Text

Initial Exam 2015-302 Final SRO Written Exam
	ML15342A373
Person / Time
Site:	Browns Ferry
Issue date:	12/07/2015
From:	; Division of Reactor Safety II
To:	;
References
	Download: ML15342A373 (267)
	v • d • e

ES-401 Site-Specific SRO Written Examination Form ES-401-8 Cover Sheet U. S. Nuclear Regulatory Commission Site-Specific SRO Written Examination Applicant Information Name:

Date: 11-24-15 Facility / Unit: Browns Ferry Units 1,2,3 Region: I II III IV Reactor Type: W CE BW GE Start Time: Finish Time:

Instructions Use the answer sheets provided to document your answers. Staple this cover sheet on top of the answer sheets. To pass the examination you must achieve a final grade of at least 80 percent overall, with 70 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 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.

Applicant's Signature Results RO/SRO-Only/Total Examination Values ______ / ______ / ______

Points Applicant's Score ______ / ______ / ______

Points Applicant's Grade ______ / ______ / ______

Percent

Q1 Unit 2 is in mode 5 with Refueling in progress, with the following system alignments:

2B RHR pump is in shutdown cooling.

Both 2A and 2B Reactor Recirc pumps are tagged out of service.

2A RPS is powered from its alternate source.

Subsequently:

Reactor Water Level drops to 0 inches and then recovers to + 75 inches.

The only action taken by the crew was to reset any actuation(s) that may have occurred.

NOTE: RHR Sys II LPCI Inboard Injection Valve, 2-FCV-74-67 RHR Sys II LPCI Outboard Injection Valve, 2-FCV-74-66 RHR Shutdown Cooling Suction Outboard Isolation Valve, 2-FCV-74-47 RHR Shutdown Cooling Suction Inboard Isolation Valve, 2-FCV-74-48 Which ONE of the following describes the minimum actions required, in accordance with 2-AOI-74-1, Loss of Shutdown Cooling, prior to restarting the 2B RHR pump to restore Shutdown cooling?

A. CLOSE the 2-FCV-74-67, OPEN the 2-FCV-74-66, then OPEN 2-FCV-74-47 and 2-FCV-74-48.

B. CLOSE the 2-FCV-74-66, OPEN the 2-FCV-74-67, then OPEN 2-FCV-74-47 and 2-FCV-74-48.

C. CLOSE the 2-FCV-74-67, OPEN 2-FCV-74-66, then OPEN 2-FCV-74-48 only.

D. CLOSE the 2-FCV-74-66, OPEN 2-FCV-74-67, then OPEN 2-FCV-74-47 only.

Q2 Units 1, 2, and 3 are operating at 100% power.

Subsequently:

A loss of all off site power occurs.

The following conditions exist:

The C Diesel Generator is supplying the C 4KV shutdown board.

The 3EB Diesel Generator is supplying the 3EB 4KV shutdown board.

All other Diesel Generators failed to start.

Assume No Operator Actions Have Been Taken Which ONE of the following completes the statement below?

Unit(s) _____ is (are) in a station black out.

A. 1 only B. 2 only C. 1 and 3 only D. 2 and 3 only

Q3 Which ONE of the following completes the statements below concerning the 250 VDC Unit batteries and battery chargers?

The Class 1E Unit Batteries have the capacity to compensate for a __ (1) __ Station Blackout event during multi-unit operations without operator action.

In accordance with 1/2-AOI-57-1D, 480V Load Shed, if the load shed logic can Not be reset the 2A 250V Battery charger may be returned to service by placing the charger select switch in __ (2) __.

A. (1) 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months (2) OFF then back to ON B. (1) 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (2) OFF then back to ON C. (1) 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months (2) EMERG D. (1) 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (2) EMERG

Q4 Which ONE of the following completes the statement below?

In the event of a Main Turbine trip without bypass valves from full power, a Reactor Scram is initiated to anticipate the __ (1) __ AND to prevent exceeding the __ (2) __

safety limit.

A. (1) rapid reduction in Reactor water level (2) Reactor water level B. (1) rapid reduction in Reactor water level (2) MCPR C. (1) rapid increase in Reactor pressure (2) Reactor water level D. (1) rapid increase in Reactor pressure (2) MCPR

Q5 Unit 1 is operating at 100% power when the B RPS MG set output breaker trips open.

Which ONE of the following describes required actions to place 1B RPS on alternate power in accordance with 1-AOI-99-1, Loss of Power to One RPS Bus?

A. Verify Circuit Protector 1B1 and 1B2 are Reset, Place the RPS bus 1B normal/alt transfer switch to ALT in Battery Board Rm 1 B. Verify Circuit Protector 1B1 and 1B2 are Reset, Place the RPS bus 1B normal/alt transfer switch to ALT in Battery Board Rm 2 C. Verify Circuit Protector 1C1 and 1C2 are Reset, Place the RPS bus 1B normal/alt transfer switch to ALT in Battery Board Rm 1 D. Verify Circuit Protector 1C1 and 1C2 are Reset, Place the RPS bus 1B normal/alt transfer switch to ALT in Battery Board Rm 2

Q6 The Shift Manager has directed entering 3-AOI-100-2, Control Room Abandonment, due to heavy smoke in the U3 MCR.

Which ONE of the following completes the statements below?

The manual reactor SCRAM performed during 3-AOI-100-2 __ (1) __based on allowing time for operators to prepare for a plant cooldown.

If the Reactor fails to scram, 3-AOI-100-2 will direct __ (2) __.

A. (1) is (2) initiating ARI B. (1) is (2) pulling RPS Scram Solenoid Fuses C. (1) is NOT (2) initiating ARI D. (1) is NOT (2) pulling RPS Scram Solenoid Fuses

Q7 Unit 1 is operating at 100% power.

An RBCCW leak develops causing the 1-FCV-70-48, RBCCW Sectionalizing valve, to close, isolating the leak.

Which ONE of the following components has Not lost cooling water?

A. Drywell equipment drain sump B. Fuel pool cooling heat exchangers C. Reactor water cleanup pump seal coolers D. RWCU Non-regenerative heat exchangers

Q8 A rupture in the control air header has occurred.

Control air pressure indicates 25 psig and lowering in the Unit 3 Control Room.

3-AOI-32-2, Loss of Control Air has been entered.

Several U3 Control Rods failed to insert during the transient.

The US directs inserting Control Rods in accordance with 3-EOI Appendix-1D Which ONE of the following completes the statement below?

In order to insert Control Rods the Unit Operator is required to dispatch personnel to manually _______.

A. open the 3-FCV-85-11A, CRD Flow Control Valve, and open the 3-PCV-85-27, CRD Cooling Water Pressure Control Valve B. close the 3-FCV-85-11A, CRD Flow Control Valve, and open the 3-PCV-85-27, CRD Cooling Water Pressure Control C. open the 3-FCV-85-11A, CRD Flow Control Valve, and close the 3-HCV-85-586, Charging Water SOV D. close the 3-FCV-85-11A, CRD Flow Control Valve, and close the 3-HCV-85-586, Charging Water SOV

Q9 Unit 2 is in day 2 of a forced outage with the following conditions:

Currently in Mode 4

Moderator Temperature band is 150° F to 180° F

Both Reactor Recirc pumps are OFF with suction valves open and discharge valves closed

RHR pump 2A is in Shutdown Cooling Subsequently:

The 2B Recirc Pump discharge valve is inadvertently opened.

With no other operator actions taken, which ONE of the following completes the statements below 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the 2B Recirc Pump discharge valve opened?

The RHR outlet temperature from the 2A RHR Heat Exchanger will __ (1) __ and actual moderator temperature will __ (2) __.

A. (1) Remain the same (2) Remain the same B. (1) Lower (2) Lower C. (1) Rise (2) Rise D. (1) Lower (2) Rise

Q 10 Unit 1 is loading fuel into the core when the following occurs:

SRM period lights illuminated.

Rising count rate on SRM meters.

Rising power level on IRM recorders.

What Immediate Operator Actions are required in accordance with 1-AOI-79-2, Inadvertent Criticality During Incore Fuel Movements?

A. Return fuel bundle to previous Spent Fuel Pool location and evacuate all personnel from Refuel Floor.

B. Remove the fuel bundle from the core and traverse the Refueling Bridge away from the Reactor core.

C. Stop all fuel handling and evacuate all personnel from Refuel Floor.

D. Remove the fuel bundle from the core and if still critical initiate SLC.

Q 11 All three Units are operating at 100% power when a small steam leak develops in Unit 2 Drywell.

The Unit Supervisor directs the Unit Operator to begin venting in accordance with the AOI.

(1) How many SGT train(s) are required to be verified running prior to venting?

(2) When venting is complete, in which Units SR-2 should the SGT run time be recorded?

A. (1) 1 (2) 1 B. (1) 1 (2) 2 C. (1) 2 (2) 1 D. (1) 2 (2) 2

Q 12 Which ONE of the following describes a basis for Alternate Rod Insertion (ARI) due to high Reactor pressure?

A. ARI limits fuel damage due to pellet expansion to less than 1%.

B. ARI reduces the challenge to the integrity of the Reactor Coolant Pressure Boundary.

C. ARI reduces unnecessary safety relief valve operation that challenges SRV and SRV piping integrity.

D. ARI reduces unnecessary safety relief valve operation that results in undesired heatup of the Suppression Pool.

Q 13 Based on the attached panel display, what changes (if any) are needed to place RHR System in Suppression Pool Cooling in accordance with 3-OI-74, Residual Heat Removal System?

A. No changes required B. Start RHRSW Pump A2 and secure RHRSW Pump C2 C. Start RHRSW Pump A1 and open 3-FCV-23-34, 3A RHR Hx Outlet Valve D. Fully open 3-FCV-74-59, RHR System I Suppression Pool Cooling/Test Valve

RHR PUMP 3A Q 14 In accordance with EOI Caution 1, LI-3-55 Reactor Water Level Flood-up Range, indicates above the minimum indicated level (MIL).

DW Temp and Reactor Pressure are in the Action Required region of Curve 8, RPV Saturation Curve.

Which ONE of the following completes the statement below?

LI-3-55 __ (1) __ due to __ (2) __.

A. (1) may Not be used (2) boiling in the instrument run B. (1) may be unreliable (2) boiling in the instrument run C. (1) may Not be used (2) being calibrated for cold conditions D. (1) may be unreliable (2) being calibrated for cold conditions

Q 15 Annunciator 3-9-3B window 15, SUPPR CHAMBER WATER LEVEL ABNORMAL is currently in alarm due to Low SP Water Level.

Which ONE of the following answer choices provides indication supporting a lowering Suppression Pool Level trend?

A. Drywell-to-Suppression Chamber Differential pressure is lowering.

B. 3-9-3C window 9 RCIC PUMP SUCTION PRESS LOW 3-PA-71-21A alarms.

C. 3-9-3E window 11 SUPPR POOL DISCH HDR PRESS LOW 3-PA-74-94 alarms.

D. HPCI Pump Suction valves automatically realign.

Q 16 An ATWS has occurred on Unit 2.

ATWS actions are complete

Reactor water level currently indicates +40 inches

Reactor Power is 46%

SLC is injecting Which ONE of the following completes the statements below?

EOI-1A requires operators to stop and prevent all injection except __ (1) __ to mitigate the consequences of the failure-to-scram.

Intentionally lowering Reactor Water Level mitigates the failure to scram by __ (2) __.

A. (1) CRD, and SLC only (2) reducing natural circulation resulting in increased void fraction B. (1) CRD, and SLC only (2) increasing natural circulation resulting in mixing of injected boron C. (1) RCIC, CRD, and SLC (2) reducing natural circulation resulting in increased void fraction D. (1) RCIC, CRD, and SLC (2) increasing natural circulation resulting in mixing of injected boron

Q 17 In accordance with step ARC-1 and NOTE 1 of EOI-1A, ATWS RPV Control, which ONE of the following conditions would allow exiting EOI-1A and entering EOI-1, RPV Control?

A. All Control Rods inserted to 00 except 18 at notch 02 B. All Control Rods inserted to 00 except 2 at notch 18 C. SLC injected into RPV to a tank level of 60%

D. SLC injected into RPV to a tank level of 40%

Q 18 All three units are operating at 100% power.

A transient occurs on Unit 2 and the following alarms are received:

2-9-4C window 27 OG AVG ANNUAL RELEASE LIMIT EXCEEDED

2-9-3A window 13 STACK GAS RADIATION HIGH

2-9-7A window 3 STACK GAS DILUTION AIR FLOW LOW The Unit 2 UO reports the following:

Stack dilution fan 2A tripped and 2B failed to start

0-FI-90-271 Stack Gas Flow on Panel 1-9-53 indicates 14,000 scfm Based on the information provided which ONE of the following identifies the Stack Gas Radiation Monitor(s) with valid indications.

A. None of the Stack Gas Radiation Monitor indications are valid.

B. Only 0-RM-90-306 WRGERMS indication is valid.

C. Only 0-RM-90-147/148 Stack Gas Monitor indications are valid.

D. 0-RM-90-306 WRGERMS and 0-RM-90-147/148 Stack Gas Monitor indications are valid.

Q 19 A fire has occurred in the Unit 3 Reactor Building.

In accordance with 0-AOI-26-1, Fire Response, the reason AUOs are assembled in the Control Room is to A. perform required SSI manual actions.

B. complete personnel accountability.

C. retrieve the Control Room Appendix R radios.

D. retrieve necessary SCBA Kits.

Q 20 In accordance with 0-AOI-57-1E, Grid Instability, what is the maximum MVAR outgoing limit to maintain the offsite qualification of both 500-Kv and161-Kv offsite power sources?

A. + 50 B. + 100 C. + 150 D. + 300

Q 21 Unit 3 is operating at 100% power when all three Reactor Feed Pump Turbines trip.

The Reactor is manually scrammed and 3-EOI-1 is entered.

As Reactor water level lowers, receipt of which alarm below corresponds to the level at which a Reactor Recirc Pump trip is required?

A. 3-9-5A window 8, REACTOR WATER LEVEL ABNORMAL B. 3-9-3F window 29, RX WTR LVL LOW LOW HPCI/RCIC INIT C. 3-9-3C window 28, RX WTR LVL LOW LOW LOW ECCS/ESF INIT D. 3-9-3C window 3, REACTOR LEVEL LOW ADS BLOWDOWN PERMISSIVE

Q 22 Unit 2 is operating at 100% Power.

Subsequently:

A transient results in the following:

2-9-4C window 35 OG POST TRTMT RAD MONITOR Hi-Hi-Hi/INOP alarms and will NOT reset.

The Automatic and Immediate actions of 2-AOI-66-2, Offgas Post-Treatment Radiation HI-HI-HI were completed.

ASSUME NO OTHER OPERATOR ACTIONS ARE PERFORMED.

Which ONE of the following describes the expected system response?

The SJAE in service prior to the event will __ (1) __.

The indication on 0-RM-90-147/148 Stack Gas RAD Monitors one hour after the immediate actions of 2-AOI-66-2 are complete will __ (2) __ they indicated prior to the transient.

A. (1) remain in service (2) be lower than B. (1) remain in service (2) remain the same as C. (1) shutdown (2) be lower than D. (1) shutdown (2) remain the same as

Q 23 Due to an error while performing surveillance testing on Unit 2, a Secondary Containment isolation was initiated.

In accordance with 0-OI-65, Standby Gas Treatment System, which ONE of the following completes the statement below?

The SGT Relative Humidity heaters will ___(1)___.

The Refuel Zone Exhaust to SGT dampers 1-FC0-064-0044 & 0045, __ (2) __

auto open.

A. (1) energize (2) will B. (1) energize (2) will Not C. (1) de-energize (2) will D. (1) de-energize (2) will Not

Q 24 Unit 1 Suppression Pool Level is + 5.5 inches.

Which ONE of the following completes the statements below?

HPCI Suction __ (1) __ automatically transfer to the Suppression Pool.

RCIC Suction __ (2) __ automatically transfer to the Suppression Pool.

A. (1) will (2) will B. (1) will (2) will Not C. (1) will Not (2) will D. (1) will Not (2) will Not

Q 25 Unit 2 is operating at 100% Power when 2-9-3D window 24 MAIN STEAM LINE LEAK DETECTION TEMP HIGH alarms.

