Text

July-August Exam 50-325, 324/2007301 Draft Simulator Scenarios (3 of 4)
	ML072960463
Person / Time
Site:	Brunswick
Issue date:	01/31/2007
From:	; - No Known Affiliation
To:	; Office of Nuclear Reactor Regulation
References
	50-324/07-301, 50-325/07-301 50-324/07-301, 50-325/07-301
	Download: ML072960463 (142)
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PROGRESS ENERGY CAROLINAS BRUNSWICK TRAINING SECTION 2007 NRC EXA BRUNSWICK JULY-AUG EXAM - 325,324/2007-301 DRAFT SIMULATOR SCENARIO 3 OF 4 2007 NRC Examination Scenario #3

SCENARIO DESCRIPTION BRUNSWICK 2007 NRC Scenario #3 The plant is operating at 94% power, End Of Cycle with RHR SW Pump 20 and TBCCW Pump 28 under clearance. A swap of NSW pumps is required for upcoming maintenance on the operating pump. After swapping NSW pu reactor power will be raised to 100 0/0.

After power has been raised a scoop tube lockup will 0 e uA" Recirc MG Set.

I&C will report a loose wire caused the problem and t n reset the scoop .

tube. Once the scoop tube has been reset and re ed, the #3 EOG will have a low starting air pressure requiring a termination (TS). (The EDG #3 must be declared inoper Following the TS determination for the EDG (, pump previo sly started will trip, requiring a restart of the SW pump origi ved from service (TS 3.7.2.8).

5S of feeOdwater heating and reduce reactor operators.

s to rise and MSL Rad Hi to alarm. The OP-04-RRCP. Power will be reduced to get worse resulting in MSL Hi-Hi alarm

. Per the guidance of OEOP nual rea ram and close the MSIVs. The manual The reactor can be scrammed by Mode switch or When' SRV ill be required for pressure control. When SRV F is opened, f ppression pool temperature will rise requiring initiation of suppression OEOP-02-PCCP. If RHR Loop A is started for suppression p e E11-F068A valve (RHR HX Service Water Outlet) will fail to open and RH will be unavailable for suppression pool cooling.

When RHR Loop B is started for suppression pool cooling, the RHR Heat Exchanger will develop a tube leak. The tube leak will initially result in leakage of service water into the RHR system and RHR high conductivity alarm. RHR SW Pump 28 will then trip (RHR SW 20 is under clearance) and E11-F068B will fail to auto close. Without an RHR Service Water pump in operation, RHR system water will now leak into service water.

Service Water high radiation will alarm. The crew will respond to the service water release per EOP-04-RRCP by closing E11-F068B, shutting down RHR Loop Band 2007 NRC Examination Scenario #3 2

isolating the heat exchanger (Critical Task).

The F SRV tailpipe will fail and Emergency Depressurization will be required per OEOP-02 PCCP when the safe region of PSP can not be maintained (Critical Task).

When the reactor is depressurized by the ED, the scenario may be terminated.

2007 NRC Examination Scenario #3 3

SIMULATOR SETUP Initial Conditions IC 183 ENP 24 for Ie 14 Rx Pwr 940/0 Core Age EGG EVENTS Event Trigger Trigger Description Number 1

NA NA 2 NA NA 3 1 Manual 4 2 Manual 5 3 Manual p Trip 6 4 Manual -V120 partially opening) 7 5 Manual 8 NA 9 6 10 7 r Tube Leak 11 8 /E11-F068B failure to close 12 V Tailpipe f~iiure - Pressure Suppression Pressure challenge Interventions Summary Malfunctions Summary Description 2007 NRC Examination Scenario #3 4

RC021F RECIRC PUMP MG SET A SCOOP FALSE TRUE 00:00:30 TUBE FAILURE

, CW019F A NUC SERVICE WATER PUMP FALSE TRUE 3 MOTOR WINDING FAULT NB005F FUEL FAILURE 0.00 100.0000 00:05:00 5 ESOO4F ADS VALVE F FAILS OPEN FALSE TRUE 6 CW013F RHR B HX TUBE LEAK 0.00 7 CW071F B RHR SW BOOSTER PUMP MOTRO FALSE 8 WINDING FAULT Annunciator Summary Window Description Tagname Override Type OVal AVal Actime Dactime Trig 6-2 DG-3 LO START AIR PRESS ZUA2162 ON ON OFF 2 Batch Files 2007 NRC Examination Scenario #3 5

II~Fi,e _-+--1Tr~jgger ~~S~:~PtjOn- - - - - 1 1

+---1 Special Instructions Load scenario file 2007 NRC Scenario 3.scn Place red cap on 2D RHR SW Booster Pump Control Switc Place red cap on 2B TBCCW Pump Control Switch Ensure ENP-24 for IC14 @ P603.

Null DVM 2007 NRC Examination Scenario #3 6

SHIFT BRIEFING Plant Status The plant is operating at 94% power, End of Cycle.

Equipment Out of Service 2D RHR SW Booster Pump is out of service for lube oil ch and is expected to be returned to service by the end of shift.

28 TBCCW Pump is out of service and under clear is anticipated to be returned to service in 48 hou .

No other equipment is out of service Plan of the Day er Pump in service with 28 Nuclear header flow Raise reactor power to maximum Recirculation control.

2007 NRC Examination Scenario #3 7

SCENARIO INFORMATION Examiner Notes Procedures Used in Scenarios:

EVENT 1

20P-43 EVENT 2

OGP-12

20P-02.0 EVENT 3

Annunciator procedure

20P-02 EVENT 4

Annunciator Procedure EventS

OAOP-18 n Guidance)

EVENT 7

res (UA-23: 2-6; UA-03: multiple)

OEOP-04-RRCP (Radioactive Release Control Procedure)

2EOP-01-RSP (Reactor Scram Procedure)

OEOP-01-RVCP (Reactor Vessel Control Procedure)

OEOP-02-PCCP (Primary Containment Control Procedure)

EVENT 8

2EOP-01-LPC (Level Power Control) 2007 NRC Examination Scenario #3 8

EVENT 9

OAOP-30 EVENT 10

APP EVENT 11

OEOP-04-RRCP EVENT 12

OEOP-02-PCCP (Primary Containment Contr Critical Tasks When a manual scra a am due to a failure on the "B" side , successful. rtion by placing the Reactor Mode Switch to Shutdo I lIy initiating ARt.

leak from the uB" RHR Heat Exchanger m, successfully isolate the Service not be maintained within the safe region of the

, h, Emergency Depressurize the reactor.

2007 NRC Examination Scenario #3 9

EVENT 1 SHIFT TURNOVER, SWAPPING NUCLEAR WATER PUMPS The crew will swap operating Nuclear Service Water Pumps in support of scheduled NSW flow measurement activities.

Malfunction required:

None Objectives:

sea Directs BOP to start 2A Nuclear Service Water' "p Service Water Pump in standby per 20P-4 ction 8.22.

BOP Place 2A Nuclear Service Water Pum Water Pump and place it in standby' Success Path:

Nuclear Service Water Pump 2A w r Service Water Pump 28 will be secured and placed in Stand A Nuclear Service Water Pump have re normal.

~l ater Pump is running normally with no 2007 NRC Examination Scenario #3 10

EVENT 1 SHIFTING NUCLEAR SERVICE WATER PUMPS Required Operator Actions Normal Plant Operation - Shifting of Nuclear Service Water Pumps SRO o Direct BOP to shift Nuclear Service Water P er 20P-43, section 8.22 BOP o Shift Nuclear Service Water P .

APPLICANT'S ACTIONS OR BEHAVIOR:

2007 NRC Examination Scenario #3 11

EVENT 2 RAISE REACTOR POWER TO -100 ok Required Operator Actions SRO Normal Operation - Raise Reactor Power to 100 0k

Direct RO to raise reactor power to 100 0Jb per 0 RO Normal 0 eration -Raise Reactor Power

Raise Reactor Power to 100% per OGP-1 '

2007 NRC Examination Scenario #3 12

EVENT 3 2A Reactor Recirc Pump Scoop Tube Lock (Spurious)

The crew responds to a spurious lock of the 2A Reactor Recirc Pump Scoop Tube Malfunctions required:

A spurious signal will be received by the 2A Reactor Re . MG set resulting in a locking of its scoop tube, preventing any controlled ch g of speed of the affected machine Objectives:

SCQ Directs actions to stop power cha verify the initiating cause is spu .

Contacts I&C to request suppo RO Refers to annunciato scoop tube status and A-6 2-4, Fluid Drive A Success Path:

Scoop Tube lock nosed, and recovered from, with the final condition bein ed to an unlocked condition and reactor pow app riner, activate TRIGGER 1

W to assist in the investigation of the failure, acknowledge the re 3 minutes, inform the SCO that a loose wire was located in the spee cuit, and that it had been repaired.

WHEN asked, as I&C, provide assistance in matching speed demand versus actual in support of unlocking the scoop tube.

WHEN asked, as TBAO, report that 2AB-TB circuit 2 is not tripped 2007 NRC Examination Scenario #3 13

EVENT 3 2A Reactor Recirc Pump Scoop Tube Lock Required Operator Actions SRO Directs actions to stop power changes and eva plant conditions to verify the initiating cause is spurious.

Contacts I&C to request support in issu Following correction of problem, .

20P-02.

RO Refers to annunciato scoop tube status an A-6 2-4, Fluid Drive APPLICANT'S A 2007 NRC Examination Scenario #3 14

EVENT 4 DG #3 Low Starting Air Header Pressure The crew responds to and diagnoses the Low Starting Air Header Pressure alarm on #3 Emergency Diesel Generator.

Malfunction required:

Emergency Diesel Generator #3 starting air header will I er to the low pressure threshold, causing annunciator 2-UA-21 6-2,DG3 Lo g Air Pressure (235 psig)

Objectives:

sea Correctly evaluates the condition of the .

Header Success Path:

seQ obtains information from the Generator is inoperable (Technical Simulator Operator Activities:

WHEN asked, report, pressure is 220 ps*

WHEN contacted a P to adjust the pressure, acknowledge the request.

2007 NRC Examination Scenario #3 15

EVENT 4 DG #3 Low Starting Air Header Pressure Required Operator Actions Normal Plant Operation - Assessing Technical Specifications due to a parameter outside establish bands (DG #3 Starting Air Header Pressure)

SRO o Successfully evaluates that the lower startin ader pressure results in an inoperability of the #3 Emergency D* rator.

o Refers to TS 3.8.1.D. (7 days for ED BOP o Responds to annunciator 2-UA-APPLICANT'S ACTIONS OR BE 2007 NRC Examination Scenario #3 16

EVENT 5 2A NUCLEAR SERVICE WATER PUMP TRIP The crew will respond to the failure of an operating Nuclear Service Water Pump failure per OAOP-18.0 and take action to restore Nuclear Service Water to within normal operating limits.

Malfunctions required:

2A Nuclear Service Water Pump will trip on electrical faul Water Pump will fail to start on a low pressure demand Objectives:

sea Enters OAOP-18.0 and directs the acti the Nuclear Service Water System t BOP Enters OAOP-18 and manuall ervice Water Pump to restore Nuclear Service Water' . \1 limits.

Success Path:

Nuclear Service erating within normal ranges with the 28 Nuclear Service w . er, activate TRIGGER 3 IF aske Service Water Building, wait 3 minutes and then report an acrid smel e 2A Nuclear Service Water Pump motor, but that there are no signs r fire IF asked to investl the Diesel Generator Building, wait 3 minutes and report that there are overcurren trips on all three phases of the 2A Nuclear Service Water Pump 4KV Breaker.

IF contacted as I&C and requested to help with the investigation of the failure of the 2A Nuclear Service Water Pump, acknowledge the request.

IF contacted as I&C, wait 3 minutes and the NSW pump issue is unknown at this time.

2007 NRC Examination Scenario #3 17

EVENT 5 2A NUCLEAR SERVICE WATER PUMP TRIP Required Operator Actions Abnormal Operating Procedures - Nuclear Service Water Failure sea Enters OAOP-18.0 and directs the actions of the BOP to cilitate restoration of the Nuclear Service Water System to within normal Ii Evaluates Technical Specifications for the inope Water Pump. TS 3.7.2. Ultimate Heat Sink - Tr BOP Enters OAOP-18 and manually starts the restore Nuclear Service Water param 2007 NRC Examination Scenario #3 18

EVENT 6/7 LOSS OF FEEDWATER HEATING/FUEL FAILURE/ATWS The crew will observe and respond to a spurious opening of the 2-FW-V120 (loss of feedwater heating), the resultant fuel failure (cold water injection overpower), and an ATWS when a reactor scram is attempted.

Malfunctions required:

2-FW-V120 (High Pressure Feedwater Heater String) ceive a spurious uOpen" signal for 30 seconds, resulting in a loss of ater heating and companion power increase. The manual scram n will be overridden to prevent a scram from being successful via de manual scram pushbuttons.

Objectives:

seQ Directs the actions of the cr. itive Reactivity Addition, in response to the opening of t . e power excursion resulting from the cold water addition.

Directs the actio rmal Rad Conditions, in response to th om the overpower event caused by t the failure of the reactor to scram.

eduction recommendations to get below

'elease Control Procedure, 2EOP-01-RSP, Reactor LPC, Level Power Control RO r, when directed, to mitigate the overpower resulting from ter heating.

Continues lowering power, as directed, in response to increases in radiological conditions in the plant resulting from fuel failure.

Inserts a manual scram, when directed, and takes the appropriate actions in response to the failure of the 'RPS system to complete a scram.

Reduces flow to lower power and drives control rods to get below the Meilia line.

2007 NRC Examination Scenario #3 19

BOP Recognizes and reports the abnormal position of the 2-FW-V120 and takes action to close the valve Observes and reports annunciators relating to fuel failure, specifically as relating to changing radiological conditions 2007 NRC Examination Scenario #3 20

EVENT 6/7 LOSS OF FEEDWATER HEATING/FUEL FAILURE/ATWS Success Path:

The crew will correctly diagnose the spurious opening of the 2-FW-V120 and take actions to close the valve and manage power level to limit the overpower condition and subsequent fuel failure.

Simulator Operator Activities:

WHEN directed by the lead examiner, activate

IF asked as an auxiliary operator, stand V120 when it is moved to a "Closed" Q,

WHEN directed by the lead examiner,

WHEN asked as E&RC, ac surveys.

2007 NRC Examination Scenario #3 21

EVENT 6/7 LOSS OF FEEDWATER HEATING/FUEL FAILURE/ATWS Required Operator Actions:

seo

Direct actions to close the 2-FW-V120 and entry into OP-xxx: Positive Reactivity Addition

Enter and direct actions of OAOP-05.0 Abnor the fuel failure.

Enter and direct actions of OEOP Procedure)

Enters and directs actions of 2EOP-2EOP-01-LPC (Level-Power Control)

RO rpower event of the cold based on radiological conditions. takes failure to scram and takes appropriate "ected to get below the Meilia line.

BOP

the position of the 2-FW-V120 and take action to close eport the changing conditions relating to fuel failure I conditions and alarms).

EVENT 6/7 LOSS OF FEEDWATER HEATING/FUEL FAILURE/ATWS 2007 NRC Examination Scenario #3 22

EVENT 6/7 LOSS OF FEEDWATER HEATING/FUEL FAILURE/ATWS APPLICANT'S ACTIONS OR BEHAVIOR:

2007 NRC Examination Scenario #3 23

EVENT 8 SRV F STUCK OPEN The crew will respond to a failure of SRV F to close following the placing of its control switch to the "AUTO" position following its manual actuation in support of reactor pressure control.

Malfunctions required:

SRV "F" will fail in the OPEN position following its R maintain reactor pressure.

Objectives:

sea Enter and direct actions associated . *sel Control Procedure) due to heating of ttl -30.0 (SRV Failure)

Directs RO/SOP to place all RO attempt to close the SRV R in Suppression Pool Cooling to mitigate the heat en SRV BOP rts placing RHR in Suppression Pool Cooling to mitigate to the failed open SRV aximizes CRD flow per SEP-09 Success Path:

Crew recognizes the failed open SRV and takes the actions as directed by the AOP and EOP relating to the failure.

2007 NRC Examination Scenario #3 24

Simulator Operator Activities WHEN requested pull SRV fuses by initiating trigger 10 2007 NRC Examination Scenario #3 25

EVENT 8 SRV F STUCK OPEN Required Operator Actions SCO Directs entry into and actions associated with OAOP-30.0 to attempt to achieve reclosure of SRV F Enters OEOP-02-PCCP (Primary Containment Con . cedure) and directs actions associated with the heating of the suppr I resulting from the stuck open SRV Directs SEP-09 to maximize CRD flow.

