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| number = ML072960448 | | number = ML072960448 | ||
| issue date = 01/31/2007 | | issue date = 01/31/2007 | ||
| title = | | title = July-August Exam 50-325, 324/2007301 Draft Simulator Scenarios (2 of 4) | ||
| author name = | | author name = | ||
| author affiliation = - No Known Affiliation | | author affiliation = - No Known Affiliation |
Revision as of 17:56, 17 April 2019
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) | |
See also: IR 05000325/2007301
Text
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 Following the in standby.The.fail to auto start W pump issue cification
progressively
plug with river*nitially slowly lower.The crew ill lower reactor power and II CWPs will trip and he Reactor had not been.The crew will respond pertrip on overcurrent.
Additionally
RWCU et, the SDV vent and drain valves will leve III drop below LL4 requiring Emergency sk).When ADS valves are opened (ADS SRV C fails to ust be overridden
off to prevent uncontrolled
injection en pressure drops below MARFP, injection may be PV level above LL4 (Critical Task).Condensate
should be o inability to throttle RHR flow for 5 minutes.The operators will start CSW pump 2C following maint pump start, CSW Pump 2A will be removed from se 2C CSW pump will then trip on overcurrent
and t (it will start manually).
The crew will respond p is addressed, a HPCllogic power failure will entry.The Circulating
Water Pumps (CWPs)intake sc silt resulting in CWP pump trips.C.ser vacuu wiU enter AOP-37.1, Intake Structu e.The the BOP operator will attempt to rec condenser vacuum will be lost causin scrammed, a scram will 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.Most control rods*LPC.When SLO will fail to automati*fail to open.Witho Depress open.Low during depres recommenced
to used for injection d 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 Red Cap on 28 CRD PP EVENTS g, lowering vacuum nal/ATWS/RWCU
G31-F004 auto close B failure
EGe NA NA Manual 3 2 4 1 NA NA NA RxPwr Core Age Trigger Trigger Description
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 8 9 3 1 4 6 7 2 5 10 Event Number 2007 NRC Examination
Scenario#2 3
FAULT RPOO5F AUTO SCRAM DEFEAT FAULT TRUE 6 Remotes Summary 6 Trig 5 Trig Dactime Tri Actime Rmptime Actime AVal OverrideTe OVal Positionl NONE BKR CTL DC FUSES CRD PUMP 2B 2B SLC PUMMP MOTOR BKR UNCOUPLE RCIC TURBINE FROM PUMP Description
DISCH VOL TEST File Override Summary Tag 10 Remf 10 K2213A Mult Description
Current Target ,t----+--I_D_--+-
-+--V_a_lu_e
__-+--+---+_---11 OUT 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 2007 NRC Examination
Scenario#2 r Pumps 5
SCENARIO INFORMATION
Examiner Notes Procedures
Used in Scenarios:
EVENT 1*OGP-12 (power reduction)SCRAMPROCEDURE)
OWER CONTROL PROCEDURE)
- 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 7*2EOP-*2EOP-01-Event 5 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 Pressure (MARFP)recommence
injection to restorer" 2007 NRC Examination
Scenario#2 eactor Flooding ater level above LL4 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 line.2007 NRC Examination
Scenario#2 power below the Melita 8
EVENT 1 SHIFT TURNOVER, LOWER REACTOR POWER TO 90 0 k 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: seQ Correctly recognizes
LPRM failure and Objectives:
- LPRM 28-13-40 fails, resulting in various annunciators
ocated with APRM#1 es downscale LPRM ermines less than 3 LPRMs operable of same.rable.Bypasses APRM#1, Determination
is made that rements are being met for the minimum number of.1-RPS, TRM 3.3 Rod Block)Evaluates Technical Specificati
Recognizes
and evaluates impac specific level-APRM#1 inope Refers to annunciato
LPRM failure and AP Recogn'Technical Operable AP BOP RO*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 28-13-4D on APRM#1 per 20P-09 M(APRM nd LPRMs per;j:eports indications
of o Direct BOP to bypass the affe'o Obtain information
from RO/SOP regar assignment, associated
LPRM statu level.RO 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: , Section entional Service Water section 8.23.Conventional
Service Water Pump Ions are normal.;;" nventional
Service Water Pump is running normally*None Success Path: sea Directs BOP to start 2C Conventional
Servi Conventional
Service Water Pump in sta,., Objectives:
BOP Place 2C Conventional
Service Wat Conventional
Service Water Pump an 8.23.2007 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 Section 8.23 BOP APPLICANT'S
ACTIONS OR BEHAVIOR: 2007 NRC Examination
Scenario#2 ps per 20P-43, 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: Diesel Generator Building, wait 3 minutes and report that all three phases of the 2C Conventional
Service Water nd the 2A ure demand signal.thin normal ranges with g.onal Service ter Pump within normal limits.BOP Enters OAOP-19 and manually starts t to restore Conventional
Service Water pa Success Path: SCQ Enters OAQP-19.0 and directs the action The Conventional
Service Water Syst, Objectives:
2C Conventional
Service Water Pump will trip on electrical
f Conventional
Service Water Pump will fail to start on a 10 2007 NRC Examination
Scenario#2 14
EVENT 4 CONVENTIONAL
SERVICE WATER PUMP FAILURE Required Operator Actions Abnormal Operating Procedures
-Conventional
Service Water Failure two Conventional
not start on a-Tracking P-19 and restores within normal parameter ATER PRESS-LOW UMP C TRIP o o Enters OAOP-19 and directs BOP to execut the system to normal parameters
o Enters and executes Conventional
Service'ranges.o Reviews Technical Specifications
for*Service Water Pumps (one electri low header pressure demand).LCO BOP SRO 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).