The BOP Operator reports that 2-TIS-1-60A; MN STEAM TUNNEL TEMP indicates170 °F and rising.

Which ONE of the following completes the statements below?

An EOI-3 entry condition __ (1) __ been met.

The MSIV closure setpoint for the Steam Tunnel temperature is __ (2) __ °F.

A. (1) has (2) 189 B. (1) has (2) 315 C. (1) has Not (2) 189 D. (1) has Not (2) 315

Q 26 Unit 1 is in Mode 5, Units 2 and 3 are in Mode 1.

A Refueling accident occurs on Unit 1 resulting in the following readings:

1-RM-90-140/142

Reactor Zone 1-RM-90-142A indicates 65mr/hr

Reactor Zone 1-RM-90-142B indicates 67mr/hr

Refuel Zone 1-RM-90-140A indicates 75mr/hr

Refuel Zone 1-RM-90-140B indicates 78mr/hr 1-RM-90-141/143

Reactor Zone 1-RM-90-143A indicates 68mr/hr

Reactor Zone 1-RM-90-143B indicates down scale

Refuel Zone 1-RM-90-141A indicates 70mr/hr

Refuel Zone 1-RM-90-141B indicates 69mr/hr Which ONE of the following identifies the ventilation response?

A. Refuel Zone isolation only B. Reactor and Refuel Zone isolation C. Reactor Zone isolation and CREV auto initiation D. Refuel Zone isolation and CREV auto initiation

Q 27 The Radwaste Operator reports that Unit 1 Reactor Building Floor Drain Sump B level is 50 inches and rising with the B Sump pump running.

Which ONE of the following completes the statements below?

An EOI-3, Secondary Containment Control, entry condition is first met when level rises an additional __ (1) __ inches.

In accordance with the EOI Program Manual Section 0-V-E, EOI-3 Secondary Containment Control Bases, the reason for isolating a system that is discharging into Secondary Containment is to __ (2) __.

A. (1) 16 (2) terminate the radioactivity release B. (1) 16 (2) maintain Reactor Building pressure negative C. (1) 25 (2) terminate the radioactivity release D. (1) 25 (2) maintain Reactor Building pressure negative

Q 28 A loss of coolant accident occurred on Unit 3 The following conditions exist:

3A RHR pump is running in LPCI mode

Reactor water level has been stabilized at +15 inches

Drywell spray was initiated using 3B RHR pump

Drywell Temperature is 250 °F and slowly lowering

Drywell Pressure is 13 psig and slowly lowering Subsequently:

3-9-3D window 29 RHR/CS DIV I TEMP HIGH alarms

The Reactor Building AUO reports that the 3A RHR Room Cooler is NOT running and would NOT start using the local pushbutton Which ONE of the following completes the statements below?

Place RHR pump __ (1) __ in service in LPCI mode and secure 3A RHR pump.

The lowest temperature at which the RHR Room Cooler will auto start is__ (2) __ if it is not already running.

A. (1) 3C (2) 95 °F B. (1) 3D (2) 95 °F C. (1) 3C (2) 148 °F D. (1) 3D (2) 148 °F

Q 29 What is the power supply for RHR SYS II INBD INJECTION VLV, 2-FCV-74-67?

480 V RMOV Board A. 2A B. 2B C. 2D D. 2E

Q 30 HPCI is running in pressure control in accordance with 2-EOI Appendix-11C, Alternate RPV Pressure Control Systems HPCI Test Mode when the following event occurs:

Condensate Storage Tank (CST) level dropped below 6800 gallons.

What is the current status of the HPCI system?

HPCI is A. operating in pressure control with suction from the CST.

B. operating in pressure control with suction from the Suppression Pool.

C. operating at shutoff head with suction from the Suppression Pool.

D. tripped on low suction pressure.

Q 31 Unit 1 Core Spray is being shut down following an automatic actuation in accordance with 1-OI-75, Core Spray, section 7.1 Core Spray System Shutdown.

At what flow is the Minimum Flow Valve, 1-FCV-75-9(37) expected to open when the Inboard Injection Valve, 1-FCV-75-25(53) is throttled closed?

A. 900 gpm B. 1350 gpm C. 2200 gpm D. 2600 gpm

Q 32 Given the following conditions:

A Unit 1 ATWS occurred

During the performance of 1-EOI-Appendix 3A, SLC INJECTION, the Standby Liquid Control (SLC) pump control switch was placed in the START- A position

SQUIB VALVE A CONTINUITY blue light is illuminated

SQUIB VALVE B CONTINUITY blue light is extinguished

SLC INJECTION FLOW TO REACTOR (Panel 1-9-5B, Window 14) is in alarm Which ONE of the following completes the statements below?

The SLC Squib valve ___ (1) ___ is OPEN.

The time to inject Hot Shutdown Boron Weight is ___ (2) ___ compared to the time with both squib valves open.

A. (1) A (2) the same B. (1) A (2) longer C. (1) B (2) the same D. (1) B (2) longer

Q 33 2-SR-3.1.4.1, SCRAM Insertion Times, is in progress.

At Panel 2-9-16 the UO performs the actions to test Control Rod 26-43, and returns the SCRAM TEST switch back to the NORMAL position.

What is the status of the scram blue light for control rod 26-43 on the full core display?

A. Illuminated while the SCRAM TEST switch is in the TEST position, but extinguishes immediately when placed back in NORMAL (power restored).

B. Illuminated while the SCRAM TEST switch is in the TEST position, but extinguishes when either scram valves reclose (limit switch).

C. Illuminated until the SCRAM RESET switch on panel 9-5 is placed in either the GRP 2/3 or 1/4 position.

D. Illuminated until the SCRAM RESET switch on panel 9-5 is placed in both the GRP 2/3 and GRP 1/4 positions.

Q 34 A reactor plant startup is being conducted on Unit 2 in accordance with GOI-100-1A, Unit Startup and Power Operation.

The reactor is critical and SRM/IRM overlap data has just been completed.

All SRMs are reading between 5.0 X 103 and 1.0 X 104 cps.

All IRMs are mid scale on range 1.

The operator has inadvertently selected both the SRMs and the IRMs for withdraw.

Which ONE of the following Control Rod Blocks will be the first automatic action to occur as the detectors are withdrawn?

A. SRM Detector Wrong position B. IRM Detector Wrong position C. SRM Downscale D. IRM Downscale

Q 35 What are the power supplies to the SRM Channels/detectors?

SRM Channels/Detectors ______.

A. A & B are powered from the A channel + 24VDC System and C & D are powered from the B channel + 24VDC System B. A & C are powered from the A channel + 24VDC System and B & D are powered from the B channel + 24VDC System C. A & B are powered from Division I, 250 VDC System and C & D are powered from Division II, 250 VDC System D. A & C are powered from Division I, 250 VDC System and B & D are powered from Division II, 250 VDC System

Q 36 Unit 2 is operating at power.

Given that Core Flow is 65%, APRM 1 will display which approximate Rod Block setpoint?

A. 102 B. 108 C. 113 D. 119

Q 37 How many LPRM detectors are assigned to each APRM channel and how many LPRM detectors are in each LPRM string?

A. 21; 3 B. 21; 4 C. 43; 3 D. 43; 4

Q 38 What Reactor Core Isolation Cooling (RCIC) design feature provides for the prevention of water hammer?

A. Suction head pressure provided by the CST B. Minimum flow valve automatic operation C. System snubbers D. Low pressure isolation

Q 39 During a Unit 1 ATWS, the UO places ADS LOGIC INHIBIT switches 1-XS-1-159A and 1-XS-1-161A in inhibit then reports:

1-9-5 window 18 ADS LOGIC BUS A INHIBITED failed to alarm.

1-9-5 window 31 ADS LOGIC BUS B INHIBITED is in alarm.

Which ONE of the following completes the statement below?

In accordance with 1-ARP-9-3C window 18 the UO will direct an AUO to ______.

A. open the ADS System Logic Bus A breaker on 250V RMOV board 1B B. pull 250V Logic A fuses on Panel 1-9-30 in the Auxiliary Instrument room C. place all ADS transfer switches in emergency at Panel 1-25-32, Backup Control Panel D. pull all ADS Solenoid power fuses at Panel 1-25-32, Backup Control Panel

Q 40 Which ONE of the following completes the statements below?

Reactor Water Level Instruments,__ (1) __ provide the Reactor Vessel water level Low-Low-Low initiation signal to ADS logic.

RHR or Core Spray pumps __ (2) __ required to be running to initiate the ADS timers.

NOTE: LIS-3-184 is Reactor Water Level A LIS-3-185 is Reactor Water Level B LIS-3-58A through D is Reactor Water Level A through D A. (1) LIS-3-58A through D (2) are B. (1) LIS-3-58A through D (2) are Not C. (1) LIS-3-184 and LIS-3-185 (2) are D. (1) LIS-3-184 and LIS-3-185 (2) are Not

Q 41 What design feature allows testing of MSIV Reactor Water Level Instrumentation associated with Primary Containment Isolation System (PCIS) without causing a device actuation?

A. 1 out of 2 taken twice logic B. 2 out of 3 logic C. 2 out of 4 voter logic D. 2 out of 2 taken once logic

Q 42 How are the ADS MSRVs affected by a loss of Drywell Control Air (DWCA)?

ADS MSRVs will A. Not operate in the Manual mode.

B. operate a minimum of three times in the Manual mode.

C. operate a minimum of five times in the Manual mode.

D. operate indefinitely in the Manual mode.

Q 43 Unit 3 is operating at 100% power, with the following feedwater alignment:

Reactor Water Level Master Controller in MAN

A RFPT Speed Controller in AUTO at 5000 RPM

B RFPT Speed Controller in AUTO at 4995 RPM

C RFPT Speed Controller in MAN at 5005 RPM How will Reactor Feed Pumps respond when the Reactor Water Level Master Controller raise pushbutton is depressed?

A. A, B and C RFPT speeds increase.

B. A, B and C RFPT speeds remain the same.

C. A and B RFPT speeds increase; RFPT C speed remains the same.

D. A and B RFPT speeds remain the same; RFPT C speed increases.

Q 44 Which ONE of the following (if any) identifies the suction source(s) that can be aligned for the Standby Gas Treatment Fans with respect to the Primary Containment System?

A. None B. Drywell ONLY C. Suppression Chamber ONLY D. Drywell and Suppression Chamber

Q 45 Unit 2 is performing 0-SR-3.8.1.1(D), Diesel Generator D Monthly Operability; the Diesel has been loaded for 30 minutes.

The following indications have just occurred.

Which ONE of the following completes the statements below?

The white light above BKR 1816 is a __ (1) __.

Based on these conditions the first expected response is __ (2) __.

A. (1) disagreement indication (2) DG D Breaker 1816 will trip open B. (1) disagreement indication (2) 4KV SD D Normal FDR BKR 1724 will trip open C. (1) Diesel Generator Overload indication (2) DG D Breaker 1816 will trip open D. (1) Diesel Generator Overload indication (2) 4KV SD D Normal FDR BKR 1724 will trip open

Q 46 All three Units are operating at 100% power.

240V Lighting Board 2A is tagged out of service for scheduled work.

An electrical fault causes 240 V Lighting Board 3B to deenergize.

Which ONE of the following completes the statements below?

The Plant Preferred MG will start __ (1) __ and energize __ (2) __on all 3 units.

A. (1) immediately (2) Panel 9-9 cabinet 4 B. (1) immediately (2) Panel 9-9 cabinet 5 C. (1) after a 6 second time delay (2) Panel 9-9 cabinet 4 D. (1) after a 6 second time delay (2) Panel 9-9 cabinet 5

Q 47 Unit 1 is operating at 100% Power.

1-9-8B window 35 UNIT PFD SUPPLY ABNORMAL alarms The Control Bay AUO reports the following lights illuminated at the Unit 1 Unit Preferred System Inverter:

1-IL-252-0001L (Red Lamp) Inverter Fuse Blown

1-IL-252-0001D (Red Lamp) Alternate Source Supplying Load ASSUME NO OPERATOR ACTIONS HAVE BEEN PERFORMED.

Which ONE of the following completes the statement below?

The Unit 1 Unit Preferred loads are being supplied through the_______.

A. Unit Preferred Inverter Static Switch B. Alternate supply to 1-PNL-9-9 cabinet 6 only C. UNIT PFD XFMR1 TO BATTERY BD 1 ALT FDR, 0-BKR-280-001/1002 D. UNIT PFD MMG SET 2 TO BATT BD 1 EMERG FDR, 0-BKR-001/1003

Q 48 All three Units are operating at 100% power when the following alarm is received:

Panel 1/2-9-23B, Window 17 DIESEL GEN B BAT CHGR OR EXH FAN ABN What local indication does the AUO have to diagnose that the cause of the alarm is the 125 VDC Battery Charger?

A. Local relay targets on the front of the charger.

B. B Diesel Generator room Emergency lights illuminated.

C. Voltage meter on the front of the battery charger.

D. Central Diesel Information Center Alarm Panels.

Q 49 All three Units are operating at 100% power.

Subsequently, 4KV SD BUS 2 de-energizes.

Which ONE of the following completes the statements below?

The D and __ (1) __ Diesel Generators will auto start.

In accordance with 0-OI-82, Standby Diesel Generator System, the Diesel Generator Maximum Continuous steady-state active power output (KW) is limited to __ (2) __.

A. (1) B (2) 2600 kW B. (1) B (2) 2860 kW C. (1) C (2) 2600 kW D. (1) C (2) 2860 kW

Q 50 Which ONE of the following completes the statement below?

When Control Air is lost, the Drywell Control Air System A. loses its only backup source of pneumatics.

B. loses one of two backup sources of pneumatics.

C. slowly depressurizes.

D. remains pressurized due to installed accumulators.

Q 51 The G Control Air Compressor is in service with the other Control Air Compressors A, B, C, and D in Standby in accordance with 0-OI-32, Control Air System.

Subsequently, the G Control Air compressor trips.

How do the other Control Air Compressors respond as pressure lowers to 90 psig?

A. Only those compressors which are selected as lead start.

B. All compressors start on a common setpoint simultaneously.

C. The compressors which are selected as lead start followed by the lag compressors with a 2 psig offset between them.

D. All control air compressors start one at a time with a 2 psig offset between them.

Q 52 All three units are operating at 100% power.

The A3 RHRSW pump is tagged for motor replacement.

Subsequently:

The C-3 EECW pump trips and the AUO reports that the pump is hot to the touch.

In accordance with 0-OI-67, Emergency Equipment Cooling Water System, which ONE of the following completes the statements below?

RHRSW pump __ (1) __ can be aligned to EECW in place of the C-3 RHRSW pump.

This pump __ (2) __ the same AUTO start signals as the C-3 RHRSW pump.

A. (1) C-1 (2) has B. (1) C-1 (2) does Not have C. (1) C-2 (2) has D. (1) C-2 (2) does Not have

Q 53 Which way does 1-FCV-70-1, RBCCW Surge Tank fill valve, fail and where do you send someone to control level in the RBCCW Surge Tank?

A. Open; Reactor Building EL 639 foot.

B. Open; Reactor Building EL 593 foot.

C. Closed; Reactor Building EL 639 foot.

D. Closed; Reactor Building EL 593 foot.

Q 54 Unit 2 is operating at 100 % power with the following indication:

Which ONE of the following completes the statements below?

In accordance with 2-OI-85, Control Rod Drive System, The Control Rod Drive system flow __ (1) __ in the normal band.

The next time the UO adjusts CRD system flow, Calculated Thermal Power

__ (2) __ be affected.

A. (1) is (2) will B. (1) is (2) will Not C. (1) is Not (2) will D. (1) is Not (2) will Not

Q 55 How much flow is provided to the CRD to get the collet fingers released from the notch in the index tube during a normal control rod withdrawal?

Which direction does the Unit Operator throttle the PCV-85-23, CRD Drive Water pressure control valve to raise Drive Water differential pressure?