BOP Recognizes failure of SRV F to close an Enters and executes OAOP-

'}directed to mitigate the ssion Pool by the stuck RO 2007 NRC Examination Scenario #3 26

EVENT 9,10 RHR HEAT EXCHANGER TUBE LEAK/SERVICE WATER FAILURE TO ISOLATE/ RHR SW BOOSTER PUMP TRIP The crew will respond to an RHR Heat Exchanger tube leak accompanied by an RHR Service Water Booster Pump trip and subsequent failure of the outflow isolation valve to automatically close (Radioactive Release).

Malfunctions required:

An RHR Heat Exchanger tube failure will occur (indicated ing conductivity of the RHR system). The supporting RHR Service Water Boo will, subsequently, trip accompanied by the Service Water Loop effluent 0688) failure to automatically close.

Objectives:

seQ Will direct the actions of DE Procedure) associated with d provide direction/

tlon.

BOP RHR Service Water Booster Pump 1-F068B (RHR Service Water Loop manipulate the 2-E11-F068B to close the valve and ath from the heat exchanger via the Service Water Success Path:

The crew will recognl e the indications of the RHR Heat Exchanger tube leak.

Following the tripping of the RHR Service Water Booster Pump and the failure of the 2-E11-F068B to close, the crew will take action to achieve isolation of the radioactive effluent via the Service Water system by closing the 2-E11-F068B.

2007 NRC Examination Scenario #3 27

EVENT 9,10 RHR HEAT EXCHANGER TUBE LEAK/SERVICE WATER FAILURE TO ISOLATEI RHR SW BOOSTER PUMP TRIP Simulator Operator Activities:

WHEN directed by the lead examiner, initiate TRIGGER 7 WHEN directed by the lead examinger, initiate TRIGG IF requested as the building auxiliary operator to manually close the 2-E11-F068B, acknowled 2007 NRC Examination Scenario #3 28

EVENT 9,10 RHR HEAT EXCHANGER TUBE LEAK/SERVICE WATER FAILURE TO ISOLATE! RHR SW BOOSTER PUMP TRIP Required Operator Actions:

SRO Directs actions associated with the Service Wa of OEOP-04-RRCP, Radioactive Release Control Procedure Provides oversight and direction, as ap ,

individual action to attempt to close BOP Recognizes and communicate Exchanger tube leak to the cr R Service Water Booster 1-F068B to automatically 88 using the control

. te the release duration from 2007 NRC Examination Scenario #3 29

EVENT 11 SRV F TAILPIPE BREAK/EMERGENCY DEPRESSURIZATION REQUIRED The crew will respond to indications of a failure of the SRV "F" tailpipe in the air space of the suppression chamber, resulting in entry of the Unsafe region of the Pressure Suppression Pressure graph, requiring an Emergency Depressurization of the reactor.

Malfunctions Required:

The SRV "F" tailpipe will experience a failure in the air e Suppression Chamber, resulting in a loss of the pressure suppress', f the suppression pool.

Objectives:

seQ rapid increase . n g loss of differential pressure ber air space.

ent, specifically the

!tle Pressure ncy Depressurization of the scribed in OEOP-02-PCCP (Primary Emergency Depressurize the reactor.

In containment pressure.

e lowering differential pressure between the air in the diagnosis of the loss of pressure

, take the actions necessary to Emergency Depressurize d control injection sources to prevent overfilling of the ssure vessel.

Success Path:

The crew will correctly diagnose the loss of pressure suppression function of the containment and complete an Emergency Depressurization of the reactor.

2007 NRC Examination Scenario #3 30

EVENT 11 SRV F TAILPIPE BREAK/EMERGENCY DEPRESSURIZATION REQUIRED Simulator Operator Activities:

WHEN directed by the lead examiner, initiate TRIGGER 9.

2007 NRC Examination Scenario #3 31

Required Operator Actions:

seQ Correctly diagnoses the SRV tailpipe failure and subsequent entry into the Unsafe region of the Pressure Suppression Pressure graph.

Direct the actions prescribed in OEOP-02-PCCP to Emer: ncy Depressurize the reactor RO/BOP Observe and report the changes in cont .

SRV tailpipe failure and support the d*

suppression function of the contain of the reactor vessel.

Simulator Operator Activities:

WHEN directed by the lead examiner, place the simulator in FREEZE.

CAUTION 2007 NRC Examination Scenario #3 32

DO NOT RESET THE SIMULATOR PRIOR TO RECEIPT OF CONCURRENCE TO DO SO FROM THE LEAD EXAMINER 2007 NRC Examination Scenario #3 33

8.22 Alternating Nuclear Service Water Pumps C Continuous Use 8.22.1 Initial Conditions

1. All applicable prerequisites as listed in Section 4.0 are D met

2. Service Water System is in operation in accordance with D Section 5.2.

8.22.2 Procedural Steps NOTE: IF a Radwaste release is in progress AND the swapping of Nuclear Service Water Pumps is NOT a routine swap (Le., taking longer than 1 or 2 minutes),

THEN the Radwaste release must be stopped.

1. IF the final number of operating Service Water Pumps D will NOT be the same as the initial number of operating Service Water Pumps, THEN ENSURE a Radwaste radioactive release is NOT in progress.

2. PLACE mode selector switches for all operable Nuclear D Service Water Pumps in MAN.

3. START Nuclear Service Water Pump B(A). D

4. CONFIRM discharge valve for the Nuclear Service Water D Pump just started automatically opens.

120P-43 Rev. 124 Page 111 of216 I

8.22.2 Procedural Steps

5. CONFIRM cooling water flow to Nuclear Service Water D Pump motor just started has been established by observing discharge into the drain hub.

6. CONFIRM Nuclear Service Water Pump B(A) discharge D pressure is greater than 40 psig.

7. IF it is desired to maintain two Nuclear Service Water Pumps running for an extended period of time, THEN PLACE both Nuclear Service Water Pump mode switches in AUTO:

- NUC SW PUMP A D

- NUC SW PUMP B D

8. WHEN it is desired to stop a Nuclear Service Water Pump, THEN PERFORM the following:

a. ENSURE mode selector switches for all operable D Nuclear Service Water Pumps are in MAN.

b. STOP Nuclear Service Water Pump A(B). D

c. CONFIRM discharge valve for Nuclear Service D Water Pump just stopped automatically closes.

d. WHEN Nuclear Service Header Pressure has stabilized, THEN PLACE both Nuclear Service Water Pump mode switches in AUTO:

- NUC SW PUMP A D

- NUC SW PUMP B D

9. COMPLETE Attachment 24. D

\20P-43 Rev. 124 Page 112 of 2161

ATTACHMENT 24 C Continuous Page 1 of 1 Use Section 8.22, Alternating Nuclear Service Water Pumps Documentation Positionl Number Description Indication Checked Verified N/A Nuclear Service Water Pump 2A AUTO Selector Switch N/A Nuclear Service Water Pump 2B AUTO Selector Switch Date/Time Completed _

Performed By (Print) Initials Reviewed By: _

Unit sea

!20P-43 Rev. 124 Page 210 of 2161

C g..... Progress Energy BRUNSWICK NUCLEAR PLANT Continuous Use PLANT OPERATING MANUAL VOLUME IV GENERAL PLANT OPERATING PROCEDURE UNIT o

OGP-12 POWER CHANGES REVISION 49 IOGP-12 Rev. 49 Page 1 of 371

TABLE OF CONTENTS SECTION PAGE 1.0 PURPOSE. 3

2.0 REFERENCES

3 3.0 PRECAUTIONS AND LIMITATIONS 5 4.0 PREREQUISITES 7 5.0 PROCEDURAL STEPS 8 5.1 Power Reduction.................................................................................................... 8 5.2 Power Increases.................................... 19 ATTACHMENTS 1 Control Rod Movement..................................................................................... 31 2 Verification of Reactor Power Lever Using Alternate Indications 34 IOGP-12 I Rev. 49 Page 2 of 371

1.0 PURPOSE This procedure provides the prerequisites, precautions, limitations, and instructional guidance for performing reactor power changes by varying Reactor Recirculation System flow or manipulating control rods when reactor power level is above reactor recirculation pump minimum speed. This procedure also provides guidance for End-of-Cycle coast down.

This procedure is also used to verify the following Technical Specifications:

1.1 SR 3.1.3.5. The coupling integrity of control rods.

1.2 TR 7.3.7.2 (ODCMS Table 7.3.7-1, footnote c and g). The sample and analysis frequency used to determine the Dose Rate of gaseous effluents.

1.3 SR 3.3.1.1.3. APRM GAFs must be set correctly within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of reaching or exceeding 230/0 rated thermal power.

2.0 REFERENCES

2.1 Technical Specifications 3.2.1 3.2.3, 3.3.1.1 3.3.1.3, 3.4.1 TR 7.3.7.2 f f f 2.2 UFSAR 2.3 001-01, Cpnduct of Operations Manual 2.4 OPLP-17, Identification, Development, Review, and Conduct of Infrequently Performed Tests or Evolutions 2.5 OGP-01, Prestartup Checklist 2.6 OGP-04, Increasing Turbine Load to Rated 2.7 OGP-05, Unit Shutdown 2.8 OGP-10, Rod Sequence Checkoff Sheets 2.9 OGP-11, Second Operator Rod Sequence Checkoff Sheets 2.10 OGP-13, Increasing Unit Capacity at End of Core Cycle 2.11 1(2)OP-02, Reactor Recirculation System Operating Procedure 2.12 1(2)OP-07, Reactor Manual Control System Operating Procedure IOGP-12 Rev. 49 Page 3 of 371

2.0 REFERENCES

2.13 1(2)OP-26, Turbine System Operating Procedure 2.14 1(2)OP-30, Condenser Air Removal and Off Gas Recombiner System 2.15 1(2)OP-32, Condensate and Feedwater System Operating Procedure 2.16 1(2)OP-34, Extraction Steam System Operating Procedure 2.17 1(2)OP-35, Heater Drains, Vents, and Level Control Operating Procedure 2.18 1(2)OP-36, Moisture Separator Reheater and Moisture Separator Reheater Drains System Operating Procedure 2.19 1(2)OP-59, Hydrogen Water Chemistry System Operating Procedure 2.20 1(2)PT-01.11, Core Performance Parameter Check 2.21 OPT-14.1, Control Rod Operability Check 2.22 NEDO-32465-A Licensing Topical Report, Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology for Reload Applications.

NRC Generic Letter 94-02, Long-Term Solution and Upgrade of Interim Operating Recommendations for Thermal-Hydraulic Instability.

2.23 SOER 94-01, Non-conservative Decisions and Equipment Performance Problems Result in a Reactor Scram 2.24 LER 1-96-02-01 2.25 INPO SOER 84-2 Control Rod Mispositioning 2.26 GE SIL 614, Backup Pressure Regulator 2.27 GE SIL 644 Supplement 1, BWR Steam Dryer Integrity 2.28 NEDC-33075P, Detect and Suppress Solution-Confirmation Density Licensing Topical Report, GE Nuclear Energy Report Revision 3 January 2004 2.29 NCR 173772, Unit 2 Control Rod Misposition IOGP-12 Rev. 49 Page 4 of 371

3mO PRECAUTIONS AND LIMITATIONS 3.1 This procedure is to be used in accordance with the procedure compliance guidelines of OGP-01, Section 5.0.

3.2 IF desired to operate the plant below reactor recirculation minimum speed (approximately 22-28% in accordance with the COLR), THEN OGP-04 is to be used for power increases and OGP-05 is to be used for power decreases.

3.3 Reactor recirculation pumps should be operated in accordance with the Flow Control Operation Map. Care should be taken to avoid the regions of possible core thermal hydraulic instability, as specified in the COLR.

IR22 1 NOTE: Instability may be indicated by:

1. OPRM PBAlCDA ALARM, A-05 5-8 alarming

2. OPRM UPSCALE TRIP, A-OS 6-8 alarming

3. An increase in baseline APRM noise level. SRMs and SRM period meters may be oscillating at the same frequency. Instability is confirmed by selecting various control rods in different quadrants and observing sustained oscillations on the LPRMs at a peak to peak duration of less than 3 seconds; OR

4. LPRM or APRM upscale or downscale alarms being received; OR

5. Sustained reactor power oscillations.

3.4 The OPRM system monitors the LPRMs for indication of thermal-hydraulic instability when greater than or equal to 25% thermal power AND less than or equal to 60% recirculation flow. This system provides alarms AND automatic trips as applicable. IF the OPRM system is inoperable AND operation is within Region A, THEN an immediate manual scram is required.

IF the OPRM system is inoperable AND indications of thermal-hydraulic instability are present with operation within Region B, 5% Buffer Region, or the OPRM Enabled Region of the applicable Flow Control Operation Map, THEN an immediate manual scram is required.

IOGP-12 Rev. 49 Page 5 of 371

3.0 PRECAUTIONS AND LIMITATIONS 3.5 Recirculation Pumps A and B speed changes shall be operated in accordance with 1(2)OP-02.

3.6 WHEN increasing reactor power, THEN APRM GAFs shall be periodically monitored. IF found greater than 1.00, THEN power increases should be suspended AND the Unit SCO should be informed.

3.7 All rod select push buttons should be deselected whenever rod movement has stabilized to minimize select switch damage from overheating.

3.8 WHEN HWC is in service, THEN an open feedwater or condensate minimum flow/recirculation valve downstream of the HWC hydrogen injection point at the condensate booster pump suction will decrease the hydrogen concentration in the feedwater.

3.8.1 This situation decreases hydrogen concentration in the reactor water and the effectiveness of HWC. Extended operation in this situation should be avoided as much as practical.

3.9 Control rod withdrawal to the Full Out position in a sequence other than that called for in OGP-10 shall be documented on Attachment 1 (utilize additional copies, as necessary, to document rod movements).

3.10 To ensure control rods are correctly placed during reactor operation, a second licensed operator shall monitor control rod movement and shall document correct placement of control rods on the procedure controlling rod movement OGP-04, OGP-11, etc.

3.11 Momentarily depressing the increase or decrease pushbutton on the following controllers will cause the selected parameter to change in increments of 0.1 %. Continually depressing the increase or decrease pushbutton on the following controllers will cause the selected parameter to change at an exponential rate:

3.11.1 SULCV FW-LIC-3269, Control Station 3.11.2 RFPT A (B) SP CrL C32-S/C-R601A(B), Control Stations 3.11.3 MSTR RFPT SPIRX LVL CTL C32-S/C-R600, Control Station 3.12 Performance of 1(2)PT-01.11, Core Performance Parameter Check, is required within* 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reaching or exceeding 23°"" rated thermal power.

IOGP-12 Rev. 49 Page 6 of 371

3.0 PRECAUTIONS AND LIMITATIONS 3.13 IF a reactor feed pump is removed from service during End-Of-Cycle coast down, THEN OPT-37.2.1, Reactor Feed Pump Turbine Tests, is NOT required.

3.14 Failure to maintain RWCU at maximum flow and temperature, when operating at low power, reduces feedwater heating which may increase the thermal duty on the feedwater nozzles.

3.15 IF BOTH of the following conditions are met, THEN OGP-12 may be used as a reference without documentation with the concurrence of the Shift Superintendent:

NOTE: Alternate power verifications may be waived for power increases provided the following conditions are met.

3.15.1 Control rod movements are NOT required for the power change.

3.15.2 Power is maintained greater than 65%.

3.16 Reactor power is limited to 75 % (Unit 1), 69 % (Unit 2) with one reactor feed pump in service.

3.17 This procedure is used to perform downpowers and power increases without a complete shutdown. It is recognized that all steps of the procedure will not be performed. The Unit SRO may discard any pages of this procedure where there are no steps required to be performed. Any pages discarded should be documented in the Comments section.

4.0 PREREQUISITES 4.1 Reactor in Mode 1 with reactor recirculation pumps above minimum speed.

4.2 The Load Dispatcher concurs with loading plans.

IOGP-12 Rev. 49 Page 7 of 371

5.0 PROCEDURAL STEPS 5.1 Power Reduction Unit_ DatelTime Started / _

Initials 5.1.1 All applicable prerequisites listed in Section 4.0 are met.

NOTE: The following indications should be observed to verify proper response to decreased speed demand from a recirculation pump speed controller:

1. Recirculation pump speed decreases

2. Recirculation loop flow decreases.

3. Reactor power decreases NOTE: Process Computer Point B018 Total Core Flow and H12-P603 recorder 1/2B21-PDRlFR-R613 will read lower than WTCF as the stability region is approached. Computer Point WTCF is the primary indication of total core flow and should be used for stability region compliance.

NOTE: IF thermal power is changed more than 15% in one hour, THEN reactor coolant shall be sampled in accordance with TR 7.3.7.2 (ODCM Table 7.3.7-1, footnote c).

