Unusual Event Classification. Additionally this EAL should be considered in making emergency classifications regarding challenges to fission product barriers not specifically address elsewhere in the EAL matrix.

8.4-A This event classification is intended to address unanticipated conditions not explicitly addressed elsewhere, but that warrant declaration of an emergency because conditions exist which the Site Emergency Director believes to fall under the Alert classification. Additionally this EAL should be considered in making emergency classifications regarding challenges to fission product barriers not specifically address elsewhere in the EAL matrix.

8.4-S This event classification is intended to address unanticipated conditions not explicitly addressed elsewhere, but that warrant declaration of an emergency because conditions exist which the Site Emergency Director believes to fall under the Site Area Emergency classification. Additionally this EAL should be considered in making emergency classifications regarding challenges to fission product barriers not specifically address elsewhere in the EAL matrix.

8.4-G This event classification is intended to address unanticipated conditions not explicitly addressed elsewhere, but that warrant declaration of an emergency because conditions exist which the Site Emergency Director believes to fall under the General Emergency classification. Additionally this EAL should be considered in making emergency classifications regarding challenges to fission product barriers not specifically address elsewhere in the EAL matrix.

CURVESITABLES:

Table 8.4-U OTHER EXAMPLE UNUSUAL EVENTS Plant Transient Response Unexpected Or Not Understood Unanalyzed Safety System Configuration Affecting, Threatening Safe Shutdown Inadequate Personnel To Achieve Or Maintain Safe Shutdown Degraded Plant Conditions Beyond License Basis Threatening Safe Operation Or Safe Shutdown Emergency Procedures Not Adequate To Maintain Safe Operation Or Achieve Safe Shutdown

I EPIP-1 I BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0049 Unit 0 EVENT CLASSIFICATION MATRIX I PAGE 85 OF 20j OTHER uescripuofl 8.4-U I I NOTE I TABLEI I Events are in process or have occurred which indicate a potential degradation in 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. Refer to Table 8.4-U for examples.

I

. m Any loss or any potential loss of containment.

OPERATING CONDITION:

ALL 8.4-Al INOTEI Events are in process or have occurred which involve an actual or potential substantial degradation in 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.

OR Any loss or potential loss of fuel cladding or RCS pressure boundary.

OPERATING CONDITION:

ALL 8.4-SI INOTEI Events are in process or have occurred which involve actual or likely major failures of plant functions needed for protection of the public or HOSTILE ACTION that results in intentional damage or malicious acts (1) toward site personnel or equipment that could lead to the likely failure thereof or, (2) prevent effective access to equipment needed for protection of the public. Any releases are not expected to result in exposure levels which exceed EPA Protective Action Guideline exposure levels beyond the site m boundary.

OR m Any loss or potential loss of both fuel cladding and RCS pressure boundary.

OR m Potential loss of either fuel cladding or RCS pressure boundary and loss of any additional barrier.

OPERATING CONDITION:

ALL 8.4-GI INOTEI I 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 2 Action Guideline exposure levels offsite for more than the immediate site area.

OR Loss of any two barriers and potential loss of third barrier.

2 OPERATING CONDITION: C)

ALL

RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation LCO 3.3.1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.1.1-1.

ACTIONS NOTE Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Place channel in trip. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channels inoperable.

OR A.2 NOTE Not applicable for Functions 2.a, 2.b, 2.c.

2.d, or 2.f.

Place associated trip 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months system in trip.

B. NOTE 8.1 Place channel in one trip 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Not applicable for system in trip.

Functions 2.a, 2.b, 2.c, 2.d,or2.f.

One or more Functions 8.2 Place one trip system in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months with one or more required trip.

channels inoperable in both trip systems.

(continued)

BFN-UNIT 1 3.3-1 Amendment No. 234, 262, 266 December 29, 2006

RPS Instrumentation 3.3.1.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One or more Functions C.1 Restore RPS trip 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with RPS trip capability capability.

not maintained.

D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition A, B, or Table 3.3.1.1-1 for the C not met. channel.

E. As required by Required E.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Action D.1 and POWER to < 30% RTP.

referenced in Table 3.3.1.1-1.

F. As required by Required F.1 Be in MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Action D.1 and referenced in Table 3.3.1.1-1.

G. As required by Required G.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action D.1 and referenced in Table 3.3.1.1-1.

H. As required by Required H.1 Initiate action to fully Immediately Action D.1 and insert all insertable referenced in control rods in core cells Table 3.3.1.1-1. containing one or more fuel assemblies.

BFN-UNIT 1 3.3-2 Amendment No. 234262 September 27, 2006

RPS Instrumentation 3.3.1.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME I. As required by Required .1 Initiate alternate method 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action D.1 and to detect and suppress referenced in thermal hydraulic Table 3.3.1.1-1. instability oscillations.

J. Required Action and J.1 Be in Mode 2. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion Time of Condition I not met.

BFN-UNIT 1 3.3-2a Amendment No.266 December 29, 2006

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS NOTES

1. Refer to Table 3.3.1.1-1 to determine which SRs apply for each RPS Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains RPS trip capability.

SURVEILLANCE FREQUENCY SR 3.3.1.1.1 Perform CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.3.1.1.2 NOTE Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER 25% RTP.

Verify the absolute difference between the 7 days average power range monitor (APRM) channels and the calculated power is 2% RTP while operating at 25% RTP.

SR 3.3.1.1.3 NOTE Not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST. 7 days (continued)

BFN-UNIT 1 3.3-3 Amendment No. 234-262 September 27, 2006

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.1.4 Perform CHANNEL FUNCTIONAL TEST. 7 days SR 3.3.1.1.5 Verify the source range monitor (SRM) and Prior to intermediate range monitor (IRM) channels withdrawing overlap. SRMs from the fully inserted position SR 3.3.1,1.6 NOTE Only required to be met during entry into MODE 2 from MODE 1.