A. (1) 2 gpm (2) open B. (1) 2 gpm (2) closed C. (1) 4 gpm (2) open D. (1) 4 gpm (2) closed

Q 56 Unit 3 is operating at 100% power when the following occurs:

The 3C RFPT tripped

Reactor Water level lowered to + 25 inches on the Normal Range instruments.

What is the expected response of the Reactor Recirc System?

Recirc Pumps speeds lower to achieve A. 480 rpm.

B. 1130 rpm.

C. a core flow of 60 Mlbm/hr.

D. a steam flow of 10.9 Mlbm/hr.

Q 57 As Reactor Power rises past 25%, what provides a signal to the Rod Block Monitor (RBM) to begin enforcing Control Rod Blocks?

A. Local Power Range Monitor B. Average Power Range Monitor C. Total Steam Flow D. Total Feedwater Flow

Q 58 Unit 3 is operating at 100% Rx Power with the following indications and alarms present:

DRYWELL DP AIR COMP DISCH AIR TEMP HIGH, Panel 9-3B window 33

DRYWELL TO SUPPR CHAMBER DIFF PRESS ABNORMAL, Panel 9-3B window 26

DRYWELL TO SUPPR CHAMBER DIFF PRESS, 3-PDS-64-137C is reading 1.41 psid

DRYWELL TEMPERATURE, 3-TE-64-52C is reading 135 °F

Drywell DP Compressor is running Which ONE of the actions below describes the highest priority?

A. Stop the DP Air Compressor B. Bypass the DP Air compressor TCV C. Open the DP Air Compressor Bypass Valve D. Blow down RCW to the DP Air Compressor after cooler

Q 59 During Refueling Operations with the Reactor mode switch in the refuel position, the following events occur:

A fuel bundle is pulled to full up from its spent fuel pool location.

The bridge is then driven over the core to its new location and the Refueling Bridge operator starts lowering the fuel bundle into the core.

NO Rod Block alarm is received during this evolution.

Based on the events that just occurred what action is immediately required by Tech Specs?

A. Suspend in-vessel fuel movement.

B. Insert a control rod withdrawal block only.

C. Verify all control rods are fully inserted only.

D. Place the reactor mode switch in the shutdown position.

Q 60 The following plant conditions exist on Unit 2:

Main Turbine Shell Warming is in progress

The UO is pulling Control Rods in accordance with 3-GOI-100-1, Unit Startup 3-OI-47, Turbine-Generator System section 5.2 Turbine Shell Warming cautions the Operators that a Reactor Scram may result when Main Turbine First stage pressure exceeds _____ psig.

A. 105 B. 115 C. 147 D. 165

Q 61 The Unit 1 Main Generator synchronization is in the progress IAW 1-GOI-100-A, Unit Startup.

The following indications are observed on panel 1-9-8:

VOLTAGE REGULATOR MAN/AUTO in MAN

GEN SYNC REF VOLTAGE, 1-E-57-54 is reading 27 V

SYSTEM SYNC REF VOLTAGE is reading 28 V

SYNCHROSCOPE 1-XI-57-55 is stopped at the 6:00 position In accordance with 1-OI-47 before the Generator PCB 214 is closed, the operator must go to __ (1) __ on the Voltage Regulator Lower/Raise Adjust Switch to match voltages.

The operator must also go to __ (2) __ on the Turbine Generator Synch Speed INC/DEC Adjust Switch until the Synchroscope is moving slowly in the clockwise direction.

A. (1) raise (2) INC B. (1) raise (2) DEC C. (1) lower (2) INC D. (1) lower (2) DEC

Q 62 What is the effect on the Reactor Feedwater System from a loss of 120V I&C Bus A?

A. RPFT 2B Woodward Governor loses power.

B. RFP 2C Minimum Flow Valve fails open.

C. RFW Start-up Level Control PDS controls are rendered inoperative.

D. RFPT/RFP 2A Vibration Monitoring Equipment loses indication.

Q 63 The Waste Collector Tank normally receives discharge from which system drains?

A. Floor B. Laundry C. Laboratory D. Equipment

Q 64 What is the power supply to the Stack-Gas Radiation Monitor (0-RM-90-147 & 148) scintillation detectors?

A. Unit 1 (+/-) 24 VDC Neutron Monitoring Battery System B. Unit 2 (+/-) 24 VDC Neutron Monitoring Battery System C. Unit 1 120 VAC Reactor Protection System D. Unit 2 120 VAC Reactor Protection System

Q 65 A fire has been reported in Unit 2 Auxiliary Instrument Room and the CO2 System failed to automatically or manually initiate.

The Unit Supervisor has ordered the AUO to manually initiate CO2 using the Pilot Control Valve Station(s).

How will the CO2 System respond when the pilot valve lever is placed in the OPEN position?

CO2 will be dispensed ___ (1) ___ and the evacuation alarm ___ (2) ___ sound.

A. (1) immediately (2) will B. (1) immediately (2) will Not C. (1) after 60 sec time delay (2) will D. (1) after 60 sec time delay (2) will Not

Q 66 What is the frequency of panel walk downs in accordance with OPDP-1, Conduct of Operations?

The Unit Operator is to perform a panel walk down a minimum of once ___________.

A. per hour B. every 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months C. every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months D. every 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months

Q 67 In accordance with 2-GOI-100-1A, Unit Startup and Power Operation, there are Initial Steps that contain an (R) before that step, what requirement is imposed?

The step A. requires Radiation Protection notification only.

B. requires holding for Radiation Protection, (RP Hold Point).

C. indicates a restriction on Reactor Power, prior to proceeding.

D. is required and shall not be omitted, unless permitted in the step.

Q 68 In accordance with ODM-4.5, Operator Aids and Operator Information System, how does the Unit Operator determine during the panel walk down, that a system is aligned correctly?

The normally running pumps shall have a ___ (1) ___red lens cover.

The normally closed valves shall have a ___ (2) ___ green lens cover.

A. (1) clear (2) clear B. (1) diffused (2) diffused C. (1) diffused (2) clear D. (1) clear (2) diffused

Q 69 Unit 1 is performing a startup in accordance with 1-GOI-100-1A, Unit Startup.

During control rod notch withdrawal, prior to critically, SRM PERIOD, (1-9-5A, Window 20), alarms and seals in.

What action(s) is/are required by 1-GOI-100-1A?

A. PAUSE Control Rod withdrawal until a stable period of greater than 100 seconds is observed.

B. REINSERT the last Control Rod withdrawn to obtain a stable period greater than 60 seconds.

C. INSERT Control Rods and ENSURE the Reactor is brought subcritical.

D. SHUTDOWN the Reactor until a thorough assessment has been performed.

Q 70 Which ONE of the following completes the statement below?

In accordance with NPG-SPP-07.3.4, Protected Equipment, when unscheduled work requires protecting equipment, it is required to be posted as Protected Equipment unless the expected unavailability time is less than __ (1) __.

A. the duration of the current shift B. the duration of the following shift C. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months D. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

Q 71 Which ONE of the following meets the requirements to be considered a "Complex Infrequently Performed Test or Evolution" (CIPTE) per NPG-SPP-06.9.1, Conduct of Testing?

A. Switching Order to remove the West Point 500KV line B. 0-SR-3.8.1.9(A) Diesel Generator A Emergency Unit 1 Load Acceptance Test C. 1-SR-3.5.1.7(COMP), HPCI Comprehensive Pump Test (IST Data)

D. 1-SR-3.5.1.6(RHR I) Quarterly RHR System Rated Flow Test Loop I

Q 72 Which ONE of the following completes the statement below?

The Wide Range Gaseous Effluent Radiation Monitor System (WRGERMS) consists of__ (1) __ ranges, AND can be monitored remotely from__ (2) __.

A. (1) two (2) all three Units Control Room B. (1) two (2) the Unit 2 Control Room C. (1) three (2) all three Units Control Room D. (1) three (2) the Unit 2 Control Room

Q 73 Which ONE of the following completes the statements below in accordance with RCI-9.1, Radiation Work Permits?

During an emergency situation, the Shift Manager has authorized immediate entry for Maintenance personnel into a High Radiation Area for which an RWP is not current.

Radiation Protection __ (1) __ be required to escort personnel entering the area.

When the area has been exited and the emergency situation is over, an RWP

__ (2) __ required to be completed for this entry.

A. (1) will (2) is B. (1) will (2) is Not C. (1) will Not (2) is D. (1) will Not (2) is Not

Q 74 Which of the following is an ENTRY CONDITION into the Emergency Operating Instructions (EOI) and what is the overall mitigating strategy as directed by that EOI?

A. RPV Pressure above 1050 psig; Maintain adequate core cooling.

B. Suppression Pool Level above (-) 1 inch; Maintain the integrity of Primary Containment.

C. Rx power >5% or unknown; Expedite plant cooldown to place the reactor in the lowest energy state.

D. Spent Fuel Pool Temperature above 100 ºF; Maintain the continued operability of equipment needed to carry out the EOIs.

Q 75 Unit 1 is operating at 100% power.

Which ONE of the following completes the statement below?

When assessing the EOI Exclusion Plot Status Boxes on the Safety Parameter Display System (SPDS):

__ (1) __ is expected to be colored red because current plant operation __ (2) __

within the Safe region of the curve.

A. (1) Curve 6, Press Suppr Press (2) is B. (1) Curve 6, Press Suppr Press (2) is Not C. (1) Curve 5, DW Spray Init Limit (2) is D. (1) Curve 5, DW Spray Init Limit (2) is Not

Q 76 In accordance with Tech Spec bases section 3.8.1, AC Sources - Operating, which ONE of the following completes the statements below?

When the A 4kv Shutdown board normal feeder breaker trips, the A Diesel Generator is required to energize the A 4KV Shutdown board within __ (1) __

seconds.

Offsite power to the A 4KV Shutdown board, when aligned through the alternate feeder breaker, __ (2) __ be credited in accordance with Technical Specification Bases.

A. (1) 5 (2) Can B. (1) 5 (2) Cannot C. (1) 10 (2) Can D. (1) 10 (2) Cannot

Q 77 Unit 3 is operating at 100% power.

CSST A is tagged on a SWLD Hold Order.

Start bus 1A and 2A have been transferred to alternate.

Which ONE of the following completes the statements below?

Based on the conditions above, multiple Units __ (1) __ claim a 161KV offsite power circuit simultaneously.

Subsequently, The Unit 3 Main Turbine trips due to Main Xfmr/USST Differential (386TX) relay operation.

Tech Spec 3.8.1, AC Sources-Operating requires restoring one offsite circuit to operable within __ (2) __.

[REFERENCE PROVIDED]

A. (1) can (2) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months B. (1) can (2) 7 days C. (1) can Not (2) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months D. (1) can Not (2) 7 days

Q 78 Unit 1 was operating at 100% Reactor Power when the following series of events occurred:

02:05 Unit 1 Control Room Evacuation is initiated due to smoke in the Control Room

02:09 the Backup Control Panel, 1-25-32 is manned

02:13 the Operator has control of Reactor Pressure

02:17 AUO reports HPCI is running

02:19 Reactor Water Level is currently (-) 30 inches and rising

02:28 RCIC is initiated from Panel 1-25-32 Which ONE of the following completes the statements below?

In accordance with EPIP-1, Emergency Plan Implementing Procedure, the HIGHEST Emergency Action Level Classification that is required for these conditions is a (an) __ (1) __.

Drywell temperature and pressure are being controlled by__ (2) __.

[REFERENCE PROVIDED]

A. (1) Alert (2) containment venting B. (1) Alert (2) operation of DW Blowers C. (1) Site Area Emergency (2) containment venting D. (1) Site Area Emergency (2) operation of DW Blowers

Q 79 All three Units are operating at 100% power.

The following are received in the Unit 1 Control Room:

Report of a leak from the South EECW header in the DG building hallway.

All EECW pumps are operating at their required flow rate.

The EECW South Header is depressurized.

In accordance with Tech Spec bases section 3.7.2, EECW System and UHS which ONE of the following completes the statements below?

The EECW system __ (1) __ operable.

The EECW system __ (2) __ supply adequate cooling for continuous operation of the Unit 1/2 Diesel Generators.

A. (1) is (2) can B. (1) is (2) can Not C. (1) is Not (2) can D. (1) is Not (2) can Not

Q 80 All three Units are operating at 100% Rx Power.

The G Control Air Compressor is tagged for scheduled work.

The following are received in the Unit 1 Main Control Room:

AIR COMPRESSOR ABNORMAL 1-9-20B window 29

SERVICE AIR XTIE VLV OPEN 1-9-20B window 30

CONTROL AIR DRYER DISCH PRESSURE LOW 1-9-20B window 32 The Turbine Building AUO reports that a fork lift has ruptured one of the Control Air Receivers.

Assume no Operator actions are taken.

NOTE: 0-AOI-32-1, Loss of Control and Service Air Compressors 1-ARP-9-5B window 28 SCRAM PILOT AIR HEADER PRESS LOW Which ONE of the following completes the statements below?

The Reactor is required to be scrammed when control air pressure first lowers below

__ (1) __ in accordance with __ (2) __.

A. (1) 66 psig (2) 1-ARP-9-5B window 28 B. (1) 66 psig (2) 0-AOI-32-1 C. (1) 55 psig (2) 1-ARP-9-5B window 28 D. (1) 55 psig (2) 0-AOI-32-1

Q 81 The Unit 1 Reactor Steam Dome Pressure spikes to 1350 psig and the Reactor Scrams.

What is the earliest notification required In accordance with NPG-SPP-03.5 Regulatory Reporting Requirements?

[REFERENCE PROVIDED]

A. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months report B. 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months report C. 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months report D. 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months report

Q 82 A LOCA is in progress. The following conditions exist on Unit 2:

Rx Pressure is 625 psig

Rx Water Level on 2-LI-3-52 is (-) 242 inches

No injection sources are available Which ONE of the following completes the statements below?

(SEE GRAPH BELOW)

Actual water level is __ (1) __ and 2-EOI-1, RPV Control, requires entering __ (2) __.

A. (1) greater than (-) 200 inches (2) Steam Cooling B. (1) greater than (-) 200 inches (2) Emergency Depressurization C. (1) less than (-) 200 inches (2) Steam Cooling D. (1) less than (-) 200 inches (2) Emergency Depressurization Correction Curve Table

Q 83 Unit 1 is operating at 20% power with two Condenser Circulating Water Pumps in service, when the following occurs:

1-XR-2-26, CONDENSATE recorder, indicates (-) 24.8 inches of Hg and is slowly degrading.

NOTE: 1-AOI-47-3, Loss of Condenser Vacuum 1-AOI-47-1, Unplanned Turbine Trip Below 30% Reactor Power 1-AOI-100-1, Reactor Scram Which ONE of the following actions (if any) is/are required to be performed?

A. No action required at this time.

B. Enter 1-AOI-47-3 and TRIP the Main Turbine ONLY.

C. Enter 1-AOI-47-1 and VERIFY Main Turbine TRIPPED.

D. Enter 1-AOI-47-3 and 1-AOI-100-1, SCRAM the Reactor, THEN TRIP the Main Turbine.

Q 84 Unit 2 is operating at 100% power.

The Unit Operator reports:

Drywell pressure is 2.20 psig

Drywell Temperature is 162 °F

Drywell pressure is slowly rising NOTE: 2-AOI-64-1, Drywell Pressure and/or Temperature High or Excessive Leakage into Drywell 2-EOI Appendix-13, Emergency Venting Primary Containment Which ONE of the following completes the statement below?

Vent the A. Drywell in accordance with 2-AOI-64-1.

B. Suppression Chamber in accordance with 2-AOI-64-1.

C. Drywell in accordance with 2-EOI Appendix-13.

D. Suppression Chamber in accordance with 2-EOI Appendix-13.

Q 85 Unit 2 is operating at 70% power performing a sequence exchange when a transient results in the following conditions:

Unit 2 is manually scrammed 2-9-3A window 27 MAIN STEAM LINE RADIATION HIGH-HIGH is in alarm 2-9-3A window 22 RX BLDG AREA RADIATION HIGH is in alarm 2-9-3F window 10 HPCI LEAK DETECTION TEMP HIGH is in alarm At 1000 the UO reports:

HPCI Room Temp 73-55A reading 160 °F

HPCI Area Radiation 90-24A reading 500 mR/hr At 1010 the UO reports:

HPCI failed to isolate

HPCI Room Temp 73-55A reading 180 °F

HPCI Area Radiation 90-24A reading 700 mR/hr

Drywell Radiation 2-RE-90-272A reading 200 R/hr At 1020 the UO reports:

HPCI Room Temp 73-55A reading 200 °F

HPCI Area Radiation 90-24A reading 900 mR/hr

Drywell Radiation 2-RE-90-272A reading 210 R/hr ASSUME that the given parameter trends continue at the same rate.