NOTE: The Shift Reactor Engineer will leave a completed copy of OENP-24.0, Form 2 with appropriate Power/Flow Map specified by COLR, in the Control Room for power reductions when the Reactor Engineer is NOT immediately available. These instructions should be designed for a rapid reduction in power and updated as control rod patterns change.

NOTE: Reactor feed pump suction flows should be maintained approximately the same during the power reduction.

5.1.2 IF final feedwater temperature reduction and pressure set adjustment has been implemented, THEN ENSURE plant configuration supports power reduction in accordance with OGP-13.

IOGP-12 Rev. 49 Page 8 of 371

5.0 PROCEDURAL STEPS Initials 5.1.3 PERFORM reactor power decreases, as directed by the Unit SCO, in accordance with the Reactor Engineer's recommendation by decreasing recirculation flow and inserting control rods in the sequence designated by OGP-10, Rod Sequence Checkoff Sheets or Attachment 1.

IOGP-12 Rev. 49 Page 9 of 371

5.0 PROCEDURAL STEPS Initials NOTE: RSHLV-1 and RSHLV-2 positions are indicated on MCC-TH and MCC-TL, respectively.

5.1.4 WHEN the HP turbine exhaust pressure decreases below 90 psig, THEN CONFIRM the following reheat steam high load valves go closed.

1. RSHLV-1

2. RSHLV-2 NOTE: IF steam pressure is decreased in the second stage tube bundles in compliance with 1(2)OP-36, Figure 1, THEN the cooldown rate limit will NOT be exceeded.

5.1.5 ADJUST Low Load Valve Panel Loaders at IR-TB-13 and IR-TB-14, as high pressure turbine exhaust pressure decreases to less than 90 psig, to decrease second stage tube bundle pressure in accordance with 1(2)OP-36, Figure 1.

IOGP-12 Rev. 49 Page 10 of 371

5.0 PROCEDURAL STEPS Initials NOTE: The Scram Reduction Task Force has recommended one RFPT be idled with one RFPT in service. This will reduce the time required for injections if the on-line RFPT should malfunction.

NOTE: IF condenser waterbox is isolated, THEN it is preferred to remove the RFPT which exhausts into that condenser.

5.1.6 WHEN reactor power is approximately 60% to 65%,

THEN REMOVE one reactor feed pump from service OR IDLE a reactor feed pump in accordance with 1(2)OP-32.

5.1.7 ENSURE VALVE CO-V49 INLET ISOLATION VALVE, CQ-V110, is open.

5.1.8 WHEN turbine load is between 450 and 550 MWe, THEN STOP one of the heater drain pumps.

5.1.9 CONFIRM the following associated discharge level control valve closes:

HEA TER DRAIN PUMP A DISCHARGE DEAERATORLEVELCONTROLVALV~

HD-LV-91-1 HEA TER DRAIN PUMP B DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-2 HEA TER DRAIN PUMP C DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-3 5.1.10 CHECK the remaining heater drain discharge level control valve stays throttled to maintain deaerator level between 45 and 59 inches.

IOGP-12 Rev. 49 Page 11 of 371

5.0 PROCEDURAL STEPS Initials 5.1.11 IF necessary, THEN THROTTLE OPEN DEAERA TOR FILL AND DRAIN VALVE, HD-V57, to control deaerator level between 45 and 59 inches as power is decreased.

5.1.12 WHEN reactor power is less than 50% AND one heater drain pump has been removed from service, THEN ADJUST SJAE CONDENSA TE RECIRCULATION VALVE, CO-FV-49, as necessary, to maintain condensate pump discharge pressure between 190 and 230 psig.

IOGP-12 Rev. 49 Page 12 of 371

5.0 PROCEDURAL STEPS Initials NOTE: The following steps are performed in accordance with recommendations from GE associated with minimizing release of corrosion product activity. The final heater drain pump in operation will be secured at a turbine load of 360 MWe at the discretion of the Unit SeQ, but in all cases by 200 MWe.

5.1.13 IF desired, THEN PERFORM the following at approximately 360 MWe:

NOTE: WHEN RFP recirculation valve is opened, a momentary decrease in feedwater flow may occur causing a momentary decrease in reactor vessel level.

1. PRIOR to removing the last operating Heater Drain Pump, PERFORM the following:

a. PLACE RFP A(B) RECIRC VLV, FW-FV-V46 (FW-FV-V47) control switch in OPEN.

b. CONFIRM RFP A(B) RECIRC VLV, FW-FV-V46 (FW-FV-V47) is open.

2. WHEN RPV level is stabilized, STOP the remaining heater drain pump.

3. CONFIRM the following associated discharge level control valve closes:

HEATER DRAIN PUMP A DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-1 HEA TER DRAIN PUMP B DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-2 HEATER DRAIN PUMP C DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-3 IOGP-12 Rev. 49 Page 13 Of37!

5.0 PROCEDURAL STEPS Initials

4. THROTTLE DEAERA TOR FILL & DRAIN VL V, HD-V57, as necessary to maintain deaerator level between 48 and 57 inches.

5. WHEN both heater drain pumps have been removed from service, THEN ADJUST SJAE CONDENSA TE RECIRCULATION VALVE, CO-FV-49, to maintain condensate pump discharge pressure 190 to 230 psig.

5.1.14 IF reactor power is to be reduced below 26% RTP, THEN CONTACT the Reactor Engineer.

IOGP-12 Rev. 49 Page 14 of 371

5.0 PROCEDURAL STEPS Initials 5.1.15 IF CMFLCPR > 1.00 OR CMAPRAT > 1.00, AND Reactor power is less than 26°A>, AND Core flow is less than or equal to 38.5 Mlbs/hr, THEN PERFORM 1(2)PT-01.11, Core Performance Parameter Check, to remove overly conservative CMFLCPR and CMAPRAT thermal limits.

5.1.16 IF recommended by the Reactor Engineer, THEN PERFORM a rod sequence exchange.

5.1.17 As directed by the Unit SCQ, INSERT OR WITHDRAW rods per the Reactor Engineer's recommendation to correct insert and withdrawal errors displayed by RWM.

5.1.18 IF generator gross electrical apparent power is reduced to 325 MVA, as seen by computer point U1(2)GENC027 or as determined by BESS, THEN REMOVE PSS from service by performing the following at PSS Control Cabinet

1. PLACE PSS CONTROL, PSSCS1, in DISABLE.

2. PLACE PSS ALARM BYPASS, PSSCS3, in BYPASS.

NOTE: WHEN RFP recirculation valve is opened, a momentary decrease in feedwater flow may occur causing a momentary decrease in reactor vessel level.

5.1.19 IF RFP A(B) RECIRC VLV, FW-FV-V46 (FW-FV-V47) was NOT opened previously, THEN PERFORM the following PRIOR to reaching 3.3 x 106 Ibm/hr:

1. PLACE RFP A(B) RECIRC VLV, FW-FV-V46 (FW-FV- V47) control switch in OPEN.

2. CONFIRM RFPA(B) RECIRC VL~ FW-FV-V46 (FW-FV-V47) is open.

IOGP-12 Rev. 49 Page 15 of 371

5.0 PROCEDURAL STEPS Initials 5.1.20 IF a heater drain pump is in-service at 200 MWe, THEN PERFORM the following:

1. STOP the remaining heater drain pump.

2. CONFIRM the associated operating discharge level control valve closes:

HEA TER DRAIN PUMP A DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-1 HEA TER DRAIN PUMP B DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-2 HEA TER DRAIN PUMP C DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-3

3. THROTTLE DEAERA TOR FILL AND DRAIN VAL VE, HD-V57, as necessary to maintain deaerator level between 48 and 57 inches.

4. WHEN both heater drain pumps have been removed from service, THEN ADJUST SJAE CONDENSA TE RECIRCULATION VALVE, CO-FV-49, to maintain condensate pump discharge pressure 190 to 230 psig.

IOGP-12 Rev. 49 Page 16 of 371

5.0 PROCEDURAL STEPS Initials NOTE: The following indications should be observed to verify proper response to decreased speed demand from a recirculation pump speed controller:

1. Recirculation pump speed decreases

2. Recirculation loop flow decreases

3. Reactor power decreases 5.1.21 REDUCE recirculation pump speeds to the low speed limit.

NOTE: IF total feedwater flow is less than 2.55 x 106 Ibm/hr, THEN Digital Feedwater Control System will automatically shift to 1 ELEM control.

5.1.22 IF required to stabilize feedwater flow (RFPT operation), THEN PERFORM the following:

1. ENSURE FW-FV-177/S0L VLV, FW-V10, is open.

2. OPEN FEDWA TER REC/RC TO CONDENSER VL V, FW-FV-177, to bypass approximately 1 x 106 Ibm/hr to the hotwell.

5.1.23 CONFIRM core thermal limits are within the prescribed limits of Technical Specifications.

IOGP-12 Rev. 49 Page 17 of 371

5.0 PROCEDURAL STEPS Initials DatelTime Completed _

Performed By (Print) Initials Reviewed By: _

Unit sca Comments:

IOGP-12 Rev. 49 Page 18 of 371

5.0 PROCEDURAL STEPS Initials 5.2 Power Increases Unit DatelTime Started- - - - - - I ----

5.2.1 All applicable prerequisites listed in Section 4.0 are met NOTE: The following indications should be observed to verify proper response to increased speed demand from a recirculation pump speed controller:

1. Recirculation pump speed increases

2. Recirculation loop flow increases

3. Reactor power increases NOTE: Turbine load should be increased in accordance with 1(2)OP-26, Figure 3.

NOTE: Procedural steps directing power increases may be performed concurrently with other steps of this procedure.

NOTE: IF thermal power is changed more than 150/0 in one hour, THEN reactor coolant shall be sampled in accordance with TR 7.3.7.2 (ODCM Table 7.3.7-1, footnote c).

NOTE: Process Computer Point 8018 total core flow and H12-P603 recorder 1/2821-PDRlFR-R613 will read lower than Process Computer Point WTCF as the stability region is approached. Computer Point WTCF is the primary indication of total core flow and should be used for stability region compliance.

IOGP-12 Rev. 49 Page 19 of 371

5.0 PROCEDURAL STEPS Initials 5.2.2 PERFORM Attachment 2 each 10°16 power change increment.

5.2.3 PERFORM power increases, as directed by the Unit seo, by withdrawing control rods in accordance with 1(2)OP-07 in the sequence designated by OGP-10, Rod Sequence Checkoff Sheets or Attachment 1 and increasing recirculation flow in accordance with Reactor Engineer's recommendation.

5.2.4 IF Digital Feedwater Level Control System is in 1-ELEM control, THEN swap to 3-ELEM control in accordance with 1(2)OP-32.

5.2.5 IF operating using FEEDWA TER RECIRC TO CONDENSER VL V, FW-FV-177, to stabilize feedwater flow, THEN CLOSE FEEDWA TER RECIRC TO CONDENSER VL V, FW-FV-177.

1. WHEN FEEDWA TER RECIRC TO CONDENSER VLV, FW-FV-177, is closed, THEN CLOSE FW-FV-177IS0L VLV, FW-V10.

IOGP-12 Rev. 49 Page 20 of 371

SuO PROCEDURAL STEPS Initials 5.2.6 PERFORM OPT-13.1, Reactor Recirculation Jet Pump Operability, prior to exceeding 25°;6 reactor power.

5.2.7 IF CMFLCPR > 1.00 OR CMAPRAT > 1.00, AND Reactor power is less than 26°;6, AND Core flow is less than or equal to 38.5 Mlbs/hr, THEN PERFORM 1(2)PT-01.11, Core Performance Parameter Check, to remove overly conservative CMFLCPR and CMAPRAT thermal limits.

5.2.8 WHEN reactor power is between 23°;6 and 28%,

THEN CONFIRM APRM GAFs are less than or equal to 1.00.

5.2.9 IF reactor power was decreased to less than 23%,

THEN PERFORM 1(2)PT-01.11, Core Performance Parameter Check, within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reaching or exceeding 23°;6 RTP.

NOTE: Heater drains recirculation should be conducted such that the system will be ready for forward pumping of the heater drains when turbine load reaches 200 MWe.

5.2.10 IF secured, THEN PLACE heater drains in the recirculation mode in accordance with 1(2)OP-35.

5.2.11 IF SJAE CONDENSA TE RECIRCULA TION VAL VE, CO-FV-49, is open, THEN THROTTLE as necessary to maintain condensate pump discharge pressure between 190 psig and 230 psig.

IOGP-12 Rev. 49 Page 21 of 371

5s0 PROCEDURAL STEPS Initials 5.2.12 WHEN generator gross electrical apparent power exceeds 325 MVA, as seen on computer point U1(2)GENC027 or as determined by BESS, THEN PLACE PSS in-service in accordance with 1(2)OP-27.

5.2.13 NOTIFY radwaste to perform the following:

1. PLACE CDDs, CFDs, and Master Flow Controllers in service as required.

2. PLACE hotweillevel control in feed and bleed in accordance with 1(2)OP-32, as desired.

5.2.14 ADJUST Low Load Valve Panel Loaders at IR-TB-13 and IR-TB-14, as main turbine load increases, to increase second stage tube bundle pressure in accordance with 1(2)OP-36, Figure 1.

5.2.15 WHEN turbine load increases to between 200 MWe and 360 MWe, PERFORM the following:

1. PLACE heater drains in forward pumping in accordance with 1(2)OP-35.

IOGP-12 Rev. 49 Page 22 of 371

5.0 PROCEDURAL STEPS Initials NOTE: WHEN RFP A(B) RECIRC VALVE, FW-FV-V46(V47), is closed, THEN a momentary increase in feedwater flow may result causing a momentary reactor water level increase.

NOTE: Unit 1 Only: IF the high flow setpoint for RFP A (B) RECIRC VALVE, FW-FV-V46(V47) has not been exceeded, the recirc valve will not close when the switch is placed in AUTO.

NOTE: Unit 2 Only: IF the low flow setpoint for RFP A (B) RECIRC VALVE, FW-FV-V46(V47) has not been exceeded, the recirc valve will close when the when the control switch is held in CLOSE, but will reopen when the switch spring returns to AUTO.

5.2.16 WHEN feedwater flow is greater than 3.3 x 106 Ibm/hr AND heater drains are forward pumping, PERFORM the following:

1. Unit 1 Only: CLOSE RFP A (B) RECIRC VALVE, FW-FV-V46(V47), by placing the control switch to AUTO.

2. Unit 2 Only: CLOSE RFP A(B) RECIRC VALVE, FW-FV-V46(V47), as follows:

a. MOMENTARILY PLACE the control switch to CLOSE.

b. CONFIRM RFP A(B) RECIRC VALVE, FW-FV-V46(V47) is closed AND the control switch is in AUTO.

5.2.17 ADJUST SJAE CONDENSA TE RECIRCULA TION VALVE, CO-FV-49, as necessary, to maintain condensate pump discharge pressure between 190 and 230 psig.

5.2.18 WHEN turbine load reaches approximately 240 MWe, THEN ENSURE HP TURB 7TH STAGE EXHAUST DRAIN VL VS MVD-MOV-CA-4/3/1/2 are closed.

IOGP-12 Rev. 49 Page 23 of 371

5.0 PROCEDURAL STEPS Initials NOTE: The Turbine Stop Valve/Control Valve Fast Closure Reactor Scram MUST be enabled PRIOR to exceeding 260/0 RTP. This may be accomplished by annunciator and relay confirmation of automatic enabling OR by manually enabling this function by removing fuses.

5.2.19 PRIOR to 26% RTP (760 MWT), CONFIRM Turbine Stop Valve/Control Valve Fast Closure Reactor SCRAM is enabled by performing the following:

1. ENSURE TSVITCV MANUAL TRIP BYPASS switches are in NORMAL at Panel H12-P609:

C71(72)-S10A C71(72)-S10C

2. ENSURE TSVITCV MANUAL TRIP BYPASS switches are in NORMAL at Panel H12-P611:

C71(72)-S10B C71(72)-S10D

3. Unit 1 only: CONFIRM TURB CV FAST CLOS/SV TRIP BYPASS (A-OS, 6-7) is clear.

4. Unit 2 only: CONFIRM TURB CV FAST CLOS/SVIRPT TRIP BYPASS (A-OS, 6-7) is clear.

IOGP-12 Rev. 49 Page 24 of 371

5.0 PROCEDURAL STEPS Initials NOTE: The K9A-D relays are deenergized when they are at the stop screws.

5. CONFIRM relay C71A(72A)-K9A on Panel H12-P609 is deenergized.

6. CONFIRM relay C71A(72A)-K9C on Panel H12-P609 is deenergized.

7. CONFIRM relay C71A(72A)-K9B on Panel H12-P611 is deenergized.

8. CONFIRM relay C71A(72A)-K9D on Panel H12-P611 is deenergized.

NOTE: Removing the following fuses will deenergize relays C71A(72A)-K9A-D and enable the reactor scram on Turbine Stop Valve/Control Valve Fast Closure.