Verify the IRM and APRM channels overlap. 7 days SR 3.3.1.1.7 Calibrate the local power range monitors. 1000 MWDIT average core exposure SR 3.3.1.1.8 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.1.1.9 NOTES

1. Neutron detectors are excluded.

2. For Function 1, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

Perform CHANNEL CALIBRATION. 92 days (continued)

BEN-UNIT 1 3.3-4 Amendment No.24-262 September 27, 2006

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.1.10 Perform CHANNEL CALIBRATION. 184 days SR 3.3.1.1.11 (Deleted)

SR 3.3.1.1.12 Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.1.1.13 NOTE Neutron detectors are excluded.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

SR 3.3.1.1.15 Verify Turbine Stop ValveClosure and 24 months Turbine Control Valve Fast Closure. Trip Oil PressureLow Functions are not bypassed when THERMAL POWER is 30% RTP.

SR 3.3.1.1.16 NOTE For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

)

Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.1.1.17 Verify OPRM is not bypassed when APRM 24 months Simulated Thermal Power is 25% and recirculation drive flow is < 60% of rated recirculation drive flow.

BFN-UNIT 1 3.3-5 Amendment No. 234, 262, 263, 266 December 29, 2006

RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 1 of 3)

Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION D.1

1. Intermediate Range Monitors a, Neutron Flux - High 2 3 G SR 3.3.1.1.1 120/125 SR 3.3.1.1.3 divisions of full SR 3.3.1.1.5 scale SR 3.3.1.1.6 SR 3.3.1.1.9 SR 3.3.1.1.14 (5 a) 3 H SR 3.3.1.1.1 120/125 SR 3.3.1.1.4 divisions of full SR 3.3.1.1.9 scale SR 3.3.1.1.14

b. flop 2 3 G SR 3.3.1.1.3 NA SR 3,3.1.1,14 (5aI 3 H SR 3,3.1.1.4 NA SR 3.3.1.1.14

2. Average Power Range Monitors

a. Neutron Flux - High, 2 G SR 3.3.1.1.1 15% RTP Setdown SR 3.3.1.1.6 SR 3.3.1.1.7 SR 3.3.1.1.13 SR 3.3.1.1.16

b. Flow Biased Simulated 1 (3 b) F SR 3.3.1.1.1 0.66W Thermal Power High SR 3.3.1.1.2 + 65% RTP SR 3.3.1.1.7 and 120%

SR 3.3.1.1.13 RTP(CI SR 3.3.1.1.16

c. Neutron Flux - High 1 (3b F SR 3.3.1.1.1 i. 120°b RTP SR 3.3.1.1.2 SR 3.3.1.1.7 SR 3.3.1.1.13 SR 3.3.1.1.16 (continued)

(a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

(b) Each APRM channel provides Inputs to both trip systems.

(c) [0.66W + 66% 0.6

- NJ RTP when reset for single loop operation per LCO 3,4.1, Recircuiation Loops Operatlng.

BFN-UNIT 1 3.3-6 Amendment No. 236, 262, 269 March 06, 2007

Control Rod Block Instrumentation TR 3.3.4 TR 3.3 INSTRUMENTATION TR 3.3.4 Control Rod Block Instrumentation LCO 3.3.4 The control rod block instrumentation for each Function in Table 3.3.4-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.4-1 NOTE Separate Condition entry is allowed for each Function.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Enter the Condition Immediately channels inoperable, referenced in Table 3.3.4-1 for the Function.

B. As required by 5.1 Place at least one 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Required Action Al inoperable channel in the and referenced in tripped condition.

Table 3.3.4-1.

C. As required by C.1 Place the channel in the Immediately Required Action A.1 tripped condition.

and referenced in Table 3.3.4-1.

C.2 Impose administrative Immediately controls to prevent control rod withdrawal.

(continued)

BFN-UNIT 1 3.3-30 TRM Revision 57 October 30. 2006

Control Rod Block instrumentation TR 3.3.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. As required by ----

NOTE Required Action A.1 InoperabIe Rod Block Logic may and referenced in also affect Technical Table 3.3.4-1. Specifications LCO 3.3.2.1, LCO 3.9.1. and LCO 3.9.2.

D.1 Impose administrative Immediately controls to prevent control rod withdrawal.

BFN-UNIT 1 3.3-31 TRM Revision 057 October 30, 2006

Control Rod Block Instrumentation TR 3.3A NOTE Refer to Table 3.3.4-1 to determine which TSRs apply for each Function.

TECHNICAL SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.3.4.1 Perform CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months TSR 3.3.4.2 NOTE For APRM Function 1 .b. not required to be performed when entering MODE 2 from MODE I until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST. 184 days TSR 3,3.4.3 NOTE

1. For IRM Functions, not required to he performed \hen entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

2. For SRM Functions. not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after IRMs on Range 2 or below.

Perform CHANNEL FUNCTIONAL TEST. Once within 7 days prior to startup AND 31 days thereafter (continued)

BFN-UNIT 1 3.3-32 TRM Revision O-57 October 30, 2006

Control Rod Block Instrumentation TR 3.3.4 TECHNICAL SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.3.4.4 Perform CHANNEL FUNCTIONAL TEST. Once within 7 days prior to startup AND Once per OPERATING CYCLE thereafter TSR 3.3.4.5 Perform CHANNEL FUNCTIONAL TEST. 92 days TSR 3.3.4.6 NOTE

1. For IRM and SRM Functions, neutron detectors are excluded.

2. For IRM Functions, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

3. For SRM Functions, not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after IRMs on Range 2 or below.

Perform CHANNEL CALIBRATION. 92 days TSR 33.4.7 NOTE For APRM Functions, neutron detectors are excluded.