t to the Technical the logic power supply source es that HPCI is inoperable
and unavailable, properly secures , and evaluates the condition with respect to Technical Evaluate the impact of the HP Specifications.
Evaluate the conditions
obs HPCI which has rendered it'*Logic power to the HPCI system will be interrupt inoperability
and unavailability.
The crew carre the system per 2 Specifications.
Objectives:
RO Malfunctions
required: sea 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 the HPCI logic power is tripped and, if directed to a.breaker immediately
tripped, again.*WHEN asked as I&C to come to the contro acknowledge
the request.2007 NRC Examination
Scenario#2 circuit 2 breaker for a reset, report that the e investigation, 17
EVENT 5 HPCI LOGIC POWER FAILURE Required Operator Actions: seQ quirements
for the days)by the applicable
HPCI power 10 s and the'the securing of HPCI and its*Evaluate the plant impact and Technical Specifica.HPCI inoperability.
(3.5.1-Verify RCIC Operab*When directed by the SCQ" procedure.
- Inform the SCQ of the annunciators
procedural
guidance, specifically
as it subsequent
unavailabilit
-2-A-1 2-5, HPCI FIC P*Direct the RO to carry out the actions nece by the annunciator
procedure AP RO 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: to rise due to s tripping on a high denser vacuum win er flow due to pump contained in OAOP-37.1 to ieat sink.condenser vacuum at (Iine-in-the-sand)
unit sca in an effort the maintain main ake structure blockage Restarts Cire ns for fouling of Circ Water Intake Screens, enters and en recognized
the condition as worsening and not cision/takes
the actions to scram the reactor.o*Circ Water Intake screen differential
pressure will vegetative
fouling, followed by Circ Water Intak differential
pressure signal.Impacted by this begin to lower due to heat sink availability
(trips).Crew recoexecutes OA recoverable, m BOP RO seQ-Enter and direct actions associated
WI Objectives:
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: is applied (hydraulic
the RTGB (pump-F004 t will fail to s/reports the A TWS conditions
arries out the actions of LEP-02.BOP reports the 28 SLC Pump failure failu";the 2-G31-F004 (RWCU outboard isolation valve).the valve.RO Will recognize the conditions
for an ATWS and 2-EOP-01-LPC (Level-Power
Con, d OEOP-Control Procedure)
Objectives:
SCO Will enter and direct the actions of 2EOP-0" Multiple control rods will fail to insert when a reactor scram sig ATWS).When started the 2B SLC Pump indication
will be I motor breaker trip).The RWCU outboard isolation valveautomaticallyclose
when the SLC system is
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 A TWS WITH SLC COMPONENT AND SIGNAL FAILURE Required Operator Actions: SCO Enter and directs the actions of 2EOP-01-RSP (Reactor Scram Procedure)
ute the actions of ary Containment
outboard isolation valve).ith reactor level and pressure control as directed by s injection from low pressure systems@LL3 BOP When directed, e"..Recognizes
and reports, Takes manual action.When directed, initiates SLC and re Direct entry into LEP-02 to insert control rods Performs the initial scram actions Directs Terminate and prevent Injection per Will recognize the conditions
for an ATWS and will enter an,'2-EOP-01-LPC (Level-Power
Control)and OEOP-02-PCC
Control Procedure)
RO 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.