Confirmation of relay deenergization SHOULD be performed after each fuse is removed. (Prints- Unit 1: 1-FP-55046, Sh 6-9, 1-FP-55085, Sh 1,3, 1-FP-55086, Sh 1,3; Unit 2: 2-FP-50015, Sh 6-9, 2-FP-50607 Sh 1,3, 2-FP-50608, Sh 1,3.)

5.2.20 IF the Turbine Stop Valve/Control Valve Fast Closure scram is NOT enabled, THEN MANUALLY ENABLE this function prior to 26% RTP (760 MWT) by performing the following for the applicable unit:

1. Unit 1 only:

a. REMOVE fuse C71-F9A from Panel H12-P609. I Ind.Ver.

b. REMOVE fuse C71-F9C from Panel H12-P609. /

Ind.Ver.

C. REMOVE fuse C71-F98 from Panel H12-P611. /

Ind.Ver.

d. REMOVE fuse C71-F9D from Panel H12-P611. /

Ind.Ver.

e. CONFIRM TURB CV FAST CLOS/SV TRIP BYPASS (A-OS, 6-7) is clear.

IOGP-12 Rev. 49 Page 25 of 371

5.0 PROCEDURAL STEPS Initials NOTE: The K9A-D relays are deenergized when they are at the stop screws.

f. CONFIRM relay C71A-K9A on Panel H12-P609 is deenergized.

g. CONFIRM relay C71A-K9C on Panel H12-P609 is deenergized.

h. CONFIRM relay C71A-K9B on Panel H12-P611 is deenergized.

i. CONFIRM relay C71A-K9D on Panel H12-P611 is deenergized.

2. Unit 2 only:

a. REMOVE fuse C72-F9A from Panel H12-P609. I Ind.Ver.

b. REMOVE fuse C72-F9C from Panel H12-P609. I Ind.Ver.

c. REMOVE fuse C72-F9B from Panel H12-P611. I Ind.Ver.

d. REMOVE fuse C72-F9D from Panel H12-P611. I Ind.Ver.

e. CONFIRM TURB CV FAST CLOSISVIRPT TRIP BYPASS (A-OS, 6-7) is clear.

NOTE: The K9A-D relays are deenergized when they are at the stop screws.

f. CONFIRM relay C72A-K9A on Panel H12-P609 is deenergized.

g. CONFIRM relay C72A-K9C on Panel H12-P609 is deenergized

h. CONFIRM relay C72A-K9B on Panel H12-P611 is deenergized.

i. CONFIRM relay C72A-K9D on Panel H12-P611 is deenergized.

IOGP-12 Rev. 49 Page 26 of 371

5.0 PROCEDURAL STEPS Initials NOTE: Installation of the C71 (72)F9A-D fuses should NOT energize the C71A(72A)K9A-D relays at this power level. Confirmation of relays remaining deenergized should be performed as each fuse is installed. IF retay(s) energize, THEN the Unit sca should be contacted immediately.

5.2.21 IF the Turbine Stop Valve/Control Valve Fast Closure scram was manually enabled, THEN PERFORM the following at approximately 35% reactor power for the applicable unit.

1. Unit 1 only:

a. INSTALL fuse C71-F9A in Panel H12-P609. I Ind.Ver.

b. INSTALL fuse C71-F9C in Panel H12-P609. I Ind.Ver.

c. INSTALL fuse C71-F98 in Panel H12-P611. I Ind.Ver.

d. INSTALL fuse C71-F9D in Panel H12-P611. I Ind.Ver.

2. Unit 2 only:

a. INSTALL fuse C72-F9A in Panel H12-P609. I Ind.Ver.

b. INSTALL fuse C72-F9C in Panel H12-P609. I Ind.Ver.

c. INSTALL fuse C72-F98 in Panel H12-P611. I Ind.Ver.

d. INSTALL fuse C72-F9D in Panel H12-P611. I Ind.Ver.

NOTE: The K9A-D relays are deenergized when they are at the stop screws.

3. CONFIRM relay C71A(72A)-K9A on Panel H12-P609 is deenergized.

4. CONFIRM relay C71A(72A)-K9C on Panel H12-P609 is deenergized.

5. CONFIRM relay C71A(72A)-K98 on Panel H12-P611 is deenergized.

IOGP-12 Rev. 49 Page 27 of 371

5.0 PROCEDURAL STEPS Initials 60 CONFIRM relay C71A(72A)-K9D on Panel H12-P611 is deenergized.

7. Unit 1 only: CONFIRM TURB CV FAST CLOSISV TRIP BYPASS (A-05, 6-7) is clear.

8. Unit 2 only: CONFIRM TURB CV FAST CLOSISVIRPT TRIP BYPASS (A-05, 6-7) is clear.

5.2.22 NOTIFY Radwaste to place additional COOs and CFDs in service as required.

5.2.23 ENSURE condensate booster pump discharge pressure is maintained greater than 380 psig.

5.2.24 WHEN reactor power exceeds 40%, THEN CONFIRM Circulating Water System operation is in conformance with NPDES restrictions in accordance with 1(2)OP-29, Figure 1.

5.2.25 START additional circulating water pumps as necessary in accordance with 1(2)OP-29 to maintain condenser vacuum.

5.2.26 WHEN heater drain tank level can NOT be maintained with only a single heater drain pump in service, THEN THROTTLE OPEN DEAERA TOR FILL & DRAIN VL V, HD-V57, as needed to permit additional power increase.

5.2.27 BEFORE starting a second heater drain pump OR increasing reactor power above 50%, ENSURE SJAE CONDENSA TE RECIRCULA TION VAL VE, CO-FV-49, is closed.

IOGP-12 Rev. 49 Page 28 of 371

5.0 PROCEDURAL STEPS Initials NOTE: As long as heater drain tank level can be maintained with only a single heater drain pump in service, it is acceptable to increase power.

5.2.28 IF desired, WHEN turbine load is between 450 and 550 MWe, THEN PLACE a second heater drain pump in service in accordance with 1(2)OP-35.

5.2.29 WHEN reactor power is greater than 50%, CLOSE VALVE CO-FV-49/NLET ISOLATION VALVE, CO- V11 0 to isolate SJAE CONDENSA TE RECIRCULATION VALVE, CO-FV-49.

WHEN reactor power is between 58% and 63 % ,

THEN CONFIRM APRM GAFs are less than or equal to 1.00.

NOTE: IF due, THEN reactor feed pump turbine tests OPT-37.2.1 and OPT-37.2.2 should be performed prior to placing the second reactor feed pump in service.

5.2.31 WHEN reactor power is between 60% and 65%

power, THEN PLACE a second reactor feed pump in service in accordance with 1(2)OP-32.

5.2.32 WHEN reactor power exceeds 65%, THEN ENSURE REHEAT STEAM HIGH LOAD VALVES, RSHLV-1 AND RSHL V-2, open.

5.2.33 WHEN reactor power is between 78% and 830/0, THEN CONFIRM APRM GAFs are less than or equal to 1.00.

~ NOTE: Control rod withdrawal to the Full Out position in a sequence other than that

~ called for in OGP-10 shall be documented on Attachment 1.

5.2.34 INCREASE reactor power as directed by the Unit SCQ, in accordance with the Reactor Engineer's recommendation.

IOGP-12 Rev. 49 Page 29 of 371

5.0 PROCEDURAL STEPS Initials 5.2.35 WHEN unit is at 100 0Jb maximum achievable reactor power, THEN ENSURE reactor pressure is at 1030 psig utilizing narrow range indication Computer Point 8015 (B016. may be used as an alternate indicator).

5.2.36 CONFIRM core thermal limits are within the prescribed limits of Technical Specifications.

5.2.37 IF this startup followed a shutdown or scram from a transient event that may have resulted in pressure loading of the steam dryer (such as SRV opening, turbine stop valve closure, or fast MSIV closure),

THEN INFORM Chemistry daily sampling of steam moisture content is required until dryer integrity is confirmed.

DatelTime Completed _

Performed By (Print) Initials Reviewed By: _

Unit sea COMMENTS:

IOGP-12 Rev. 49 Page 30 of 371

ATTACHMENT 1 Page 1 of 3 Control Rod Movement The purpose of this attachment is to document rod pattern prior to power change.

Complete the rod pattern or attach Display 810 edit 51 47 43 39 35 31 27 23 19 15 11 07 03 02 06 10 14 18 22 26 30 34 38 42 46 50 Unit Date_ _ Time_ _ Reviewed by Reactor Engineer _

Unit Date_ _ Time_ _ Reviewed by Unit sca _

IOGP-12 Rev. 49 Page 31 of 371

ATTACHMENT 1 Page 2 of 3 Control Rod Movement Page of ___ SRO Initials: _

Control Correct Rod If Applicable, Control Rod Licensed Overtravel Full Out Second Licensed Rod Selected and OPT-14.1 Position Operator Check* Position Operator Verified**** Completed*** Check**

/ To

WHEN a control rod is withdrawn to the Full Out position, either MAINTAIN the continuous withdrawal signal for at least 3 to 5 seconds OR APPLY a separate notch withdrawal signal, AND PERFORM the following rod coupling integrity check:

- CONFIRM ROD OVER TRA VEL (A-OS 4..2) annunciator does NOT alarm. (SR 3.1.3.5)

- CONFIRM rod full out light is not lost.

- CONFIRM rod position indication on the four-rod display indicates position 48.

- CONFIRM ROD DRIFT (A-05 3-2) annunciator does NOT alarm.

- VERIFY the rod reed switch position indicator corresponds to the control rod position indicated by the Full Out reed switch.

- - Applicable for control rods moved from intermediate to fully withdrawn position. Technical Specification SR 3.1.3.2 must be completed for these rods if NOT performed within the previous seven days. This surveillance requirement is NOT required to be performed until seven days after the control rod is withdrawn and thermal power is greater than the LPSP of RWM.

- - - Concurrent Verification of rod selection required prior to rod movement.

IOGP-12 I Rev. 49 I Page 32 of 37 1

ATTACHMENT 1 Page 3 of 3 Control Rod Movement Other Instructions DatelTime Completed _

Performed By (Print) Initials Reviewed By: _

Unit sea IOGP-12 Rev. 49 Page 33 of 371

ATTACHMENT 2 Page 1 of 3 Verification of Reactor Power Level Using Alternate Indications UNIT: _ DATE:

NOTE: This attachment is used to validate the heat balance at approximately 100/0 power increments.

1. OBTAIN valid Heat Balance (Display 820 or OPT-01.8D, Core Thermal Power Calculation) AND RECORD heat balance % power in Table 1.

20 OBTAIN LPRM % PWR (Display 861, Filtered LPRM Readings Edit) AND RECORD in Table 1.

TABLE 1 TIME APPROX. STEAM LPRM 0A> HEAT APRM INITIALS RX FLOW POWER BALANCE % GAFs POWER % POWER Power ~1.00 N/A TURBINE N/A N/A N/A N/A ON LINE 30%

40%

50°A>

60%

70%

800/0 90%

1000/0 Definitions for Table 1:

HEAT BALANCE - A calculation of core thermal power obtained by solving an energy balance on the reactor vessel. Valid heat balance calculations may be obtained from Display 820 edit or manually by performing OPT-01.8D, Core Thermal Power Calculation. Caution must be taken to ensure any failed sensors have valid substituted values.

LPRM % POWER - An alternate indication of reactor power calculated only on the process computer which is obtained by averaging calibrated LPRM readings.

STEAM FLOW - An alternate indication of reactor power obtained by correlating the total steam flow to a valid heat balance. Total steam flow can be obtained from process computer point B041, ERFIS points C32FA014, C32FA015, C32FA016, C32FA017, or RTGB indications C32-R603A, B, C, D on P603.

IOGP-12 Rev. 49 Page 34 of 371

ATTACHMENT 2 Page 2 of3 Verification of Reactor Power Level Using Alternate Indications

3. PERFORM the following to obtain Total Steam Flow (Mlb/hr):

Steam Line (A) (B) (C) (D)

(ERFIS) C32FA014 C32FA015 C32FA016 C32FA017 (P603) C32-R603A C32-R6038 C32-R603C C32-R603D Total Steam Flow =(A) + (8) + (C) + (D) = _

OR USE computer point 8041

4. PERFORM the following to log on to ERFIS at the ERFIS VT-200 terminal on the SRO's desk:

a. TYPE: SET HOST EC01 8 (EC02B)

OR SET HOST EC01A (EC02A)

b. TYPE: GEPACUSER at USERNAME prompt

c. TYPE: GEPAC at PASSWORD prompt NOTE: Typing MAN runs an interactive program called MAN_ALTDSP, which performs alternate power calculations based upon user supplied plant inputs.

Decimal points must be entered for all values. The equivalent % power output from this program will be used for the comparison in the next step.

IOGP-12 Rev. 49 Page 35 of 371

ATTACHMENT 2 Page 3 of 3 Verification of Reactor Power Level Using Alternate Indications NOTE: Typing NE runs an automatic program called NE_MAIN, which reads ERFIS computer points and automatically calculates the alternate power correlations for display. There are 7 screens in the program. The user can type "A" to advance from one screen to the next or the user can enter the number of the screen (1-7) he wishes to display next. The Alternate Power Display is screen 6. The user can enter "H" for online HELP. The user must enter HE" to EXIT the program.

d. TYPE: MAN (for manual input and enter data at screen prompts)

OR

e. TYPE: NE (for automatic input) and select screen 6 (type: 6).

5. RECORD STEAM FLOW alternate indication (% power) in Table 1 of this attachment using the value obtained from MAN or NE programs.

6. COMPARE the Heat Balance (0/0) with the other alternate indications (%).

7. IF the heat balance is greater than all alternate indications (conservative as is)

OR one or more alternate indications are within +/- 5% of the heat balance (normal acceptance), THEN power ascension may continue.

8. IF power ascension is NOT permitted, THEN CONTACT Reactor Engineering to account for the differences in agreement.

9. REPEAT the above steps at 10% increments until the reactor is at 100% power.

IOGP-12 Rev. 49 Page 36 of 371

REVISION

SUMMARY

Revision 49 adds steps to open/close RFP A (B) RECIRC VALVE, FW-FV-V46(V47) based on recommendations from engineering (EC 66310) and NCR 224388. Wording in note requiring sampling when thermal power changes exceed 15% in one hour revised to match wording in ODCM. Same note added to down power portion of procedure (PRR 214286). Steps added to isolate and un-isolate CO-FV-49 when power is greater than 50% increasing or decreasing (PRR 220976).

Revision 48 incorporates EC 60117, deleting all actions related to SRI.

Revision 47 incorporates editorial changes to allow pages to be discarded if not used and increase the number of available lines for individual rod motion documentation for .

Revision 46 updates Precautions and Limitations Section to include a step to address annotation of "last step performed" and "first step performed" to preclude the use of "N/A" for steps not performed. Attachment 1 was updated to add an additional line for recording data (PRR 203184). The CAPR and commitment annotations of Reference 2.29 were removed because the subsequent NCR assignment was downgraded from a CAPR to an ENHN (205988).

Revision 45 requires jet pump loop flows to be matched within 7.5 mlb/hr or 3.5 mlb/hr based upon total core flow.

Revision 44; incorporates a standardized description of a 'coupling integrity check' as a note in Attachment 1, Control Rod Movement. A formatting change is included to include page numbering and SRO initials in Attachment 1 for ease of tracking.

Revision 43 incorporates EC 62831 by removing the Unit 1 only regarding overly conservative thermal limit calculations by Powerplex under certain plant conditions so that the instructions apply for Unit 2 as well.

Revision 42 incorporates EC 59708, B1C16 Core Reload, adding new Cautions and steps for Unit 1 concerning overly conservative Powerplex thermal limit calculations under certain plant conditions.

Revision 41; changes reactor pressure at 100% power on Unit 1 to 1030 psig in Step 5.2.34 in accordance with EC 59217.

Revision 40 incorporates EC 62384, to add a Caution and revise a second Caution related to thermal limit penalties between 260/0 and 40% power with core flow greater than 65% and at all core flows when power is less than 260/0. Step 5.1.14 was also revised to remove the reference to core flow.

IOGP-12 Rev. 49 Page 37 of 371

8~4 Recovery from Scoop Tube Lockout c Continuous Use 8D4.1 Initial Conditions 1D Annunciator FLUID DRIVE A(B) SCOOP TUBE LOCK, 0 A-6 2-4 (A-7 1-6), is actuated.

