Text

July-August Exam 50-325, 324/2007301 Draft Simulator Scenarios (2 of 4)
	ML072960448
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: ML072960448 (110)
	v • d • e

PROGRESS ENERGY CAROLINAS BRUNSWICK TRAINING SECTION 2007 NRC EXA BRUNSWICK JULY-AUG EXAM -325, 324/2007-301 DRAFT SIMULATOR SCENARIO 2 OF 4 2007 NRC Examination Scenario #2

SCENARIO DESCRIPTION BRUNSWICK 2007 NRC Scenario #2 The plant is operating at 100 % power, Middle of Cycle with CSW Pump 2C and CRD Pump 28 under clearance. A downpower is required for upcoming turbine valve testing. While power is being reduced an LPRM will fail downs causing a Technical Specification inoperability of the #1 APRM on LPRM level in or the B level.

The operators will start CSW pump 2C following maint Following the pump start, CSW Pump 2A will be removed from se in standby. The 2C CSW pump will then trip on overcurrent and t . fail to auto start (it will start manually). The crew will respond p W pump issue is addressed, a HPCllogic power failure will cification entry.

The Circulating Water Pumps (CWPs) intake sc progressively plug with river silt resulting in CWP pump trips. C. ser vacuu *nitially slowly lower. The crew wiU enter AOP-37.1, Intake Structu e. The ill lower reactor power and the BOP operator will attempt to rec II CWPs will trip and condenser vacuum will be lost causin he Reactor had not been scrammed, a scram will Most control rods* . The crew will respond per 2-EOP LPC. When SLO trip on overcurrent. Additionally RWCU will fail to automati* et, the SDV vent and drain valves will fail to open.

Witho leve III drop below LL4 requiring Emergency Depress sk). When ADS valves are opened (ADS SRV C fails to open. Low ust be overridden off to prevent uncontrolled injection during depres en pressure drops below MARFP, injection may be recommenced to PV level above LL4 (Critical Task). Condensate should be used for injection d o inability to throttle RHR flow for 5 minutes.

When the rods are all inserted and/or hot shutdown boron weight has been injected and level is being restored to 170-200", the scenario may be terminated.

2007 NRC Examination Scenario #2 2

SIMULATOR SETUP Initial Conditions IC 181 ENP 24 for IC 13 RxPwr 1000~

Core Age EGe Red Cap on 28 CRD PP EVENTS Event Trigger Trigger Description Number 1 NA NA 2 1 Manual 3 NA NA 4 2 5 3 6 4 g, lowering vacuum 7 nal/ATWS/RWCU G31-F004 auto close NA B failure 8

9 10 MalflD Mult ID Current Target Rmptime Actime Dactime Trig Value Value N1048M 28-13-40 LPRM AMPLIFIER FAILS LOW FALSE TRUE ES015F HPCI POWER SUPPLY FAILURE FALSE TRUE 2 CW015F C SCREEN HI DELTA P 0.00 70.00000 3 2007 NRC Examination Scenario #2 3

FAULT RPOO5F AUTO SCRAM DEFEAT FAULT TRUE 6 Remotes Summary Remf 10 Mult Description Current Target Rmptime Actime Trig

,t--- -+--I_D_--+- -+--V_a_lu_e_ _-+--V_alu,§~mt~"r,- +- -+-- -+_---11 BKR CTL DC FUSES CRD PUMP 2B OUT 2B SLC PUMMP MOTOR BKR 5 UNCOUPLE RCIC TURBINE FROM PUMP Override Summary Tag 10 Description Positionl Trig K2213A DISCH VOL TEST 6 Override T e OVal AVal Actime Dactime Tri File NONE Special Instructions Load scenario file 2007 NRC Scenario 1.scn Ensure ENP-24 for IC-14 @ P603.

2007 NRC Examination Scenario #2 4

SHIFT BRIEFING Plant Status The plant is operating at maximum power, Middle of Cycle.

Equipment Out of Service Several LPRMs have failed and are bypassed CRD Pump 2B is under clearance to replace oil in the "

of service for four hours.

CSW Pump 2C was under clearance and is r has been placed in service, CSW Pump 2A .,

No other equipment is out of service Plan of the Day Following shift turnover, reduce Following the downpower swap C r Pumps 2007 NRC Examination Scenario #2 5

SCENARIO INFORMATION Examiner Notes Procedures Used in Scenarios:

EVENT 1

OGP-12 (power reduction)

EVENT 2

Annunciator 2-A-06 Window 1-7 (LPRM downscale)

20P-09 (Bypassing LPRM)

Technical Specifications EVENT 3

OOP-43 (Shifting Conventional Service Water Pu EVENT 4

OAOP-19:

Event 5 EVENT 7

2EOP- SCRAM PROCEDURE)

2EOP OWER CONTROL PROCEDURE)

EVENT 8

None EVENT 9

2EOP-01-LPC EVENT 10 2007 NRC Examination Scenario #2 6

EVENT 10

2EOP-01-LPC Critical Tasks Perform emergency depressurization when determination is made that level cannot be restored and maintained above LL4.

When reactor pressure drops below the Minimum Altern eactor Flooding Pressure (MARFP) recommence injection to restore r " ater level above LL4 2007 NRC Examination Scenario #2 7

EVENT 1 SHIFT TURNOVER, LOWER REACTOR POWER TO 900/0 The crew lowers reactor power to 90°A> per SeQ direction Malfunctions required - None Objectives:

sea - Directs RQ to lower reactor power to 90°A> per GP-RO - Lowers reactor power to 900/0 using Recirc flow, Success Path:

Reactor power is lowered and stabilized at 9 Simulator Operator Activities:

IF requested, as NE, insert ro power below the Melita line.

2007 NRC Examination Scenario #2 8

EVENT 1 SHIFT TURNOVER, LOWER REACTOR POWER TO 90 0k Required Operator Actions SRO Normal Operation - Lower Reactor Power to 900k

Direct RO to lower reactor power to 90% per OG RO Normal 0

Lower Reactor Power to 90% per OGP-1 2007 NRC Examination Scenario #2 9

EVENT 2 LPRM Failure The crew responds to an LPRM failure Malfunctions required:

LPRM 28-13-40 fails, resulting in various annunciators ocated with APRM #1 Objectives:

seQ Correctly recognizes LPRM failure and Recognizes and evaluates impac specific level - APRM #1 inope Evaluates Technical Specificati RO Refers to annunciato LPRM failure and AP BOP es downscale LPRM ermines less than 3 LPRMs operable of same.

Recogn' rable. Bypasses APRM #1, Determination is made that Technical rements are being met for the minimum number of Operable AP .1 - RPS, TRM 3.3 Rod Block)

WHEN directed by lead examiner, activate TRIGGER 1

WHEN asked, as I&C, to assist in the investigation of the failure, acknowledge the request.

2007 NRC Examination Scenario #2 10

EVENT 2 LPRM Failure Required Operator Actions Annunciator Response - LPRM downscale SRO o Obtain information from RO/SOP regar M(APRM assignment, associated LPRM statu nd LPRMs per level.

o Direct BOP to bypass the affe' RO

j: eports indications of 28-13-4D on APRM #1 per 20P-09 APPLICANT'S ACTI NS OR BEHAVIOR:

2007 NRC Examination Scenario #2 11

EVENT 3 SHIFTING CONVENTIONAL SERVICE WATER PUMPS The crew will swap operating Conventional Service Water Pumps in support of scheduled Maintenance.

Malfunction required:

None Objectives:

sea Directs BOP to start 2C Conventional Servi Conventional Service Water Pump in sta,.,

BOP Place 2C Conventional Service Wat Conventional Service Water Pump an , Section 8.23.

Success Path:

entional Service Water section 8.23.

Conventional Service Water Pump Ions are normal.

" nventional Service Water Pump is running normally 2007 NRC Examination Scenario #2

EVENT 3 SHIFTING CONVENTIONAL SERVICE WATER PUMPS Required Operator Actions Normal Plant Operation - Shifting of Conventional Service Water Pumps SRO o Direct BOP to shift Conventional Service W ps per 20P-43, Section 8.23 BOP APPLICANT'S ACTIONS OR BEHAVIOR:

2007 NRC Examination Scenario #2 13

EVENT 4 CONVENTIONAL SERVICE WATER PUMP FAILURE The crew will respond to the failure of an operating Conventional Service Water Pump failure per OAOP-19.0 and take action to restore Conventional Service Water to within normal operating limits.