lish and reports to the unit sca of d, when directed, secures n that a problem exists with RCIC uate discharge head for inject water implements
alternate actions in the taining critical parameters.,e co
that there is not any flow noise coming from turbine end of the shaft appears to be turning and the rs to not be turning.Observes RCIC perfRCle's inability to de RCIC.Evaluates indications
of RCIC unavailability, and utilizes Le course of action.Success Path: WH the RCI" pump end Obiectives:
BOP Rele will not develop discharge pressure and/or flow whe inject water into the vessel Malfunctions
Required: sea 2007 NRC Examination
Scenario#2 26
EVENT 9 RCIC COUPLING FAILURE Required Operator Actions: seQ to develop flow ility.*Dispatches
AO to investigate
RelC*Attempts to operate RCIC and inform and/or discharge head, assisting i*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 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.C Tank (Hot Shutdown r water leve ergency Dep ssurize the el-Power Control Flowchart from Low Pressure and Alternate.s not opening when LEP-02 jumpers are 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 Correctly evaluates inability t Level 4 and provides direction t reactor and recommence
injection Informs the SeQ when Boron We*Objectives:
2-B21-F013C (ADS Valve C)will fail to open when its c"Open" position.BOP RO Continues to insert c Malfunctions
Required: sea 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 ter level above Low cy Depressurize
the ntrol Flowchart e Tank (Hot Shutdown from Low Pressure and Alternate.s not opening when LEP-02 jumpers are Control Switches in Open Position, when directed.013C ADS valve does not open and informs SeQ ional SRV when directed Directs BOP operator to termin Emergency Depressurize
the Condensate
and Feedwater to r Correctly evaluates inability to maintain R Level 4 and provides direction to the cre E reactor and recommence
injection i Level-Po Informs the SeQ when Boron Wei BOP RQ Continues to insert c seo EOP Action-Emergency Depressurize
the reactor and res e level above LL4 with a failure of ADS Valve C to open 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: band , or Hot Shutdown Boron Weight and to 200".Direct BOP operator to raise using Feedwater and Condensa If all rods in, direct R Control Objectives:
RO Success Path: None None BOP sea Recognize conditions
exist to allow r normal operating band 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 a range of 170" to 200" upon achieving AllWeight RO Continue to insert control rods and/or i Shutdown Boron Weight is achieved BOP APPLICANT'SA'2007 NRC Examination
Scenario#2 reactor water level to hutdown Boron t 0" to 200" using 33
Simulator Operator Activities:
WHEN directed by the lead examiner, placethesimulator
in FREEZE.CAUTION DO NOT RESET THE SIMULATOR P OF CONCURRENCE
TO DO SO EXAMINER 2007 NRC Examination
Scenario#2 TO RECEIPT THE LEAD 34
RPV Level Transmitters (FIGURE 01.2-4 from 80-01)Ot02i0ID" LI CR 1AI I J I I I I I I I , I-'CR z CONTROL ROOM LT N038 2/3 CORE HEIGHT.INTERLOCK
U R6i0*150" to+150" 150" to 550"
550*CR A paoa RSDP I---------,r---f-------.
I 14-------I-----....J
I I I__I@R@'R615 CR 5977 P60i 2/3 CORE HEIGHT*J 1 INTERLOCK I I I I I
J I C32S'50-210" R606 CR B P603
Ot0210"----.Ra09o to 210" I A CR LI I ROO4 I B CR I 210" 1 P601--------1 BX RSDP
Progress Energy IOGP-12 BRUNSWICK NUCLEAR PLANT PLANT OPERATING MANUAL VOLUME IV GENERAL PLANT OPERATING PROCEDURE UNIT o OGP-12 POWER CHANGES REVISION 49 Rev.49 C Continuous
Use Page 1 of 371
SECTION TABLE OF CONTENTS 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.Thisprocedure
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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of reaching or exceeding 23%rated thermal power.2.0 REFERENCES
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 IR221 NOTE: 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.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 3.11.2 3.11.3 SULCV FW-LIC-3269, Control Station RFPT A (B)SP CTL C32-SIC-R601A(B), Control Stations MSTR RFPT SPIRX L VL 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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 3.15.2 Control rod movements are NOT required for the power change.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.
Anypagesdiscarded
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 5.1 Power Reduction Unit DatelTime Started/---------Initials 5.1.1 All applicable
prerequisites
listed in Section 4.0 are met.NOTE: NOTE: NOTE: NOTE: 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 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.
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).TheShift 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.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
IOGP-12 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
1Rev.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 1.2.WHEN the HP turbine exhaust pressure decreases below 90 psig, THEN CONFIRM the following reheat steam high load valves go closed.RSHLV-1 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 t THEN it is preferred to remove the RFPTwhichexhausts
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 IOGP-12 CHECK the remaining heater drain discharge level control valve stays throttled to maintain deaerator level between 45 and 59/inches.