At 1030, what will be the highest event classification required to be declared based on expected values?

[REFERENCE PROVIDED]

A. Notification of Unusual Event B. Alert C. Site Area Emergency D. General Emergency

Q 86 All three Units are operating at 100% Power.

The B Diesel Generator was tagged at 0100 on 11/23/2015.

An electrical fault occurred at 0900 on 11/23/2015.

See attached Unit 2 ICS screen shot IAW the Conditions above and Technical Specifications, the most limiting completion time required for Standby Liquid Control (SLC) is _____.

[REFERENCE PROVIDED]

A. 1700 on 11/23/2015 B. 2100 on 11/23/2015 C. 0500 on 11/24/2015 D. 0900 on 11/30/2015

Q 87 Unit 2 is performing a startup with the following conditions:

All IRMs are on Range 4 reading between 50 and 75 on the 125 scale except:

IRM E is Bypassed

IRM D is Bypassed Subsequently:

At 0800, the IM Foreman reports that the following Acceptance Criteria was recorded during the most recent performance of 2-SR-3.3.1.1.9 (IRM C), IRM Channel C Calibration.

Which ONE of the following is the required action (if any) in accordance with Tech Spec 3.3.1.1?

[REFERENCE PROVIDED]

A. No action is required B. Place the Channel or the Trip system in Trip by 1400 C. Place the Channel or the Trip system in Trip by 2000 D. Be in MODE 3 by 2000

Q 88 Unit 2 is in Mode 5 with a Core shuffle in progress.

0800 - SRM A was returned to service but remains INOP pending RTO of a Design Change.

0900 - SRM C started and continued to exhibit erratic operation causing intermittent Rod blocks and was bypassed.

0920 - SRM C begins indicating a steady reading consistent with SRM B and D.

At 0925 which ONE of the following completes the statements below?

In accordance with 2-OI-92, Source Range Monitors, SRM C __ (1) __.

In accordance with Tech Spec Bases and 0-GOI-100-3A, Refueling Operations (In-Vessel Operations), fuel loading can __ (2) __.

A. (1) shall remain bypassed (2) Not continue B. (1) shall remain bypassed (2) continue in B and D quadrants C. (1) can be returned to service (2) Not continue D. (1) can be returned to service (2) continue in B and D quadrants

Q 89 All three units are operating at 100% power.

0-SR-3.8.1.1(A) Diesel Generator A Monthly Operability test is currently in progress With the Diesel Generator loaded.

Subsequently:

All off-site power is lost.

NOTE: Appendix 17A RHR System Operation Suppression Pool Cooling 0-AOI-57-1A Loss of Offsite Power (161 and 500KV)/Station Blackout Which ONE of the following completes the statements below?

When off-site power is lost the A Diesel Generator output breaker will __ (1) __.

If Suppression Pool Cooling is required by EOI-2, __ (2) __ dictates the order in which pumps are to be started to place Suppression Pool Cooling in service.

A. (1) remain closed (2) Appendix 17A B. (1) trip and then reclose (2) Appendix 17A C. (1) remain closed (2) 0-AOI-57-1A D. (1) trip and then reclose (2) 0-AOI-57-1A

Q 90 Unit 2 is operating at 100% power.

IMs are performing RPS And Rod Block High Water Level in Scram Discharge Tank Functional Test (2-LS-85-45A & 2-LS-85-45L)

0130 The IMs removed 2-LS-85-45A, West CRD SCRAM Discharge volume SCRAM Trip, from service in accordance with the surveillance.

0330 The IMs report that 2-LS-85-45A did Not change states during testing.

[REFERENCE PROVIDED]

Based on information provided which ONE of the following completes the statements below?

A valid high level in only the West CRD SCRAM Discharge volume __ (1) __ cause a full Reactor Scram.

In accordance with Tech Spec 3.3.1.1 the most limiting completion time is __ (2) __.

A. (1) will (2) 1530 B. (1) will (2) 1930 C. (1) will Not (2) 1530 D. (1) will Not (2) 1930

Q 91 Unit 1 Rx Startup following a refueling outage is in progress with the following conditions:

Reactor Mode Switch is in the Startup position

RCIC System Rated Flow at Low RPV Pressure surveillance is in progress

Control Rod 18-23 has been declared SLOW

Control Rod 38-23 has been declared SLOW

Control Rod 22-23 is currently at position 48 Subsequently:

The UO reports receipt of the Control Rod 22-23 SCRAM Accumulator Light.

The Reactor building AUO reports:

The Nitrogen Charging Connection Cap cannot be re-installed and RT VLV TO PI-85-34, 2-RTV-085-229A (star valve) is currently open.

Which ONE of the following completes the statement below?

The Tech Spec required action(s) is (are) to ______.

[REFERENCE PROVIDED]

A. enter MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months B. declare Control Rod 22-23 SLOW or INOP only C. fully insert Control Rod 22-23 and declare it INOP only D. fully insert Control Rod 22-23, declare it INOP, and disarm it

Q 92 Unit 2 is at 100% power.

2-9-5A window 17 CONTROL ROD DRIVE UNIT TEMP HIGH is in alarm.

Which ONE of the following completes the statements below?

The setpoint for the CONTROL ROD DRIVE UNIT TEMP HIGH is __ (1) __.

If the Control Rod Drive temperature remains above the alarm setpoint after completion of the ARP actions the US is required to determine if Tech Spec section

__ (2) __ is met.

A. (1) 240 °F (2) 3.1.3 Control Rod Operability B. (1) 240 °F (2) 3.1.4 Control Rod Scram Time C. (1) 350 °F (2) 3.1.3 Control Rod Operability D. (1) 350 °F (2) 3.1.4 Control Rod Scram Time

Q 93 2-SR-3.6.1.3.5(94), TIP System PCIV Operability Test was last performed on 08/01/2015. The Frequency of this test is once every 92 days.

The TIP System PCIV Operability Test was scheduled on 10/24/2015 however the test could not be performed as scheduled.

In accordance with Tech Spec section SR 3.0.2, on what date will the TIP Ball valves become INOP if the surveillance is not performed?

A. 11/02/2015 B. 11/16/2015 C. 11/25/2015 D. 01/25/2016

Q 94 To maintain an active SRO license, an SRO must actively perform a minimum of

______ per calendar quarter in a position credited for watch-standing proficiency.

A. 40 hours4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months only B. a complete tour of the plant and 40 hours4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months C. 5-12 hour shifts only D. a complete tour of the plant and 5-12 hour shifts

Q 95 Unit 2 is operating at 100% power.

RHR SHUTDOWN COOLING SUCT OUTBD ISOL VLV, 2-FCV-74-47 is INOP

At 0900: A Tech Spec LCO 3.0.3 is entered.

At 0920: 2-GOI-100-12A, Unit Shutdown from Power Operation to Cold Shutdown and Reductions in Power During Power Operations, has been entered.

At 0930: The OATC begins lowering power in accordance with the Urgent Load Reduction Reactivity Control Plan.

Which ONE of the following completes the statements below?

2-FCV-74-47 __ (1) __ required to be returned to operable status in accordance with Tech Spec 3.4.7 Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown prior to entering Mode 3.

In accordance with NPG-SPP-03.5 the NRC is required to be notified by __ (2) __.

A. (1) is (2) 1320 B. (1) is (2) 1330 C. (1) is Not (2) 1320 D. (1) is Not (2) 1330

Q 96 Which procedure authorizes the use of the eSOMs Off-Normal Equipment Alignment tracker and what is the specified time allowed before making an entry in the Off-Normal Equipment Alignment tracker?

A. NPG-SPP-10.1 System Status Control Before the end of the current shift B. OPDP-1 Conduct of Operations Before the end of the current shift C. NPG-SPP-10.1 System Status Control Within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months D. OPDP-1 Conduct of Operations Within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

Q 97 In accordance with LCO 3.0.4, Tech Spec Bases, what condition allows entry into a MODE or other specified condition in the Applicability with the LCO not met?

When the associated ACTIONS A. to be entered can be completed within the specified completion time.

B. permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time.

C. allow continued operation of equipment under administrative control.

D. permit not entering the required actions for supported equipment while the associated support equipment is inoperable.

Q 98 All three Units are operating at 100% power.

The Control Bay AUO reports that there is no Unit 1 & 2 Control Bay Supply Fan running. Attempts to start the 1A & 1B Control Bay Supply Fan has failed.

What action(s) if any are required by Tech Spec?

[REFERENCE PROVIDED]

A. No action is required.

B. Perform 0-SR-3.3.7.1.2 on 0-RM-90-259B once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

C. Verify alternate monitoring capability once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

D. Restore the affected CREV subsystem to Operable within 7 days.

Q 99 The Unit 1 Control Room receives a Turbine Building smoke alarm on the Fire Protection Display Panel.

A member of the plant security force calls the control room and reports smoke in the Turbine Building.

The Shift Manager has evaluated 0-SSI-001, Safe Shutdown Instructions.

NOTE: EPIP-17, Fire Emergency Procedure 0-SSI-26, Turbine Bldg, Radwaste Bldg 0-AOI-26-1, Fire Response Based on the above conditions, which ONE of the following describes the actions required of the operating crew?

Enter 0-AOI-26-1 and __ (1) __.

In accordance with 0-AOI-26-1, announce the fire location over the PA and __ (2) __.

A. (1) 0-SSI-26 (2) NOTIFY the Clements Volunteer Fire Department by calling the Limestone County 911 Center B. (1) 0-SSI-26 (2) MONITOR Control board indications for equipment failures or spurious operation C. (1) EPIP-17 (2) NOTIFY the Clements Volunteer Fire Department by calling the Limestone County 911 Center D. (1) EPIP-17 (2) MONITOR Control board indications for equipment failures or spurious operation

Q 100 Which ONE of the following completes both statements in accordance with EPIP-1 Emergency Classification Procedure?

IF an Emergency Action Level (EAL) for a higher classification was exceeded, but the present situation indicates a lower classification, THEN the higher classification

__ (1) __ be declared.

IF an Emergency Action Level (EAL) was exceeded but has now been totally resolved (prior to event declaration), THEN the event __ (2) __ required to be reported to the NRC.

A. (1) should still (2) is B. (1) should still (2) is Not C. (1) should Not (2) is D. (1) should Not (2) is Not

BROWNS FERRY NUCLEAR PLANT Unit 0 Emergency Plan Implementing Procedure EPIP-1 EMERGENCY CLASSIFICATION PROCEDURE Revision 0051 Quality Related Level of Use: Reference Use Effective Date: 04/06/2015 Responsible Organization: Radiological Emergency Preparedness PREPARED BY: Sally C. Taubuki APPROVED BY: Steven M. Bono

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 PAGE 1 OF 206 TABLE OF CONTENTS TABLE OF CONTENTS ........................................................................................................................... 1 SECTION I

1.0 INTRODUCTION

................................................................................................................................ 3 1.1 Purpose .............................................................................................................................................. 3

2.0 REFERENCES

................................................................................................................................... 3 2.1 Industry Documents ............................................................................................................................ 3 2.2 Plant Instructions ................................................................................................................................ 3 3.0 INSTRUCTIONS ................................................................................................................................. 4 3.1 General Instructions ............................................................................................................................ 4 3.2 BFN EPIP-1 Overview ........................................................................................................................ 5 4.0 QA Records ....................................................................................................................................... 6 5.0 GLOSSARY of ABBREVIATIONS, ACRONYMS, AND DEFINITIONS ............................................ 7 6.0 EVENT CLASSIFICATION INDEX ................................................................................................... 15 SECTION II EVENT CLASSIFICATION MATRIX ...................................................................................................... 17 1.0 Reactor ............................................................................................................................................. 17 2.0 Primary Containment ........................................................................................................................ 25 3.0 Secondary Containment .................................................................................................................. 33 4.0 Radioactivity Release ....................................................................................................................... 39 5.0 Loss of Power ................................................................................................................................... 45 6.0 Hazards ............................................................................................................................................ 51 7.0 Natural Events .................................................................................................................................. 69 8.0 Emergency Director Judgment ......................................................................................................... 77 SECTION III BASIS ..................................................................................................................................................... 87 1.0 Reactor ............................................................................................................................................. 87 2.0 Primary Containment ...................................................................................................................... 107 3.0 Secondary Containment ................................................................................................................ 125 4.0 Radioactivity Release ..................................................................................................................... 134 5.0 Loss of Power ................................................................................................................................. 145 6.0 Hazards .......................................................................................................................................... 155 7.0 Natural Events ................................................................................................................................ 180 8.0 Emergency Director Judgment ....................................................................................................... 187

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 17 OF 206 REACTOR 1.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 18 OF 206 NOTES 1.1-U1/1.1-A1 Applicable when the Reactor Head is removed and the Reactor Cavity is flooded.

1.1-S1 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 Engineering.

CURVES/TABLES:

TABLE 1.1 - G2 MINIMUM STEAM COOLING PRESS (MSCP)

NUMBER OF OPEN MSRVs MSCP (PSIG) 6 or More 190 5 230 4 290

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 19 OF 206 WATER LEVEL Description Description 1.1-U1 NOTE 1.1-U2 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 remain covered by water. remain covered by water.

OPERATING CONDITION: OPERATING CONDITION Mode 5 ALL 1.1-A1 NOTE 1.1-A2 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:

Mode 5 ALL 1.1-S1 NOTE 1.1-S2 Reactor water level can NOT be maintained Reactor water level can NOT be determined.

above -162 inches. (TAF)

OPERATING CONDITION: OPERATING CONDITION:

ALL Mode 1 or 2 or 3 1.1-G1 1.1-G2 NOTE TABLE 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 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 conditions and unable to restore and maintain MSCP in Table 1.1-G2.

OPERATING CONDITION:

Mode 1 or 2 or 3 OPERATING CONDITION:

Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 20 OF 206 NOTES 1.2 Subcritical is defined as reactor power below the heating range and not trending upward.

CURVES/TABLES:

CURVE 1.2-G HEAT CAPACITY TEMP LIMIT

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 21 OF 206 SCRAM FAILURE REACTOR COOLANT ACTIVITY Description Description 1.3-U Reactor coolant activity exceeds 26 Ci/gm dose equivalent I-131 (Technical Specification Limits) as determined by chemistry sample.

OPERATING CONDITION ALL 1.2-A NOTE 1.3-A Failure of RPS automatic scram functions to bring Reactor coolant activity exceeds 300 Ci/gm dose the reactor subcritical equivalent Iodine-131 as determined by chemistry AND sample.

Manual scram or ARI (automatic or manual) was successful.

OPERATING CONDITION:

OPERATING CONDITION: Mode 1 or 2 or 3 Mode 1 or 2 1.2-S NOTE Failure of automatic scram, manual scram, and ARI to bring the reactor subcritical.

OPERATING CONDITION:

Mode 1 or 2 1.2-G CURVE Failure of automatic scram, manual scram, and ARI. Reactor power is above 3%

AND Either of the following conditions exists:

Suppression Pool temp exceeds HCTL.

Refer to Curve 1.2-G.

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

OPERATING CONDITION:

Mode 1 or 2

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 22 OF 206 NOTES CURVES/TABLES:

CURVE 1.5-S HEAT CAPACITY TEMP LIMIT

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 23 OF 206 MSL / OFFGAS LOSS OF DECAY HEAT RADIATION REMOVAL Description Description 1.4-U 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.

OPERATING CONDITION:

Mode 1 or 2 or 3 1.5-A Reactor moderator temperature can NOT be maintained below 2120 F whenever Technical Specifications require Mode 4 conditions or during operations in Mode 5.