Malfunctions required:

2C Conventional Service Water Pump will trip on electrical f nd the 2A Conventional Service Water Pump will fail to start on a 10 ure demand signal.

Objectives:

SCQ Enters OAQP-19.0 and directs the action The Conventional Service Water Syst, BOP Enters OAOP-19 and manually starts t onal Service ter Pump to restore Conventional Service Water pa within normal limits.

Success Path:

thin normal ranges with g.

Diesel Generator Building, wait 3 minutes and report that all three phases of the 2C Conventional Service Water 2007 NRC Examination Scenario #2 14

EVENT 4 CONVENTIONAL SERVICE WATER PUMP FAILURE Required Operator Actions Abnormal Operating Procedures - Conventional Service Water Failure SRO o Enters OAOP-19 and directs BOP to execut the system to normal parameters o Reviews Technical Specifications for* two Conventional Service Water Pumps (one electri not start on a low header pressure demand). - Tracking LCO BOP o Enters and executes P-19 and restores Conventional Service ' within normal parameter ranges.

o ATER PRESS-LOW UMP C TRIP AP 2007 NRC Examination Scenario #2 15

EVENT 5 HPCI LOGIC POWER FAILURE The crew will observe and respond to HPCI power failure annunciator and diagnose that the condition has resulted in HPCI being inoperable and unavailable. The sca will evaluate the impact to plant operation, including Technical Specification action statement(s).

Malfunctions required:

Logic power to the HPCI system will be interrupt inoperability and unavailability.

Objectives:

sea Evaluate the conditions obs HPCI which has rendered it' Evaluate the impact of the HP t to the Technical Specifications.

RO the logic power supply source The crew carre es that HPCI is inoperable and unavailable, properly secures the system per 2 , and evaluates the condition with respect to Technical Specifications.

2007 NRC Examination Scenario #2 16

EVENT 5 HPCI LOGIC POWER FAILURE Simulator Operator Activities:

WHEN directed by the lead examiner, activate TRIGGER 2.

WHEN asked as an auxiliary operator, report that pan circuit 2 breaker for the HPCI logic power is tripped and, if directed to a. a reset, report that the breaker immediately tripped, again.

WHEN asked as I&C to come to the contro e investigation, acknowledge the request.

2007 NRC Examination Scenario #2 17

EVENT 5 HPCI LOGIC POWER FAILURE Required Operator Actions:

seQ

Evaluate the plant impact and Technical Specifica . quirements for the HPCI inoperability. (3.5.1 - Verify RCIC Operab days)

Direct the RO to carry out the actions nece by the annunciator procedure RO

Inform the SCQ of the annunciators HPCI power 10 s and the procedural guidance, specifically as it 'the securing of HPCI and its subsequent unavailabilit A-1 2-5, HPCI FIC P

When directed by the SCQ" by the applicable procedure.

AP 2007 NRC Examination Scenario #2 18

EVENT 6 CIRC WATER INTAKE SCREEN FOULING WITH LOWERING CONDENSER VACUUM The crew will respond to an insurge of vegetative debris on the Circ Water intake screens accompanied by a lower condenser vacuum.

Malfunctions required:

Circ Water Intake screen differential pressure will to rise due to vegetative fouling, followed by Circ Water Intak s tripping on a high differential pressure signal. Impacted by this denser vacuum win begin to lower due to heat sink availability ( er flow due to pump trips).

Objectives:

seQ - Enter and direct actions associated WI contained in OAOP-37.1 to ieat sink.

o condenser vacuum at (Iine-in-the-sand)

RO unit sca in an effort the maintain main BOP ake structure blockage Restarts Cire Crew reco ~ ns for fouling of Circ Water Intake Screens, enters and executes OA en recognized the condition as worsening and not recoverable, m cision/takes the actions to scram the reactor.

2007 NRC Examination Scenario #2 19

EVENT 6 CIRC WATER INTAKE SCREEN FOULING WITH LOWERING CONDENSER VACUUM Simulator Operator Activities WHEN directed by lead examiner, activate TRIGGER 3 WHEN contacted, report that there is significant vegetative deb* on the eirc Water trash racks and that more can be seen coming down the int nal.

WHEN contacted, report that the screens have heavy continuing to rotate.

IF directed as the AO to place screenwash in h* .

request.

2007 NRC Examination Scenario #2 20

EVENT 6 CIRC WATER INTAKE SCREEN FOULING WITH LOWERING CONDENSER VACUUM Required Operator Actions SCO

Enter and direct actions associated with OAOP-37 o Directs the RO to lower reactor power reduction directions o Directs the BOP to take appropri maintain the main condenser o Establishes and communic which time the crew will sc RO

Lowers reactor power to SCO per ENP-24 BOP

Enters and Intake P availa 2007 NRC Examination Scenario #2 21

EVENT 7/8 ATWS WITH SLC COMPONENT AND SIGNAL FAILURE The crew will respond to a failure of the Reactor to complete a scram and a subsequent SLC Pump failure and associated RWCU failure to isolate.

Malfunctions required:

Multiple control rods will fail to insert when a reactor scram sig is applied (hydraulic ATWS). When started the 2B SLC Pump indication will be I the RTGB (pump motor breaker trip). The RWCU outboard isolation valve -F004 will fail to t

automatically close when the SLC system is initiated~

Objectives:

SCO Will enter and direct the actions of 2EOP-0 "

Will recognize the conditions for an ATWS and 2-EOP-01-LPC (Level-Power Con, d OEOP-Control Procedure)

RO s/reports the ATWS conditions reports the 28 SLC Pump failure failu "; the 2-G31-F004 (RWCU outboard isolation valve).

the valve.

arries out the actions of LEP-02.

BOP Perform the actions associated with reactor level and pressure control as directed by the SeQ.

Controls RPV pressure 800 to 1000 psig with SRVs Terminates and Prevents injection as directed Terminates and Prevents injection from low pressure systems @LL3 2007 NRC Examination Scenario #2 22

Success Path:

Following insertion of the scram signal, crew recognizes and responds to the ATWS condition and directs/carries out the actions as delineated by the EOPs. The crew also recognizes and responds to the failures associated with the SLC system (SLC Pump trip, failure of the 2-G31-F004 to automatically close).

Simulator Operator Activities:

WHEN SLC is initiated, wait 2 minutes and initiate TR WHEN asked, report that the breaker fo the 28 reset the breaker, report the breaker immedi WHEN scram jumpers are requested, wait 5 WHEN requested (I&C and/or Me.;

request to get the Scram Discharg 2007 NRC Examination Scenario #2 23

EVENT 7/8 ATWS WITH SLC COMPONENT AND SIGNAL FAILURE Required Operator Actions:

SCO Enter and directs the actions of 2EOP-01-RSP (Reactor Scram Procedure)

Will recognize the conditions for an ATWS and will enter an , ' ute the actions of 2-EOP-01-LPC (Level-Power Control) and OEOP-02-PCC ary Containment Control Procedure)

Direct entry into LEP-02 to insert control rods Directs Terminate and prevent Injection per RO Performs the initial scram actions When directed, initiates SLC and re Recognizes and reports, outboard isolation valve).

Takes manual action.

When directed, e" .

BOP ith reactor level and pressure control as directed by s injection from low pressure systems @LL3 2007 NRC Examination Scenario #2 ?4

APPLICANT'S ACTIONS OR BEHAVIOR:

2007 NRC Examination Scenario #2 25

EVENT 9 RCIC COUPLING FAILURE The crew will respond to indications of RCIC failure to develop adequate discharge pressure and determines its unavailability to provide high pressure injection, subsequently pursuing actions with HPCI/RCIC not available.

Malfunctions Required:

Rele will not develop discharge pressure and/or flow whe inject water into the vessel Obiectives:

sea Evaluates indications of RCIC unavailability, and utilizes Le lish course of action.