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 IOGP-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.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
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 2005.1.13 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 TERDRAINPUMP B DISCHARGE
HD-LV-91-2
HEA TER DRAIN PUMP C DISCHARGE
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 IOGP-12 IF reactor power is to be reduced below 26%RTP, THEN CONTACT the Reactor Engineer.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 WITHDRA W 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 1.2.IOGP-12 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 10 6 Ibm/hr: PLACE RFP A (B)RECIRC VLV, FW-FV-V46 (FW-FV-V47)
control switch in OPEN.CONFIRM RFP A (B)RECIRC VLV, FW-FV-V46 (FW-FV-V47)
is open.Rev.49 Page 15 of 371
5.0 PROCEDURAL
STEPS Initials 5.1.20 1.2.IF a heater drain pump is in-service
at 200 MWe, THEN PERFORM the following:
STOP the remaining heater drain pump.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 10 6 Ibm/hr, THEN Digital Feedwater Control System will automatically
shift to 1 ELEM control.5.1.22 1.2.5.1.23 IOGP-12 IF required to stabilize feedwater flow (RFPT operation), THEN PERFORM the following:
ENSURE FW-FV-177/S0L
VLV, FW-V10, is open.OPEN FEDWA TER REC/RC TO CONDENSER VL V, FW-FV-177, to bypass approximately1x 10 6 Ibm/hr to the hotwell.CONFIRM core thermal limits are within the prescribed
limits of Technical Specifications.
Rev.49 Page 17 of 371
Initials 5.0 PROCEDURAL
STEPS Initials DatelTime Completed_Performed By (Print)Comments: Reviewed By:_Unit sca 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 istheprimary
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 5.2.4 5.2.5 1.IOGP-12 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.
IF Digital Feedwater Level Control System is in 1-ELEM control, THEN swap to 3-ELEM control in accordance
with 1 (2)OP-32.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.
WHEN FEEDWA TER RECIRC TO CONDENSER VLV, FW-FV-177, is closed, THEN CLOSE FW-FV-177/S0L
VLV, FW-V10.Rev.49 Page 20 of 371
5.0 PROCEDURAL
STEPS 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reaching or exceeding 23°/b RTP.Initials 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 IOGP-12 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.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.
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 1.2.5.2.17 5.2.18 WHEN feedwater flow is greater than 3.3 x 10 6 Ibm/hr AND heater drains are forward pumping, PERFORM the following:
Unit 1 Only: CLOSE RFP A(B)RECIRC VALVE, FW-FV-V46(V47), by placing the control switch to AUTO.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.ADJUST SJAE CONDENSA TE RECIRCULA TION VALVE, CO-FV-49, as necessary, to maintain condensate
pump discharge pressure between 190 and 230 psig.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 1.PRIOR to 26%RTP (760 MWT), CONFIRM Turbine Stop Valve/Control
Valve Fast Closure Reactor SCRAM is enabled by performing
the following:
ENSURE TSVITCV MANUAL TRIP BYPASS switches are in NORMAL at Panel H 12-P609: C71(72)-S10A
C71(72)-S10C
IOGP-12 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.Rev.49 Page 24 of 371
5.0 PROCEDURAL
STEPS 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.
Initials 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 1,3,50608, 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 NOTE: The K9A-D relays are deenergized
when they are at the stop screws.Initials 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 1.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.Unit 1 only: a.INSTALL fuse C71-F9A in Panel H12-P609.b.INSTALL fuse C71-F9C in Panel H12-P609.c.INSTALL fuse C71-F98 in Panel H12-P611.d.INSTALL fuse C71-F9D in Panel H12-P611./Ind.Ver./Ind.Ver./Ind.Ver./Ind.Ver.2.Unit 2 only: a.INSTALL fuse C72-F9A in Panel H12-P609.b.INSTALL fuse C72-F9C in Panel H12-P609.c.INSTALL fuse C72-F98 in Panel H12-P611.d.INSTALL fuse C72-F9D in Panel H12-P611.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.
/Ind.Ver./Ind.Ver./Ind.Ver./Ind.Ver.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 5.2.27 IOGP-12 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.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.Rev.49 Page 28 of 371
5.0 PROCEDURAL
STEPS 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.Initials 5.2.28 5.2.29 5.2.30 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.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.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 5.2.32 5.2.33 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.WHEN reactor power exceeds 65°1'<>, THEN ENSURE REHEAT STEAM HIGH LOAD VALVES, RSHLV-1 AND RSHL V-2, open.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 IOGP-12 INCREASE reactor power as directed by the Unit SCQ, in accordance
with the Reactor Engineer's
recommendation.