OPERATING CONDITION:

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

OPERATING CONDITION:

Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 24 OF 206 THIS PAGE INTENTIONALLY BLANK

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 25 OF 206 PRIMARY CONTAINMENT 2.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 26 OF 206 NOTES CURVES/TABLES:

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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 27 OF 206 PRIMARY CONTAINMENT PRIMARY CONTAINMENT PRESSURE HYDROGEN Description Description 2.1-A TABLE Drywell pressure at or above 2.45 psig AND Indication of Primary System leakage into Primary Containment. Refer to Table 2.1-A.

OPERATING CONDITION:

Mode 1 or 2 or 3 2.1-S CURVE 2.2-S 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%

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

OPERATING CONDITION: OPERATING CONDITION:

Mode 1 or 2 or 3 Mode 1 or 2 or 3 2.1-G CURVE 2.2-G Drywell pressure can NOT be maintained in the Drywell or Suppression Chamber safe area of Curve 2.1-G. hydrogen concentration at or above 6%

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

OPERATING CONDITION: OPERATING CONDITION:

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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 28 OF 206 NOTES CURVES/TABLES:

TABLE 2.3-A/2.3-S2 DRYWELL RADIATION LEVELS WITH RCS BARRIER INTACT INSIDE PRIMARY CONTAINMENT UNIT 1 UNIT 2 UNIT 3 RAD MONITOR R/HR RAD MONITOR R/HR RAD MONITOR R/HR 1-RE-90-272A 196 2-RE-90-272A 642 3-RE-90-272A 196 1-RE-90-273A 297 2-RE-90-273A 297 3-RE-90-273A 297 TABLE 2.3-S1/2.3-G2 DRYWELL RADIATION LEVELS WITH RCS BARRIER NOT INTACT INSIDE PRIMARY CONTAINMENT UNIT 1 UNIT 2 UNIT 3 RAD MONITOR R/HR RAD MONITOR R/HR RAD MONITOR R/HR 1-RE-90-272A 2981 2-RE-90-272A 2263 3-RE-90-272A 2981 1-RE-90-273A 2960 2-RE-90-273A 2960 3-RE-90-273A 2960 TABLE 2.3-G1 DRYWELL RADIATION LEVELS WITH RCS BARRIER NOT INTACT INSIDE PRIMARY CONTAINMENT UNIT 1 UNIT 2 UNIT 3 RAD MONITOR R/HR RAD MONITOR R/HR RAD MONITOR R/HR 1-RE-90-272A 90091 2-RE-90-272A 68405 3-RE-90-272A 90091 1-RE-90-273A 89450 2-RE-90-273A 89450 3-RE-90-273A 89450 TABLE 2.3/2.5-U INDICATIONS OF LOSS OF PRIMARY CONTAINMENT Unexplained Loss Of Containment Pressure Exceeding 1, 2, or 3-SI-4.7.A.2.a Limits Inability To Isolate Any Line Exiting Containment When Isolation Is Required Venting Irrespective Of Offsite Release Rates Per EOIs/SAMGs

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 29 OF 206 DRYWELL RADIATION Description Description 2.3-A TABLE US 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.

OPERATING CONDITION:

Mode 1 or 2 or 3 2.3-S1 TABLE US 2.3-S2 TABLE US Drywell radiation levels at or above the values Drywell radiation levels at or above the values listed in Table 2.3-S1/2.3-G2 with the RCS barrier listed in Table 2.3-A/2.3-S2, with the RCS barrier NOT intact inside Primary Containment. intact inside Primary Containment, AND 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 maintained.

OPERATING CONDITION: OPERATING CONDITION:

Mode 1 or 2 or 3 Mode 1 or 2 or 3 2.3-G1 TABLE US 2.3-G2 TABLE US Drywell radiation levels at or above the values Drywell radiation levels at or above the values listed in Table 2.3-G1 with the RCS barrier NOT listed in Table 2.3-S1/2.3-G2 with the RCS barrier intact inside Primary Containment. NOT intact inside Primary Containment, AND 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 maintained.

OPERATING CONDITION: OPERATING CONDITION:

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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 30 OF 206 NOTES CURVES/TABLES:

TABLE 2.3/2.5-U INDICATIONS OF LOSS OF PRIMARY CONTAINMENT Unexplained Loss Of Containment Pressure Exceeding 1, 2, or 3-SI-4.7.A.2.a Limits Inability To Isolate Any Line Exiting Containment When Isolation Is Required Venting Irrespective Of Offsite Release Rates Per EOIs/SAMGs

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 31 OF 206 DRYWELL INTERNAL LOSS OF PRIMARY LEAKAGE CONTAINMENT Description Description 2.4-U 2.5-U TABLE Drywell unidentified leakage exceeds 10 gpm Inability to maintain Primary Containment pressure boundary. Refer to Table 2.3/2.5-U.

OR Drywell identified leakage exceeds 40 gpm.

OPERATING CONDITION: OPERATING CONDITION:

Mode 1 or 2 or 3 Mode 1 or 2 or 3 2.4-A Drywell unidentified leakage exceeds 50 gpm.

OPERATING CONDITION:

Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 32 OF 206 THIS PAGE INTENTIONALLY BLANK

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 33 OF 206 SECONDARY CONTAINMENT 3.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 34 OF 206 NOTES CURVES/TABLES:

TABLE 3.1 MAXIMUM SAFE OPERATING AREA TEMPERATURE LIMITS APPLICABLE PANEL 9-21 MAX SAFE OPERATING AREA TEMPERATURE ELEMENTS VALUE 0F (UNLESS OTHERWISE NOTED) UNIT 1 UNIT 2 UNIT 3 RHR A/C Pump Room 74-95A 215 150 155 RHR B/D Pump Room 74-95B 150 210 215 HPCI Turbine Area 73-55A 275 270 270 CS A/C Pump and RCIC Turbine Area 71-41A 190 190 190 RCIC Steam Supply Area 71-41B, 41C, 41D 195 200 250 HPCI Steam Supply Area 73-55B, 55C, 55D 245 240 240 RHR A/C Pump Supply Area 74-95H 245 240 240 RHR B/D Pump Supply Area 74-95G 190 240 240 Main Steam Line Leak Detection High (XA-55-3D-24) Panel 9-3 TIS-1-60A 315 315 315 RHR Valve Room 74-95E 175 170 175 RWCU Isol Logic Channel A/B Temp (XA-55-5B-32/33) Panel 9-5 175 170 175 High 69-835A, B, C, D Aux Inst Room RWCU Outbd Isol Vlv Area 69-29F 220 220 220 RWCU Hx Area 69-29G 220 220 220 RWCU Hx Exh Duct 69-29H 220 220 220 RWCU Recirc Pump A Area 69-29D 215 215 215 RWCU Recirc Pump B Area 69-29E 215 215 215 RHR A/C Hx Room 74-95C 210 195 200 RHR B/D Hx Room 74-95D 210 195 200 FPC Hx Area 74-95F 160 155 155 TABLE 3.1-G/3.2-G INDICATIONS OF POTENTIAL OR SIGNIFICANT FUEL CLADDING FAILURE WITH RCS BARRIER INTACT INSIDE PRIMARY CONTAINMENT UNIT 1 DRYWELL RADIATION UNIT 2 DRYWELL RADIATION UNIT 3 DRYWELL RADIATION 1-RE-90-272A > 196 R/HR 2-RE-90-272A > 642 R/HR 3-RE-90-272A > 196 R/HR 1-RE-90-273A > 297 R/HR 2-RE-90-273A > 297 R/HR 3-RE-90-273A > 297 R/HR Reactor Coolant Activity Reactor Coolant Activity Reactor Coolant Activity

> 300 Ci/gm Dose Equivalent > 300 Ci/gm Dose Equivalent > 300 Ci/gm Dose Equivalent Iodine 131 Iodine 131 Iodine 131

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 35 OF 206 SECONDARY CONTAINMENT TEMPERATURE Description 3.1-S TABLE US An unisolable Primary System leak is discharging into Secondary Containment AND Any area temperature exceeds the Maximum Safe Operating Temperature limit listed in Table 3.1.

OPERATING CONDITION:

Mode 1 or 2 or 3 3.1-G TABLE US An unisolable Primary System leak is discharging into Secondary Containment AND Any area temperature exceeds the Maximum Safe Operating Temperature limit listed in Table 3.1 AND Any indication of potential or significant fuel cladding failure exists. Refer to Table 3.1-G/3.2-G with RCS Barrier intact inside Primary Containment.

OPERATING CONDITION Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 36 OF 206 NOTES CURVES/TABLES:

TABLE 3.2 MAXIMUM SAFE OPERATING AREA RADIATION LIMITS AREA RAD MONITOR MAX SAFE VALUE MR/HR UNIT 1 UNIT 2 UNIT 3 RHR West Room 90-25A 1000 1000 1000 RHR East Room 90-28A 1000 1000 1000 HPCI Room 90-24A 1000 1000 1000 CS/RCIC Room 90-26A 1000 1000 1000 Core Spray Room 90-27A 1000 1000 1000 Suppr Pool Area 90-29A 1000 1000 1000 CRD-HCU West Area 90-20A 1000 1000 1000 CRD-HCU East Area 90-21A 1000 1000 1000 TIP Drive Area 90-23A 1000 1000 1000 North RWCU System Area 90-13A 1000 1000 1000 South RWCU System Area 90-14A 1000 1000 1000 RWCU System Area 90-9A 1000 1000 1000 MG Set Area 90-4A 1000 1000 1000 Fuel Pool Area 90-1A 1000 1000 1000 Service Flr Area 90-2A 1000 1000 1000 New Fuel Storage 90-3A 1000 N/A N/A TABLE 3.1-G/3.2-G INDICATIONS OF POTENTIAL OR SIGNIFICANT FUEL CLADDING FAILURE WITH RCS BARRIER INTACT INSIDE PRIMARY CONTAINMENT UNIT 1 DRYWELL RADIATION UNIT 2 DRYWELL RADIATION UNIT 3 DRYWELL RADIATION 1-RE-90-272A > 196 R/HR 2-RE-90-272A > 642 R/HR 3-RE-90-272A > 196 R/HR 1-RE-90-273A > 297 R/HR 2-RE-90-273A > 297 R/HR 3-RE-90-273A > 297 R/HR Reactor Coolant Activity Reactor Coolant Activity Reactor Coolant Activity

> 300 Ci/gm Dose Equivalent > 300 Ci/gm Dose Equivalent > 300 Ci/gm Dose Equivalent Iodine 131 Iodine 131 Iodine 131

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 37 OF 206 SECONDARY CONTAINMENT RADIATION Description 3.2-A Any of the following high radiation alarms on Panel 9-3:

1, 2, or 3-RA-90-1A, 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 AND Confirmation by Refuel Floor personnel that irradiated fuel damage may have occurred.

OPERATING CONDITION:

ALL 3.2-S TABLE US An unisolable Primary System leak is discharging into Secondary Containment AND Any area radiation level at or above the Maximum Safe Operating Area radiation limit listed in Table 3.2.

OPERATING CONDITION:

Mode 1 or 2 or 3 3.2-G TABLE US An unisolable Primary System leak is discharging into Secondary Containment AND Any area radiation level at or above the Maximum Safe Operating Area radiation limit listed in Table 3.2.

AND Any indication of potential or significant fuel cladding failure exists. Refer to Table 3.1-G/3.2-G with RCS Barrier intact inside Primary Containment.

OPERATING CONDITION Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 38 OF 206 THIS PAGE INTENTIONALLY BLANK

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 39 OF 206 RADIOACTIVITY RELEASES 4.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 40 OF 206 NOTES 4.1-U 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-U

2. 0-SI 4.8.B.1.a.1 release fraction exceeds 2.0 If neither assessment can be conducted 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 either of the following methods:

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

2. Projected 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. Projected 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 7

Gaseous Release Rate Stack Noble Gas (WRGERMS) 2.88 X 10 Ci/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 MREM/HR Gamma 1 Hour Table 4.1-A RELEASE LIMITS FOR ALERT TYPE MONITORING METHOD LIMIT DURATION 9

Gaseous Release Rate Stack Noble Gas (WRGERMS) 2.88 X 10 Ci/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 RELEASE LIMITS FOR SITE AREA EMERGENCY TYPE MONITORING METHOD LIMIT DURATION 9

Gaseous Release Rate Stack Noble Gas (WRGERMS) 5.9 X 10 Ci/sec 15 Minutes Site Boundary Radiation Reading Field Assessment Team 100 MREM/HR Gamma 1 Hour

-7 Site Boundary Iodine-131 Field Assessment Team 3.9 X 10 CI /cm 3 1 Hour Table 4.1-G RELEASE LIMITS FOR GENERAL EMERGENCY TYPE MONITORING METHOD LIMIT DURATION Gaseous Release Rate Stack Noble Gas (WRGERMS) 5.9 X 10 10 µCi/sec 15 Minutes Site Boundary Radiation Reading Field Assessment Team 1000 MREM/HR Gamma 1 Hour

-6 3 Site Boundary Iodine-131 Field Assessment Team 3.9 X 10 µCI / cm 1 Hour

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 41 OF 206 GASEOUS EFFLUENT Description 4.1-U NOTE TABLE Gaseous release exceeds ANY limit and duration in Table 4.1-U.

OPERATING CONDITION:

ALL 4.1-A NOTE TABLE Gaseous release exceeds ANY limit and duration in Table 4.1-A.

OPERATING CONDITION:

ALL 4.1-S NOTE TABLE 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 mrem TEDE or 500 mrem thyroid CDE.

OPERATING CONDITION:

ALL 4.1-G NOTE TABLE 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.

OPERATING CONDITION ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 42 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 43 OF 206 MAIN STEAM LINE LIQUID EFFLUENT BREAK Description Description 4.2-U 4.3-U Liquid release rate exceeds 20 times ECL as Main Steam Line break outside determined by chemistry sample Primary Containment with isolation.

AND Release duration exceeds or will exceed 60 minutes.

OPERATING CONDITION: OPERATING CONDITION:

Mode 1 or 2 or 3 ALL 4.3-A Liquid release rate exceeds 2000 times ECL as determined by chemistry sample AND Release duration exceeds or will exceed 15 minutes.

OPERATING CONDITION:

ALL 4.2-S Unisolable Main Steam Line break outside Primary Containment.

OPERATING CONDITION:

Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 44 OF 206 THIS PAGE INTENTIONALLY BLANK

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 45 OF 206 LOSS OF POWER 5.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 46 OF 206 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-A1 or 5.1-A2.

5.1-A1 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 5.1-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.

CURVES/TABLES:

Table 5.1 UNIT 4KV SHUTDOWN BOARD APPLICABILITY APPLICABLE UNIT APPLICABLE 4KV SHUTDOWN BOARDS UNIT 1 A, B, C, and D UNIT 2 A, B, C, and D UNIT 3 3A, 3B, 3C, and 3D

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 47 OF 206 LOSS OF AC POWER Description Description 5.1-U NOTE TABLE US Loss of normal and alternate supply voltage to ALL unit specific 4KV shutdown boards from Table 5.1 for greater than 15 minutes AND At least two Diesel Generators supplying power to unit specific 4KV shutdown boards listing in Table 5.1.

OPERATING CONDITION:

ALL 5.1-A1 NOTE TABLE US 5.1-A2 NOTE TABLE US 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 AND Only ONE source of power available to the remaining board.

OPERATING CONDITION: OPERATING CONDITION:

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

OPERATING CONDITION:

Mode 1 or 2 or 3 5.1-G NOTE TABLE US Loss of voltage to ALL unit specific 4KV shutdown boards from Table 5.1 AND Either of the following conditions exists;

Restoration of at least one 4KV shutdown board is NOT likely within three hours.

Adequate core cooling can NOT be assured.

OPERATING CONDITION:

Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 48 OF 206 NOTES 5.2 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.

CURVES/TABLES:

Table 5.2-U UNIT 4KV SHUTDOWN BOARD APPLICABILITY APPLICABLE UNIT APPLICABLE 4KV SHUTDOWN BOARDS UNIT 1 A, B, C, AND D UNIT 2 A, B, C, AND D 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 1 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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 49 OF 206 LOSS OF 250V DC POWER Description Description 5.2-U NOTE TABLE US Unplanned loss of 250V DC control power to ALL unit specific 4KV shutdown boards from Table 5.2-U for greater than 15 minutes OR Unplanned loss of 250V DC control power to unit specific 480V shutdown boards A and B for greater than 15 minutes.