BOP Observes RCIC perf - and reports to the unit sca of RCle's inability to de d, when directed, secures RCIC.

Success Path:

n that a problem exists with RCIC uate discharge head for inject water implements alternate actions in the taining critical parameters.

WH , e co ~~room that there is not any flow noise coming from the RCI" turbine end of the shaft appears to be turning and the pump end rs to not be turning.

2007 NRC Examination Scenario #2 26

EVENT 9 RCIC COUPLING FAILURE Required Operator Actions:

seQ

Correctly diagnose, based on information provided a* or observed, that RCIC is not available as an injection source and e the Level-Power Control EOP based on the information BOP

Attempts to operate RCIC and inform to develop flow and/or discharge head, assisting i ility.

Dispatches AO to investigate RelC APPLICANT'S ACTIONS OR BE 2007 NRC Examination Scenario #2 27

EVENT 10,11 SDV VENTS & DRAINS FAIL TO OPEN, EMERGENCY DEPRESSURIZATION ON INABILITY TO MAINTAIN LEVEL WITH ONE ADS VALVE FAILING TO OPEN, RESTORATION OF LEVEL The crew will respond to the inability to maintain Reactor Water Level above Low Level 4 (LL4) and a subsequent failure of one ADS valve to open.

Malfunctions Required:

2-B21-F013C (ADS Valve C) will fail to open when its c "Open" position.

Objectives:

sea Correctly evaluates inability t r water leve Level 4 and provides direction t ergency Dep ssurize the reactor and recommence injection el-Power Control Flowchart RO Continues to insert c Informs the SeQ when C Tank (Hot Shutdown Boron We*

. s not opening when LEP-02 jumpers are BOP from Low Pressure and Alternate Control Switches in Qpen Position, when directed.

013C ADS valve does not open and informs SCQ ional SRV when directed cted, commences feeding the Reactor Vessel using the sate system to establish the level band as directed by the SCQ Success Path:

The crew terminates and prevents injection sources, Emergency Depressurizes the reactor, identifies the failure of the B21-F013C to open and opens an SRV in its place and, when reactor pressure lowers below the Minimum Alternate Flooding Pressure, commences injection with the Feed and Condensate system to restore level above Low Level 4 (LL4).

2007 NRC Examination Scenario #2 28

Simulator Operator Activities:

WHEN directed by the lead examiner, delete override K2213A (two line items) and report to the control room that the scram discharge volume vents and drains have been repaired.

- WHEN REACTOR PRESSURE IS 120 PSIG AND INJECTION HAS COMMENCED, THEN when directed by the lead examiner, remove SDV vent drain malfunction and remove the ATWS malfunction.

2007 NRC Examination Scenario #2 ?Q

EVENT 10,11 SDV VENTS & DRAINS FAIL TO OPEN, EMERGENCY DEPRESSURIZATION ON INABILITY TO MAINTAIN LEVEL WITH ONE ADS VALVE FAILING TO OPEN, RESTORATION OF LEVEL Required Operator Actions EOP Action - Emergency Depressurize the reactor and res e level above LL4 with a failure of ADS Valve C to open seo Correctly evaluates inability to maintain R ter level above Low Level 4 and provides direction to the cre E cy Depressurize the reactor and recommence injection i Level-Po ntrol Flowchart Directs BOP operator to termin Emergency Depressurize the Condensate and Feedwater to r RQ Continues to insert c Informs the SeQ when e Tank (Hot Shutdown Boron Wei

. s not opening when LEP-02 jumpers are BOP from Low Pressure and Alternate Control Switches in Open Position, when directed.

013C ADS valve does not open and informs SeQ ional SRV when directed 2007 NRC Examination Scenario #2 30

APPLICANT'S ACTIONS OR BEHAVIOR:

2007 NRC Examination Scenario #2 31

EVENT 10,11 RESTORATION OF REACTOR WATER LEVEL - ALL RODS IN OR HOT SHUTDOWN BORON WEIGHT The crew will determine all rods in or Hot Shutdown Boron Weight has been achieved and restore reactor water level to a range of 170" to 200" Malfunctions Required:

None Objectives:

sea Recognize conditions exist to allow r normal operating band Direct BOP operator to raise band using Feedwater and Condensa If all rods in, direct R Control RO BOP Success Path:

, or Hot Shutdown Boron Weight and to 200".

None 2007 NRC Examination Scenario #2 32

EVENT 10,11 RESTORATION OF REACTOR WATER LEVEL - ALL RODS IN OR HOT SHUTDOWN BORON WEIGHT Required Operator Actions:

EOP Action - Restore reactor vessel level to the normal operating band seQ Execute the steps of 2EOP-01-LPC to direct res reactor water level to a range of 170" to 200" upon achieving All Rod-- hutdown Boron Weight RO Continue to insert control rods and/or i t Shutdown Boron Weight is achieved BOP 0" to 200" using APPLICANT'S A '

2007 NRC Examination Scenario #2 33

Simulator Operator Activities:

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

CAUTION DO NOT RESET THE SIMULATOR P TO RECEIPT OF CONCURRENCE TO DO SO THE LEAD EXAMINER 2007 NRC Examination Scenario #2 34

RPV Level Transmitters (FIGURE 01.2-4 from 80-01)

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INTERLOCK ---~~@-1 U

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C BRUNSWICK NUCLEAR PLANT

~ Progress Energy 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 Level Using Alternate Indications...... 34 IOGP-12 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 23% 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 2.2 UFSAR 2.3 001-01, Conduct 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 Operatin'g 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

380 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.

IR221 NOTE: Instability may be indicated by:

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

2. OPRM UPSCALE TRIP, A-05 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)QP-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 SeQ 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 ok. 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 CTL C32-SIC-R601A(B), Control Stations 3.11.3 MSTR RFPT SPIRX LVL CTL C32-SIC-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

5aO PROCEDURAL STEPS Unit DatelTime Started 5.1 Power Reduction - - - - -/- - - -

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°1'<> 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 SeQ, 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 of37 I

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 t

which exhausts into that condenser.

5.1.6 WHEN reactor power is approximately 60°A> to 65°A>,

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, CO- V11 0, 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 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 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 DEAERATOR 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°A> AND one heater drain pump has been removed from service, THEN ADJUST SJAE CONDENSA TE RECIRCULA TION VALVE, CO-FV-49, as necessary, to maintain condensate pump discharge pressure between 190 and 230psig.

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 seo, 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:

HEA TER DRAIN PUMP A DISCHARGE DEAERA TOR LEVEL CONTROL VAL VE, HD-LV-91-1 HEA TER DRAIN PUMP B DISCHARGE DEAERATORLEVELCONTROLVALV~

HD-LV-91-2 HEA TER DRAIN PUMP C DISCHARGE DEAERATORLEVELCONTROLVALV~

HD-LV-91-3 IOGP-12 Rev. 49 Page 13 of 371

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%, 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 RFP A (B) RECIRC VLV, 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 DEAERATOR FILL AND DRAIN VALVE, 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- - - - - - / ----

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 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: Process Computer Point 8018 total core flow and H12-P603 recorder 1/2B21-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% power change increment.

( R2S I 5.2.3 PERFORM power increases, as directed by the Unit SCO, 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 VLV, 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-177/S0L VLV, FW-V10.

IOGP-12 Rev. 49 Page 20 of 371

5.0 PROCEDURAL STEPS Initials 5.2.6 PERFORM OPT-13.1, Reactor Recirculation Jet Pump Operability, prior to exceeding 25% reactor power.

5.2.7 IF CMFLCPR > 1.00 OR CMAPRAT > 1.00, AND Reactor power is less than 260/0, 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% 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°/b 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 CONDENSATE RECIRCULATION VALVE, 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

5.0 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 COOs, CFOs, and Master Flow Controllers in service as required.

2. PLACE hotwelilevel 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 26°A> 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 CLOSISV TRIP BYPASS (A-05, 6-7) is clear.

4. Unit 2 only: CONFIRM TURB CV FAST CLOS/SVIRPT TRIP BYPASS (A-05, 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. /

Ind.Ver.

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

Ind.Ver.