Rev.49 Page 29 of 371
5.0 PROCEDURAL
STEPS Initials Initials 5.2.35 5.2.36 5.2.37 COMMENTS: 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).
CONFIRM core thermal limits are within the prescribed
limits of Technical Specifications.
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)Reviewed By:_Unit sea 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 0610 14 182226 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
Page of__ATTACHMENT
1 Page 2 of 3 Control Rod Movement 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/To/To/To/To/To/To/To/To/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.I OGP-12 I Rev.49 I Page 32 of 37 1
Initials ATTACHMENT
1 Page 3 of 3 Control Rod Movement Other Instructions
_DatelTime Completed_Performed By (Print)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
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 (ERFIS)(P603)(A)C32FA014 C32-R603A (B)C32FA015 C32-R603B (C)C32FA016 C32-R603C (0)C32FA017 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 powerchangesexceed
15%in one hour revised to match wording in ODCM.Same note added to down power portion of procedure (PRR214286).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 Attachment
1.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 POSSIBLE PLANT EFFECTS less than or equal to 3 on the 0 to 125 scale 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
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 POSSIBLE PLANT EFFECTS Less than 17 LPRM detector inputs to flux average Less than 3 LPRM detectors per axial level.Self-test fault.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 downscaleandany 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
I but available.
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.
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
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 POSSIBLE PLANT EFFECTS Deenergized
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
8.4.1 8.4 Bypassing a LPRM Initial Conditions
Initials DatelTime Started-------C Continuous
Use 1.8.4.2 LPRM is required to be bypassed (indication
invalid, erratic, etc.).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 BAR GRAPH 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"123 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 itsscanningdisabled
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
Initials 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)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 A.One or more required channels inoperable.
A.1 REQUIRED ACTION Place channel in trip.COMPLETION
TIME 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> A.2-----------NOTE------------
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Not applicable
for Functions2.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 CTIONS (continued)'
CONDITION REQUIRED ACTION COMPLETION
TIME B.------------NOTE:----------------
B.1 Place channel in one trip 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 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 <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Action D.1 and referenced
in POWER to<26%RTP.Table 3.3.1.1-1.
A (continued)
Brunswick Unit 2 3.3-2 Amendment No.247 I
RPS Instrumentation
3.3.1.1 CTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION
TIME*F.As required by Required F.1 Be in.MODE 2.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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 <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated
Completion
Time POWER to<20%RTP.of Condition I not met.A Brunswick Unit 2 3.3-3 Amendment No.243 I
RPS Instrumentation
3.3.1.1 SURVEILLANCE
REQUIREMENTS
..:::-----------------------------------------
NOTE S------------------------------------------------
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
r entry into associated
Conditions
and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated
Function maintains RPS trip capability.
SR 3.3.1.1.1 SR 3.3.1.1.2 SR 3.3.1.1.3 SR 3.3.1.1.4 Brunswick Unit 2 SURVEILLANCE (Not used.)Perform CHANNEL CHECK.----------------------------NOTE----------------------------
Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER230/0 RTP.Adjust the average power range monitor (APRM)channels to conform to the calculated
power while operating at230/0 RTP.---------------------------NOTE----------------------------
Not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.Perform CHANNEL FUNCTIONAL
TEST.3.3-4 FREQUENCY 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 24 hours 7 days 7 days (continued)
Amendment No.2471
RPS Instrumentation
3.3.1.1 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 s (continued)
Brunswick Unit 2 3.3-5 Amendment No.243 I
SURVEILLANCE
REQUIREMENTS (continued)
SURVEI LLANCE RPS Jnstru-mentation
3.3.1.1 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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.S R 3.3.1.113---------------------------
NOT E S----------------------------
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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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.
SR 3.3.1.1.14 (Not used.)24 months 24 months SR 3.3.1.1.15
Brunswick Unit 2 Perform LOGIC SYSTEM FUNCTIONAL
TEST.3.3-6 24 months (continued)
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 is26%RTP.SR 3.3.1.1.17
N
aTE S---------------------
1.Neutron detectors are excluded.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.