OPERATING CONDITION:

Modes 4 or 5 5.2-S NOTE TABLE US 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.

OPERATING CONDITION:

Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 50 OF 206 THIS PAGE INTENTIONALLY BLANK

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 51 OF 206 HAZARDS 6.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 52 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 53 OF 206 RADIOLOGICAL Description Description 6.1-U Valid, unexpected increase of ANY in-plant ARM reading to 1000 mrem/hr (except TIP room).

OPERATING CONDITION:

ALL 6.1-A1 6.1-A2 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.

AND Personnel required in the affected area(s).

OPERATING CONDITION: OPERATING CONDITION:

ALL ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 54 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 55 OF 206 CONTROL ROOM TURBINE FAILURE EVACUATION Description Description 6.3-U Turbine failure resulting in casing penetration OR Significant damage to turbine or generator seals during operation.

OPERATING CONDITION:

Mode 1, or 2 6.2-A 6.3-A Control Room Abandonment from entry into Turbine failure resulting in visible structural 1, 2, or 3-AOI-100-2 or 0-SSI-16 for ANY Unit damage to or visible penetration of ANY of the Control Room. following structures from missles:

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

OPERATING CONDITION: Mode 1 or 2 ALL 6.2-S Control Room Abandonment from entry into 1, 2, or 3-AOI-100-2 or 0-SSI-16 for ANY Unit Control Room AND Control of reactor water level, reactor pressure, and reactor power (for Modes 1, or 2, or 3) or decay heat removal (for Modes 4, or 5) per 1, 2, or 3-AOI-100-2 or 0-SSI-16 as applicable, can NOT be established within 20 minutes after evacuation is initiated.

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 56 OF 206 NOTES CURVES/TABLES:

Table 6.4-U1 APPLICABLE PLANT AREA Reactor Building Refuel Floor 4KV Shutdown Board Rooms 4KV Shutdown Battery Board Rooms 480V Shutdown Board Rooms RMOV Board 3A and 3B Rooms 4KV Bus Tie Board Room Control Bay Elevation 593, 606, And 617 Diesel Generator Buildings (All Elevations)

Turbine Building (All Elevations)

Intake Pumping Station (All Elevations)

Radwaste Building (All Elevations)

Cable Tunnel (Intake To Turbine Building)

Standby Gas Treatment Building Table 6.4-A APPLICABLE PLANT AREA Reactor Building Refuel Floor 4KV Shutdown Board Rooms 4KV Shutdown Battery Board Rooms 480V Shutdown Board Rooms RMOV Board 3A and 3B Rooms 4KV Bus Tie Board Room Control Bay Elevation 593, 606, And 617 Diesel Generator Buildings (All Elevations)

Intake Pumping Station (All Elevations)

Cable Tunnel (Intake To Turbine Building)

Standby Gas Treatment Building

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 57 OF 206 FIRE / EXPLOSION Description Description 6.4-U1 TABLE 6.4-U2 Confirmed fire in ANY plant area listed in Unanticipated explosion within the protected area Table 6.4-U1 resulting in visible damage to ANY permanent AND structure or equipment.

NOT extinguished within 15 minutes.

OPERATING CONDITION: OPERATING CONDITION:

ALL ALL 6.4-A TABLE 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.

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 58 OF 206 NOTES CURVES/TABLES:

Table 6.5/6.6 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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 59 OF 206 TOXIC GASES Description 6.5-U TABLE EITHER of the following conditions exists:

Normal operations impeded due to access restrictions caused by toxic gas concentrations within 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 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:

ALL 6.5-A TABLE 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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 60 OF 206 NOTES CURVES/TABLES:

Table 6.5/6.6 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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 61 OF 206 FLAMMABLE GASES Description 6.6-U TABLE EITHER of the following conditions exists:

Release of flammable gas within the site boundary 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 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).

OPERATING CONDITION:

ALL 6.6-A TABLE 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 instrumentation.

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 62 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 63 OF 206 SECURITY Description Description 6.7-U

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

OR

2. A credible Browns Ferry threat notification OR

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

OPERATING CONDITION:

ALL 6.7-A

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

OR

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

OPERATING CONDITION:

ALL 6.7-S A HOSTILE ACTION is occurring or has occurred within the PROTECTED AREA as reported by the Security Shift Supervisor OPERATING CONDITION:

ALL 6.7-G

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

OR

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

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 64 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 65 OF 206 VEHICLE CRASH Description 6.8-U Vehicle crash (for example; aircraft or barge) into plant structures or systems within the protected area boundary.

OPERATING CONDITION:

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

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 66 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 67 OF 206 SPENT FUEL STORAGE Description 6.9-U Damage to a loaded cask CONFINEMENT BOUNDARY from ANY of the following:

Natural phenomena (e.g., seismic event, tornado, flood, lightning, snow/ice accumulation, etc.)

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

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

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 68 OF 206 THIS PAGE INTENTIONALLY BLANK

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 69 OF 206 NATURAL EVENTS 7.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 70 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 71 OF 206 EARTHQUAKE Description 7.1-U Valid annunciation in Unit 1 Control Room, Panel 1-XA-55-22C, Window 5, START OF STRONG MOTION ACCELEROGRAPH AND Assessment by Unit One and Two Control Room personnel that an earthquake has occurred.

OPERATING CONDITION:

ALL 7.1-A Valid annunciation in the Unit 1 Control Room, Panel 1-XA-55-22C, Window 6, 1

/2 SSE RESPONSE SPECTRUM EXCEEDED AND Assessment by Unit One and Two Control Room personnel that an earthquake has occurred.

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 72 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 73 OF 206 TORNADO / HIGH WINDS Description 7.2-U Report by plant personnel of tornado striking within the protected area boundary.

OPERATING CONDITION:

ALL 7.2-A Tornado striking plant vital area OR Onsite wind speed above 90 MPH as indicated using the meteorological data screen of the Integrated Computer System (ICS).

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 74 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 75 OF 206 FLOOD Description 7.3-U Wheeler Lake level exceeds or is predicted to exceed elevation 565 feet.

AND Water entering permanent plant structures due to flooding.

OPERATING CONDITION:

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

AND EITHER of the following conditions exists:

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

Equipment required for safe shutdown is affected.

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 76 OF 206 THIS PAGE INTENTIONALLY BLANK

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 77 OF 206 EMERGENCY DIRECTOR JUDGMENT 8.0

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 78 OF 206 NOTES CURVES/TABLES:

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 79 OF 206 TECHNICAL SPECIFICATIONS Description 8.1-U Inability to reach required shutdown condition (Mode 3 or Mode 4) within Technical Specification Limiting Conditions for Operation (LCO) limits.

OPERATING CONDITION:

Mode 1 or 2 or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 80 OF 206 NOTES CURVES/TABLES:

Table 8.2-U LOSS OF COMMUNICATIONS Onsite Communications Offsite Communication Plant Phone System Node 1 Bell Lines Two-Way Radio System Digital Microwave (NSS 1, NSS 2, OPS F2, and OPS F4)

Sound Power Phones NRC Emergency Telecommunication System Nextel Communication System Cellular Phones (If Available)

Health Physics Radio Network

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 81 OF 206 LOSS OF COMMUNICATION Description 8.2-U TABLE Unplanned loss of onsite communication listed in Table 8.2-U that defeats the Plant Operations Staffs ability to perform routine operations OR Unplanned loss of ALL off-site communication listed in Table 8.2-U.

OPERATING CONDITOIN:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 82 OF 206 NOTES 8.3 Significant Transient is an unplanned event involving one or more of the following:

(1) 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.

CURVES/TABLES:

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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 83 OF 206 LOSS OF ASSESSMENT CAPABILITY Description 8.3-U 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 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:

MODE 1, or 2, or 3 8.3-A NOTE 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:

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

A significant transient is in progress.

OPERATING CONDITION:

MODE 1, or 2, or 3 8.3-S NOTE TABLE Loss of most or all annunciators associated with safety systems AND Compensatory non-alarming safety system indications are NOT available (SPDS, ICS)

AND Indications needed to monitor safety functions are NOT available (Refer to Table 8.3-S)

AND A significant transient is in progress.

OPERATING CONDITION:

MODE 1, or 2, or 3

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 84 OF 206 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.

CURVES/TABLES:

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

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 85 OF 206 OTHER Description 8.4-U NOTE TABLE 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.

OR Any loss or any potential loss of containment.

OPERATING CONDITION:

ALL 8.4-A NOTE 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-S NOTE 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 boundary.

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

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

OPERATING CONDITION:

ALL 8.4-G NOTE Events are in process or have occurred which involve actual or imminent substantial core degradation or melting with potential for loss of containment integrity or HOSTILE ACTION that results in an actual loss of physical control of the facility. Releases can be reasonably expected to exceed EPA Protective Action Guideline exposure levels offsite for more than the immediate site area.

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

OPERATING CONDITION:

ALL

EPIP-1 BFN EMERGENCY CLASSIFICATION PROCEDURE Rev. 0051 Unit 0 EVENT CLASSIFICATION MATRIX PAGE 86 OF 206 THIS PAGE INTENTIONALLY BLANK

NPG-SPP-03.5 Regulatory Reporting Requirements Rev. 0011 Page 1 of 97 Quality Related Yes ; No NPG Standard Programs and Processes Validation Date 11-21-2014 Review Frequency 3 years Validated By John Laffrey Effective Date 01-30-2015 Level of Use: Information Use Responsible Peer Team/Working Group: Licensing John Laffrey for P.R. Wilson 1-16-2015 Approved by:

Corporate Functional Area Manager Date

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 7 of 97 Table of Contents 1.0 PURPOSE ................................................................................................................................. 9 2.0 SCOPE ...................................................................................................................................... 9 3.0 PROCESS ................................................................................................................................. 9 3.1 Roles and Responsibilities ......................................................................................................... 9 3.1.1 Corporate Licensing ................................................................................................... 9 3.1.2 Site Licensing ............................................................................................................. 9 3.1.3 Site Design Engineering ............................................................................................. 9 3.1.4 Site Operations ........................................................................................................... 9 3.2 Instructions............................................................................................................................... 10 3.2.1 Periodic Reports ....................................................................................................... 10 3.2.2 Event or Condition Reporting ................................................................................... 10 3.2.3 Processing Reports .................................................................................................. 13 4.0 RECORDS ............................................................................................................................... 14 4.1 QA Records ............................................................................................................................. 14 4.2 Non-QA Records...................................................................................................................... 14 5.0 DEFINITIONS .......................................................................................................................... 14

6.0 REFERENCES

........................................................................................................................ 19 6.1 Source Documents .................................................................................................................. 19 6.1.1 Business Requirements ............................................................................................ 19 6.1.2 Requirements Documents ........................................................................................ 19 6.2 Developmental References...................................................................................................... 20 : Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants ......................................................................................................... 21 : Reporting of Events or Conditions Affecting Activities Involving Byproduct, Source or Special Nuclear Material Licenses ................................................................................................................ 37 : Reporting of Events or Conditions Affecting Independent Spent Fuel Storage Installation (ISFSI) .............................................................. 43 : Other Regulatory Reporting ................................................................................ 50 : Part 21 Screening, Evaluation and NRC Notifications ...................................... 55 : Reporting of Decommissioning Funding ........................................................... 73

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 8 of 97 Table of Contents (continued) : Communication with the NRC Following A Significant Operational Event................................................................................................. 78 : Internal Notification of Events Requiring Serious Accident Investigations ....................................................................................................... 80 : Registration Requirements for Spent Fuel Storage Cask Placed into Service .............................................................................................. 83 0: Reporting Fitness for Duty Events Under 10 CFR 26 ....................................... 84 1: Receipt of NRC Emergency Notification System Blast Dial ............................. 93 2: NRC Form 361 Event Notification Worksheet Guidance .................................. 94 Source Notes ........................................................................................................ 97

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 21 of 97 Attachment 1 (Page 1 of 16)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 1.0 PURPOSE This Attachment 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 §50.73 to promptly report various types of conditions or events and provide written follow-up reports, as appropriate. This Attachment provides reporting guidance applicable to licensed power reactors.

NOTES

1) Attachment 2, 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. Depending on the location of the licensed activity, either Site or Corporate 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 Dosimetry Administrative Processes.

2) Attachment 3 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 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 §72.74. Operations is responsible for making the immediate, 4-hour, and 24-hour notifications to NRC in accordance with §72.75. Site 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. Site Licensing is responsible for developing (with 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. 0011 Processes Page 22 of 97 Attachment 1 (Page 2 of 16)

Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.0 REQUIREMENTS NOTES

1) Internal management notification requirements for reportable plant events and conditions are found in Procedure NPG-SPP-01.12, TVA Nuclear Event Response Process. The Operations Shift Manager is responsible for notifying Site Operations Management and the Site Duty Plant Manager. The Site Duty Plant Manager is responsible for making the remaining internal management notifications to the NDO who communicates to the fleet executives, in accordance with NPG-SPP-01.6, Nuclear Duty Officer. Internal management notification was previously described in Appendix D of NPG-SPP-03.5. Internal management notifications of emergent issues is described in Procedure NPG-SPP-01.12, TVA Nuclear Event Response Process.

2) NRC NUREG-1022, Revision 3 and subsequent revisions should be used, in its entirety, 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 TVA NPG Nuclear Licensing Webpage.

3) In addition to reviewing the clarifying discussion and examples associated with specific reporting criteria [e.g., discussion of utilization of engineering judgment when evaluating Unanalyzed Conditions in NUREG -1022, Section 3.2.4(B)], NUREG-1022, Section 2, Reporting Areas Warranting Special Mention, should also be reviewed. [R.1]

3.1 Immediate Notification - NRC TVA is required by §50.72 and §73.71 to notify NRC immediately if certain types of events occur. This Attachment contains the types of events and the allotted time in which NRC must be notified. (Refer to NRC Form 361 at www.nrc.gov). Operations is responsible for making the reportability determinations for §50.72 and §50.73 reports. Site Nuclear Security and Corporate Nuclear Security are responsible for making the reportability determinations for 73.71 reports. For any §50.72, §50.73, or §73.71 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 §50.72. The Site Security Manager will request the Plant Shift Manager to call the NRC Operations Center, when appropriate.

Notification is via the Emergency Notification System. If the Emergency Notification System is not operative, use a telephone, telegraph, mailgram, or facsimile.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 23 of 97 Attachment 1 (Page 3 of 16)

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

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) by performing a Form 361 search. Attachment 12 provides guidance for completing NRC Form 361.

A. The Immediate Notification Criteria of §50.72 is divided into 1-hour, 4-hour, and 8- 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. 10 CFR 50.36(c)(1)(i)(A), (Technical Specifications) - Safety Limits as defined by the Technical Specifications which have been exceeded (violated)

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

NOTE If it is discovered that a condition existed which met the Emergency Plan criteria 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 §50.54(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 information.

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

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 24 of 97 Attachment 1 (Page 4 of 16)

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

(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 in accordance with 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.

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 notification:

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

2. §50.72(b)(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 actuation results from and is part of a pre-planned sequence during testing or reactor operation.

3. §50.72(b)(2)(iv)(B) - 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.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 25 of 97 Attachment 1 (Page 5 of 16)

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

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 with §50.72(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 8-hour notification:

NOTE With the exception of Events or Conditions that Could Have Prevented Fulfillment of a Safety Function," ENS notifications are required for any event that occurred within three years of discovery, even if the event was not ongoing at the time of discovery.

1. §50.72(b)(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.

2. §50.72(b)(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 below], 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:

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 26 of 97 Attachment 1 (Page 6 of 16)

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

NOTE Actuation of the RPS when the reactor is critical is also reportable under §50.72(b)(2)(iv)(B) 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 (BWRs) including: core spray systems; high-pressure coolant injection system; low pressure injection function of the residual heat removal system.

(5) BWR reactor core isolation cooling system; isolation condenser system; and feedwater coolant injection 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).