C. REMOVE fuse C71-F9B from Panel H12-P611. /

Ind.Ver.

d. REMOVE fuse C71-F9D from Panel H*12-P611. /

Ind.Ver.

e. CONFIRM TURB CV FAST CLOS/SV TRIP BYPASS (A-05, 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-05, 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 I 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 relay(s) energize, THEN the Unit SCQ 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°A> reactor power for the applicable unit.

1. Unit 1 only:

a. INSTALL fuse C71-F9A in Panel H12-P609. /

Ind.Ver.

b. INSTALL fuse C71-F9C in Panel H12-P609. /

Ind.Ver.

c. INSTALL fuse C71-F98 in Panel H12-P611. /

Ind.Ver.

d. INSTALL fuse C71-F9D in Panel H12-P611. /

Ind.Ver.

2. Unit 2 only:

a. INSTALL fuse C72-F9A in Panel H12-P609. /

Ind.Ver.

b. INSTALL fuse C72-F9C in Panel H12-P609. /

Ind.Ver.

c. INSTALL fuse C72-F98 in Panel H12-P611. /

Ind.Ver.

d. INSTALL fuse C72-F9D in Panel H12-P611. /

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)-K9B on Panel H12-P611 is deenergized.

IOGP-12 Rev. 49 Page 27 of 371

5aO PROCEDURAL STEPS Initials

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

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

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

5.2.22 NOTIFY Radwaste to place additional CODs 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 NPOES 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 fong 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 VAL VE CO-FV-49 INLET ISOLA TION VAL VE, CO-V11 0 to isolate SJAE CONDENSA TE RECIRCULATION VALVE, CO-FV-49.

5.2.30 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°1'<> 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°1'<>, THEN ENSURE REHEAT STEAM HIGH LOAD VALVES, RSHLV-1 AND RSHL V-2, open.

5.2.33 WHEN reactor power is between 78% and 83 % ,

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°A> maximum achievable reactor power, THEN ENSURE reactor pressure is at 1030 psig utilizing narrow range indication Computer Point B015 (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 ROO OVER TRAVEL (A-05 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-OS 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 sca 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 10 %

power increments.

1. OBTAIN valid Heat Balance (Display 820 or OPT-01.8D, Core Thermal Power Calculation) AND RECORD heat balance 0A> power in Table 1.

2. OBTAIN LPRM 0A> PWR (Display 861, Filtered LPRM Readings Edit) AND RECORD in Table 1.

TABLE 1 TIME APPROX. STEAM LPRM% HEAT APRM INITIALS RX FLOW POWER BALANCE 0.!c> GAFs POWER 0/0 POWER Power ~1.00 N/A TURBINE N/A N/A N/A N/A ON LINE 300/0 40%

500/0 60%

700/0 80%

90°.!c>

100°.!c>

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) (0)

(ERFIS) C32FA014 C32FA015 C32FA016 C32FA017 (P603) C32-R603A C32-R603B C32-R603C C32-R603D Total Steam Flow = (A) + (B) + (C) + (D) = _

OR USE computer point B041

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 B (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 0A> 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 "E" 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 (0A> power) in Table 1 of this attachment using the value obtained from MAN or NE programs.

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

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°A> 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 Sook 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 26% and 40% power with core flow greater than 650/0 and at all core flows when power is less than 26%. Step 5.1.14 was also revised to remove the reference to core flow.

IOGP-12 Rev. 49 Page 37 of 371

Unit 2 APP A-06 1-7 Page 1 of 2 LPRM DOWNSCALE AUTO ACTIONS LPRM in inverse video is displayed on the associated APRM ODA header and APRM chassis at P608.

CAUSE

1. Anyone of 124 LPRMs indicating less than or equal to 3 on the 0 to 125 scale.

2. LPRM detector failure.

3. Control rod insertion OBSERVATIONS

1. The APRM channel with input from the affected LPRM may indicate slightly lower than other APRM channels.

ACTIONS NOTE: Periodic LPRM downscale or upscale alarms spuriously illuminating and clearing is an indication of neutronic/thermal-hydraulic instability. LPRMs provide input to OPRM channels for detection and suppression of thermal hydraulic instability events. The OPRM System alarms are a quick method for detection of these instability events.

1. Check the following annunciators to analyze whether the LPRM DOWNSCALE alarm is the result of a thermal-hydraulic instability event:

OPRM TRIP ENABLED (A-OS 4-8)

OPRM PBA/CDA ALARM (A-OS S-8)

LPRM UPSCALE (A-06 1-8)

OPRM UPSCALE TRIP (A-OS 6-8)

2. Identify the affected LPRMs as follows:

a. At the APRM NUMAC or ODA, identify the affected APRM by indication of LPRM in inverse video displayed on the header.

b. Use PPC Displays 863 (864, 86S, 866) LPRM BAR CHART-APRM 1(2,3,4) or PPC Display 861, FILTERED LPRM READINGS EDIT to identify LPRMs indicating below the downscale setpoint.

c. If desired, use APRM ODA/NUMAC LPRM BARGRAPHS display to identify downscale LPRMs.

12APP-A-06 Rev. 45 Page 12 of 821

Unit 2 APP A-06 1-7 Page 2 of 2 ACTIONS (Continued)

NOTE: The core power shape should be symmetrical at each LPRM plane throughout the core.

3. Compare downscale LPRM(s) to other LPRMs as follows:

a. Observe the PPC FILTERED LPRM READINGS EDIT display 861 for symmetry.

b. Select a control rod adjacent to the affected LPRM string and observe the LPRM BARGRAPH display on RBM ODAs for symmetry.

NOTE: Bypassing an LPRM may cause an APRM, OPRM, or RBM channel Inop due to too few LPRM inputs if other LPRMs are already bypassed.

4. If the affected LPRM indication is invalid or erratic, then refer to 20P-09 for bypassing the LPRM.

DEVICE/SETPOINTS Any of 124 LPRMs less than or equal to 3 on the 0 to 125 scale POSSIBLE PLANT EFFECTS

1. A bypassed or inoperative LPRM detector may result in a Tech Spec LCO.

2. APRM channel inoperable.

3. RBM channel inoperable.

4. OPRM channel inoperable.

REFERENCES

1. LL-09364 - 94

2. Technical Specification B3.3.1.1

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

4. 2-FP-05851

5. 20P-09, Neutron Monitoring System Operating Procedure

!2APP-A-06 Rev. 45 Page 13 of 821

Unit 2 APP A-06 3-7 Page 1 of 2 APRM TROUBLE AUTO ACTIONS

1. Rod Withdrawal Block if alarm initiated by too few LPRM detectors per level or too few LPRM detectors in flux average.

CAUSE

1. The quantity of operating LPRM detectors at any given reactor level is less than three.

2. The quantity of operating LPRM detectors in the flux average is less than 17.

3. Any self-test fault.

OBSERVATIONS

1. ROD OUT BLOCK (A-OS 2-2) alarm.

2. The Rod Withdrawal Permissive indicating light will be off.

3. On APRM BARGRAPH display at P608 and PPC Displays 882-885, LPRMs in average is less than 17, if this condition caused the alarm.

ACTIONS NOTE: If cause of the alarm is due to too few LPRMs in the average or too few LPRMs per axial level, the APRM is inoperable in accordance with Tech Spec Basis 3.3.1.1. However, no trip is automatically sent to the Voters.

1. If necessary to determine which APRM initiated the alarm, perform the following at each APRM ODA:

a. Press ETC soft key to obtain TRIP STATUS soft key.

b. Press TRIP STATUS soft key.

c. Observe an asterisk in inverse video in the Trouble Alarm column, indicating this APRM initiated the alarm.

d. Press INOP STATUS soft key to determine cause of the alarm.

2. Refer to Tech Spec Section 3.3.i.l for required actions.

3. If the APRM cannot be returned to operable status, then if possible, place the affected APRM in Bypass.

4. When plant conditions allow, return LPRMs to service and remove the affected APRM from Bypass.

5. If self-test fault initiated the alarm, then contact I&C.

12APP-A-06 Rev. 45 Page 40 of 821

Unit 2 APP A-06 3-7 Page 2 of 2 ACTIONS APRM Channels 1 through 4 Less than 17 LPRM detector inputs to flux average Less than 3 LPRM detectors per axial level.