SR 3.3.1.1.18 Brunswick Unit 2 Verify the RPS RESPONSE TIME is within limits.Adjust the flow control trip reference card to conform to reactor flow.3.3-7 24 months on a STAGGERED TEST BASIS Once within 7 days after reaching equilibrium
conditions
following refueling outage (continued)
Amendment No.247 I
SURVEILLANCE
RPS Instrumentation
3.3.1.1 FREQUENCY SR 3.3.1.1.19
Verify OPRM is not bypassed when APRM Simulated 24 months Thermal Power is25%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
FUNCTION 1.Intermediate
Range Monitors a.Neutron Flux-High b.Inop 2.Average Power Range Monitors a.Neutron Flux-High (Setdown)b.Simulated Thermal Power-High
APPLICABLE
MODES OR OTHER SPECIFIED CONDITIONS
2 2 5(3)2 REQUIRED CHANNELS PER TRIP SYSTEM 3 3 3 3 CONDITIONS
REFERENCED
FROM REQUIRED ACTIOND.1 G H G H G F SURVEILLANCE
REQUIREMENTS
SR 3.3.1.1.2 SR 3.3.1.1.4 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
SR 3.3.1.1.2 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.13
SR 3.3.1.1.15
SR 3.3.1.1-4 SR 3.3.1.1.5 SR 3.3.1.1.15
SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.15
SR 3.3.1.1.2 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
SR 3.3.1.1.2 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
SR 3.3.1.1.18
ALLOWABLE VALUE120/125 divisions of tull scale1201125 divisions of full scale NA NA
RTPO.5SW+62.6%RTP(b}and117.1%RTP (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,"RecirculationLoopsOperating." 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
Table 3.3.1.1-1 (page 2 of 3)Reactor Protection
System Instrumentation
RPS Instrumentation
3.3.1.1 FUNCTION 2.Average Power Range Monitors (continued)
c.Neutron Flux-High d.Inop e.2-Out-0f-4
Voter f.OPRM Upscale 3.Reactor Vessel Steam DomeHigh 4.Reactor Vessel Water Level-Low Level 1 5.Main Steam Isolation Vaive-Closure
6.Drywell Pressure-High
APPLICABLE
MODES OR OTHER SPECIFIED CONDITIONS
1,2 1,2RTP 1,2 1,2 1,2 REQUIRED CHANNELS PER TRIP SYSTEM 2 2 2 8 CONDlnONS REFERENCED
FROM REQUIRED ACTION 0.1 F G G G G F G SURVEILLANCE
REQUIREMENTS
SR 3.3.1.1.2 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
SR 3.3.1.1.5 SR 3.3.1.1.11
SR 3.3.1.1.2 SR 3.3.1.1.5 SR 3.3.1.1.11
SR 3.3.1.1.15
SR 3.3.1.1.17
SR 3.3.1.1.2 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
SR 3.3.1.1.2 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
SR 3.3.1.1.2 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
SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.13
SR 3.3.1.1.15
SR 3.3.1.1.17
SR 3.3.1.1.2 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
ALLOWABLE VALUE118.7%RTP NA NA NA(d}1077 psig153 inches10%dosed1.8 psig (continued)(c)Each APRM channel provides inputs to both trip(d)See COLR for OPRM period based detection algorithm (PBDA)setpoint limits.Brunswick Unit 2 3.3-10 Amendment No.243
Table 3.3.1.1-1 (page 3 of 3)Reactor Protection
System Instrumentation
RPS Instrumentation
3.3.1.1 FUNCTION 7.Scram Discharge Volume Water Level-High
8.Turbine Stop Vafve-Closure
9.Turbine Control Valve Fast Closure, Control Oil Pressure-low
10.Reactor Mode Switch-Shutdown Position 11.Manual Scram APPLICABLE
MODES OR OTHER SPECJFIED CONDITIONS
1,2 5(alRTPRTP 1,2 1,2 REQUIRED CHANNELS PER TRIP SYSTEM 2 2 4 2 CONDITIONS
REFERENCED
FROM REQUIRED ACTlOND.1 G H E E G H G H SURVEILlANCE
REQUIREMENTS
SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.13
SR 3.3.1.1.15
SR 3.3.1.1.5 SR 3.3.1.1.9 SR 3.3.1.1.13
SR 3.3.1.1.15
SR 3.3.1.1.5 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
SR 3.3.1.1.5 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
SR 3.3.1.1.12
SR 3.3.1.1.15
SR 3.3.1.1.12
SR 3.3.1.1.15
SR 3.3.1.1.9 SR 3.3.1.1.15
SR 3.3.1.1.9 SR 3.3.1.1.15
ALLOWABLE VALUE108 gallons108 gallons10%closed500 psig NA NA NA NA (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 COMPENSA lrORY CONDITION MEASURE COMPLElrlON
TIME A.--------------NOTE---------------
A.1 Restore channel(s)
to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 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
1Refer 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated
Function maintains control rod block capability.