Perform CHANNEL CALIBRATION. Once per OPERATING CYCLE (continued)

BFN-UNIT 1 33..33 TRM Revision 0---57 October 30, 2006

Control Rod Block Instrumentation TR 3.3.4 TECHNICAL SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TSR 3.3.4.8 Perform CHANNEL CALIBRATION. 24 months TSR 3.3.4.9 Perform CHANNEL FUNCTIONAL TEST. During OPERATING CYCLE BFN-UNIT 1 3.3-33a TRM Revision 57 October 30, 2006

Control Rod Block Instrumentation TR 3.3.4 Table 3.3.4-1 (page 1 of 3)

Control Rod Block Instrumentation APPLICABLE REQUIRED CONDiTIONS TECHNICAL ALLOWABLE MODES OR CHANNELS REFERENCED SURVEILLANCE VALUE OTHER PER TRIP FROM REQUIREMENTS SPECIFIED FUNCTION REQUIRED FUNCTION CONDITIONS (a> ACTION A.i

1. Average Power Range Monitors

a. APRM Upscale 1 3 3 TSR 3.3.4.1 (b)

(Flow Bias> TSR 33.4.2 TSR 3.3.4.7

b. APRMUpscaIe 2 3 B TSR 3.3.4.1 :12%

(Startup) (c) TSR 3.3.4.2 TSR 3.3,47 C. APRM 1 3 B TSR 3.3.4.1 >3%

Dowescale (d) TSR 3.3.4.2 TSR 3.3.4.7

d. APRM 1,2 3 B TSR 3.3.4.1 tel Inoperative TSR 3.3.4.2

2. Intermediate Range Monitors

a. IRM Upscale (c) 2 6 B TSR 3.3.4.1 1081125 of TSR 3.3.4.3 Ml scale TSR 3.3.4.6

b. IRMDovnscale 2 6 B TSR 3.3.4.1 5f125 of full (C) (1) TSR 3.3.4.3 scale TSR 3.3.4.6 (continued)

(a) During repair or calibration of equipment, not more than one SRM or APRM channel nor more than two IRM channels may be bypassed. Bypassed channels are not counted as OPERABLE channels to meet the minimum OPERABLE channel requirements.

(b) The APRM Rod Block Allowable Value shall he less than or equal to the limit specified in the CORE OPERATING LIMITS REPORT.

(c) This function is bypassed when the MODE switch is placed in the Run position.

(d) This funchon is only active when the MODE switch is in the Run position.

(e) The inoperative trips for the APRMs are produced by the following functions:

1. Local APRM chassis MODE switch not in operate.

2. Less than the required minimum number of LPRM inputs, both total and per axial level.

3. APRM module unplugged.

4. Self-test detected critical fault.

(f) IRM downscale is bypassed when it is on its lowest range.

BFN-UNIT 1 3.3-34 TRM Revision OT-57 October 30, 2006

Control Rod Block Instrumentation TR 3.3.4 Table 3.3.4-1 (page 2 of 3)

Control Rod Block Instrumentation APPLICABLE REQUIRED CONDITIONS TECHNICAL ALLOWABLE MODES OR CHANNELS REFERENCED SURVEILLANCE VALUE OTHER PER TRIP FROM REQUIREMENTS SPECIFIED FUNCTION REQUIRED FUNCTION CONDITIONS (a> ACTION Al

2. Intermediate Range Monitors (continued)

c. IRM Detector 2 6 B TSR 3.3.44 (g)

Not in Startup TSR 3.3.4.7 Position (C)

d. 1RM 2 6 B TSR 3.3.4.3 (Ii)

Inoperative (c)

3. Source Range Monitor

a. SRM Upscale 2(i) 3(j) B TSR 3.3.4.1 iX1u (c) TSR 3.3.4.3 counts/sec.

TSR 3.3.4.6

b. SRM 2 (I) 3 tj) B TSR 3.3.4.1 3 Downscale TSR 3.3.4.3 counts/sec.

(c) (k) TSR 3.3.4.6

c. SRM Detector 2 (i) 3 tj) B TSR 3.3.4.4 (g>

not in Startup TSR 3.3.4.7 Position (c) (k)

d. SRM 2 (I) 3 j) B TSR 3.3.4.3 (h)

Inoperative (c)

(continued)

(a) During repair or calibration of equipment, not more than one SRM or APRM channel nor more than two IRM channels may be bypassed. Bypassed channels are not counted as OPERABLE channels to meet the minimum OPERABLE channel requirements.

(c) This function is bypassed when the MODE switch is placed in the Run position.

(g) Detector traverse is adjusted to 114 +/- 2 inches, placing the detector lower position 24 inches below the lower core plate.

(h) The inoperative trips for the SRMs and IRMs are produced by the following functions:

1. Local operatecaIibrate switch not in operate.

2. Power supply voltage low.

3. Circuit boards not in circuit.

(i) With IRMs on Range 2 or below.

U) IRM channels A, E. C. G all in range 8 or above bypasses SRM channels A and C functions. IRM channels B, F, D. H all in range 8 or above bypasses SRM channels B and D functions.

(k> SRM5 A and C downscale functions are bypassed when IRMs A, C, E. and 0 are above range 2. SRMs 8 and D downscale function is bypassed when IRMs B, D, F, and H are above range 2. SRM detector not in startup position is bypassed when the count rate is CPS or the above condition is satisfied.

BFN-UNIT 1 3.3-35 TRM Revision 0-57 October 30, 2006

Control Rod Block Instrumentation TR 3.3.4 Table 3.34-1 (page 3 of 3)

Control Rod Block Instrumentation APPLICABLE REQUIRED CONDITIONS TECHNICAL ALLOWABLE MODES OR CHANNELS REFERENCED SURVEILLANCE VALUE OTHER PER TRIP FROM REQUIREMENTS SPECIFIED FUNCTION REQUIRED FUNCTION CONDITIONS a) ACTION A. 1

4. Scram Discharge Volume Water Level

a. High Water 1.2 1 (I) C TSR 3.3.4.5 25 gal.

Level in West TSR 3.3.4.8 S cram Discharge Tank (LS-85-45L)

b. High Water 1.2 1 (I) C TSR 3.3.4.5 s 25 gal.

Level in East TSR 3.3.4.8 Scram Discharge Tank (LS-85.45M)

5. Rod Block Logic 1,2 1 D TSR 3.3.4.9 N/A (a) During repair or calibration of equipment, not more than one SRM or APRM channel nor more than two IRM channels may be bypassed. Bypassed channels are not counted as OPERABLE channels to meet the minimum OPERABLE channel requirements.

(I) This function may be bypassed when the Reactor MODE Switch is in the Shutdown or Refuel position.