Self-test fault.

POSSIBLE PLANT EFFECTS

1. APRM inoperable.

2. If an APRM channel is inoperable or bypassed, a Tech Spec LCO or TRM Compensatory Measure may result.

REFERENCES

1. LL-09364 - 94

2. 2-FP-OS8S1

3. Tech Spec 3.3.1.1, B3.3.1.1, TRMS 3.3

4. APP A-OS 2-2, ROD OUT BLOCK 12APP-A-06 Rev. 45 Page 41 of 821

Unit 2 APP A-05 2-2 Page 1 of 2 ROD OUT BLOCK AUTO ACTIONS

1. Rod withdrawal prohibited.

CAUSE

1. South SDV not drained.

2. North SDV not drained.

3. SRM downscale and any IRM is below Range 3.

4. IRM downscale and affected IRM channel is not on Range 1.

5. SRM upscale/inoperative and any IRM channel is below Range 8.

6. IRM upscale and the reactor system mode switch is not in the RUN position.

7. IRM A upscale/inoperative and the reactor system mode switch is not in the RUN position.

8. SRM detector not fully inserted and log count rate is less than or equal to 100 cps (bypassed when all IRM channels are above Range 2 or the reactor system mode switch is in the RUN position) .

9. IRM B upscale/inoperative and the reactor system mode switch is not in the RUN position.

10. APRM downscale and the reactor system mode switch is in the RUN position.

11. APRM UPSCALE alarm.

12. APRM UPSCALE TRIP/INOP alarm.

13. Less than 17 LPRM inputs to any APRM or less than 3 LPRMs per axial level for any APRM.

14. RBM downscale and reactor system mode switch is in the RUN position.

15. REM upscale/inoperative.

16. Recirc flow signal to any APRM greater than or equal to 110%.

17. Discharge Volume Hi Water Level Trip Bypass switch in Bypass with the Reactor System Mode Switch in Shutdown or Refuel.

18. Reactor System Mode Switch in Refuel with a second rod selected and another rod not full in.

NOTE: The Service Platform has been removed. Associated refuel interlocks are non-functional but available.

I

19. Reactor System Mode Switch in Startup AND the refuel bridge is over the core OR the service platform is loaded.

20. Reactor System Mode Switch in Refuel with the service platform loaded.

21. Reactor System Mode Switch in Refuel with the refuel bridge over the core AND the grapple loaded OR not full up.

22. Reactor System Mode Switch in Refuel with the refuel bridge over the core AND any refuel bridge hoist loaded.

23. No power to the refuel bridge.

24. Reactor System Mode Switch in Shutdown.

25. Any IRM detector not fully inserted and the reactor mode switch is not in RUN.

26. Circuit malfunction.

12APp-A-05 Rev. 52 Page 20 of 941

Unit 2 APP A-OS 2-2 Page 2 of 2 OBSERVATIONS

1. Selected rod will not withdraw.

2. Rod withdraw permissive light is off.

3. SOUTH SDV NOT DRND (A-OS 1-1) alarm.

4. NORTH SDV NOT DRND (A-OS 2-S) alarm.

S. SRM DOWNSCALE (A-OS 1-3) alarm.

6. IRM DOWNSCALE (A-OS 1-4) alarm.

7. SRM UPSCALE/INOP (A-OS 2-3) alarm.

8. IRM UPSCALE (A-OS 2-4) alarm.

9. IRM A UPSCALE/INOP (A-OS 3-4) alarm.

10. SRM DET RETRACT NOT PERMITTED (A-OS 4-3) alarm.

11. IRM B UPSCALE/INOP (A-OS 4-4) alarm.

12. APRM DOWNSCALE (A-06 2-7) alarm.

13. APRM UPSCALE (A-06 2-8) alarm.

14. APRM TROUBLE (A-06 3-7) alarm.

15. APRM UPSCALE TRIP/INOP (A-06 3-8) alarm.

16. RBM DOWNSCALE/TROUBLE (A-06 4-7) alarm.

17. RBM UPSC/INOP (A-06 4-8) alarm.

18. FLOW REF OFF NORMAL (A-06 S-7) alarm.

ACTIONS

1. Refer to appropriate Annunciator procedure listed in OBSERVATIONS.

2. Verify proper position of the Discharge Volume Hi Water Level Trip Bypass switch, refer to APP A-OS I-S.

3. Verify proper positioning of the refueling equipment and power supplies.

DEVICE/SETPOINTS Rod Out Block Relays C12A-K1 or C12A-K2 Deenergized POSSIBLE PLANT EFFECTS

1. Control rods may not be withdrawn from the core while the rod block is in effect.

REFERENCES

1. LL-9364 - 74

2. FP-S0012 - 6 12APP-A-05 Rev. 52 Page 21 of 941

8.4 Bypassing a LPRM C Continuous Use 8.4.1 Initial Conditions Initials DatelTime Started- - - - - - -

1. LPRM is required to be bypassed (indication invalid, erratic, etc.).

8.4.2 Procedural Steps NOTE: Bypassing an LPRM may cause an APRM, RBM, or OPRM Channel to be inoperable from too few inputs if additional LPRMs have been previously bypassed. The minimum number of inputs to APRM and OPRM can be identified using numerous PPC Displays - Displays 863 (864, 865, 866),

LPRM BAR CHART - APRM 1 (2, 3, 4) and Displays 888 (889, 890,891)

OPRM 1 (2,3,4) STATUS/DATA, are examples.

1. IDENTIFY the number of LPRMs in average to APRM using the APRM BARGRAPH on Panel P608, or applicable PPC Display.

2. CONFIRM the LPRM can be bypassed and minimum number of LPRM inputs maintained to the affected APRM and OPRM.

3. PLACE applicable APRM in BYPASS,

4. PERFORM the following to bypass an LPRM at Panel P608:

LPRM - - -

a. CONFIRM BYP is indicated for the selected APRM channel.

b. PRESS ETC soft key to obtain BYPASS SELECTIONS soft key.

c. PRESS BYPASS SELECTIONS soft key.

120P-09 Rev. 25 Page 19 of 331

8.4.2 Procedural Steps

d. ENTER password "1 2 3 4" AND PRESS ENT.

e. Using the cursor keys, SELECT the LPRM AND PRESS BYPASS/HV OFF soft key.

f. CONFIRM LPRM status changes to BYPASS/HV OFF.

g. PRESS EXIT soft key.

5. ENSURE APRM GAF is less than or equal to 1.00, by performing Section 8.1 to adjust APRM GAFs, if required.

6. NOTIFY Reactor Engineer LPRM is bypassed.

7. ENSURE the computer point for the bypassed LPRM, on ppe Screen 861, has its scanning disabled AND a zero value inserted as follows:

a. MOVE the curser to the poke point for the LPRM to be bypassed.

b. PRESS the trackball <SELECT> button.

c. CONFIRM the point 10 for the LPRM appears in the message area at the bottom of the window.

d. PRESS the <CONTROL POINT 10> hardkey.

e. CONFIRM the OATA POINT display appears showing data associated with the desired point 10.

f. PLACE the curser on the green scanning

'lENABLED" text AND CLICK.

g. TYPE 'lD" to disable.

h. PRESS keypad "ENTER" key.

120P-09 Rev. 25 Page 20 of 331

8.4.2 Procedural Steps

i. CONFIRM scanning text changes to "DISABLED".

j. CLICK on the value in the upper right hand area of the screen.

k. TYPE "0" for the substitute value.

I. PRESS keypad "ENTER" key.

m. CONFIRM the point value entered appears in cyan.

8. ENSURE applicable APRM is removed from BYPASS.

9. ENSURE the Unit Status Database, LPRM Status, is updated to reflect the bypassed LPRM.

10. ENSURE a W/R is initiated for the bypassed LPRM.

11. NOTIFY Unit sca the LPRM has been bypassed.

DatelTime Completed _

Performed By (Print) Initials Reviewed By: _

Unit sca 120P-09 Rev. 25 Page 21 of 331

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

APPLICABILITY: According to Table 3.3.1.1-1.