TR 3.3.1 TR 3.3.2 TR 3.3.3 TR 3.3.4 Brunswick Unit 2 TEST
Not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.Perform CHANNEL FUNCTIONAL
Perform CHANNEL
Neutron detectors are excluded.Perform CHANNEL CALIBRATION.
Adjust recirculation
drive flow to conform to reactor flow.3.3-2 FREQUENCY 7 days 92 days 24 months Once within 7 days after reaching equilibrium
conditions
following refueling outage (continued)
Revision No.23 I
Control Rod Block Instrumentation
3.3 TEST REQUIREMENTS (continued)
TR 3.3.5 Brunswick Unit 2 TEST---------------------------------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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.Perform CHANNEL FUNCTIONAL
llEST.3.3-3 FREQUENCY 184 days Revision No.23 I
Control Rod Block Instrumentation
3.3 Table 3.3-t (page 1 of 1)Control Rod Brock Instrumentation
FUNCTION 1.Average Power Range Monitors APPliCABlE
MODES OR OTHER SPECIFIED CONDITIONS
REQUIRED CHANNELS TEST REQUIREMENTS
ALLOWABLE VALUE 3.Upscale (Row Biased)b.Inoperative
c.Downscale d.Upscale (Rxed)1,2 2 3 TR 3.3.3:SO.5SW+TR 3.3.4 55.0%RTpa)
TR 3.3.5 and:S 109.3%RTP 3 TR 3.3.5 NA 3 TR 0 3.3.51.1%APRM power 3 TR 3.3.3
TR 0 3.3.5 2.Source Range Monitors a.Detector Not Fun In b.Upscale c.Inoperative
d..Downscale 3.Intermediate
Range Monitors'-a.Detector Not Full In b.Upscale c.Inoperable
d.Downscale 4.Scram Discharge Volume Water Level-High
2{b).5 2 TR 3.3.1 NA 2(c).5 2 TR 3.3.1 10 5 cps 2(c).5 2 TR 3.3.1 NA 2(b).5"2 TR 3.3.1
2.5 6 TR 3.3.1 NA 2.5 6 TR 3.3.11081125 of full scale 2.5 6 TR 3.3.1 NA
6 TR 3.3.1
of full scale
1{g}TR 3.3.2
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
procedures.(b)Bypassed when
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-Multiple Control Rod Withdrawal-Refueling.-
0 (9)0 Signal is
in Chal')nel A logic only."Unit 2 0 3.3-4 00 ,Revision No.306"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 f\.---------NOTE-------------------
A.1 Only applicable
when Unit 1 is in MODE 4 or 5.One required nuclear service water (NSW)pump inoperable
due to an inoperable
Unit 1 NSW header.REQUIRED ACTION COMPLETION
TIME
Enter applicable
Conditions
and Required Actions of LeO 3.8.1, nACOperating," for diesel generators (DGs)made inoperable
by NSW.Restore required NSW 14 days pump to OPERABLE status.(continued)
Brunswick Unit 2 3.7-4 Amendment No.233
ACTIONS (continued)
SW System and UHS 3.7.2 CONDITION REQUIRED ACTION COMPLETION
TIME B.One required NSW pump 8.1---------------N()TE-------------
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
ACTIONS (continued)
SW System and UHS 3.7.2 CONDITION REQUIRED ACTION COMPLETION
TIME D.Required Action C.1 and D.1 Restore required CSW 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> associated
Completion
Time pump to OPERABLE not met.status.E.Two required CSW pumps E.1---------------NOTE-------------
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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable.
- pump to OPERABLE status.AND OR One required CSW pump inoperable.
F.2 Restore required CSW 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> pump to OPERABLE status.(continued)
Brunswick Unit 2 3.7-6 Amendment No.233
ACTIONS (continued)
SW System and UHS 3.7.2 CONDITION REQUIRED ACTION COMPLETION
TIME G.One required NSW pump G.1 Verify by administrative
Immediately
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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> pump to OPERABLE status.OR G.2.2 Restore one required CSW 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> pump to OPERABLE status.Water temperature
of the H.1 Verify water temperature
of Once per hour UHS>90.5°F and92°F.the UHS is::;90.5°F averaged over previous 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.(continued)
Brunswick Unit 2 3.7-7 Amendment No.240 I
ACTIONS (continued)
CONDITION I.Required Action and 1.1 associated
Completion
Time of Condition A, B, 0, E, F, AND G, or H not met.1.2 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 REQUIRED ACTION Be in*MODE 3.Be in MODE 4.3.7-8 SW System and UHS 3.7.2 COMPLETION
TIME 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 36 hours Amendment No.233
SWSystem and UHS 3.7.2 SURVEILLANCE
REQUIREMENTS
SURVEILLANCE
FREQUENCY SR 3.7.2.1 SR 3.7.2.2 SR 3.7.2.3 SR 3.7.2.4 Verify the water level in the SW pump suction bay of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> the intake structure is-6 ft mean sea level.Verify the water temperature
of UHS is s 90.5°F.24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
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.--------------------------------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)
SR 3.7.2.5 SURVEILLANCE
N()lrE---------------------------------
Isolation of flow to individual
components
does not render SW System inoperable.