2. Lockout bus power is avaiiableD 0

3. The cause of the scoop tube lockout has been corrected. 0

4. Plant conditions have stabilizedD 0 8.4.2 Procedural Steps

1. CHECK RECIRC RUNBACK A(B) light is off. 0

2. ADJUST the potentiometer on the affected RECIRC PUMP 2A(B) SPEED CONTROL until the speed demand signal has settled out and is nulled with the actual pump speed as required by the following guide-linesD

a. IF the lockout was MANUALLY initiated for a 0 SHORT duration with STABLE plant conditions then no adjustment is required.

bD IF step 8D4.2.2Da is NOT applicable THEN 0 REQUEST assistance from I&C in adjusting the controller to a nulled condition.

120P-02 Rev. 126 Page 59 of 1531

8.4.2 Procedural Steps

3. OBSERVE the affected pump speed, loop flow and core o flow for changes that would indicate a speed change when the scoop tube is unlocked.

NOTE: IF flow controller operation is unstable when the scoop tube lockout is reset, THEN it may be necessary to manually lock out the affected scoop tube.

4. PLACE SCOOP TUBE A (B) LOCK switch to RESET. o

5. CHECK flow conditions stable. o

6. CHECK annunciator FLUID DRIVE A (B) SCOOP TUBE o LOCK, A-6 2-4 (A-7 1-6), is clear.

7. WHEN both RecircUlation Pumps are reset, THEN o ADJUST flow as directed by the Unit SeQ.

120P-02 Rev. 126 Page 60 of 1531

Unit 2 APP UA-21 6-2 Page 1 of 1 DG-3 LO START AIR PRESS AUTO ACTIONS NONE CAUSES

1. Air compressor malfunction.

2. Air leaks on Starting Air System.

3. Circuit malfunctions.

OBSERVATIONS

1. Low starting air pressure indication on diesel generator control panel (less than 235 psig) .

2. LOW STARTING AIR PRESSURE alarm on local diesel generator control panel.

ACTIONS

1. Verify that diesel generator starting air compressors are running.

2. Check for air leaks.

3. Check for proper air compressor operation per OP-39, Diesel Generators.

4. If air leaks exist or a circuit malfunction is suspected, ensure that a WRjJO is prepared.

DEVICEjSETPOINTS DG-PSL-6536-3 (air pressure switch) 235 psig DG-PSL-6537-3 (air pressure switch) 235 psig POSSIBLE PLANT EFFECTS

1. Loss of diesel generator may result in technical specification LCO.

REFERENCES

1. 9527-LL-9358 - 15

2. Technical Specifications 3.8.1, 3.8.2

3. OP-39, Diesel Generators 12APP-UA-21 Rev. 19 Page 31 of 331

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

a. Two Unit 2 qualified circuits between the offsite transmission network and the *onsite Class 1E AC Electrical Power Distribution System;

b. Four diesel generators (DGs); and

c. Two Unit 1 qualified circuits between the offsite transmission network and the onsite Class 1E AC Electrical Power Distribution System.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

~-----------------------------~()TE----------------------------------------------------------

LCO 3.0.4.b is not applic~ble to DGs.

CONDITION REQUIRED ACTION COMPLETION* TIME A. --------------NOTE--------------- A.1 Restore Unit 1 offsite circuit 45 days Only.applicable when Unit 1 to OPERABLE status.

is in MODE 4 or 5.

One Unit 1 offsite circuit inoperable.

(continued)

Brunswick *Unit 2 3.8-1 Amendment No. 260 I

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. -------------~OTE:~-------------- B.1 Declare required feature(s) Immediately from

1. Only applicable when with no power available discovery of Unit 1 is in MODE 4 inoperable when the Condition B or 5. redundant required concurrent with feature(s) are inoperable. inoperability of

2. Condition B shall not be redundant required entered in conjunction feature(s) with Condition A.

Two Unit 1 offsite circuits inoperable due to one Unit 1 balance of plant circuit path to the downstream 4.16 kV emergency bus inoperable for planned maintenance.

AND AND 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months DG associated with the affected downstream B.2 Perform SR 3.8.1.1 for AND 4.16 kV emergency bus OPERABLE offsite inoperable for planned circuit(s). Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months maintenance. thereafter B.3 Restore both Unit 1 offsite 7 days circuits and DG to OPERABLE status. AND 10 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 2 3.8-2 Amendment No. 235 I

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

c. One offsite circuit inoperable C.1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for reasons other than OPERABLE offsite Condition A or B. circuit(s).

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND C.2 Declare required feature(s) 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from with no offsite power discovery of no available inoperable when offsite power to one the redundant required 4.16 kVemergency feature(s) are inoperable. bus concurrent with inoperability of redundant required feature(s)

AND C.3 Restore offsite circuit to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

10 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 2 3.8-3 Amendment No. 235 I

AC Soufces~perating 3~8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. One DG inoperable for 0.1 Perform SR 3.8.1.1 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months reasons other than OPERABLE offsite Condition B. circuit(s).

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND D.2 Declare required feature(s),. *4 hours from I supported" by the inoperabre discovery of DG, inoperable when the redundant required

Condition 0 concurrent with J

feature(s) are inoperable. inoperability of redundant required feature(s)

AND D.3.1 Determine OPERABLE 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months DG(s) are not inoperable due to common cause failure.

OR 0.3.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE DG(s).

0.4 Restore DG to OPERABLE 7 days status.

10 days from discovery of failure to meet LCO 3.8.1.a or b (continued)

Brunswick Unit 2 3.8-4 Amendment No. 235 t

AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. Two or more offsite circuits E.1 Declare required feature(s) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from inoperable for reasons other inoperable when the discovery of than Condition B. redundant required Condition E feature(s) are inoperable. concurrent with inoperability of redundant required feature(s)

/

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

F. One offsite circuit inoperable ----------------------NOTE------------------

for reasons other than Enter applicable Conditions and Condition 8. Required Actions of LCO 3.8.7, "Distribution Systems-Operating,"

AND when ConditionF is entered with no AC power source to any 4.16 kV One DG inoperable for emergency bus.

reasons other than -----------------------------------------

Condition B.

F.1 Restore offsite circuit to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OPERABLE status.

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

G. Two or more DGs G.1 Restore all but one DG to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months inoperable. OPERABLE status.

(continued)

Brunswick Unit 2 3.8-5 Amendment No. 235 I

AC Sources-Operating 3.8.1 A CTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME H. Required Action and H.1 Bein MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, S, C, D,E, F AND or G not met.

H.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months L One or more offsite circuits 1.1 Enter LCO 3.0.3. Immediately and two or more DGs inoperable.

OR Two or more offsite circuits and one DG inoperable for reasons other than Condition B.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power 7 days availability for each offsite circuit.

(continued)

Brunswick Unit 2 3.8-6 Amendment No. 235 I

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued)

SURVEILLANCE FREQUENCY SR 3.8.1.2 -------------------------NOTES--------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met.

3. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG starts from standby conditions and 31 days achieves steady state voltage 2 3750 V and ~ 4300 V and frequency 2 58.8 Hz and ~ 61.2 Hz.

(continued)

Brunswick Unit 2 3.8-7 Amendment No. 235 I

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.3 ----------------------------~()TES----------------------------------

1. DG loadings may include gradual loading.

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 3.8.1.2 or SR 3.8.1.7.

5. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG is synchronized and loaded and 31 days operates for ~ 60 minutes at a load ~ 2800 kW and

3500 kW.

SR 3.8.1.4 Verify each engine mounted tank contains ~ 150 gal of 31 days fuel oil.

SR 3.8.1.5 Check for and remove accumulated water from each 31 days

. engine mounted tank.

SR 3.8.1.6 Verify the fuel oil transfer system operates to transfer 31 days fuel oil from the day fuel oil storage tank to the engine mounted tank.

(continued)

Brunswick Unit 2 3.8-8 Amendment No. 235 I

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS continued)

SURVEILLANCE FREQUENCY SR 3.8.1.7 ----------------------------~()TES----------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG starts from standby condition and 184 days achieves, in ~ 10 seconds, voltage ~ 3750 V and frequency ~ 58.8 Hz, and after steady state conditions are reached, maintains voltage ~ 3750 V and::; 4300 V and frequency ~ 58.8 Hz and s 61.2 Hz.

(continued)

Brunswick Unit 2 3.8-9 Amendment No. 235 I

AC Sources-Operating 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.8 ----------------------------N()llE~---------------------------------

1. SR 3.8.1.8.a shall not be performed in MODE 1 or 2 for the Unit 2 offsite circuits. However, credit may be taken for unplanned events that satisfy this SR.

2. SR 3.8.1.8.a is not required to be met if the- unit power supply is from the preferred *offsite circuit.

3. A single test at the specified Frequency will satisfy this ~urveillance for both units.

Verify: 24 months

a. Automatic transfer capability of the unit power supply from the normal circuit to the preferred offsite circuit; and

b. Manual transfer of the unit power supply from the preferred offsite circuit to the alternate offsite circuit.

(continued)

Brunswick Unit 2 3.8-10 Amendment No. 235 t

AC Sources-Operating 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.9 ----------------------------NOlrES---------------------------------

1. This Surveillance shall not be performed in MODE 1, 2, or 3 for DG 3 and DG 4. However, credit may be taken for unplanned events that satisfy this SR.

2. If performed with the DG synchronized with offsite power, it shalf be performed at a power factor::; 0.9.

3. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG rejects a load greater than or equal to 24 months its associated core spray pump without tripping.

(continued)

Brunswick Unit 2 3.8-11 Amendment No. 235 i

AC Sources-Operating 3.8.1 SURVEILLANCE FREQUENCY

~()lrES---------------------------------

A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG's automatic trips are bypassed on an 24 months actual or simulated ECCS initiation signal except:

a. Engine overspeed;

b. Generator differential overcurrent; C. Low lube oil pressure;

d. Reverse power;

e. Loss of field; and.

f. Phase overcurrent (voltage restrained).

(continued)

Brunswick Unit 2 3.8-12 Amendment No. 235 I

AC Sources-operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY

N()lIES------------------------------~--

1. Momentary transients outside the load and power factor ranges do not invalidate this test.

2. A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify each DG operating at a power factor s 0.9 24 months operates for ~ 60 minutes loaded to ~ 3500 kW and s 3850 kW.

N()TES---------------------------------

A single test at the specified Frequency will satisfy this Surveillance for both units.

Verify a*n actual or simulated ECCS initiation signal is 24 months capable of overriding the test mode feature to return each DG to ready-to-Ioad operation.

(continued)

Brunswick Unit 2 3.8-13 Amendment No. 235 I

AC Sources-Operating 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.13 ----------------------------~()lrES---------------------------------

This Surveillance shall not be performed in MODE 1, 2, or 3 for the load sequence relays associated with DG 3 and DG 4. However, credit maybe taken for unplanned events that satisfy this SR.

Verify interval between each sequenced load block is 24 months within +/- 10% of design interval for each load sequence relay.

(continued)

Brunswick Unit 2 3.8-14 Amendment No. 235 I

AC Sources-Operating 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.14 ----------------------------NOllES---------------------------------

1. All DG starts may be preceded by an engine prelube period.

2. This Surveillance shall not be performed in MODE 1, 2, or 3 for DG 3 and DG 4. However, credit may be taken for unplanned events that satisfy this SR.

Verify, on actual or simulated loss of offsite power 24 months signal in conjunction with an actuator 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

~ 10.5 seconds,

2. energizes auto-connected emergency loads through load sequence relays,

3. maintains steady state voltage ~ 3750 V and ~ 4300 V,

4. maintains steady state frequency ~ 58.8 Hz and ~ 61.2 Hz, and

5. supplies permanently connected and auto-connected emergency loads for'

~ 5 minutes.

Brunswick Unit 2 3.8-15 Amendment No. 2351

RHRSW System 3.7.1 3.7 PLANT SYSTEMS 3.7.1 Residual Heat Removal Service Water (RHRSW) System Leo 3.7.1 TwoRHRSW subsystems shall be OPERABLE.

APPLICABILITY: MODES 1,2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. OneRHRSWpump A.1 Restore RHRSW pump to 14 days inoperable. OPERABLE status.

(continued)

Brunswick Unit .2 3.7-1 Amendment No. 260 I

RHRSW System 3.7.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One RHRSWsubsystem B.1 --------------~()TE--------------

inoperable for reasons other Enter applicable Conditions than ConditionA. and Required Actions of LeO 3.4.7, IlResidual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown,'- for RHR shutdown cooling made inoperable by RHRSW System..

~~----------------------------------

Restore RHRSW 7 days subsystem to OPERABLE status.

Ce Both RHRSW subsystems C.1 -------------~()TE--------------

inoperable. Enter applicable Conditions and Required Actions of LCO 3.4~7 for RHR shutdown cooling made inoperable by RHRSW System.

Restore one RHRSW 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months subsystem-to OPERABLE status.

(continued)

Brunswick Unit 2 3.7-2 Amendment No. 260

RHRSW System 3.7.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and 0.1 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 0.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.1.1 Verify each RHRSW manual, power operated, and 31 days 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.

Brunswick Unit 2 3.7-3 Amendment No. 233

BRUNSWICK NUCLEAR PLANT PLANT OPERATING MANUAL VOLUME XXI ABNORMAL OPERATING PROCEDURE UNIT o

OAOP-18.0 NUCLEAR SERVICE WA TER SYSTEM FAILURE REVISION 19 IOAOP-18.0 Rev. 19 I Page 1 of 11 I

1.0 SYMPTOMS 1.1 NUCLEAR HDR SERV WTR PRESS-LOW (UA-01 1-10) in alarm (Setpoint - 42 psig) 1.2 Nuclear Service Water (NSW) Header pressure, SW-PI-143-1, on Panel XU-2, less than 40 psig 1.3 NUCLEAR HDR SW PUMP A TRIP (UA-01 2-10) in alarm 1.4 NUCLEAR HDR SW PUMP B TRIP (UA-01 4-10) in alarm 1.5 CONV HDR SW PUMP A TRIP (UA-01 1-8) in alarm 1.6 CONV HDR SW PUMP B TRIP (UA-01 4-8) in alarm 1.7 CONV HDR SW PUMP C TRIP (UA-01 4-9) in alarm 1.8 No service water pumps operating as indicated on Panel XU-2 1.9 Both discharge valves open on any conventional service water (CSW) pump as indicated on Panel XU-2 or locally.

NOTE: High flows could indicate excessive usage, valve failure, pipe leak, or rupture down stream of the flow transmitter. Low flows could indicate the low SW header pressure problem is not caused by that component.

1.10 Service Water flow to RBCCW HX exceptionally high or low indicated on SW-FI-1158-1 on Panel XU-2 (normal flow is 2500-7200 gpm) 1.11 RHR SW flow exceptionally high or low indicated on E11-FI-R602A(B) on PanelP603 1.12 Floor drain high level alarms or flood status alarms if leak or rupture is possible cause 1.13 Plugged SW intake screens, trash racks, or SW pump discharge strainers 1.14 High NSW Header pressure approaching pump shutoff head (approximately 90 psig)

IOAOP-18.0 Rev. 19 Page 2 of 11 I

2.0 AUTOMATIC ACTIONS 2.1 NSW pump selected to AUTO starts AND discharge valve D opens.

2.2 CSW pump(s) selected to AUTO on the NSW Header starts D AND discharge valve to NSW Header opens 2.3 IF diesel generators are operating, THEN cooling water valves D may shift to the opposite unit NSW Header.

2.4 IF RHR SW pumps are operating on the NSW Header, THEN D the pumps may trip on low suction pressure.

3.0 OPERATOR ACTIONS 3.1 Immediate Actions None 3.2 Supplementary Actions 3.2.1 IF NSW Header pressure remains low after additional pumps are started, THEN PERFORM the following to reduce flow:

1. REDUCE service water flow to RBCCW heat D exchangers.

NOTE: A minimum flow rate of 4500 gpm is required for containment cooling during accident conditions.

2. REDUCE RHR SW flow. D IOAOP-18.0 Rev. 19 Page 3 of 11 I

3.0 OPERATOR ACTIONS NOTE: The diesel generator jacket water cooler outlet valves can be throttled to a minimum heat exchanger differential pressure of 2 psi.

3. IF diesel generators are operating, THEN THROTTLE the following valves while monitoring jacket water temperature:

JACKET WATER COOLER SERVICE WA TER D OUTLET VAL VE, 2-SW- V206 JACKET WA TER COOLER SERVICE WA TER D OUTLET VALVE, 2-SW-V207 JACKET WA TER COOLER SERVICE WA TER D OUTLET VAL VE, 2-SW-V208 JACKET WA TER COOLER SERVICE WA TER D OUTLET VAL VE, 2-SW-V209 3.2.2 IF NSW Header pressure is low from a known leak or pipe rupture, THEN PERFORM the following:

1. ISOLATE that section of piping, if possible. D

2. IF leak can NOT be isolated, THEN STOP all service D water pumps supplying the NSW Header.

3.2.3 IF a CSW pump indicates both of its discharge valves are D open, THEN CLOSE the discharge valve for the header NOT selected.