ACTIONS

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

Separate Condition entry is* allowed for each channel.

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

A.2 -----------NOTE------------ 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Not applicable for Functions 2.a, 2.b, 2.c, 2.d, or 2.f.

Place associated trip system in trip.

(continued)

Brunswick Unit 2 3.3-1 Amendment No. 243 I

RPS Instrumentation 3.3.1.1 A CTIONS (continued)'

CONDITION REQUIRED ACTION COMPLETION TIME B. ------------NOTE:---------------- B.1 Place channel in one trip 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Not applicable for Functions system in trip.

2.a, 2.b, 2.c, 2.d, or 2.f.

OR One or more Functions with B.2 Place one trip system in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months one or more required trip.

channels inoperable in both trip systems.

c. One or more Functions with C.1 Restore RPS trip capability. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months RPS trip capability not maintained.

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

E. As required by Required E.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Action D.1 and referenced in POWER to < 26% RTP.

Table 3.3.1.1-1.

(continued)

Brunswick Unit 2 3.3-2 Amendment No. 247 I

RPS Instrumentation 3.3.1.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

F. As required by Required F.1 Be in.MODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Action 0.1 and referenced in Table 3.3.1.1-1.

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

H. As required by Required H.1 Initiate action to fully insert Immediately Action 0.1 and referenced in all insertable control rods in Table 3.3.1.1-1. core cells containing one or more fuel assemblies.

I. As required by Required 1.1 Initiate alternate method to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action 0.1 and referenced in detect and suppress Table 3.3.1.1-1. thermal hydraulic instability oscillations.

J. Required Action and J.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion Time POWER to < 20% RTP.

of Condition I not met.

Brunswick Unit 2 3.3-3 Amendment No. 243 I

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS

..:::----------------------------------------- NOTES ------------------------------------------------

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

2. When a channel is placed in an inoperable status* solely for performance of required Surveillances entry into associated Conditions and Required Actions may be delayed for r

up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains RPS trip capability.

SURVEILLANCE FREQUENCY SR 3.3.1.1.1 (Not used.) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.1.1.2 Perform CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.3.1.1.3 ----------------------------NOTE----------------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER ~ 230/0 RTP.

Adjust the average power range monitor (APRM) 7 days channels to conform to the calculated power while operating at ~ 230/0 RTP.

SR 3.3.1.1.4 ---------------------------NOTE----------------------------

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

Perform CHANNEL FUNCTIONAL TEST. 7 days (continued)

Brunswick Unit 2 3.3-4 Amendment No. 2471

RPS Instrumentation 3.3.1.1 s URVEJLLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.1.5 Perform a functional test of each automatic scram 7 days contactor.

SR 3.3.1.1.6 Verify the source range monitor (SRM) and Prior to withdrawing intermediate range monitor (IRM) channels overlap. SRMs from the fully inserted position .

SR 3.3.1.1.7 --------------------------------NOTE--------------------------------

Only required to be met during entry into MODE 2 from MODE 1.

Verify the IRM and APRM channels overlap. 7 days SR 3.3.1.1.8 Calibrate the local power range monitors. 1100 MWOrr average core exposure SR 3.3.1.1.9 Perform CHANNEL FUNCTIONAL TEST: 92 days SR 3.3.1.1.10 Calibrate the trip units. 92 days (continued)

Brunswick Unit 2 3.3-5 Amendment No. 243 I

RPS Jnstru-mentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEI LLANCE FREQUENCY SR 3.3.1.1.11 --------------------------------NOTES------------------------------

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

2. For Functions 2.b and 2.f, the CHANNEL FUNCTIONAL TEST includes the recirculation flow input processing, excluding the flow transmitters.

Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.1.1.12 Perform CHANNEL FUNCTIONAL TEST. 24 months S R 3.3. 1. 1~ 13 --------------------------- NOTES----------------------------

1. Neutron detectors are excluded.

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

3. For Functions 2.b and 2.f, the recirculation flow transmitters that feed the APRMs are included.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.1.1.14 (Not used.)

SR 3.3.1.1.15 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months (continued)

Brunswick Unit 2 3.3-6 Amendment No. 243

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.1.16 Verify Turbine Stop Valve-Closure and Turbine 24 months Control Valve Fast Closure, Trip Oil Pressure-Low Functions are not bypassed when THERMAL POWER is ~ 26 % RTP.

SR 3.3.1.1.17 --------------------------NaTE S---------------------

1. Neutron detectors are excluded.

2~ For Functions 3 and 4, the sensor response time may be assumed to be the design sensor response time.

3. For Function 5, "n" equals 4 channels for the purpose of determining the STAGGERED TEST BASIS Frequency.

4. For Function 2.e, un" equals 8 channels for the purpose of determining the STAGGERED TEST BASIS Frequency. Testing of APRM and Oscillation Power Range Monitor (OPRM) outputs shall alternate.

24 months on a Verify the RPS RESPONSE TIME is within limits. STAGGERED TEST BASIS SR 3.3.1. 1.18 Adjust the flow control trip reference card to conform Once within 7 days to reactor flow. after reaching equilibrium conditions following refueling outage (continued)

Brunswick Unit 2 3.3-7 Amendment No. 247 I

RPS Instrumentation 3.3.1.1 SURVEILLANCE FREQUENCY SR 3.3.1.1.19 Verify OPRM is not bypassed when APRM Simulated 24 months Thermal Power is ~ 25% and recirculation drive flow is

60%.

Brunswick Unit 2 3.3-8 Amendment No. 243 I

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

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

1. Intermediate Range Monitors

a. Neutron Flux-High 2 3 G SR 3.3.1.1.2 ~ 120/125 divisions of tull SR 3.3.1.1.4 scale SR 3.3.1.1.5 SR 3.3.1.1.6 SR 3.3.1.1.7 SR 3.3.1.1.13 SR 3.3.1.1.15 3 H SR 3.3.1.1.2 ~ 1201125 divisions of full SR 3.3.1.1.4 scale SR 3.3.1.1.5 SR 3.3.1.1.13 SR 3.3.1.1.15

b. Inop 2 3 G SR 3.3.1.1-4 NA SR 3.3.1.1.5 SR 3.3.1.1.15 5(3) 3 H SR 3.3.1.1.4 NA SR 3.3.1.1.5 SR 3.3.1.1.15

2. Average Power Range Monitors

a. Neutron Flux-High (Setdown) 2 G SR 3.3.1.1.2 ~22.7% RTP SR 3.3.1.1.5 SR 3.3.1.1.7 SR 3.3.1.1.8 SR 3.3.1.1.11 SR 3.3.1.1.13

b. Simulated Thermal Power-High F SR 3.3.1.1.2 ~ O.5SW + 62.6% RTP(b}

SR 3.3.1.1.3 and SR 3.3.1.1.5 ~ 117.1% RTP SR 3.3.1.1.8 SR 3.3.1.1.11 SR 3.3.1.1.13 SR 3.3.1.1.18 (continued)

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

(b) ~ [0.55 (W - b.W) + 62.6% RTP] when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating." The value of b.W is defined in plant procedures.

(c) Each APRM channel provides inputs to both trip systems.

Brunswick Unit 2 3.3-9 Amendment No. 247

RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 2 of 3)

Reactor Protection System Instrumentation APPLICABLE CONDlnONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION 0.1 REQUIREMENTS VALUE

2. Average Power Range Monitors (continued)

c. Neutron Flux-High F SR 3.3.1.1.2 ~ 118.7% RTP SR 3.3.1.1.3 SR 3.3.1.1.5 SR 3.3.1.1.8 SR 3.3.1.1.11 SR 3.3.1.1.13

d. Inop 1,2 G SR 3.3.1.1.5 NA SR 3.3.1.1.11

e. 2-Out-0f-4 Voter 1,2 2 G SR 3.3.1.1.2 NA SR 3.3.1.1.5 SR 3.3.1.1.11 SR 3.3.1.1.15 SR 3.3.1.1.17

f. OPRM Upscale ~20% RTP SR 3.3.1.1.2 NA(d}

SR 3.3.1.1.5 SR 3.3.1.1.8 SR 3.3.1.1.11 SR 3.3.1.1.13 SR 3.3.1.1.18 SR 3.3.1.1.19

3. Reactor Vessel Steam Dome Pressure- 1,2 2 G SR 3.3.1.1.2 ~ 1077 psig High SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.17

4. Reactor Vessel Water Level-Low Level 1 1,2 2 G SR 3.3.1.1.2 ~ 153 inches SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.17

5. Main Steam Isolation Vaive-Closure 8 F SR 3.3.1.1.5 ~ 10% dosed SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.17

6. Drywell Pressure-High 1,2 G SR 3.3.1.1.2 ~ 1.8 psig SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.10 SR 3.3.1.1.13 SR 3.3.1.1.15 (continued)

(c) Each APRM channel provides inputs to both trip sys~ems.