NOTE For systems within scope, the inadvertent TS inoperability of a system in a required mode of applicability constitutes an event or condition for which there is no longer reasonable expectation that equipment can fulfill its safety function. Therefore, such events or conditions are reportable as an "Event or Condition that Could Have Prevented Fulfillment of a Safety Function."

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 27 of 97 Attachment 1 (Page 7 of 16)

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

4. §50.72(b)(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:

(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.

NOTE According to §50.72 (b)(3)(vi) events covered by §50.72(b)(3)(v) 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 this paragraph if redundant equipment in the same system was operable and available to perform the required safety function.

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

6. §50.72(b)(3)(xiii) - 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 [§50.72], 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. 0011 Processes Page 28 of 97 Attachment 1 (Page 8 of 16)

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

(1) Immediately report:

(i) The results of ensuing evaluations or assessments of plant conditions, (ii) The effectiveness of response or protective measures taken, and (iii) Information related to plant behavior that is not understood.

(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 accordance with the license condition.

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. Depending on where the information originates, either Corporate or Site Licensing is responsible for determining 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 Attachment 1, Section 3.5]). 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.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 29 of 97 Attachment 1 (Page 9 of 16)

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

A. Telephone Report Required Content:

If the telephone notification option is selected (NUREG 1022, Revision 3, Section 3.2.6., 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 information:

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

b. Whether each train actuation was complete or partial.

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

NOTE Licensing will ensure that the information that is provided to NRC during the Sixty-Day telephone report is verified in accordance with NPG-SPP-03.10.

B. Telephone Report Development and Review Licensing will:

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

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. For events in which safety limits or limiting safety system settings are exceeded, reports are made as required by 10 CFR 50.72 and 50.73.

B. 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.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 30 of 97 Attachment 1 (Page 10 of 16)

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

C. Reporting Radiation Injuries

1. §140.6(a) requires, as promptly as practicable, submittal of a written notice [e.g.,

report] 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. Licensee Event Reports A written report shall be prepared in accordance with §50.73(a)(1) 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 3, 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 Attachment 1, Section 3.4]) required by §50.73.

NOTE Unless otherwise 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(a)(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-03.5 Programs and Rev. 0011 Processes Page 31 of 97 Attachment 1 (Page 11 of 16)

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 surveillance 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 discovery of the event.

3. §50.73(a)(2)(i)(C) - Any deviation from the plants Technical Specifications authorized pursuant to §50.54(x).

4. §50.73(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. §50.73(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 under Item 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.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 32 of 97 Attachment 1 (Page 12 of 16)

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

NOTE 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 submitting a written LER

(§50.73(a)). [Refer to , Attachment 1, Section 3.4]

8. §50.73(a)(2)(iv)(B) - 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, intermediate-head, and low-head injection systems and the low pressure injection function of residual (decay) heat removal systems.

d. ECCS for boiling water reactors (BWRs) 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; isolation condenser system; and feedwater coolant injection system.

f. 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 service water systems that do not normally run and that serve 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:

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

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 33 of 97 Attachment 1 (Page 13 of 16)

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 perform the required safety function

[§50.73(a)(2)(vi)].

10. §50.73(a)(2)(vii) - Any event where a single cause or condition caused at least one independent train or channel to become inoperable in multiple systems or two independent trains or channels to become inoperable in a single system designed to:

(A) Shut down the reactor and maintain it in a safe shutdown condition; (B) Remove residual heat; (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident.

11. §50.73(a)(2)(viii)(A) - 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. §50.73(a)(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 radionuclides except tritium and dissolved noble gases.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 34 of 97 Attachment 1 (Page 14 of 16)

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

13. §50.73(a)(2)(ix)(A) - Any event or condition that as a result of a single cause could have prevented the fulfillment of a safety function for two 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 residual 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 [§50.73(a)(2)(ix)(B)].

14. §50.73(a)(2)(x) - Any event 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 including fires, toxic gas releases, or radioactive releases.

15. 10 CFR 73, Appendix G, paragraph I - If a one hour notification is made in Attachment 1, section 3.1.B.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 Attachment 5 in this procedure.

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 35 of 97 Attachment 1 (Page 15 of 16)

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

17. SQN and WBN only (Non-radiological environmental reporting requirements to the NRC, as required from SQN and WBN Operating License (OL), Appendix B.)

a. WBN or SQN 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:

(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; (5) 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. SQN OL Appendix B compliance guidance is provided in the flowchart in NPG-SPP-05.5, Environmental Control, Appendix B.

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

NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0011 Processes Page 36 of 97 Attachment 1 (Page 16 of 16)

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

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

(1) Refer to NPG-SPP-05.5, Environmental Control, Section Compliance with the NRC Appendix B to the Facility Operating License, for additional guidance.

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

3.6 Retraction or Cancellation of Event Reports An ENS notification may be retracted via a follow-up telephone call. If an ENS notification is make and its later determined that the event or condition was not reportable, Plant Operations should call the NRC Operations Center on the ENS telephone to retract the notification and explain the rational for that decision. There is no set time limit for ENS telephone retractions. However, because most retractions occur following completion of engineering and/or management review, it is expected that retractions would occur shortly after such review.

Cancellation of LERs submitted should be made by letter. The letter should state that the LER is being cancelled (i.e., formally withdrawn). The bases for the cancellation should be explained so that the staff can review and understand the reasons supporting the determination.

Control Rod OPERABILITY 3.1.3 3.1 REACTIVITY CONTROL SYSTEMS 3.1.3 Control Rod OPERABILITY LCO 3.1.3 Each control rod shall be OPERABLE.

APPLICABILITY: MODES 1 and 2.

ACTIONS

NOTE-----------------------------------------------------

Separate Condition entry is allowed for each control rod.

CONDITION REQUIRED ACTION COMPLETION TIME A. One withdrawn control -----------------NOTE------------------

rod stuck. Rod worth minimizer (RWM) may be bypassed as allowed by LCO 3.3.2.1, "Control Rod Block Instrumentation," if required, to allow continued operation.

A.1 Verify stuck control rod Immediately separation criteria are met.

AND A.2 Disarm the associated 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months control rod drive (CRD).

AND (continued)

BFN-UNIT 1 3.1-7 Amendment No. 234

Control Rod OPERABILITY 3.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3 Perform SR 3.1.3.3 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from each withdrawn discovery of OPERABLE control rod. Condition A concurrent with THERMAL POWER greater than the low power setpoint (LPSP) of the RWM AND A.4 Perform SR 3.1.1.1. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months B. Two or more withdrawn B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months control rods stuck.

C. One or more control rods C.1 -------------NOTE------------

inoperable for reasons RWM may be bypassed other than Condition A or as allowed by B. LCO 3.3.2.1, if required, to allow insertion of inoperable control rod and continued operation.

Fully insert inoperable 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months control rod.

AND C.2 Disarm the associated 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months CRD.

(continued)

BFN-UNIT 1 3.1-8 Amendment No. 234, 274 June 26, 2009

Control Rod OPERABILITY 3.1.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. -------------NOTE------------ D.1 Restore compliance with 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Not applicable when BPWS.

THERMAL POWER

> 10% RTP. OR D.2 Restore control rod to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Two or more inoperable OPERABLE status.

control rods not in compliance with banked position withdrawal sequence (BPWS) and not separated by two or more OPERABLE control rods.

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, C, or D not met.

OR Nine or more control rods inoperable.

BFN-UNIT 1 3.1-9 Amendment No. 234

Control Rod OPERABILITY 3.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.3.1 Determine the position of each control rod. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.1.3.2 (Deleted).

SR 3.1.3.3 --------------------------NOTE-------------------------

Not required to be performed until 31 days after the control rod is withdrawn and THERMAL POWER is greater than the LPSP of the RWM.

Insert each withdrawn control rod at least one 31 days notch.

SR 3.1.3.4 Verify each control rod scram time from fully In accordance withdrawn to notch position 06 is d 7 with SR 3.1.4.1, seconds. SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4 (continued)

BFN-UNIT 1 3.1-10 Amendment No. 234, 274 June 26, 2009

Control Rod OPERABILITY 3.1.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.3.5 Verify each control rod does not go to the Each time the withdrawn overtravel position. control rod is withdrawn to "full out" position AND Prior to declaring control rod OPERABLE after work on control rod or CRD System that could affect coupling BFN-UNIT 1 3.1-11 Amendment No. 234

Control Rod Scram Times 3.1.4 3.1 REACTIVITY CONTROL SYSTEMS 3.1.4 Control Rod Scram Times LCO 3.1.4 a. No more than 13 OPERABLE control rods shall be "slow," in accordance with Table 3.1.4-1; and

b. No more than 2 OPERABLE control rods that are "slow" shall occupy adjacent locations.

APPLICABILITY: MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of the LCO A.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months not met.

BFN-UNIT 1 3.1-12 Amendment No. 234

Control Rod Scram Times 3.1.4 SURVEILLANCE REQUIREMENTS

NOTE-----------------------------------------------------

During single control rod scram time Surveillances, the control rod drive (CRD) pumps shall be isolated from the associated scram accumulator.

SURVEILLANCE FREQUENCY SR 3.1.4.1 Verify each control rod scram time is within Prior to the limits of Table 3.1.4-1 with reactor steam exceeding dome pressure t 800 psig. 40% RTP after each reactor shutdown t 120 days SR 3.1.4.2 Verify, for a representative sample, each 120 days tested control rod scram time is within the cumulative limits of Table 3.1.4-1 with reactor steam operation in dome pressure t 800 psig. MODE 1 (continued)

BFN-UNIT 1 3.1-13 Amendment No. 234, 239 November 21, 2000

Control Rod Scram Times 3.1.4 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.4.3 Verify for each affected control rod scram Prior to declaring time is within the limits of Table 3.1.4-1 with control rod any reactor steam dome pressure. OPERABLE after work on control rod or CRD System that could affect scram time SR 3.1.4.4 Verify each affected control rod scram time is Prior to within the limits of Table 3.1.4-1 with reactor exceeding steam dome pressure t 800 psig. 40% RTP after fuel movement within the affected core cell AND Prior to exceeding 40% RTP after work on control rod or CRD System that could affect scram time BFN-UNIT 1 3.1-14 Amendment No. 234, 239 November 21, 2000

Control Rod Scram Times 3.1.4 Table 3.1.4-1 (page 1 of 1)

Control Rod Scram Times

NOTES----------------------------------------------------

1. OPERABLE control rods with scram times not within the limits of this Table are considered "slow."

2. Enter applicable Conditions and Required Actions of LCO 3.1.3, "Control Rod OPERABILITY," for control rods with scram times > 7 seconds to notch position 06.

These control rods are inoperable, in accordance with SR 3.1.3.4, and are not considered "slow."

SCRAM TIMES(a)(b)

(seconds)

NOTCH POSITION REACTOR STEAM DOME PRESSURE t 800 psig 46 0.45 36 1.08 26 1.84 06 3.36 (a) Maximum scram time from fully withdrawn position, based on de-energization of scram pilot valve solenoids at time zero.

(b) Scram times as a function of reactor steam dome pressure, when < 800 psig are within established limits.

BFN-UNIT 1 3.1-15 Amendment No. 234

Control Rod Scram Accumulators 3.1.5 3.1 REACTIVITY CONTROL SYSTEMS 3.1.5 Control Rod Scram Accumulators LCO 3.1.5 Each control rod scram accumulator shall be OPERABLE.

APPLICABILITY: MODES 1 and 2.

ACTIONS

NOTE-----------------------------------------------------

Separate Condition entry is allowed for each control rod scram accumulator.

CONDITION REQUIRED ACTION COMPLETION TIME A. One control rod scram A.1 --------------NOTE------------

accumulator inoperable Only applicable if the with reactor steam dome associated control rod pressure t 900 psig. scram time was within the limits of Table 3.1.4-1 during the last scram time Surveillance.

Declare the associated 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months control rod scram time "slow."

OR A.2 Declare the associated 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months control rod inoperable.

(continued)

BFN-UNIT 1 3.1-16 Amendment No. 234

Control Rod Scram Accumulators 3.1.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Two or more control rod B.1 Restore charging water 20 minutes from scram accumulators header pressure to t 940 discovery of inoperable with reactor psig. Condition B steam dome pressure concurrent with t 900 psig. charging water header pressure

< 940 psig AND B.2.1 --------------NOTE------------

Only applicable if the associated control rod scram time was within the limits of Table 3.1.4-1 during the last scram time Surveillance.

Declare the associated 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months control rod scram time "slow."

OR B.2.2 Declare the associated 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months control rod inoperable.

(continued)

BFN-UNIT 1 3.1-17 Amendment No. 234

Control Rod Scram Accumulators 3.1.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One or more control rod C.1 Verify all control rods Immediately upon scram accumulators associated with discovery of inoperable with reactor inoperable accumulators charging water steam dome pressure are fully inserted. header pressure

< 900 psig. < 940 psig AND C.2 Declare the associated 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months control rod inoperable.

D. Required Action and D.1 --------------NOTE------------

associated Completion Not applicable if all Time of Required Action inoperable control rod B.1 or C.1 not met. scram accumulators are associated with fully inserted control rods.

Place the reactor mode Immediately switch in the shutdown position.

BFN-UNIT 1 3.1-18 Amendment No. 234

Control Rod Scram Accumulators 3.1.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.5.1 Verify each control rod scram accumulator 7 days pressure is t 940 psig.

BFN-UNIT 1 3.1-19 Amendment No. 234

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 BFN-UNIT 2 3.1-23 Amendment No. 253, 290 September 27, 2004

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.7.1 Verify available volume of sodium pentaborate 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months solution (SPB) is t 4000 gallons.

SR 3.1.7.2 Verify continuity of explosive charge. 31 days SR 3.1.7.3 Verify the SPB concentration is t 8.0% by 31 days weight.

AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after water or boron is added to solution SR 3.1.7.4 Verify the SPB concentration is d 9.2% by 31 days weight.

AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after water or boron is added to solution OR (continued)

BFN-UNIT 2 3.1-24 Amendment No. 253, 290 September 27, 2004

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY Verify the concentration and temperature of Once within boron in solution are within the limits of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after Figure 3.1.7-1. discovery that SPB concentration is

> 9.2% by weight AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter SR 3.1.7.5 Verify the minimum quantity of Boron-10 in the 31 days SLC solution tank and available for injection is t 186 pounds.

SR 3.1.7.6 Verify the SLC conditions satisfy the following 31 days equation:

AND

( C )( Q )( E )

1 (13 wt. %)(86 gpm)(19.8 atom%) Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after water or boron is where, added to the solution C = sodium pentaborate solution concentration (weight percent)

Q = pump flow rate (gpm)

E = Boron-10 enrichment (atom percent Boron-10)

SR 3.1.7.7 Verify each pump develops a flow rate t 39 24 months gpm at a discharge pressure t 1325 psig.

(continued)

BFN-UNIT 2 3.1-25 Amendment No. 255, 290 September 27, 2004

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.7.8 Verify flow through one SLC subsystem from 24 months on a pump into reactor pressure vessel. STAGGERED TEST BASIS SR 3.1.7.9 Verify all piping between storage tank and 24 months pump suction is unblocked.

SR 3.1.7.10 Verify sodium pentaborate enrichment is within 24 months the limits established by SR 3.1.7.6 by calculating within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and verifying by AND analysis within 30 days.

After addition to SLC tank SR 3.1.7.11 Verify each SLC subsystem manual, power 31 days operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position, or can be aligned to the correct position.

BFN-UNIT 2 3.1-26 Amendment No. 255, 290 September 27, 2004

SLC System 3.1.7 Figure 3.1.7-1 Sodium Pentaborate Solution Temperature Versus Concentration Requirements BFN-UNIT 2 3.1-27 Amendment No. 253

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.

(continued)

BFN-UNIT 2 3.3-1 Amendment No. 258 March 05, 1999

RPS Instrumentation 3.3.1.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. -------------NOTE------------- B.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, or 2.f. OR B.2 Place one trip system in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months One or more Functions trip.

with one or more required channels inoperable in both trip systems.

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.

(continued)

BFN-UNIT 2 3.3-2 Amendment No. 258 March 05, 1999

RPS Instrumentation 3.3.1.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME 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.