BFN-UNIT 1 3.3-36 TRM Revision 0. 57. 61 March 14, 2007

SLC System 3.1.7 3.1 REACTIVITY CONTROL SYSTEMS 3.1.7 Standby Liquid Control (SLC) System LCO 3.1.7 Two SLC subsystems shall be OPERABLE.

APPLICABILITY: MODES 1,2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SLC subsystem A.1 Restore SLC subsystem 7 days inoperable, to OPERABLE status.

B. Two SLC subsystems B.1 Restore one SLC 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months inoperable, subsystem to OPERABLE status.

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met.

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

SLC System 3.1.7 130 120 H.

110 ACCEPTABLE (PTovided thi urveitbne rcquiimcnts met)

_ 100 a:

90 H

80 z

NOT H ACCEPTABLE 70 60

i 50 40 U JO 20 30 CONCENTRATION (weigh: Percent Sodium Pentaborate in So1ution Figure 3.1.7-1 Sodium Pentaborate Solution Temperature Versus Concentration Requirements

ECCS Operating 3.5.1 3.5 EMERGENCY CORE COOLING SYSTEMS (EGGS) AND REACTOR GORE ISOLATION COOLING (RGIG) SYSTEM 3.5.1 EGGS - Operating LCO 3.5.1 Each EGGS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE.

APPLICABILITY: MODE 1, MODES 2 and 3, except high pressure coolant injection (H PCI) and ADS valves are not required to be OPERABLE with reactor steam dome pressure 150 psig.

ACTIONS NOTE LCO 3.0.4.b is not applicable to H PCI.

CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure EGOS A.1 Restore low pressure 7 days injection/spray subsystem EGGS injection/spray inoperable, subsystem(s) to OPERABLE status.

OR One low pressure coolant injection (LPGI) pump in both LPGI subsystems inoperable.

(continued)

(1)

- This Completion Time may be extended to 14 days on a one-time basis. This temporary approval expires June 1 2005.

BFN-UNIT 2 3.5-1 Amendment No. 253, 269, 286, 294 May 9, 2005

ECCS Operating 3.5.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

BFN-UNIT 2 3.5-la Amendment No. 286 December 1, 2003

ECCS Operating 3.5.1 ACTIONS (continued CONDITION REQUIRED ACTION COMPLETION TIME C. HPCI System inoperable. C.1 Verify by administrative Immediately means RCIC System is OPERABLE.

AND C.2 Restore HPCI System to 14 days OPERABLE status.

D. HPCI System inoperable. D.1 Restore HPCI System to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

AND OR Condition A entered.

D.2 Restore low pressure 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ECCS injection/spray subsystem to OPERABLE status.

E. One ADS valve E.1 Restore ADS valve to 14 days inoperable. OPERABLE status.

F. One ADS valve F.1 Restore ADS valve to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. OPERABLE status.

AND Condition A entered. F.2 Restore low pressure 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ECCS injection/spray subsystem to OPERABLE status.

(continued>

BEN-UNIT 2 3.5-2 Amendment No. 253.. 269 March 12, 2001

ECCS Operating 3.5.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME G. Two or more ADS valves G.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months inoperable.

AND OR G.2 Reduce reactor steam 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Required Action and dome pressure to associated Completion 150 psig.

Time of Condition C, D, E, or F not met.

H. Two or more low pressure H.1 Enter LCO 3.0.3. Immediately ECCS injection/spray subsystems inoperable for reasons other than Condition A.

OR HPCI System and one or more ADS valves inoperable.

BEN-UNIT 2 3.5-3 Amendment No. 2 269 March 12, 2001

ECCS Operating 3.5.1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS - Operating LCO 3.5.1 Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE.

APPLICABILITY: MODE 1, MODES 2 and 3, except high pressure coolant injection (HPCI) and ADS valves are not required to be OPERABLE with reactor steam dome pressure 150 psig.

ACTIONS LCO 3.0.4.b is not applicable to H PCI.

CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS A.1 Restore low pressure 7 days injection/spray subsystem ECCS injection/spray inoperable, subsystem(s) to OPERABLE status.

OR One low pressure coolant injection (LPCI) pump in both LPCI subsystems inoperable.

(continued)

BEN-UNIT 3 3.5-1 Amendment No. 212, 229 244 December 1, 2003

ECCS Operating 3.5.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

BEN-UNIT 3 3.5-la Amendment No. 244 December 1, 2003

ECCS Operating 3.5.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. HPCI System inoperable. C.1 Verify by administrative Immediately means RCIC System is OPERABLE.

AND C.2 Restore HPCI System to 14 days OPERABLE status.

D. HPCI System inoperable. D.1 Restore HPCI System to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

AND OR Condition A entered.

D.2 Restore low pressure 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ECCS injection/spray subsystem to OPERABLE status.

E. One ADS valve E.1 Restore ADS valve to 14 days inoperable. OPERABLE status.

F. One ADS valve F.1 Restore ADS valve to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. OPERABLE status.

AND Condition A entered. F.2 Restore low pressure 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ECCS injection/spray subsystem to OPERABLE status.

(continued)

BFN-UNIT 3 3.5-2 Amendment No. 242T 229 March 12, 2001

ECCS Operating 3.5.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Two or more ADS valves G.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months inoperable.

AND OR G.2 Reduce reactor steam 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Required Action and dome pressure to associated Completion 150 psig.

Time of Condition C, D, E, or F not met.

H. Two or more low pressure H.1 Enter LCD 3.0.3. Immediately ECCS injection/spray subsystems inoperable for reasons other than Condition A.

OR HPCI System and one or more ADS valves inoperable.

BFN-UNIT 3 3.5-3 Amendment No. 24.2 229 March 12, 2001

PCIVs 3.6.1.3 3.6 CONTAINMENT SYSTEMS 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

LCO 3.6.1.3 Each PCIV, except reactor building-to-suppression chamber vacuum breakers, shalt be OPERABLE.

APPLICABILITY: MODES 1,2, and 3, When associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, Primary Containment Isolation Instrumentation.