IOAOP-18.0 Rev. 19 Page 4 of 11 I

3DO OPERATOR ACTIONS 3.2.4 IF NSW Header pressure is low from a suspected leak or pipe rupture at an unknown location OR decreased service water pump availability, THEN PERFORM the following:

NOTE: The following steps isolate sections of the NSW Header in an attempt to restore the NSW Header pressure to greater than or equal to 40 psig. This isolation will start with sections that will have the least effect on existing plant conditions. The valves may be operated in any sequence desired to increase service water header pressure and to assist in tr0':Jbleshooting.

NOTE: Additional valve closure is NOT required if the source is identified and header pressure increases to greater than or equal to 40 psig.

1. MOMENTARILY CLOSE the following valves in an attempt to locate the source of the leak:

NUC SW TO VITAL HEADER VLV SW-V117 0 NUC SW SUPPL Y VLV, SW-V105 RBCCW HXS SW INLET VL V, SW-V103 OR 0 SW-V106 SW-V117 BYPASS LINE ISOLATION VLV, 0 SW-V340

2. IF desired to maintain SW-V117 closed, THEN OPEN 0 supply breaker MeC 1XB(2XB) DP2 to disable the auto open feature.

IOAOP-18.0 Rev. 19 Page 5 of 11 I

3.0 OPERATOR ACTIONS

3. IF isolation of the above listed components did NOT increase NSW Header to greater than or equal to 40 psig, THEN CLOSE the following valves:

a. 1-SW-V800, UNIT 1 DIESEL BLDG. SERVICE D WA TER SUPPL Y VALVE

b. 2-SW-V255, DIESEL BLDG. SERVICE WATER D SUPPLY VALVE

4. IF isolation of the above fisted components did NOT increase NSW Header to greater than or equal to 40 psig, THEN PERFORM the following:

a. ASSUME NSW Header rupture has occurred. D

b. STOP all service water pumps supplying the NSW D Header.

[]I] 3.2.5 IF NSW or CSW Header pressure approaches pump D shutoff head of approximately 90 psig, THEN ENSURE UNIT 1(2) SERVICE WATER OUTLET VALVE, 1(2)-SW-V442, is open.

3.2.6 IF service water to RBCCW is isolated OR service water D pumps supplying the NSW Header are tripped, THEN REFER to OAOP-16.0.

3.2.7 IF service water to the Diesel Generator Building is D isolated OR service water pumps supplying the NSW Header are tripped, THEN ENSURE the opposite unit is capable of supplying cooling.

3.2.8 IF service water to RHR is isoJated OR service water D pumps supplying the NSW Header are tripped, THEN ENSURE cooling water supplied from the CSW Header, if required.

3.2.9 IF service water to the vital header is isolated OR service D water pumps supplying the NSW Header are tripped, THEN ENSURE cooling water supplied from the CSW Header, if required.

IOAOP-18.0 Rev. 19 Page 6 of 11 I

3.0 OPERATOR ACTIONS 3.2.10 IF any diesel generator is operating, THEN PERFORM the following:

1. ENSURE cooling water supply valve to operating diesel D is open.

2. OBSERVE operating diesel generator service water D header pressure, SW-PI-153-1 (2, 3, 4), located on Engine Control Panel.

3. IF service water header pressure to the operating diesel D is less than or equal to 25 psig, THEN PERFORM the following:

a. DEPRESS AUTO-STOP push button to trip the D operating diesel.

b. IF loss of power to 4KV E buses occurs, THEN D REFER to OAOP-36.1.

c. IF off-site power is available, THEN ENERGIZE D the 4KV E buses in accordance with OOP-50.1.

3.2.11 IF the CSW Header is to supply additional loads, THEN D START additional CSW pumps as required.

3.2.12 IF the CSW Header is to supply RBCCW, THEN PERFORM the following:

1. CLOSE anyone of the following to isolate NSW to RBCCW:

RBCCW HX SERVICE WA TER INLET VAL VE, D SW-V103 RBCCW HX SERVICE WATER INLET VAL VE, D SW-V106 NUCLEAR HEADER TO RBCCW HEA T D EXCHANGER SUPPLY VALVE, SW-V193

2. OPEN CONVENTIONAL HEADER TO RBCCW HEA T D EXCHANGERS SUPPLY VALVE, SW-V146.

IOAOP-18.0 Rev. 19 Page 7 of 11 I

3.0 OPERATOR ACTIONS 3.2.13 IF fire protection water is needed for containment heat removal, THEN PERFORM the following:

1. CLOSE CONV SW SUPPL Y VL V, SW-V101. D

2. CLOSE NUC SW SUPPLY VLV, SW-V105. D

3. OPEN CONV-NUC HDR XTIE VL V, SW- V1 02. D

4. OPEN RHR SERVICE WA TER HEADER FLUSH D VALVE, SW-V140.

5. OPEN WELL WATER FLUSH TO SERVICE WATER D SHUT-OFF VALVE, WW-V203.

6. Unit 1 Only: UNLOCK AND OPEN FIRE PROTECTION D (WELL WA TER) TO SERVICE WA TER FLUSH SHUT-OFF VALVE, 2-FP-PIV20.

7. Unit 2 Only: UNLOCK AND OPEN FIRE PROTECTION D (WELL WA TER) TO SERVICE WA TER FLUSH SHUT-OFF VAL VE, 2-FP-PIV10.

8. PLACE E11-F068A(B) INTERLOCK BYPASS keylock D switch, E11-CS-5607A(B), in BYPASS.

NOTE: Maximum heat removal per Ibm of fire protection water is achieved by maximizing RHR flow and minimizing fire protection water flow.

NOTE: Design flow for the Electric and Diesel Fire Pumps is 2000 gpm each.

9. THROTTLE OPEN RHR HEA T EXCHANGER A (B) D SERVICE WATER DISCHARGE VALVE, E11-PDV-F068A(B), to obtain the desired flow rate.

10. MONITOR AND CONTROL Fire Protection Tank level to D maintain level above 27 feet 6 inches.

IOAOP-18.0 Rev. 19 Page 8 of 11 I

3.0 OPERATOR ACTIONS 3.2.14 IF AC power is NOT available to the NSW pumps, OR pumps will NOT start, THEN PERFORM the following:

1. IF affected pump's 4KV E bus is de-energized, THEN o REFER to OAOP-36.1.

2. ENSURE discharge valve on all non-operating NSW pumps are fUlly closed.

o NOTE: Pump breaker indicating lights illuminated indicates that control power fuses are NOT blown.

3. IF the affected pump's 4KV E bus is energized, THEN 0 CHECK each affected pump breaker for tripped electrical protection devices and for blown control power fuses.

3.2.15 IF low NSW Header pressure appears to be from 0 plugged service water trash racks, screens, or discharge strainers, THEN wash the screens AND NOTIFY maintenance to clean trash racks.

3.2.16 IF the NSW Header or portions of the header are no 0 longer in service, THEN REFER to Technical Specification 3.7.2.

3.2.17 RESTORE normal system operation in accordance with 0 plant operating procedures as plant conditions permit.

IOAOP-18.0 Rev. 19 Page 9 of 111

4.0 GENERAL DISCUSSION The Nuclear Service Water System is used primarily for removing heat from the RHR System, diesel generators, and RBCCW Systems. The safety objective of the system is to serve as a heat sink for the general cooling requirements of the RHR heat exchangers, RHR service water booster pumps, RHR seal coolers, Core Spray, and RHR room coolers, and the diesel generator coolers. This system also serves as a backup for core flooding.

5.0 REFERENCES

5.1 Technical Specification 3.7.2 5.2 OAOP-16.0, RBCCW System Failure 5.3 OAOP-36.1, Loss of Any 4KV Buses or 480V E Buses 5.4 OOP-50.1, Diesel Generator Emergency Power System Operating Procedure 5.5 IER #92-21-03(IFI); FACTS #93B9034 6.0 ATTACHMENTS None IOAOP-18.0 Rev. 19 Page 10 of 11 I

REVISION

SUMMARY

Revision 19 incorporates EC 55373, Fire Pump Nomenclature Change.

Revision 18 is an editorial correction to replace the Desdemona font used for check-off boxes.

Revision 17 - Incorporated editorial and format changes as follows, changed cover page logo, removed cover page bar code, changed to Word XP format, added place keeping aid to Sections 2.0 and 3.0, and made minor grammatical changes for format and clarity.

Revision 16 added SW-V340, SW-V117 BYPASS LINE ISOLATION VALVE to Supplementary Actions as an additional valve to close to isolate a suspected leak on the Nuclear Service Water Header - Vital Header, added step to disable SW-V117 from auto opening updated Tech Spec References for ITS, and upgraded the format to OAP-005 standards.

Revision 15, clerical revision due to conversion of procedure from WordPerfect 5.1 DOS to Microsoft Word 7.0.

IOAOP-18.0 Rev. 19 Page 11 of 11 I

Unit 2 APP UA-17 6-1 Page 1 of 2 BUS E3 4KV MOTOR OVLD AUTO ACTIONS NONE CAUSE

1. Motor overload in one of the following motors:

a. RHR Pumps lA and/or 2A (Breakers AI8 and AJl)

b. RHR SW Pump 1A and/or 2A (Breakers AI9 and AI7)

c. Core Spray Pump 2A (Breaker AI6)

d. CRD Pump 2A (Breaker AJ2)

e. Conventional Service Water Pump 2A (Breakers AJ4)

f. Nuclear Service Water Pump 2A (Breaker AJ3)

2. Circuit, electrical, or mechanical malfunction OBSERVATIONS

1. Annunciator CORE SPRAY PUMP 2A OVERLOAD (A-Ol 6-6).

2. Annunciator RHR SW PUMP 2A OVERLOAD (A-Ol 2-9).

3. Annunciator RHR PUMP 2A OVERLOAD (A-Ol 4-8).

4. Unit 1 Annunciator RHR SW PUMP lA OVERLOAD (A-Ol 2-9).

5. Unit 1 Annunciator RHR PUMP 1A OVERLOAD (A-01 4-8) .

ACTIONS

1. Direct Auxiliary Operator to Bus E3 switchgear to confirm which pump has an overload condition.

2. If in other than an emergency condition, shift to alternate equipment, if feasible, per applicable operating procedure.

3. If applicable, refer to appropriate annunciator and operating procedure for further action.

DEVICE/SETPOINTS 51 Reference respective equipment annunciators 12APP-UA-17 Rev. 25 Page 41 of 491

Unit 2 APP UA-17 6-1 Page 2 of 2 POSSIBLE PLANT EFFECTS

1. Loss of essential equipment during an emergency condition.

2. Severe damage to motors of applicable pumps.

3. Loss of safety equipment may result in a Technical Specification LCO.

REFERENCES

1. LL - 93 5 8 - 8

2. LL-9047 - 49

3. lAPP A-01

4. 2APPA-01 12APP-UA-17 Rev. 25 Page 42 of 491

Unit 2 APP UA-01 1-10 Page 1 of 2 NUCLEAR HDR SERV WTR PRESS-LOW AUTO ACTIONS 1.. If the nuclear service water header pressure decreases to 40 psig, the standby nuclear service water pump selected to AUTO will start..

2.. If a standby conventional service water pump is selected to the nuclear header and AUTO and the nuclear header pressure decreases to 40 psig, then that conventional service water pump will start..

CAUSE 1.. Nuclear or conventional service water pump tripped..

2.. Nuclear or conventional service water pump strainer clogged .

3.. Improper valve alignment

4. System piping failure .

5. Circuit malfunction.

OBSERVATIONS 1.. NUCLEAR HDR SW PUMP A(B) TRIP [UA-01 2-10(4-10)] alarm .

2.. Service water nuclear header pressure, as indicated on SW-PI-143-1 on RTGB Panel XU2, indicating less than or equal to 42 psig .

3.. NUC SW PUMP STRAINER A(B) DIFF-HIGH [UA-01 3-10(5-10)] alarm .

ACTIONS 1.. If the standby service water pump did not automatically start, start the pump .

2.. If the service water pump strainer is not automatically backwashing, start the strainer backwashing .

3.. Check the valve lineup..

4.. If a circuit or equipment malfunction is suspected, ensure that a WR/JO is prepared .

5.. If the nuclear service water header pressure cannot be maintained above 40 psig, refer to OAOP-18, Nuclear Service Water System Failure .

DEVICE/SETPOINTS Pressure Switch SW-PSL-142 42 psig 12APP-UA-01 Rev.. 57 Page 22 of 1021

Unit 2 APP UA-01 1-10 Page 2 of 2 POSSIBLE PLANT EFFECTS

1. Reduced cooling capability of systems using nuclear service water.

REFERENCES

1. LL-9352 - 22

2. OAOP-18, Nuclear Service Water System Failures

3. APP UA-01 2-10 (4-10), NUCLEAR HDR SW PUMP A (8) TRIP

4. APP UA-01 3-10 (5-10), NUC SW PUMP STRAINER A (8) DIFF-HIGH 12APP-UA-01 Rev. 57 Page 23 of 1021

Unit 2 APP UA-01 2-10 Page 1 of 2 NUCLEAR HDR SW PUMP A TRIP AUTO ACTIONS

1. If the nuclear service water header pressure decreases to 40 psig, the standby nuclear service water pump selected to AUTO will start.

2. If a standby conventional service water pump is selected to the nuclear header and AUTO and the nuclear service water header decreases to 40 psig, that conventional service water pump will start.

CAUSE

1. Overcurrent (12 amps with 12 second time delay, 20 amps instantaneous).

2. Circuit malfunction.

OBSERVATIONS

1. Nuclear Service Water Pump A status light, as indicated on RTGB Panel XU2, turns green.

2. Nuclear service water header pressure, as indicated on SW-PI-143-1 on RTGB Panel XU2, decreasing.

3. If the nuclear service water header pressure decreases to 42 psig, NUCLEAR HDR SERV WTR PRESS-LOW (UA-01 1-10) alarm.

ACTIONS

1. If the standby nuclear or conventional service water pump did not automatically start, start the pump.

2. If the vital service water header loses pressure due to the pump trip and cannot be restored, transfer the vital header supply to the conventional header.

3. Check the phase current transformers.

4. Check the lock-out relay.

5. Verify Nuclear Service Water Pump 2A discharge SW-V19 closes.

6. If a circuit or equipment malfunction is suspected, ensure that a WR/JO is prepared.

DEVICE/SETPOINTS Overcurrent Relays 50/51 12 amps with 12 second time delay 20 amps instantaneous Lock-out Relay 86 Relay 74 Energized

!2APP-UA-01 Rev. 57 Page 37 of 1021

Unit2 APP UA-01 2-10 Page 2 of 2 POSSIBLE PLANT EFFECTS

1. Reduced cooling capability of systems using nuclear service water.

2. If Nuclear Service Water Pump A is inoperable, a technical specification LCO may result.

REFERENCES

1. LL-9352 - 22

2. Technical Specification 3.7:'2

3. APP UA-01 1-10, NUCLEAR HDR SERV WTR PRESS-LOW 12APP-UA-01 Rev. 57 Page 38 of 1021

BRUNSWICK NUCLEAR PLANT PLANT OPERATING MANUAL VOLUME XXI ABNORMAL OPERATING PROCEDURE UNIT 2

2AOP-03.0 POSITIVE REA CTIVITY ADDITION REVISION 9 12AOP-03.0 Rev. 9 Page 1 of 121

1.0 SYMPTOMS 1~ 1 An unexpected or unexplained rise in reactor power indicated by the J

following:

- Rising neutron flux level

- Positive reactor period

- Rod block

- LPRM UPSCALE (A-06 1-8) is in alarm

- APRM UPSCALE (A-06 2-8) is in alarm OPRM PBAlCDA ALARM (A-OS 5-8) is in alarm OPRM UPSCALE TRIP (A-OS 6-8) is in alarm.

2DO AUTOMATIC ACTIONS Possible reactor scram due to high neutron flux.

12AOP-03.0 Rev. 9 Page 2 of 121

300 OPERATOR ACTIONS 3.1 Immediate Actions NOTE: IF possible, when changing core flow with two reactor recirculation pumps operating, maintain pump speed and jet pump loop flow mismatch within the allowable limit. Operation outside the mismatch limits is addressed in Step 3.2.10.

3.1.1 IF necessary to prevent a reactor scram, THEN D REDUCE reactor power in accordance with OENP-24.0, Form 2, Immediate Reactor Power Reduction Instructions.

3.1.2 IF reactor recirculation pump speed is rising, THEN PLACE the affected pump{s) SCOOP TUBE A (B) LOCK o

switch to TRIP.