I. As required by Required I.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 Table thermal hydraulic 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 2 3.3-3 Amendment No. 258, 273 July 26, 2001

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 t 25% RTP.

Verify the absolute difference between the 7 days average power range monitor (APRM) channels and the calculated power is d 2% RTP while operating at t 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 2 3.3-4 Amendment No. 253

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 MWD/T 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)

BFN-UNIT 2 3.3-5 Amendment No. 253

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 Valve - Closure and 24 months Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is t 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 t 25% and recirculation drive flow is 60% of rated recirculation drive flow.

BFN-UNIT 2 3.3-6 Amendment No. 258 March 05, 1999

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 d 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 d 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. Inop 2 3 G SR 3.3.1.1.3 NA SR 3.3.1.1.14 5(a) 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 3(b) G SR 3.3.1.1.1 d 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 d 0.66 W Thermal Power - High SR 3.3.1.1.2 + 66% RTP SR 3.3.1.1.7 and d 120%

SR 3.3.1.1.13 RTP(c)

SR 3.3.1.1.16

c. Neutron Flux - High 1 3(b) F SR 3.3.1.1.1 d 120% 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) [.66 W + 66% - .66 ' W] RTP when reset for single loop operation per LCO 3.4.1, Recirculation Loops Operating.

NOTE: This page is applicable after commencing Cycle 11 operation.

BFN-UNIT 2 3.3-7 Amendment No. 256 December 23, 1998

RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 2 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

2. Average Power Range Monitors (continued)

d. Inop 1,2 3(b) G SR 3.3.1.1.16 NA

e. 2-Out-Of-4 Voter 1,2 2 G SR 3.3.1.1.1 NA SR 3.3.1.1.14 SR 3.3.1.1.16

f. OPRM Upscale 1 3(b) I SR 3.3.1.1.1 NA(e)

SR 3.3.1.1.7 SR 3.3.1.1.13 SR 3.3.1.1.16 SR 3.3.1.1.17

3. Reactor Vessel Steam Dome 1,2 2 G SR 3.3.1.1.1 d 1090 psig Pressure - High(d) SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.14

4. Reactor Vessel Water Level - 1,2 2 G SR 3.3.1.1.1 t 528 inches Low, Level 3(d) SR 3.3.1.1.8 above vessel SR 3.3.1.1.13 zero SR 3.3.1.1.14

5. Main Steam Isolation Valve - 1 8 F SR 3.3.1.1.8 d 10% closed Closure SR 3.3.1.1.13 SR 3.3.1.1.14

6. Drywell Pressure - High 1,2 2 G SR 3.3.1.1.8 d 2.5 psig SR 3.3.1.1.13 SR 3.3.1.1.14

7. Scram Discharge Volume Water Level - High

a. Resistance Temperature 1,2 2 G SR 3.3.1.1.8 d 50 gallons Detector SR 3.3.1.1.13 SR 3.3.1.1.14 5(a) 2 H SR 3.3.1.1.8 d 50 gallons SR 3.3.1.1.13 SR 3.3.1.1.14 (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.

(d) During instrument calibrations, if the As Found channel setpoint is conservative with respect to the Allowable Value but outside its acceptable As Found band as defined by its associated Surveillance Requirement procedure, then there shall be an initial determination to ensure confidence that the channel can perform as required before returning the channel to service in accordance with the Surveillance. If the As Found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

Prior to returning a channel to service, the instrument channel setpoint shall be calibrated to a value that is within the acceptable As Left tolerance of the setpoint; otherwise, the channel shall be declared inoperable.

The nominal Trip Setpoint shall be specified on design output documentation which is incorporated by reference in the Updated Final Safety Analysis Report. The methodology used to determine the nominal Trip Setpoint, the predefined As Found Tolerance, and the As Left Tolerance BFN-UNIT 2 3.3-8 Amendment No. 253, 254, 258, 260, 296, 309 February 15, 2013

RPS Instrumentation 3.3.1.1 band, and a listing of the setpoint design output documentation shall be specified in Chapter 7 of the Updated Final Safety Analysis Report.

(e) Refer to COLR for OPRM period based detection algorithm (PBDA) setpoint limits.

BFN-UNIT 2 3.3-9 Amendment No. 253, 254, 258, 260, 296, 309 February 15, 2013

RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 3 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

7. Scram Discharge Volume Water Level - High (continued)

b. Float Switch 1,2 2 G SR 3.3.1.1.8 d 46 gallons SR 3.3.1.1.13 SR 3.3.1.1.14 5(a) 2 H SR 3.3.1.1.8 d 46 gallons SR 3.3.1.1.13 SR 3.3.1.1.14

8. Turbine Stop Valve - Closure t 30% RTP 4 E SR 3.3.1.1.8 d 10% closed SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15

9. Turbine Control Valve Fast t 30% RTP 2 E SR 3.3.1.1.8 t 550 psig Closure, Trip Oil Pressure - SR 3.3.1.1.13 Low(d) SR 3.3.1.1.14 SR 3.3.1.1.15

10. Reactor Mode Switch - 1,2 1 G SR 3.3.1.1.12 NA Shutdown Position SR 3.3.1.1.14 5(a) 1 H SR 3.3.1.1.12 NA SR 3.3.1.1.14

11. Manual Scram 1,2 1 G SR 3.3.1.1.8 NA SR 3.3.1.1.14 5(a) 1 H SR 3.3.1.1.8 NA SR 3.3.1.1.14

12. RPS Channel Test Switches 1,2 2 G SR 3.3.1.1.4 NA 5(a) 2 H SR 3.3.1.1.4 NA 13.Deleted (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

(d) During instrument calibrations, if the As Found channel setpoint is conservative with respect to the Allowable Value but outside its acceptable As Found band as defined by its associated Surveillance Requirement procedure, then there shall be an initial determination to ensure confidence that the channel can perform as required before returning the channel to service in accordance with the Surveillance. If the As Found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

Prior to returning a channel to service, the instrument channel setpoint shall be calibrated to a value that is within the acceptable As Left tolerance of the setpoint; otherwise, the channel shall be declared inoperable.

The nominal Trip Setpoint shall be specified on design output documentation which is incorporated by reference in the Updated Final Safety Analysis Report. The methodology used to determine the nominal Trip Setpoint, the predefined As Found Tolerance, and the As Left Tolerance band, and a listing of the setpoint design output documentation shall be specified in Chapter 7 of the Updated Final Safety Analysis Report.

BFN-UNIT 2 3.3-10 Amendment No. 258, 276, 296 September 14, 2006

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 1E 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 DGs.

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 2 3.8-1 Amendment No. 253, 286 December 1, 2003

AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 Declare required 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from feature(s) with no offsite discovery of no power available offsite power to inoperable when the one shutdown redundant required board concurrent feature(s) are inoperable. with inoperability of redundant required feature(s)

AND A.3 Restore required offsite 7 days circuit to OPERABLE status. AND 21 days from discovery of failure to meet LCO B. One required Unit 1 and 2 B.1 Verify power availability 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months DG inoperable. from the offsite transmission network. AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter AND (continued)

BFN-UNIT 2 3.8-2 Amendment No. 307

AC Sources - Operating 3.8.1 ACTIONS (continued)

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 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 Perform SR 3.8.1.1 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)

BFN-UNIT 2 3.8-3 Amendment No. 307

AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.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)

BFN-UNIT 2 3.8-3a Amendment No. 307

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One division of 480 V C.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)

BFN-UNIT 2 3.8-4 Amendment No. 253

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 LCO 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.

(continued)

BFN-UNIT 2 3.8-5 Amendment No. 253

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.

I. Required Action and I.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 AND Condition A, B, C, D, E, F, or H not met. I.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 2 3.8-6 Amendment No. 253

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME K. One or more required K.1 Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from Unit 3 DGs feature(s) supported by discovery of inoperable. the inoperable Unit 3 DG Condition K inoperable when the concurrent with redundant required inoperability of feature(s) are inoperable. redundant required feature(s)

AND K.2 Declare affected SGT and 30 days CREVs subsystem(s) inoperable.

BFN-UNIT 2 3.8-7 Amendment No. 253

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS

NOTE---------------------------------------------------

SR 3.8.1.1 through SR 3.8.1.9 are applicable to the Unit 1 and 2 AC sources.

SR 3.8.1.10 is applicable only to Unit 3 AC sources.

SURVEILLANCE FREQUENCY SR 3.8.1.1 -------------------------NOTES------------------------

1. Performance of SR 3.8.1.4 satisfies this SR.

2. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.

3. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.

When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.4 must be met.

Verify each DG starts from standby 31 days conditions and achieves steady state voltage t 3940 V and d 4400 V and frequency t 58.8 Hz and d 61.2 Hz.

(continued)

BFN-UNIT 2 3.8-8 Amendment No. 253

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.2 -------------------------NOTES------------------------

1. DG loadings may include gradual loading as recommended by the manufacturer.

2. Momentary transients outside the load range do not invalidate this test.

3. This Surveillance shall be conducted on only one DG at a time.

4. This SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.1 or SR 3.8.1.4.

Verify each DG is synchronized and loaded 31 days and operates for t 60 minutes at a load t 2295 kW and d 2550 kW.

(continued)

BFN-UNIT 2 3.8-9 Amendment No. 253

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 Verify the fuel oil transfer system operates to 31 days automatically transfer fuel oil from 7-day storage tank to the day tank.

SR 3.8.1.4 --------------------------NOTE-------------------------

All DG starts may be preceded by an engine prelube period.

Verify each DG starts from standby condition 184 days and achieves, in d 10 seconds, voltage t 3940 V and frequency t 58.8 Hz. Verify after DG fast start from standby conditions that the DG achieves steady state voltage t 3940 V and d 4400 V and frequency t 58.8 Hz and d 61.2 Hz.

(continued)

BFN-UNIT 2 3.8-10 Amendment No. 253

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.5 --------------------------NOTE-------------------------

If performed with the DG synchronized with offsite power, it shall be performed at a power factor d 0.9.

Verify each DG rejects a load greater than or 24 months equal to its associated single largest post-accident load, and:

a. Following load rejection, the frequency is d 66.75 Hz; and

b. Following load rejection, the steady state voltage recovers to t 3940 V and d 4400 V.

c. Following load rejection, the steady state frequency recovers to t 58.8 Hz and d 61.2 Hz.

SR 3.8.1.6 --------------------------NOTE-------------------------

All DG starts may be preceded by an engine prelube period followed by a warmup period.

Verify on an actual or simulated accident 24 months signal each DG auto-starts from standby condition.

(continued)

BFN-UNIT 2 3.8-11 Amendment No. 255 November 30, 1998

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.7 --------------------------NOTE-------------------------

Momentary transients outside the load and power factor ranges do not invalidate this test.

Verify each DG operating at a power factor 24 months d 0.9 operates for t 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s:

a. For t 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded t 2680 kW and d 2805 kW; and

b. For the remaining hours of the test loaded t 2295 kW and d 2550 kW.

SR 3.8.1.8 Verify interval between each timed load block 24 months is within the allowable values for each individual timer.

(continued)

BFN-UNIT 2 3.8-12 Amendment No. 255 November 30, 1998

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.9 --------------------------NOTE-------------------------

All DG starts may be preceded by an engine prelube period.

Verify, on an actual or simulated loss of 24 months offsite power signal in conjunction with an actual or simulated ECCS initiation signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in d 10 seconds,

2. energizes auto-connected emergency loads through individual timers,

3. achieves steady state voltage t 3940 V and d 4400 V,

4. achieves steady state frequency t 58.8 Hz and d 61.2 Hz, and

5. supplies permanently connected and auto-connected emergency loads for t 5 minutes.

SR 3.8.1.10 For required Unit 3 DGs, the SRs of Unit 3 In accordance Technical Specifications are applicable. with applicable SRs BFN-UNIT 2 3.8-13 Amendment No. 255 November 30, 1998

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 1E AC Electrical Power Distribution System;

b. Unit 3 diesel generators (DGs) with two divisions of 480 V load shed logic and common accident signal logic OPERABLE; and

c. Unit 1 and 2 DG(s) capable of supplying the Unit 1 and 2 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 DGs.

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 3 3.8-1 Amendment No. 212, 244 December 1, 2003

AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 Declare required 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from feature(s) with no offsite discovery of no power available offsite power to inoperable when the one shutdown redundant required board concurrent feature(s) are inoperable. with inoperability of redundant required feature(s)

AND A.3 Restore required offsite 7 days circuit to OPERABLE status. AND 21 days from discovery of failure to meet LCO B. One required Unit 3 DG B.1 Verify power availability 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable. from the offsite transmission network. AND Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months thereafter AND (continued)

BFN-UNIT 3 3.8-2 Amendment No. 266

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 3 DG, Condition B inoperable when the concurrent with 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 3 DG(s) are not inoperable due to common cause failure.

OR B.4.2 Perform SR 3.8.1.1 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE Unit 3 DG(s).

AND (continued)

BFN-UNIT 3 3.8-3 Amendment No. 266

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.5 Restore Unit 3 DG to 7 days from 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)

BFN-UNIT 3 3.8-3a Amendment No. 266

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One division of 480 V C.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)

BFN-UNIT 3 3.8-4 Amendment No. 212

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 LCO 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 3 DG status.

inoperable.

OR F.2 Restore Unit 3 DG to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 3 DG inoperable.

(continued)

BFN-UNIT 3 3.8-5 Amendment No. 212

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME H. Two or more Unit 3 H.1 Restore all but one Unit 3 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months DGs inoperable. DG to OPERABLE status.

I. Required Action and I.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 AND Condition A, B, C, D, E, F, or H not met. I.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 3 DGs inoperable.

OR Two required offsite circuits and one or more Unit 3 DGs inoperable.

OR Two divisions of 480 V load shed logic inoperable.

OR Two divisions of common accident signal logic inoperable.

(continued)

BFN-UNIT 3 3.8-6 Amendment No. 212

AC Sources - Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME K. One or more required K.1 Declare required 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from Unit 1 and 2 DGs feature(s) supported by discovery of inoperable. the inoperable Unit 1 and Condition K 2 DG inoperable when the concurrent with redundant required inoperability of feature(s) are inoperable. redundant required feature(s)

AND K.2 Declare affected SGT and 30 days CREVs subsystem(s) inoperable.

BFN-UNIT 3 3.8-7 Amendment No. 212

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS

NOTE---------------------------------------------------

SR 3.8.1.1 through SR 3.8.1.9 are applicable to the Unit 3 AC sources. SR 3.8.1.10 is applicable only to Unit 1 and 2 AC sources.

SURVEILLANCE FREQUENCY SR 3.8.1.1 -------------------------NOTES------------------------

1. Performance of SR 3.8.1.4 satisfies this SR.

2. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading.

3. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer.

When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.4 must be met.

Verify each DG starts from standby 31 days conditions and achieves steady state voltage t 3940 V and d 4400 V and frequency t 58.8 Hz and d 61.2 Hz.

(continued)

BFN-UNIT 3 3.8-8 Amendment No. 212

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.2 -------------------------NOTES------------------------

1. DG loadings may include gradual loading as recommended by the manufacturer.

2. Momentary transients outside the load range do not invalidate this test.

3. This Surveillance shall be conducted on only one DG at a time.

4. This SR shall be preceded by and immediately follow, without shutdown, a successful performance of SR 3.8.1.1 or SR 3.8.1.4.

Verify each DG is synchronized and loaded 31 days and operates for t 60 minutes at a load t 2295 kW and d 2550 kW.

(continued)

BFN-UNIT 3 3.8-9 Amendment No. 212

AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 Verify the fuel oil transfer system operates to 31 days automatically transfer fuel oil from 7-day storage tank to the day tank.

SR 3.8.1.4 --------------------------NOTE-------------------------

All DG starts may be preceded by an engine prelube period.

Verify each DG starts from standby condition 184 days and achieves, in d 10 seconds, voltage t 3940 V and frequency t 58.8 Hz. Verify after DG fast start from standby conditions that the DG achieves steady state voltage t 3940 V and d 4400 V and frequency t 58.8 Hz and d 61.2 Hz.

(continued)

BFN-UNIT 3 3.8-10 Amendment No. 212