BEN-UNIT 3 3.6-9 Amendment No. 212

PCIVs 3.6.1.3 ACTIONS

____________I,s._,I.__,

1. Penetration flow paths except for 18 and 20 inch purge valve penetration flow paths may be unisolated intermittently under administrative controls.

2. Separate Condition entry is allowed for each penetration flow path.

3. Enter applicable Conditions and Required Actions for systems made inoperable by PCIVs.

4. Enter applicable Conditions and Required Actions of LCO 3.6.1.1, Primary Containment, when PCIV leakage results in exceeding overall containment leakage rate acceptance criteria in MODES 1, 2, and 3.

CONDITION REQUIRED ACTION COMPLETION TIME A. ------------NOTE----- A.1 Isolate the affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months except for Only applicable to penetration flow path by main steam line penetration flow paths use of at least one closed with two PCIVs. and de-activated AND automatic valve, closed manual valve, blind 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for main One or more penetration flange, or check valve steam line flow paths with one PCIV with flow through the inoperable except due to valve secured.

MSIV leakage not within limits.

AND (continued)

BFN-UNIT3 3.6-10 Amendment No. 212

PCIVs 3.6.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 ----- --NOTE Isolation devices in high radiation areas may be verified by use of administrative means.

Verify the affected Once per 31 days penetration flow path is for isolation isolated. devices outside primary containment AND Prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment (continued)

BFN-UNIT 3 3.6-11 Amendment No. 212

PCI Vs 3.6.1.3 ACTIONS (continued CONDITION REQUIRED ACTION COMPLETION TIME B. NOTE B.1 Isolate the affected 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Only applicable to penetration flow path by penetration flow paths use of at least one closed with two PCIVs. and de-activated automatic valve, closed manual valve, or blind One or more penetration flange.

flow paths with two PCIVs inoperable except due to MSIV leakage not within limits.

C. --------------NOTE----- C.1 Isolate the affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months except for Only applicable to penetration flow path by excess flow check penetration flow paths use of at least one closed valves (EFCVs) with only one PCIV. and de-activated

automatic valve, closed AND manual valve, or blind One or more penetration flange. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for flow paths with one PCIV EFCVs inoperable. AND C.2 --------------NOTE Isolation devices in high radiation areas may be verified by use of administrative means.

Verify the affected Once per 31 days penetration flow path is isolated.

(continued)

BEN-UNIT 3 3.6-12 Amendment No. 212

PCIVs 3.6.1.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One or more penetration D.1 Restore leakage rate to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months flow paths with MSIV within limit.

leakage not within limits.

E. Required Action and E.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, B, C, AND or D not met in MODE 1, 2, or 3. E.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months F. Required Action and F.1 Initiate action to suspend Immediately associated Completion operations with a Time of Condition A, B, C, potential for draining the or D not met for PCIV(s) reactor vessel (OPDRVs).

required to be OPERABLE during MODE 4 or 5.

F.2 --------------NOTE-----------

Only applicable for inoperable RHR Shutdown Cooling Valves.

Initiate action to restore Immediately valve(s) to OPERABLE status.

BFN-UNIT 3 3.6-13 Amendment No. 212

NPG Standard Regulatory Reporting Requirements NPG-SPP-03,5 Programs and Rev, 0007 Processes Page 18 of 97 Appendix A (Page 1 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 1.0 PURPOSE This Appendix identifies reporting requirements; and instructions for determining reportability, preparation, and transmittal of LERs; and notification to NRC for events occurring at TVAs licensed nuclear plants.

2.0 SCOPE TVA is required by §50.72 and §5013 to promptly report various types of conditions or events and provide written follow-up reports, as appropriate. This appendix provides reporting guidance applicable to licensed power reactors.

NOTES 1 Appendix B provides additional reporting criteria found in §Part 20, 30, 40. and 70 that may be applicable to events involving byproduct, source or special nuclear material possessed by the licensed nuclear plant Site Licensing and Site RadCon are responsible for making the reportability determinations for §Part 20, 30, 40, or 70 events associated with their site. Corporate Licensing and Corporate RadChem are responsible for making the reportability determinations for §Part 20, 30, 40, or 70 events associated with all other TVA licensed activities. Licensing is responsible for developing (with input from affected organizations) and submitting the immediate notification and written reports to NRC in accordance with §Part 20, 30, 40, or 70 requirements. Reporting requirements for personnel exposure required by §Part 20 are contained in RCTP-105. Personnel Inprocessing and Dosimetnj Administrative Processes.

2) Appendix C contains the criteria for reporting if events or conditions affecting ISFSI.

TVA, as the general licensee of the ISFSI, is required by §72.216 to make initial and written reports in accordance with §72.74 and §72.75. Operations is responsible for making the reportability determinations for §72.74 and §72.75 reports. For any event, condition, or issue having the potential for being reportable, contact Site Licensing for consultation and concunence on the reportability determination. In no event shall the lack of licensing concurrence result in a failure to meet specified reporting timeframes.

Operations is responsible for making the immediate notification to NRC in accordance with §72.74. Operations is responsible for making the immediate, 4-hour, and 24-hour notifications to NRC in accordance with §72.76. Licensing is responsible for developing (with input from affected organizations) and submitting the written reports required by §72.75.

3) Reporting requirements for events or conditions affecting the physical protection of the licensed nuclear plant specified in §73.71 are contained in NSDP-1, Safeguards Event Reporting Guidelines. Responsibilities for reportability determinations and immediate notification requirements are assigned to Site Nuclear Security and Corporate Nuclear Security. Licensing is responsible for developing (..ith input from affected organizations) and submitting the written reports required by §73.71.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0007 Processes Page 19 of 97 Appendix A (Page 2 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3M REQUIREMENTS NOTES

1) Internal management notification requirements for plant events are found in Appendix D. The Operations Shift Manager is responsible for notifying Site Operations Management and the Duty Plant Manager. The Duty Plant Manager is responsible for making the remaining internal management notifications.

2) NRC NUREG-1022, Supplements and subsequent revisions should be used as guidance for determining reportability of plant events pursuant to §50.72 and §50.73.