FREQUENCY 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:
MODE1, MODES 2*and 3, except high pressure coolant injection (HPCI)and ADS*valves are not required to be OPERABLE with reactor steam dome pressure150 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
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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.AND OR One core spray (CS)subsystem inoperable.
8.2 Restore CS subsystem to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.(continued)
Brunswick Unit 2 3.5-1 Amendment No.2601
ECCS-operating
3.5.1 CTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION
TIME c.Required Action and C.1 Be in MODE 3.12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> associated
Completion
Time of Condition A or B not met.AND C.2 Be in MOOE4.36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> 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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.AND OR One low pressure ECCS injection/spray
subsystem is E.2 Restore low pressure 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 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.A (continued)
Brunswick Unit 2 3.5-2 Amendment No.233
ECCS-Operating
3.5.1 CTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION
TIME G.One required ADS valve G.1 Restore required ADS valve 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable.
to OPERABLE status.AND OR One low pressure ECCS G.2 Restore low pressure 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> injection/spray
subsystem ECCS injection/spray
subsystem to OPERABLE status.H.One required ADS valve H.1 Restore required ADS valve 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable.
to OPERABLE status.AND OR HPCI System inoperable.
H.2 Restore HPCI System to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.L Required Action and 1.1 Be in MODE12 hours associated
Completion
Time of Condition OJ E, F, G, or H AND not met.1.2 Reduce reactor steam 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR dome pressure to150 psig.Two or more required ADS valves inoperable.
A (continued)
Brunswick Unit 2 3.5-3 Amendment No.233
ECCS-Operating
3.5.1 ACTIONS (continued)
CONDITION J.Two or more low pressure J.1 ECCS injection/spray
subsystems
for reasons other than Condition A or B.HPCI System and two or more required ADS valves inoperable.
SURVEILLANCE'
REQUIREMENTS
REQUIRED ACTI.ON Enter LCO 3.0.3.COMPLETION
TIME Immediately
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)
SR 3.5.1.2 SURVEILLANCE
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.
FREQUENCY 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 SR 3.5.1.4 SR 3.5.1.5 Verify ADS pneumatic supply header pressure is 295 psig.Verify the RHR System cross tie valve is locked closed.-------------------------------NOTE--------------------------------
Not required to be performed if performed within the previous 31 days.31 days 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)
SR 3.5.1.6 SURVEILLANCE
Verify the following ECCS pumps develop the 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 FREQUENCY 92 days CS LPCI4100 gpm 114,000 gpm 2113 psig20 psig SR 3.5.1.7 SR 3.5.1.8-------------------------------NOTE--------------------------------
Not required to be performed until 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after reactor steam pressure is adequate to perform the test.Verify, with reactor pressure::;
1045 and945 psig, 92 days the HPCI pump unit can develop a flow rate4250 gpm against a system head corresponding
to reactor pressure.-------------------------------NOTE--------------------------------
Not required to be performed until 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 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 rate4250 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)
SR 3.5.1.9 SURVEILLANCE
N
0 TE-----------------------
Vessel injection/spray
may be excluded.FREQUENCY SR 3.5.1.10 Verify each ECCS injection/spray
subsystem actuates 24 months on an actual or simulated automatic initiation
signal.--------------------------NOTE------------------------
Valve actuation may be excluded.SR 3.5.1.11 Verify the ADS actuates on an actual or simulated automatic initiation
signal.-----------------------------NOTE-------------------------------
Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor steam pressure is adequate to perform the test.24 months SR 3.5.1.12 Verify each required ADS valve opens when manually 24 months actuated.-----------------------------NOTE-------------------------------
Instrumentation
response time may be assumed to be the design instrumentation
response time.Brunswick Unit 2 Verify the ECCS RESPONSE TIME for each ECCS injection/spray
subsystem is within the limit.3.5-7 24 months Amendment No.233