(d) See COLR for OPRM period based detection algorithm (PBDA) setpoint limits.

Brunswick Unit 2 3.3-10 Amendment No. 243

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

Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECJFIED PER TRIP REQUIRED SURVEILlANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTlOND.1 REQUIREMENTS VALUE

7. Scram Discharge Volume 1,2 2 G SR 3.3.1.1.5 ~ 108 gallons Water Level-High SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.15 5(al 2 H SR 3.3.1.1.5 ~ 108 gallons SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.15

8. Turbine Stop Vafve-Closure ~26% RTP 4 E SR 3.3.1.1.5 ~ 10% closed SR 3.3.1.1-.9 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.16 SR 3.3.1.1.17

9. Turbine Control Valve Fast Closure, ~26% RTP 2 E SR 3.3.1.1.5 ~ 500 psig Control Oil Pressure-low SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.16 SR 3.3.1.1.17

10. Reactor Mode Switch- Shutdown Position 1,2 G SR 3.3.1.1.12 NA SR 3.3.1.1.15 H SR 3.3.1.1.12 NA SR 3.3.1.1.15

11. Manual Scram 1,2 G SR 3.3.1.1.9 NA SR 3.3.1.1.15 H SR 3.3.1.1.9 NA SR 3.3.1.1.15 (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

Brunswick Unit 2 3.3-11 Amendment No. 247

Control Rod Block Instrumentation 3.3 3.3 CONTROL ROD BLOCK INSTRUMENTATION TRMS 3.3 The control rod block instrumentation for each Function in Table 3.3-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3-1.

COMPENSATORY MEASURES

NOlrE-----------------------------------------------------------

Separate Condition entry is allowed for each channel.

REQUIRED COMPENSAlrORY CONDITION MEASURE COMPLElrlON TIME A. --------------NOTE--------------- A.1 Restore channel(s) to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Only applicable for OPERABLE status.

Functions 1, 2 and 3.

One or more functions with one or more required channels inoperable.

B. One or more functions with B.1 Place one channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months control rod block capability not maintained.

OR Required Compensatory Measures and associated Completion Time of Condition A not met.

Brunswick Unit 2 3.3-1 Revision No. 23 I

Control Rod Block Instrumentation 3.3 TEST REQUIREMENTS

~OTE:~----------------------------------------------------------

1~ Refer to Table 3.3-1 to determine which TRs apply for each Control Rod Block Instrumentation Function.

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

TEST FREQUENCY TR 3.3.1 ---------------------------------~OlrE-------------------------------

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

Perform CHANNEL FUNCTIONAL lrE~T. 7 days TR 3.3.2 Perform CHANNEL FUNCTIO~AL TE~lr. 92 days TR 3.3.3 --------------------------------N()TE~------------------------------

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION. 24 months TR 3.3.4 Adjust recirculation drive flow to conform to reactor Once within 7 days flow. after reaching equilibrium conditions following refueling outage (continued)

Brunswick Unit 2 3.3-2 Revision No. 23 I

Control Rod Block Instrumentation 3.3 TEST REQUIREMENTS (continued)

TEST FREQUENCY TR 3.3.5 ---------------------------------N()llE-------------------------------

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

Perform CHANNEL FUNCTIONAL llEST. 184 days Brunswick Unit 2 3.3-3 Revision No. 23 I

Control Rod Block Instrumentation 3.3 Table 3.3-t (page 1 of 1)

Control Rod Brock Instrumentation APPliCABlE MODES OR OTHER SPECIFIED REQUIRED TEST ALLOWABLE FUNCTION CONDITIONS CHANNELS REQUIREMENTS VALUE

1. Average Power Range Monitors

3. Upscale (Row Biased) 3 TR 3.3.3 :SO.5SW +

TR 3.3.4 55.0%RTpa)

TR 3.3.5 and :S 109.3% RTP

b. Inoperative 1,2 3 TR 3.3.5 NA 0

c. Downscale 3 TR 3.3.5 ~ 1.1%APRM power

d. Upscale (Rxed) 2 3 TR 3.3.3 ~14%RTP TR 3 .3 .5 0

2. Source Range Monitors

a. Detector Not Fun In 2{b).5 2 TR 3.3.1 NA

b. Upscale 2(c).5 2 TR 3.3.1 ~5x 105 cps

c. Inoperative 2(c).5 2 TR 3.3.1 NA d.. Downscale 2(b).5 "2 TR 3.3.1 ~3cps

3. Intermediate Range Monitors '-

a. Detector Not Full In 2.5 6 TR 3.3.1 NA

b. Upscale 2.5 6 TR 3.3.1 ~ 1081125 of full scale

c. Inoperable 2.5 6 TR 3.3.1 NA

d. Downscale ~e).5 6 TR 3.3.1 ~3/125 of full scale

4. Scram Discharge Volume Water Level-High 1.2.~ 1{g} TR 3.3.2 ~73gallons TR 3.3.3 (a) :SfO.55(W -I1W) + 55.00k RTP} whenTechnicai Specification 3.3.1'01. Function2.b, is reset for single loop operation per lCO 3.4.1, -Recirculation Loops Operating.- The value of aw is defined in pI~nt procedures.

(b) Bypassed when ~etector is reading > 100 cps or Intennediate Range Monitor (IRM) channels are on Range 3 or higher.

(c) Bypassed when associated JRM channels are on Range 8 or higher.

(d) Deleted.

(e) Bypassed when IRM channels are on Range 1.

(f) With°any control rod withdrawn fromoa core celt containing one or more fueJassemblies. Not applicable to control rods removed perTechriical Specification 3.10.5,

Single Control Rod Drive (CRD) Removal-Refueling," or 3_10~6. -Multiple Control Rod Withdrawal-Refueling.- 0 (9) 0 Signal is contajne~ in Chal')nel A logic only.

Brun~wick "Unit 2 3.3-4 ,Revision No. 306 0 00 "I

SW System and UHS 3.7.2 3.7 PLANT SYSTEMS 3.7.2 Service Water (SW) System and Ultimate Heat Sink (UHS)

Leo 3.7.2 SW System and UHS shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME f\. ---------NOTE------------------- A.1 ---------------NOTE-------------

Only applicable when Unit 1 Enter applicable Conditions is in MODE 4 or 5. and Required Actions of LeO 3.8.1, nAC Sources-Operating," for diesel One required nuclear generators (DGs) made service water (NSW) pump inoperable by NSW.

inoperable due to an inoperable Unit 1 NSW header. Restore required NSW 14 days pump to OPERABLE status.

(continued)

Brunswick Unit 2 3.7-4 Amendment No. 233

SW System and UHS 3.7.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One required NSW pump 8.1 ---------------N()TE-------------

inoperable for reasons other Enter applicable Conditions than Condition A. and Required Actions of LCO 3.8. 1 for DGs made inoperable by NSW.

Restore required NSW 7 days pump to OPERABLE status. AND 14 days from discovery of failure to meet LeO Cg One.required conventional C.1 Verify the one OPERABLE Immediately service water (CSW)-pump CSW pump and one inoperable. OPERABLE Unit 2 NSW pump are powered from separate 4.16 kV emergency buses.

AND C.2 Restore required CSW 7 days pump to ()PERABLE status. AND 14 days from discovery of failure to meet LCO (continued)

Brunswick Unit 2 3.7-5 Amendment NO. 233

SW System and UHS 3.7.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action C.1 and D.1 Restore required CSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months associated Completion Time pump to OPERABLE not met. status.