A text searchable copy of NUREG-1022 is maintained on the WA NPG Nuclear Licensing Webpage at address http:lltvanweh.cha.tva.govilicensing/Pages/NRC.

Industry Guidance Documents.htm.

31 Immediate Notification NRC -

TVA is required by §50.72 to notify NRC immediately if certain types of events occur. This appendix contains the types of events and the allotted time in which NRC must be notified.

(Refer to Fom NPG-SPP-03.5-l or NRC Form 361). Operations is responsible for making the reportability detem,inations for §50.72 and §50.73 reports. For any event, condition, or issue having the potential for being reportable, contact Site Licensing for consultation and concurrence on the reportability determination. In no event shall the lack of licensing concurrence result in a failure to meet specified reporting timeframes. Operations is responsible for making the immediate notification to NRC in accordance with §5072.

Notification is via the Emergency Notification System. if the Emergency Notificaon System is not operative, use a telephone, telegraph, rnaiigram, or facsimile.

NOTE The NRC Event Notification Worksheet may be used in preparing for notifying the NRC. This Worksheet may be obtained directly from the NRC website (www.nrc..gov) under Form 361, or TVA NPG Form NPG-SPP-03.5-1 may be used.

A. The Immediate Notificaon Criteria of50.72 is divided into 1-hour, 4-hour. and hour -

phone calls. Notify the NRC Operations Center within the applicable time limit for any item which is identified in the immediate Notification Criteria.

B. The following criteria require 1-hour notification:

1. (Technical Specifications) Safety Limits as defined by the Technical Specifications which have been violated.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0007 Processes Page 20 of 97 Appendbc A (Page 3 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification NRC (continued)

2. §50.72(a)(1)(i) The declaration of any of the Emergency classes specified in the licensees approved Emergency Plan.

NOTE fit is discovered that a condition existed which met the Emergency Plan criteda but no emergency was declared and the basis for the emergency class no longer exists at the time of discovery, an ENS notification (and notification of the Operations Duty Specialist), within one hour of discovery of the undeclared (or misclassified) event, shall be made. However, actual declaration of the emergency class is not necessary in these circumstances.

3. §50.72(b).(1) Any deviation from the plants Technical Specifications authorized pursuant to §S0.54(x).

4. 10 CFR 73, Appendix G, paragraph I Safeguards Events. The requirements of

§73.71. Reporting of Safeguard Events, are also applicable. Refer to NSDP-1, Safeguards Event Reporting Guidelines, for additional infomiation.

a. Any event in which there is reason to believe that a person has committed or caused. or attempted to commit or cause, or has made a credible threat to commit or cause:

(1) A theft or unlawful diversion of special nuclear material; or (2) Significant physical damage to a power reactor or any facility possessing SSNM or its equipment or carrier equipment transporting nuclear fuel or spent nuclear fuel, or to the nuclear fuel or spent nuclear fuel a facility or carrier possesses: or (3) Interruption of normal operation of a licensed nuclear power reactor through the unauthorized use of or tampering with its machinery, components, or controls including the security system. [Note: a Confirmed Cyber Attack at any NPG site is reported to the NRC iaw the requirements of 10 CFR 73, Appendix G. Review the Incident Categorization section in NPG-SPP- 12.8.8.]

b. An actual entry of an unauthorized person into a protected area, material access area, controlled access area, vital area, or transport.

c. Any failure, degradation, or the discovered vulnerability in a safeguard system that could allow unauthorized or undetected access to a protected area, material access area, controlled access area, vital area, or transport for which compensatory measures have not been employed.

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Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification NRC (continued)

d. The actual or attempted introduction of contraband into a protected area, material access area, vital area, or transport.

C. The following criteria require 4-hour nobfication:

1. §50.72(b)(2)(i) The initiaon of any nuclear plant shutdown required by the plants Technical Specflcations.

2. §5D72b(2)(iv(A) Any event that results or should have resulted in Emergency Core Cooling System (ECCS) discharge into the reactor coolant system as a result of a valid signal except when the actuaon results from and is part of a pre-planned sequence during testing or reactor operation.

3. §Eo.72(bx2)(ivx8 Any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.

NOTES

1) NPG-SPP-05.14 provides additional instructions regarding addressing and informally communicating events to outside agencies involving radiological spills and leaks.

2) Routine or day-to-day communications between TVA organizations and state agencies typically do not constitute a formal notification to other government agencies that would require a report in accordance .vith §5O72(b)(2)(xi).

4. §50.72(b)(2{xi Any event or situation, related to the health and safety of the public or onsite 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 onsite fatality or inadvertent release of radioactive contaminated materials.

D. The following criteria require B-hour notification:

NOTE The non-emergency events specified below are only reportable if they occurred within three years of the date of discovery.

1. §5D.72(bl(3)(ii)(A) Any event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0001

Processes Page 22 of 97 Appendix A (Page 5 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 31 Immediate Notification NRC (continued)

2. §50J2b)(3)(ii)(B)- Any event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety.

3. §50..72(b)(3)(iV(A Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B) [see list belo, except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.

a.. The systems to which the requirements of paragraph §50.72(b)(3)(iv)(A) apply are:

NOTE Actuation of the RPS when the reactor is critical is also reportable under §S0.72(b)(2(ivXB) above.

(1) Reactor protection system (RPS including: reactor scram or reactor trip.

(2) General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves (MSIVs).

(3) Emergency core cooling systems (ECCS) for pressurized water reactors (PWRs including: high-head, intermediate-head, and low-head injection systems and the low pressure injection function of residual (decay) heat removal systems, (4) ECCS for boiling water reactors (6WRs) including: core spray systems; high-pressure coolant injection system; low pressure injection function of the residual heat removal system.

(5) BWP reactor core isolation cooling system.

(6) PWR auxiliary or emergency feedwater system.

(7) Containment heat removal and depressurization systems. including containment spray and fan cooler systems (8) Emergency ac electrical power systems, including: Emergency diesel generators (EDGs).

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0007

Processes Page 23 of 97 Appendix A Page 6 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification NRC (continued)

4. §50.72(bl(3)(v) Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to:

(Al Shut down the reactor and maintain it in a safe shutdown condition; (6) Remove residual heat.;

(C) Control the release of radioactive material: or (D) Mitigate the consequences of an accident.