3.1.3 IF HPCI OR RCIC is injecting AND operation is NOT D required, THEN SECURE the system as necessary.

!2AOP-03.0 Rev. 9 Page 3 of 121

3.0 OPERATOR ACTIONS 3.2 Supplementary Actions NOTE: Reactor recirculation pump speed and jet pump loop flow mismatch should be maintained within the following limits:

- 20% speed and jet pump loop flows within 10% (maximum indicated 6 6 difference 7.5 x10 Ibs/hr) with total core flow less than 58x10 Ibs/hr

- 10 % speed and jet pump loop flows within 50/0 (maximum indicated 6

difference 3.5 x10 Ibs/hr) with total core flow greater than or equal to 6

58x10 fbs/hr NOTE: Process Computer Point U2CPWTCF, when validated, is the primary

_indication of total core flow, and should be used for stability region compliance. If U2CPWTCF is invalid, U2NSSWDP or Attachment 1 may be used as an alternate indication of total core flow based on Core Plate dp.

NOTE: As the stability region is approached, Process Computer Point B018, Total Core Flow, and recorder 2B21-PDR/FR-R613, located on H12-P603, will read lower than Process Computer Point U2CPWTCF.

NOTE: The following computer screens may be used for reference:

- 802, Power/Flow - OPRM Operable - TLO

- 803, Power/Flow - OPRM Inoperable - TLO

- 804, Power/Flow - OPRM Operable - SLO

- 805, Power/Flow - OPRM Inoperable - SLO

- 806, Power/Flow - OPRM Operable - FWTR

- 807, Power/Flow - OPRM Inoperable - FWTR.

NOTE: Operation outside the analyzed regions of the power to flow map should be minimized.

3.2.1 PERFORM the following to determine the current operating point on the applicable Power-Flow Map:

1. IF reactor recirculation pump speed AND jet pump loop D flow mismatch is within the allowable limits, THEN DETERMINE the current operating point using the applicable Power-Flow Map, as specified by OENP-24.0.

12AOP-03.0 Rev. 9 Page 4 of 121

3.0 OPERATOR ACTIONS

2. IF reactor recirculation pump speed OR jet pump loop flow mismatch is NOT within the allowable limits, OR the plant is in single loop operation, THEN PERFORM the following:

NOTE: To compensate for signal noise, an average of several core DP readings should be used. Process Computer Point 8017 or ERFIS point 821 DA014 is the preferred method for obtaining this average.

a. IF a valid total core flow is NOT available from D U2CPWTCF OR U2NSSWDP, THEN DETERM.INE total core flow using Attachment 1.

DETERMINE the current operating point using the D applicable Power-Flow Map, as specified by OENP-24.0.

3.2.2 IF OPRM System is operable AND the current operating point is in the Scram Avoidance Region, THEN use one of the following methods to immediately exit the region:

6 NOTE: Total core flow should NOT exceed 45 x 10 Ibs/hr (58%) in single loop operation.

NOTE: IF possible, when changing core flow with two reactor recirculation pumps operating, maintain pump speed and jet pump loop flow mismatch within the allowable limit. Operation outside the mismatch limits is addressed in Step 3.2.10.

RAISE core flow. D INSERT control rods in accordance with D OENP-24.0, Form 2, Immediate Reactor Power Reduction Instructions.

12AOP-03.0 Rev. 9 Page 5 of 121

3.0 OPERATOR ACTIONS 3.2.3 IF the temperature differential between the coolant within D the dome and the bottom head drain can NOT be maintained less than 145°F during the performance of this procedure, THEN INSERT a manual reactor scram.

3.2.4 IF OPRM System is inoperable, THEN PERFORM the following:

1. IF either of the following conditions are met, THEN INSERT a manual reactor scram:

The current operating point is in Region A D NOTE: Instability may be indicated by any of the following:

- OPRM PBAICDA ALARM (A-05 5-8) is in alarm

- OPRM UPSCALE TRIP (A-05 6-8) is in alarm

- A rise in baseline APRM noise level. SRM power level and period meters may also be oscillating at the same frequency

- LPRM and/or APRM upscale or downscale alarms being received Sustained reactor power oscillations with a peak to peak duration of less than 3 seconds.

Indications of thermal hydraulic instability exist D AND the current operating point is in Region B, the 5% Buffer Region, or the OPRM Enabled Region.

12AOP-03.0 Rev. 9 Page 6 of 121

3.0 OPERATOR ACTIONS

2. IF the current operating point is in Region S, THEN use one of the following methods to exit the region:

6 NOTE: Total core flow should NOT exceed 45 x 10 Ibs/hr (58%) in single loop operation.

NOTE: IF possible, when changing core flow with two reactor recirculation pumps operating, maintain pump speed and jet pump loop flow mismatch within the allowable limit. Operation outside the mismatch limits is addressed in Step 3.2.10.

RAISE core flow. D INSERT control rods in accordance with D OENP-24.0, Form 2, Immediate Reactor Power Reduction Instructions.

NOTE: Operating time in the 50/0 Buffer Region should be minimized.

3. IF the current operating point is in the 50/0 Buffer Region, D THEN INCREASE monitoring nuclear instrumentation for thermal hydraulic instability.

3.2.5 NOTIFY the duty Reactor Engineer. D

@] 3.2.6 MONITOR individual LPRM bar graphs from RBM ODAs D or PPC for reactor power oscillations.

@] 3.2.7 MONITOR the following for reactor power oscillations:

APRMs D SRMs D SRM period meters D 12AOP-03.0 Rev. 9 Page 7 of 121

3~O OPERATOR ACTIONS 3.2.8 MONITOR core thermal parameters AND ADJUST the following per the Reactor Engineer's recommendations:

Rod position D Reactor recirculation pump speed D 3.2.9 IF OPRM System is inoperable AND entry into the 5% D Buffer Region is required, THEN INCREASE monitoring nuclear instrumentation for thermal hydraulic instability.

IF reactor recirculation pump speed OR jet pump loop flow mismatch is outside the allowable limits, THEN DECLARE the pump with lower speed inoperable in accordance with Tech Spec 3.4.1 AND THEN PERFORM one of the following:

1. IF possible without violating thermal limits, AND while D maintaining reactor power less than or equal to 100%,

THEN RAISE the speed of the slower pump.

2. PERFORM the following to attempt to lower the speed of D the faster pump:

a. LOWER the demand signal to the affected reactor D recirculation pump.

b. UNLOCK the scoop tube. D

c. IF the reactor recirculation pump speed does NOT D lower, THEN LOCK the scoop tube.

d. EVALUATE local operation of the scoop tube D from the Baily positioner in accordance with the applicable section of 20P-02.

12AOP-03.0 I Rev. 9 Page 8 of 12 1

3.0 OPERATOR ACTIONS 302011 IF reactor recirculation pump speed OR jet pump loop D flow mismatch is outside the allowable limits, AND the allowable mismatch can NOT be restored, AND the Unit sca determines to SECURE the affected pump, THEN;

a. ESTABLISH conditions that will NOT place the D core in an undesirable position on the applicable Power-Flow Map after securing the pump.

b. SECURE the affected pump in accordance with D 20P-020 3.2.12 RESTORE reactor power to less than or equal to 1000/0. D 302.13 MONITOR off-gas radiation AND NOTIFY E&RC to take D coolant samples to determine if fuel element failure has occurredo 3.2~ 14 IF feedwater heating has been lost, THEN REFER to the following Operating Procedures:

201-03.2 note MM, to evaluate feedwater D temperature for operation with applicable Power/Flow map and MCPR restrictions 20P-35, to evaluate feedwater heater D performance 20P-32, to remove feedwater heaters from service D and confirm operations within design values.

@] 3.2~ 15 INITIATE a Condition Report for any control rod found D out of intended position.

!2AOP-03.0 Revo 9 Page 9 of 121

4&0 GENERAL DISCUSSION Positive reactivity insertion will cause an increase in reactor thermal power. Some of the causes of cold water addition are loss of feedwater heating, raising the speed of a reactor recirculation pump, control rod drop, and inadvertent HPCr or RCrC initiation. The severity of this transient is determined by how long the abnormally high power level is sustained, especially on a loss of feedwater heating.

The OPRM system provides alarms and automatic trips as applicable. If the OPRM System is inoperable, then Tech Specs require an alternate method to detect and suppress thermal hydraulic instability oscillations in accordance with BWR Owner's Group Guidelines for Stability Interim Corrective Action, June 6 1994. This requires three stability monitoring regions (Region A - manual scram, Region B immediate exit, and 50/0 Buffer).

5.0 REFERENCES

NEDO-32465-A, Licensing Topical Report: Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology for Reload Applicability GE Nuclear Energy, August 1996

(~ 5.2 SOER 84-2, Control Rod Mispositioning

@J 5.3 General Electric Service Information Letter No. 251/251, Supplement 1 6.0 ATTACHMENTS 1 Estimated Total Core Flow vs. Core Support Plate Delta-P 12AOP-03.0 Rev. 9 Page 10 of 121

ATTACHMENT 1 Page 1 of 1 Esttm,ated Total CoreFJowvs.Core SUpport Plate Delta Pfor B2C18 j I 27.0 l---.-"-----+-----+-.. --.-t--~+,--~---.+ . . --._+__--.-+-.. . -.-.......+--.._.....:_---*+----*-'7---*---*+-.. .- . . **-t-*--*-*---;.;-*-**~-----*~*** .---+----r---.4~---.+--- ........b"---I-,,{t%~A 26.0 I/IIIVI) 26.0 4-*--...,..'-***---**t** .._-..---+**-***.***;,--.......*--+--*..*----*....;... .*-----+*--*...-***j---*-**+------*-j-*--*--**.." ***-*******i:-*--***-*f**---*-**-..*+*..*..***--..+-----*--**;..**..*-----+-- ...--'i***.*-.....-f.--,-. .;.~_._... _f--- - ....:.f-.... *--I_If_;'~-f~:~**:~'I-*,;f;0

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20 25 30 35 40 45 50 55 65 10 75 80 85 Core Flow (IM~blhr) 12AOP-03.0 Rev. 9 Page 11 of 121

REVISION

SUMMARY

Revision 9 incorporates EC 60117 which deleted the select rod insert from Unit 2.

Revision 8 incorporates EC 62929 by updating the title of the core dIp attachment to B2C18.

Revision 7 adds jet pump loop flow limits to allowable recirc pump speed mismatch criteria.

Revision 6 addresses concerns identified in AR 180915 by addition of a step to allow the operators the option to use local operation of the scoop tube to control speed of the malfunctioning pump. Notes were added/revised to clarify operation of the reactor recirculation pumps with speeds outside the mismatch limits. A step was added to establish conditions that would not place the core in an undesirable condition following removal of the pump, if a decision has been made to secure the affected pump.

Revision 5 incorporates EC 46653 (child 62488) by adding PPC point U2NSSWDP as an alternate for determining total core flow. This revision also adds a caution that an idle recirc pump may not be restarted to exit the scram avoidance region.

Revision 4 incorporates EC 50100 by updating annunciator A-05 5-8 noun name to

'OPRM PDA/CDA ALARM' and EC 56472 by updating the core flow-core dIp figure for the current fuel cycle, update map numbers and add reference to 201-03.2 for evaluation of FW temperatures.

Revision 3 -Incorporated ED 55156 which adds computer screens 811 and 812 to Note prior to Step 3.2.1 and corrected nomenclature for screens 806, 807, 808, and 809.

Revision 2 - Format changes to meet the requirements of OAP-005 and Microsoft Word XP. This change does NOT implement an intent change. Additional administrative changes classified as "editorial": are bolding action verbs, italicizing components, change of cover page logo, removal of the "bar code" from the cover page, and adding place keeping aids.

Revision 1 incorporates EC 46720 Power Range Neutron Monitoring and EC 49331 B2C 16 Reload cord Design (figure 1).

Revision 0 separates the Unit 2 information steps from OAOP-03.0.

12AOP-03.0 Rev. 9 Page 12 of 121

~ Progress Energy BRUNSWICK NUCLEAR PLANT PLANT OPERATING MANUAL VOLUME XXI ABNORMAL OPERATING PROCEDURE UNIT o

OAOP-05.0 RADIOACTIVE SPILLS, HIGH RADIATION, AND AIRBORNE ACTIVITY REVISION 20 IOAOP-05.0 Rev. 20 Page 1 of 10 I

1.0 SYMPTOMS 1.1 AREA RAD REFUEL FLOOR HIGH (UA-03 3-7) is in alarm~

1.2 AREA RAD NEW FUEL STORAGE HIGH (UA-03 4-7) is in alarm.

1.3 PROCESS RX BLDG VENT RAD HI (UA-03 4-5) is in alarm.

1.4 TURB BLDG VENT RAD HIGH (UA-03 3-3) is in alarm.

1.5 Area Radiation Monitor (ARM) is in alarm.

1.6 Continuous Air Monitor (CAM) is in alarm.

'1.7 Turbine Building once-through effluent monitor indicates elevated activity.

1.8 Routine surveys indicate high radiation, contamination and/or airborne activity.

1.9 Report of spill, leak, br potential damage to new or spent fuel.

2.0 AUTOMATIC ACTIONS 2.1 IF PROCESS RX BLDG VENT RAD HI-HI (UA-03 3-5) is in alarm, THEN the following actions occur:

Reactor Building Ventilation isolation 0 SBGTS auto start 0 Group 6 Isolation. 0 3.0 OPERATOR ACTIONS 3.1 Immediate Actions IF a fuel assembly was dropped or damaged, THEN o ENSURE the Control Room Emergency Ventilation System (CREVS) is in operation.

IOAOP-05.0 Rev. 20 Page 2 of 10 I

3~O OPERATOR ACTIONS 3.2 Supplementary Actions 3.2.1 EVACUATE unnecessary personnel from the affected D area.

NOTE: Simultaneous or multiple actuations of fire alarms within the Reactor Building may provide additional indication of a High Energy Line Break (HELB).

NOTE: The Reactor Building Sprinkler System is required to be isolated within 15 minutes of indication of a HELB. Location of the system isolation valves has been provided below to expedite isolation:

FP-PIV45, Near Radwaste Building - Northeast Corner FP-PIV33, East end of the Unit 2 Reactor Building FP-V214, Deluge Valve Pit No.1 next to Unit 1 Reactor Building FP-V214, Deluge Valve Pit No.2 next to Unit 2 Reactor Building 3.2.2 IF a HELB is indicated in the Reactor Building, THEN PERFORM the following:

1. UNLOCK AND CLOSE UNIT 1(2) REACTOR BUILDING D SPRINKLER SHUTOFF VAL VE, 2-FP-PIV45(33).

IF additional sprinkler system isolation is required, THEN D UNLOCK AND CLOSE DELUGE VALVE 1(2)FP-DV20 SHUTOFF VALVE, 1(2)FP-V214.

IOAOP-05.0 Rev. 20 Page 3 of 10 I

3.0 OPERATOR ACTIONS 3.2.3 IF new or spent fuel damage is suspected, THEN PERFORM the following:

1. PLACE any fuel that is being moved in a safe condition. D

2. SECURE further fuel movement. D

3. EVACUATE personnel from the following areas:

Refueling Floor D Drywell, if occupied D Reactor Building, -17' Elev., if Shutdown Cooling in D service.

ECCS Pipe Tunnel D

- Any area determined to have the potential for high D radiation.

4. ISOLATE Secondary Containment. D

5. START Standby Gas Trains. D 3.2.4 NOTIFY E&RC to perform the following as necessary:

- Area radiation survey D

- Air sampling D Smear survey D Post the affected area as necessary D Control access to reduce exposure and D contamination.

IOAOP-05.0 Rev. 20 Page 4 of 10 I

3.0 OPERATOR ACTIONS 3.2.5 IF a spin has occurred during handling of spent resin, THEN PERFORM the following:

1. IF spill is located outside the Radwaste Building, THEN D CONTACT Security to control access to the North access road and the adjacent Protected Area fence until surveys are completed and the area released.

2. IF spill threatens to enter the Storm Drain System, THEN PERFORM the following:

ENSURE the Storm Drain Basin pumps are secured D CONTACT Chemistry to sample basin and approve D for release.

3.2.6 IF a solid or liquid spill has occurred AND radiation levels permit, THEN PERFORM the following:

1. ISOLATE the source. D

2. NOTIFY Health Physics. D

3. SECURE the area of the spill. D

4. MITIGATE the effects of the spill by use of absorbents, D dikes, covering, etc.

3.2.7 MONITOR ARMs, CAMs, and ventilation radiation monitors for the affected area .

NOTE: Unknown sources of radiation and contamination conditions in the Reactor Building may require giving considerations to terminating all refueling floor activities .