E. Two required CSW pumps E.1 ---------------NOTE-------------

inoperable. Enter applicable Conditions and Required Actions of LeO 3.7.1, nResidual Heat Removal Service Water (RHRSW) System," for RHRSW subsystems made inoperable by CSW.

Restore one required CSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months pump to OPERABLE status. AND 14 days from discovery of failure to meet LCO F. One required NSW pump F.1 Restore required NSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. *pump to OPERABLE status.

AND OR One required CSW pump inoperable. F.2 Restore required CSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months pump to OPERABLE status.

(continued)

Brunswick Unit 2 3.7-6 Amendment No. 233

SW System and UHS 3.7.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME G. One required NSW pump G.1 Verify by administrative Immediately inoperable. means that two Unit 2 NSW pumps are OPERABLE.

AND AND Two required CSW pumps inoperable. G.2.1 Restore requiredNSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months pump to OPERABLE status.

OR G.2.2 Restore one required CSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months pump to OPERABLE status.

H~ Water temperature of the H.1 Verify water temperature of Once per hour UHS > 90.5°F and ~ 92°F. the UHS is ::; 90.5°F averaged over previous 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period.

(continued)

Brunswick Unit 2 3.7-7 Amendment No. 240 I

SW System and UHS 3.7.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME I. Required Action and 1.1 Be in *MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A, B, 0, E, F, AND G, or H not met.

1.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR Required Action C.2 and associated Completion Time not met.

OR Two or more required NSW pumps inoperable.

OR SW System inoperable for reasons other than Conditions A, B, C, D, E, F, and G.

OR UHS inoperable for reasons other than Condition H.

Brunswick Unit 2 3.7-8 Amendment No. 233

SWSystem and UHS 3.7.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.2.1 Verify the water level in the SW pump suction bay of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the intake structure is ~ -6 ft mean sea level.

SR 3.7.2.2 Verify the water temperature of UHS is s 90.5°F. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.7.2.3 -------------------------------~()TE-~-----------------------------

Isolation of flow to individual components does not render SW System inoperable.

Verify each SW System manual, power operated, and 31 days automatic valve in the flow paths servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.2.4 --------------------------------N()TE--------------------------------

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

2. Isolation of flow to individual components does not render SW System inoperable.

Verify automatic transfer of each DG cooling water 92 days supply from the normal SW supply to the alternate SW supply on low DG jacket cooling water supply pressure.

(continued)

Brunswick Unit 2 3.7-9 Amendment No. 240

SW System and UHS 3.7.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.7.2.5 -------------------------------N()lrE---------------------------------

Isolation of flow to individual components does not render SW System inoperable.

Verify each required SW System automatic component 24 months actuates on an actual or simulated initiation signal.

Brunswick Unit 2 3.7-10 Amendment No. 233

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

APPLICABILITY: MODE 1, MODES 2*and 3, except high pressure coolant injection (HPCI) and ADS

valves are not required to be OPERABLE with reactor steam dome pressure ~ 150 psig.

ACTIONS

N()TE----------------------------------------------------------

LCO 3.0.4.b is not applicable to HPCI.

CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS A.1 Restore low pressure .7 days injection/spray subsystem ECCS injection/spray inopera~le. subsystem to OPERABLE status.

OR One -low pressure coolant injection (LPCI) pump in each subsystem inoperable.

B. One LPCI pump inoperable. B.1 Restore LPCI pump to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

AND OR One core spray (CS) subsystem inoperable. 8.2 Restore CS subsystem to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

(continued)

Brunswick Unit 2 3.5-1 Amendment No. 2601

ECCS-operating 3.5.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

c. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A or B not met. AND C.2 Be in MOOE4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months D. HPCI System inoperable. 0.1 Verify by administrative Immediately means RCtC System is OPERABLE.

AND 0.2 Restore HPCI System to 14 days OPERABLE status.

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

AND OR One low pressure ECCS injection/spray subsystem is E.2 Restore low pressure 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. ECCS injection/spray subsystem to OPERABLE status.

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

(continued)

Brunswick Unit 2 3.5-2 Amendment No. 233

ECCS-Operating 3.5.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME G. One required ADS valve G.1 Restore required ADS valve 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable. to OPERABLE status.

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

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

AND OR HPCI System inoperable. H.2 Restore HPCI System to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

L Required Action and 1.1 Be in MODE 3~ 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition OJ E, F, G, or H AND not met.

1.2 Reduce reactor steam 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR dome pressure to

~ 150 psig.

Two or more required ADS valves inoperable.

(continued)

Brunswick Unit 2 3.5-3 Amendment No. 233

ECCS-Operating 3.5.1 ACTIONS (continued)

CONDITION REQUIRED ACTI.ON COMPLETION TIME J. Two or more low pressure J.1 Enter LCO 3.0.3. Immediately ECCS injection/spray subsystems inoperable for reasons other than Condition A or B.

HPCI System and two or more required ADS valves inoperable.

SURVEILLANCE' REQUIREMENTS SURVEILLANCE FREQUENCY

. SR 3.5.1.1 Verify, for each ECCS injection/spray subsystem, the 31 days piping is filled with water from the pump discharge valve to the injection valve.

(continued)

Brunswick Unit 2 3.5-4 Amendment No. 233

ECCS-Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.2 -------------------------------NOTE--------------------------------

Low pressure coolant injection (LPC1) subsystems may be considered OPERABLE during alignment and operation for decay heat removal with reactor steam dome pressure *Iess than the Residual Heat Removal (RHR) shutdown cooling isolation pressure in MODE 3, jf capable of being manually realigned and not otherwise inoperable.

Verify each ECCS injection/spray subsystem manual, 31 days power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.5.1.3 Verify ADS pneumatic supply header pressure is 31 days 295 psig.

SR 3.5.1.4 Verify the RHR System cross tie valve is locked 31 days closed.

SR 3.5.1.5 -------------------------------NOTE--------------------------------

Not required to be performed if performed within the previous 31 days.

Verify each recirculation pump discharge valve and Once each startup bypass valve cycles through one complete cycle of full prior to exceeding travel or is de-energized in the closed position. 250/0 RTP (continued)

Brunswick Unit 2 3.5-5 Amendment No. 233

ECCS-Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.6 Verify the following ECCS pumps develop the 92 days specified flow rate against a system head corresponding to the specified reactor pressure.

SYSTEM HEAD CORRESPONDING NO. OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF CS ~ 4100 gpm 1 ~ 113 psig LPCI ~ 14,000 gpm 2 ~ 20 psig SR 3.5.1.7 -------------------------------NOTE--------------------------------

Not required to be performed until 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months after reactor steam pressure is adequate to perform the test.

Verify, with reactor pressure::; 1045 and ~ 945 psig, 92 days the HPCI pump unit can develop a flow rate

~ 4250 gpm against a system head corresponding to reactor pressure.

SR 3.5.1.8 -------------------------------NOTE--------------------------------

Not required to be performed until 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months after reactor steam pressure is adequate to perform the test.

Verify, with reactor pressure::; 180 psig, the HPCI 24 months pump unit can develop a flow rate ~ 4250 gpm against a system head corresponding to reactor pressure.

(continued)

Brunswick Unit 2 3.5-6 Amendment No. 233

ECCS-Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.9 -------------------------------N0 TE-----------------------

Vessel injection/spray may be excluded.

Verify each ECCS injection/spray subsystem actuates 24 months on an actual or simulated automatic initiation signal.

SR 3.5.1.10 --------------------------NOTE------------------------

Valve actuation may be excluded.

Verify the ADS actuates on an actual or simulated 24 months automatic initiation signal.

SR 3.5.1.11 -----------------------------NOTE-------------------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure is adequate to perform the test.

Verify each required ADS valve opens when manually 24 months actuated.

SR 3.5.1.12 -----------------------------NOTE-------------------------------

Instrumentation response time may be assumed to be the design instrumentation response time.

Verify the ECCS RESPONSE TIME for each ECCS 24 months injection/spray subsystem is within the limit.

Brunswick Unit 2 3.5-7 Amendment No. 233

ML072960448

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