NOTE According to §50,72 (b)(3)(vi) events covered by §50.72(b)(3)(v) may include one or more procedural :eors equipment failures, and/or discovery of design.

analysis, fabrication, construction, and/or procedural inadequacies. However, individual component failures need not be reported pursuant this paragraph if redundant equipment in the same system was operable and available to perform the required safety function.

5. §50.72(b)(3)(xifl Any event requiring the transport of a radioactively contaminated person to an offsite medical facility for treatment.

6. §5D.72(b)(3)(xUi) Any event that results in a major 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).

E. Follow-up Notification (50.72(c))

With respect to the telephone notifications made under paragraphs (a) and (b) [50.72 (a) and §50.72 (b), respectively] of this section [50.721, in addition to making the required initial notification, 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 the Emergency Classes, if such a declaration has

NPG Standard Regulatory Reporting Requirements NPG-SPP-03,5 Programs and Rev. 0007 Processes Page 24 of 97 Appendix A (Page 7 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification NRC (continued) not been previously n,ade or ii:l Any change from one Emergency Class to another, or (iii) A termination of the Emergency Class.

(1) immediately report:

(i) The results of ensuing evakjations 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.

(2) Maintain an open, continuous communication channel with the NRC Operations Center upon request by the NRC.

3.2 Twenty-Four Hour Notification NRC -

Any violation of the requirement contained in specific operating license conditions, shall be reported to NRC in acoordance with the license oondition.

3.3 Two-Day Notification NRC -

§50.9(b) The NRC shall be notified of incomplete or inaccurate information which contains significant implications for the public health and safety or common defense and security.

Notification shall be provided to the administrator of the appropriate regional office within two working days of identifying the information. Licensing is responsible for detemiining reportability (with input from affected organizations) and notifying NRC in accordance with

§50.9.

3.4 Sixty-Day Verbal Report

§50.73(a)(2)(iv)(A) requires that any event or condition that resulted in manual or automatic actuation of the specified systems be reported as a Licensee Event Report (LER Refer to Appendix A, Section 3.5J). This CFR section also allows that in the case of an invalid actuation, other than actuation of the reactor protection system when the reactor is critical, an optional telephone notification may be placed to the NRC Operations Center within 60 days after discovery of the event instead of submitting a written LER.

A Verbal Report Required Content:

N PG Stan darci Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev 0007 Processes Page 25 of 97 Appendix A (Page 8 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.4 Sixty-Day Verbal Report (continued)

If the verbal notification option is selected (NUREG 1022, Revision 2, Section 12.6.,

System Actuation). instead of an LER. the verbal report:

1. 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 infomiation:

a. The specific train(s) and system(s) that were actuated.

b. bether each train actuation was complete or partial.

c. Whether or not the system started and functioned successfully.

NOTE Licensing will ensure that the information that is provided to NRC during the Sixty-Day Verbal Report is verified in accordance with NPG-SPP-03.i0.

B. Verbal Report Development and Review Licensing will:

1. Develop (with input from responsible organization) the response (i.e. report summary) to address the required inpLlt,

2. Ensure that the reporting details are approved by site vice president or his designee prior to making the verbal report.

C. Telephone Report Timeliness Operations will make the 60-day telephone report promptly after the response is approved by the site vice president or his designee.

3.5 Written Report NRC-A. A report on a Safety Limit Violation shall be submitted to the NRC, the NSRB, and the Site Vice President if required by Technical Specifications,

8. Any violation of the requirements contained in the Operating license conditions in lieu of other reporting requirements requires a written follow-up report if specified in the license.

C. Reporting Radiation Injuries

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev, 0007 Processes Page 26 of 97 Appendix A Page 9 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)

1. §1 4&.6{a) requires, as promptly as possible, submittal of a written notice [e.g.,

reporti in the event of:

a. Bodily injury or property damage arising out of or in connection with the possession or use of the radioactive material at the licensees facility

[location]; or

b. in the course of transportation; or

c. in the event any radiation exposure claim is made. (Refer to RCDP-9, Radiological and Chemistry Control Radiological Exposure Inquiries)

2. The written notice shall contain particulars sufficient to identify the licensee and reasonably obtainable information with respect to time, place, and circumstances thereof, or the nature of the claim.

D. Ucensee Event Reports A written report shall be prepared in accordance with §50.73(a(i) for items in the 60-day report criteria or Technical Specifications. The report shall be complete and accurate in accordance with the methods outlined in this procedure. The completed forms shall be submitted to the USNRC, Document Control Desk. Washington, DC 20555. NUREG 1022, Revision 2, contains the instructions for completion of the LER form. Licensing is responsible for developing (with input from affected organizations) and submitting the written reports (or optional telephone reports [refer to Appendix A, Section 3.4Jl required by §50.73.

NOTE Unless otherise specified in the reporting criteria below, an event shall be reported if it occurred within three years of the date of discovery regardless of the plant mode or power level, and regardless of the significance of the structure.

system, or component that initiated the event.

E. Report Criteria

1. §50.73(a(2)(i)A) The completion of any nuclear plant shutdown required by the plants Technical Specifications.

2. §50,73(ai(2)(i)(B) Any operation or condition which was prohibited by the plants Technical Specifications, except when:

a The Technical Specification is administrative in nature;

NPG Standard Regulatory Reporting Requirements NPG-SPP-035 Programs and Rev, 0007 Processes Page 27 of 97 Appendix A (Page 10 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)

b. The event consisted solely of a case of a late suiveillance test where the oversight was corrected, the test was performed, and the equipment was found to be capable of performing its specified safety functions; or

c. The Technical Specification was revised prior to discovery of the event such that the operation or condition was no longer prohibited at the time of discoverj of the event.

3. §5013(a)(2)(i)(C) Any deviation from the plants Technical Specifications authorized pursuant to §50.54(x).

4. §5073(a)(2)ii)(A) Any event or condition that resulted in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded.