3.. 2.. 8 IF necessary, THEN PERFORM the following:

1.. PLACE any fuel that is being moved in a safe condition. D 2.. SECURE further fuel movement.. D IOAOP-05.0 Rev. 20 Page 5 of 10 I

3.0 OPERATOR ACTIONS 3.2.9 IF high airborne activity exists in occupied spaces, THEN PERFORM the following:

1. IF possible, THEN SECURE ventilation from the affected D area.

2. IF an evolution such as grinding, sampling, or valve D operation is causing the high airborne activity, THEN STOP the evolution.

3.2.10 IF high airborne activity exists in the Turbine Building AND the wide range gas monitor (WRGM) OR the once-through effluent monitor indicates an elevated activity, THEN PERFORM the following:

1. Unit 1: IF in Once-Through ventilation lineup, THEN D SHUTDOWN Turbine Building ventilation system per 10P-37.3.

2. Unit 2: IF in Once-Through ventilation lineup, THEN D PLACE Turbine Building ventilation system in Recirculation lineup per 20P-37.3.

3.2.11 IF high radiation fevels exist, THEN PERFORM the following:

1. INITIATE a search to locate and isolate the source of D any coolant or steam leak.

2. IF radiography is in progress, AND personnel are in D danger of abnormal exposure, THEN SECURE radiography.

3. ENSURE all personnel in the area monitor their D dosimetry and report unusual exposure to E&RC.

IOAOP-05.0 Rev. 20 Page 6 of 10 I

3.0 OPERATOR ACTIONS

4. IF fuel failure has occurred, THEN ISOLATE the following systems as necessary:

Reactor Water Cleanup D Main Steam Lines (MSIVs) D RHR Shutdown Cooling Mode. D WHEN directed by E&RC, THEN normal access may be D granted to areas evacuated.

IOAOP-05.0 Rev. 20 Page 7 of 10 I

4.0 GENERAL DISCUSSION Liquid radioactive spills may be caused by valve packing leaks, leaky fittings, system leaks, or system draining evolutions. Liquids spills should be covered with an absorbent material to minimize the spread of contamination. Solid spills may be caused by leaks from the containers or process streams which handle radioactive material or by an accident during the transport of new or spent fuel, radioactive sources, or other solid radioactive materials. Solid spills should be covered by a damp material to minimize the spread of airborne contamination. A spill of highly radioactive solid materials such as spent resin, filter sludge, neutron sources, or irradiated reactor internal components may create a serious personnel exposure problem and should be handled with extreme caution. In addition, high radiation and high airbo"rne activity may accompany a spill.

High airborne activity may occur from reactor coolant leaks, coolant spills, radwaste leaks, sampling, grinding, draining, and other maintenance. High airborne activity in the turbine buildings may require ventilation shutdown or realignment to the recirculation lineup if the ventilation systems are operating in the once-through lineup.

High radiation levels may be caused by radiation "streaming," loss of or degraded shielding, fuel element damage, high airborne activity, coolant spills, or radiography.

New or spent fuel damage may occur within the plant during fuel handling operations. Fuel may be damaged if it is inadvertently dropped or allowed to collide with objects. Damage may also be sustained if heavy objects (shipping casks, reactor vessel head, drywell head, etc.) are allowed to fall on the fuel.

These accidents may release a substantial amount of radioactive noble gases, halogens, and other fission products into the secondary containment. The secondary containment will be automatically isolated due to high radiation at its ventilation exhaust plenum. Although Standby Gas Treatment (S8GT) System will reduce the activity released to the environs, there is a chance that technical specification limits may be exceeded.

The dose consequence calculation for the fuel handling accident does not credit the secondary containment or automatic CREVS start, however, it does assume that CREVS is manually initiated within 20 minutes of a dropped/damaged fuel assembly. Based on this analysis, Technical Specifications do not require secondary containment or CREVS automatic initiation instrumentation except during Modes 1, 2, or 3 or during operations with the potential to drain the Reactor vessel.

IOAOP-05.0 Rev. 20 Page 8 of 10 I

4~O GENERAL DISCUSSION Personnel exposure hazards may be present from any of these conditions, and care must be taken to maintain exposure ALARA. Operator actions should be to prevent escalation of the accident and to minimize the spread of contamination.

Engineering developed the following criteria to help determine whether a fire condition or a high energy line break (HELB) is present.

If a HELB condition exists, then most (or all) of the fire alarms in the building will alarm in rapid succession (within seconds of each other). False fire alarm annunciators (without flow annunciations) can be triggered by the presence of steam in the atmosphere near the detectors.

If a fire condition exists, then fire alarms will initially be received in only one or a few areas and any subsequent alarms will annunciate as the fire spreads.

5.0 REFERENCES

5.1 ESR 01-00400, AST Implementation for Fuel Handling 6.0 ATTACHMENTS None IOAOP-05.0 Rev. 20 Page 9 of 10 I

REVISION

SUMMARY

Revision 20 - Clarified expectations for response to radioactive spills in Section 3.2.6.

Revision 19 - Editorial Correction to change font of place keeping check boxes.

Revision 18: Adds requirements for Turbine Building Ventilation lineup if high airborne activity exists in the Turbine Building. Moved caution at step 3.2.11 to before step 4.

Added additional information to the General Discussion section .

Revision 17 - Incorporated Editorial Change to move page break to place entire Step 3.2.3 on page 4.

Revision 16 -Incorporated AR121633 by adding additional areas to evacuate in Step 3.2.3.3 and adding Step 3.2.11 to allow personnel to re-enter area evacuated when directed E&RC Revision 15 - Format changes to meet the requirements of GAP-005 and Microsoft Word XP.

Revision 14 incorporated a substep to Section 3.1 to start CREVS in the event that a fuel assembly is dropped or damaged and added wording to Section 4.0 that the dose calculation assumes that CREVS is manually initiated within 20 minutes of a dropped fuel assembly and that CREVS automatic initiation instrumentation and secondary containment are only required in Modes 1, 2, or 3 or during operations with the potential to drain the vessel. Changes have been made in accordance with ESR 01-00400.

Revision 13 incorporates new supplemental operator actions required by BNP HP Technical Report, Resin Transfer and Storage in the Radwaste Processing Area.

IOAOP-05.0 I Rev. 20 Page 10 of 10 I

BRUNSWICK NUCLEAR PLANT PLANT OPERATING MANUAL VOLUME XXI ABNORMAL OPERATING PROCEDURE UNIT o

OAOP-30.0 SAFETY/RELIEF VALVE FAILURES REVISION 13 IOAOP-30.0 Rev. 13 Page 1 of 91

1.0 SYMPTOMS 1.1 SAFETY/RELIEF VALVE OPEN (A-03 1-10) is in alarm.

1.2 SAFETY OR DEPRESS VL V LEAKING (A-03 1-1) is in alarm.

1.3 Open indication on Panel P601 for the affected safety/relief valve.

1.4 Process Computer Alarm Display indicating the affected safety/relief valve number.

1.5 Steam flow/feed flow mismatch with feed flow greater than steam flow.

1.6 Generator power decrease.

1.7 Reactor vessel level increase due to swell. Level may settle out at a lower value due to steam flow/feed flow mismatch.

1.8 Suppression pool level oscillation.

1.9 Suppression pool level increase.

1.10 Suppression pool temperature increase.

1.11 Safety/relief valve leak detection temperature, as read on 821- TR-R614 at Panel P614, indicates higher than normal for the affected safety/relief valve.

1.12 Safety/relief valve noise amplitude millivolt signal, as read on Fluid Flow Detector Cabinet CB-XU-73, indicates higher than normal for the affected safety/relief valve.

2.0 AUTOMATIC ACTIONS 2.1 IF Digital Feedwater Level Control System remains in 3 element control, THEN the system will establish an equilibrium reactor vessel water level below the original level.

2.2 IF Digital Feedwater Level Control System shifts to single element control, THEN reactor vessel level should return to approximately the original level.

2.3 The EHC system will reduce generator load as necessary to maintain reactor pressure.

IOAOP-30.0 Rev. 13 Page 2 of 91

3.0 OPERATOR ACTIONS 3.1 Immediate Actions 3.1 ~ 1 IF a safety/relief valve is stuck open, THEN PERFORM the following:

1. CYCLE the control switch of the affected safety/relief D valve to OPEN and CLOSE OR OPEN and AUTO several times.

2. ENSURE the affected safety/relief valve control switch is D left in CLOSE OR AUTO.

3.2 Supplementary Actions 3.2.1 IF suppression pool temperature increases to 110°F, THEN PERFORM the following:

1. INSERT a manual reactor SCRAM. D

2. REFER to 1(2)EOP-01-RSP. D 3.2.2 IF a safety/relief valve is stuck open, THEN PERFORM the following:

NOTE: Pulling safety/relief valve fuses will de-energize the red and green indicating lights on Panel P601.

1. PULL the fuses in the order listed in Attachment 1 for the D affected safety/relief valve.

MONITOR tailpipe temperatures using sonic readings on D Panel XU-73 to determine the safety/relief valve position.

IOAOP-30.0 Rev. 13 Page 3 of 91

3.0 OPERATOR ACTIONS

3. IF it is determined that the affected safety/relief varve can NOT be closed, THEN IMMEDIATELY PERFORM the following:

INSERT a manual reactor SCRAM 0 REFER to 1(2)EOP-01-RSP 0 MONITOR primary containment parameters 0 REFER to OAOP-14.0. 0 3.2.3 IF a safety/relief valve is leaking, THEN PERFORM the following:

1. MONITOR tailpipe temperatures. 0

2. MONITOR primary containment parameters. 0

3. REFER to OAOP-14.0. 0

4. IF leakage is causing the suppression pool temperature 0 to increase, THEN PLACE Suppression Pool Cooling in service in accordance with 1(2)OP-17, as necessary.

5. COMMENCE a reactor shutdown in accordance with 0 OGP-05, as necessary.

NOTE: Technical Specification 3.6.1.6.1 (Modes 1, 2, or 3) requires completion of OPT-02.3.1 b, Suppression Pool to Drywell Vacuum Breaker Position Check,

'within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after any discharge of steam to the suppression chamber from any source.

NOTE: A leaking/weeping SRV is NOT considered to be a discharge of steam to the suppression pool and does NOT require performance of SR 3.6.1.6.1 or SR 3.6.1.6.2.

3.2.4 IF in Mode 1,2, or 3, THEN ENSURE OPT-02.3.1 b, 0 Suppression Pool to Drywell Vacuum Breaker Position Check, is completed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after any discharge of steam to the suppression chamber from any source.

IOAOP-30.0 Rev. 13 Page 4 of 91

3.0 OPERATOR ACTIONS NOTE: Technical Specification 3.6.1.6.2 (Modes 1,2, or 3) requires completion of OPT-02.3.1, Suppression Chamber to Drywell Vacuum Breakers Operability Test, within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after any discharge of steam to the suppression chamber from the SRVs.

NOTE: A leaking/weeping SRV is NOT considered to be a discharge of steam to the suppression pool and does NOT require performance of SR 3.6.1.6.1 or SR 3.6.1.6.2.

3.2.5 IF in Mode 1, 2 or 3, THEN ENSURE OPT-02.3.1, D Suppression Chamber to Drywell Vacuum Breakers Operability Test, is completed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after any discharge of steam to the suppression chamber from the SRVs.

3.2.6 IF reactor depressurization occurred through an SRV D from normal operating pressure, THEN PERFORM an inspection of the drywell and the suppression pool in the area of the failed valve prior to startup.

IOAOP-30.0 Rev. 13 Page 5 of 91

4.0 GENERAL DISCUSSION This procedure describes the actions to be taken in the event an SRV fails to close after actuation or is found to be leaking by.

5.0 REFERENCES

5.1 1(2)EOP-01-RSP, Reactor Scram Procedure Flowchart 5.2 1(2)APP-A-03, Annunciator Procedure For Panel A-03 5.3 OGP-05, Unit Shutdown 5.4 OPT-02.3.1, Suppression Chamber To Drywell Vacuum Breakers Operability Test 5.5 OPT-02.3.1 b, Suppression Pool To Drywell Vacuum Breaker Position Check 5.6 OAOP-14.0, Abnormal Primary Containment Conditions 5.7 1(2)OP-17, Residual Heat Removal System Operating Procedure 5.8 Technical Specifications 3.6.1.6, 3.6.2.1 5.9 Regulatory Compliance White Letter on vacuum breakers and SRV discharge of steam; Mark Turkal, March 15, 2006 6.0 ATTACHMENTS 1 SRV Fuse Location/Number IOAOP-30.0 Rev. 13 Page 6 of 91

ATTACHMENT 1 Page 1 of 2 SRV Fuse Location/Number NOTE: The SRV fuses should be pulled in the listed order to ensure the power sensing relay is NOT required to shift.

Panel H12-P628 SRV Fuse Location E.P. Number B21-F013A CC-F25 821C-F7A CC-F34 821C-F8A CC-F5 821C-F3A CC-F14 821C-F4A B21-F0138 CC-F45 821C-F78 CC-F46 821C-F88 CC-F43 821C-F38 CC-F44 821C-F48 821-F013C CC-F27 821C-F7C CC-F36 821C-F8C CC-F7 821C-F3C CC-F16 821C-F4C B21-F013D CC-F28 821C-F7D CC-F37 821C-F8D CC-F8 821C-F3D CC-F17 821C-F4D 821-F013E CC-F29 821C-F7E CC-F38 821C-F8E CC-F9 821C-F3E CC-F18 821C-F4E IOAOP-30.0 Rev. 13 Page 7 of 91

ATTACHMENT 1 Page 2 of 2 SRV Fuse Location/Number Panel H12-P628 SRV Fuse Location E.P. Number 821-F013F CC-F51 (UNIT 1) 821C-F7F (UNIT 1)

CC-F49 (UNIT 2) 821C-F7F (UNIT 2)

CC-F52 (UNIT 1) 821C-F8F (UNIT 1)

CC-F50 (UNIT 2) 821C-F8F (UNIT 2)

CC-F47 821C-F3F CC-F48 821C-F4F 821-F013G CC-F31 821C-F7G CC-F40 821C-F8G CC-F11 821C-F3G CC-F20 821C-F4G 821-F013H CC-F32 821C-F7H CC-F41 821C-F8H CC-F12 821C-F3H CC-F21 821C-F4H B21-F013J CC-F33 821C-F7J CC-F42 821C-F8J CC-F13 821C-F3J CC-F22 821C-F4J 821-F013K CC-F30 821C-F7K CC-F39 821C-F8K CC-F10 821C-F3K CC-F19 821C-F4K 821-F013L CC-F26 821C-F7L CC-F35 821C-F8L CC-F6 B21C-F3L CC-F15 821C-F4L IOAOP-30.0 Rev. 13 Page 8 of 91

REVISION

SUMMARY

Revision 13: As requested by PRR 188012, clarified the note on Page 4 and on Page 5 to reflect that a leaking/weeping SRV is not considered to be a discharge of steam to the suppression pool. Revis-ed format of 3.2.3 sub-steps for clarification.

Revision 12 incorporates Tech Spec Change TSC-2004-04 for suppression chamber to drywell vacuum breakers, Steps 3.2.3.6 and 3.2.4.

Revision 11 is an editorial correction to replace the Desdemona font used for check-off boxes.

Revision 10 - This revision incorporates the administrative requirements of OAP-005.

Changes include restructuring the procedure wording for clarity and consistency. This change does NOT implement an intent change. The steps in this procedure were divided into two categories. The first is for an open SRV and the second for a leaking SRV. The intent of the operator actions remains unchang.ed. Additional administrative changes classified as "editorial" are bolding action verbs, italicizing components, change of cover page logo, removal of the "bar code" from the cover page, changing the word processing software to Microsoft Word XP, and adding place keeping aids.

Revision 9 incorporated TSC-2001-08, which changed Step 3.2.7 performance frequency from 2 to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after discharging steam to the suppression chamber for OPT-02.3.1 b, Suppression Pool to Drywell Vacuum Breaker Position Indication Check, and converted the procedure to Word 2000 software.

Revision 8 added Notes, new Steps 3.2.1, 3.2.2 and Attachment 1 to attempt to close the stuck open SRV by pulling the appropriate fuses in Panel H12-P628, and updated procedure layout to agree with current Writer's Guide format.

Revision 7 formatted procedure in accordance with OAP-005, deleted Step 3.3.2 (ref to Tech Spec if> 160°F torus temp and> 200 psig reactor pressure) in accordance with ITS 3.6.2.1-L2, required performance of OPT-02.3.1 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months in accordance with ITS 3.6.1.6-L6, and replaced reference to the Process Computer printout with the Process Computer alarm display in Section 1.0.

IOAOP-30.0 Rev. 13 Page 9of 91

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