5. §50.73(a)(2)(ii)(B) Any event or condition that resulted in the nuclear power plant being in an unanalyzed condition that significantly degraded plant safety.

6. §50.73(a)(2)(iii) Any natural phenomenon or other external condition that posed an actual threat to the 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.

7. §5013(a)(2)(iv)(A) Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B (see list in Section 3.5E.8 below], except when

a. The actuation resulted from and was part of a pre-planned sequence during testing or reactor operation; or

b. The actuation was invalid and (i) Occurred while the system was properly removed from service or (ii) Occurred after the safety function had been already completed.

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Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)

N OTE In the case of an invalid actuation, other than actuation of the reactor protection system (RPS when the reactor is critical, a telephone notification to the NRC Operations Center within 60 days after discovery of the event may be provided instead of sLibmitting a written LER (5a.73(fl. [Refer to Appendix A, Section 3.4]

8. §6013(a)(2)(iv)(8) The systems to which the requirements to paragraph (a)(2)(iv)(A) of this section apply are:

a. Reactor protection system (RPS) including: reactor scram or reactor trip.

b. General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves (MSIVs).

c. Emergency core cooling systems (ECCS) for pressurized water reactors (PWRs) including: high-head, intemiediate-head, and low-head injection systems and the low pressure injection function of residual (decay) heat removal systems.

d. ECCS for boiling water reactors (BV/Rs) including; core spray systems; high-pressure coolant injection system; low pressure injection function of the residual heat removal system.

e. BWR reactor core isolation cooling system.

1. PWR auxiliary or emergency feedwater system.

g. Containment heat removal and depressurization systems, including containment spray and fan cooler systems.

h. Emergency ac electrical power systems, including: emergency diesel generators (EDGs).

i. Emergency serice water systems that do not normally run and that sere as ultimate heat sinks.

9. §50.73(a)(2)(v) Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to:

(Al Shut down the reactor and maintain it in a safe shutdown condition;

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0007 Processes Page 29 of 97 Appendix A (Page 12 of 14 Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)

(B) Remove residual heat; (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident.

NOTE Events reported above may include one or more procedural errors, equipment failures, and/or discovery of design, analysis. fabrication, construction. and/or procedural inadequacies. However. individual component failures need not be reported pursuant to this criterion if redundant equipment in the same system was operable and available to perfom the required safety function

[S0.73(a)(2)(vi)j.

10. §50J3a)(2(vU) iy 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 (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.

1 1. §50J3((2)(vinXA) Any airborne radioactivity 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 , resulted in airborne radionuclide concentrations in an unrestricted area that exceeded 20 times the applicable concentration limits specified in Appendix B to Part 20, table 2, column 1.

12. §E.0.731a)(2)(viii}(B) 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 , exceeds 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 radionudides except tritium and dissolved noble gases.

NPG Standard Regulatory Reporting Requ ireme ms N PG-SPP-03.5 Programs and Rev. 0007 Processes Page 30 of 97 Appendix A (Page 13 of I 4 Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 35 Written Report NRC (continued)

3. §E0.73aX2)(ix(A) Any event or condition that as a result of a single cause could have prevented the fulfillment of a safety function for ro or more trains or channels in different systems that are needed to:

a. Shut down the reactor and maintain it in a safe shutdown condition;

b. Remove residLial heat;

c. Control the release of radioactive material; or

d. Mitigate the consequences of an accident.

NOTE Events covered above may include cases of procedural error, equipment failure, and/or discovery of a design, analysis, fabrication, construction.

and/or procedural inadequacy. However, licensees are not required to report an event pursuant to this criterion if the event results from a shared dependency among trains or channels that is a natural or expected consequence of the approved plant design or normal and expected wear or degradation [&0.73(a)2l(ix)(B)J.

14. §60.73a(2)(x) Any event that posed an actual threat to the safety of the nuclear power plant or significanDy hampered 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.

15. 10 CFR 73, Appendix G. paragraph I If a one hour notification is made in Appendix A. section 3i .8.4 of this procedure, then a written notification to the NRC is required within 60 days.

16. For reporting a defect found installed in the Plants Safety Related Equipment, Radioactive Wastes System, and Special Nuclear Material within an LER, §Part 21 NRC Reporting of Defects and Noncompliance, see Appendix G in this procedure.

17 SON and WBN only (Non-radiological environmental reporting requirements to the NRC as required from SON and WBN Tech Spec (TS) Appendix 8)

a. WBN or SON shall record any occurrence of unusual or important environmental events. Unusual or important events are those that potentially could cause or indicate environmental impact causally related with station operation. The following are examples:

NPG Standard Reguktory Reporting Requirements NPG-SPP.-03.5 Programs and Rev. 0007 Processes Page 31 of 97 Appendix A (Page 14 of 14)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)

(1) Excessive bird impaction events; (2) Onsite plant or animal disease outbreaks; (3) Unusual mortality of any species protected by the Endangered Species Act of 1973:

(4) Fish kills near the plant site; (6) Unanticipated or emergency discharges of waste water or chemical substances that exceeds the limits of, or is not authorized by, the NPDES permit and requires 24-hour notification to the County or State of Tennessee; WBN only (6) Identification of any threatened or endangered species for which the NRC has not initiated consultation with the Federal Wildlife Service (FWS).

(7) Increase in nuisance organisms or conditions in excess of levels anticipated in station environmental impact appraisals.

b. SON TS Appendix B compliance guidance is provided in the owchart in NPG-SPP-O5.5, Environmental Control, Appendix B.

c. WBN TS Appendix B compliance is met through the procedures referenced in NPG-SPP-05.5.

d. Once an unusual or important event has occurred, the required actions are:

(1) Refer to NPG-SPP-05.S. Environmental Conol, Section Compliance with the NRC Appendix B to the Facility Operating License, for additional guidance.

(2) If required. SON or WBN Site Licensing shall make a written report to the NRC in accordance with the NRC Non-routine Report, TS Appendix B, Subsections 5.4.2, within 30 days, in the event of a reportable occurrence in which a limit specified in a relevant pemiit or certificate issued by another Federal, State, or local agency is exceeded.

ML13191A879

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