ML20129B141
| ML20129B141 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 05/22/1985 |
| From: | Briden D, Quennoz S, Richter L TOLEDO EDISON CO. |
| To: | |
| Shared Package | |
| ML20129B131 | List: |
| References | |
| PP-1102.03, NUDOCS 8507290086 | |
| Download: ML20129B141 (70) | |
Text
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, PP 1102.03 Davis-Besse Nuclear Pcwer Statien Cnit No. 1 Plant P ccedure PP 1102.03 TRIP REX:CVERY
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1 PP 1102.03.13
- 1. PURPOSE 1.1 Section 4 provides the steps to aa'ke the transition from the plant conditions in EP 1202.01 RPS, .SFAS, SFRCS Trip or SG Tube Rupture, to the initial conditions required for Section 5.
1.2 Section 5 provides the steps to take the plant from post trip hot standby conditions to the conditions required for entry into either the plant startup or the plant shutdown and cooldown p rocedure. l
- 2. PRECAUTIONS AND LIMITATIONS 2.1 RX startup is NOT permitted unless the cause of the RX trip is known and corrected. Attachments 1 and 3 aust be completed for every reactor trip. If any Technical Specification Safety Limit (Section 2.0) has been exceeded, operation shall not be resumed until authorized by the Commission as per-10 CFR 50.36 Section C. A review of the Computer Post Trip Review is a useful guide in determining the cause of the RX trip.
2.2 Steam Generator limitations are:
The maximum cooldown rate is 100*F/hr. I When cooling down or depressurizing a steam generator, do "NE" exceed a differential temperature between the RCS cold leg and ,
, the steam generator upper downconer temperature of 25'F.
The minimum temperature limits of the main and auxiliary feedwater ;
nozzles are 90*F and 40*F, respectively, at hot standby conditions. ;
For filling SG, refer to SG Secondary Fill, Drain, and Layup ;
SP 1106.08. A minimum feedwater temperature of 185'T is recomended -
at RCS temperatures exceeding 280*F. Max. .iT between SG downconer and feedwater temperature is 350*F.
For operation below 5 percent power, the main feedwater nozzles
- must be supplied with a continuous minimum feedwater flow of l >32 gym to reduce thermal cycling. SG level aust be maintained J i
between 18" and 348" on the startup range level indication when the RCS is in Mode 4 or above.
2.3 The startup feedpump may be operated during the trip recovery provided special requirements outlined in SP 1106.27, Startup Feedpump Operating Procedure, are followed.
l 2.4 The CID Safety Group I will always be at its upper limit during
- dilution except during performance of approved physics testing.
All suberitical boron concentration changes in the RCS will be I
verified for each predicted change of 30 ppe boros.
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s t e 3 PP 1102.03.13 3
loop or condenser pressure greater than 16.9 inches Hg A or
!!SIV's less than 907, open) the ataespheric steam vent valves must be used for steam header pressure /RCS cooldown rate control.
2.10 Ensure gland sealing steam and auxiliary steam loads are shifted from the main steam header to the Auxiliary Boiler after reactor shutdown to prevent cooldown of the RCS. With a low decay heat load present high steam usage from the main steam line could reduce steam line pressure and result in high RCS cooldown rates. If Amiliary Boiler is lost, the main steam reducing station can be used to prevent loss of condenser vacuum but steam usage aust be limited.
2.11 During operation with a positiva moderator temperature co' e fficient and with baron concentration gieater than 1200 ppa, added caution should be used when changing Tave in order to prevent a Tave transient.
2.12 The RCS (except PZR) tesp. and press shall be limited in accordance with the limit lines shown on Figures 1 and 2 PP 1101.01, during hestup, cooldown, criticality, and inservice leak and hydrostatic testing with:
- a. A max heatup or cocidown of 100*F if any one hour period per Technical specifications.
CAUTION: For heatup below 532*F and cooldown below 550*F, in addition.to the Tech spec limit of 100*F/hr heatup or cooldown rate a further resistriction is imposed for allowable number of heatup and cooldown cycles considerations. Whenever the rate is greater than 15'F/hr the heatup rate should be trended-(trend pen with 100*F/hr grease per line or similar tracking device) OR manually plotted every five minutes. The rate should be maintained less than 1.67'T per minute. If the temperature deviates by more than 15*F from the temperature which would occur at that point in ,
time assuming the rate was maintained at 1.67'T !
per minute the temperature must be restored to a .
point between the 100*F per hour heatup line and
- 15'T limit point by holding and maintaining the RCS tempesture. In addition a DVR sust be submitted for documentation to ensure a specific evaluation to determine the impact upon the allowable number of heatup and cooldown cycles is performed. This limit applied to all RCS components
- (including the PZR). For further guidance refer to Standing Order #23.
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5 PP 1102.03.13
, 3.2 NSSS Plant Limits and Precautions, PP 1101.01 3.3 NSSS Setpoints, PP 1101.02 3.4 EP 1202.01, RPS, SFAS, SFRCS Trip or SG Tube Rupture 3.5 Operational Chemical Control Limits, PP 1101.04 3.6 Plant Prestartup Check, PP 1102.01 (Prestart Checklist) 3.7 Reactor Coolant System Operating Procedure, SP 1103.00 Series 3.8 Auxiliary System Operating Procedures, S? 1104.00 Series 3.9 Instrumentation and Control Systems Procedures, SP 1104.00 Series 3.10 Steam System Operating Procedures, SP 1106.00 Series 3.11 Electrical System Operating Procedures, SP 1107.00 Series 3.12 AD 1839.00, Station Operations 3.13 USAR Section 6 and 7 3.14 Baron Control, SP 1103.04 3.17 Reactivity Balance Calculation 4 PLANT POST TRIP SUPPIL M AL ACTIONS NOTE: Some steps in this section may not be applicable to the plant conditions for all trips. They should be marked N/A after getting the Shift Supervisor's concurrence. Include a brief explanation of the reason the step is N/A.
4.1 If the STAS has initiated, perform Attachment 6 for STAS ekuipment recovery guidelines, in parallel with the remainder of Section 4 4.2 If the STRCS has initiated for any trip except for loss of four RCP's perform Attachment 7 for STRCS recovery guidelines, in parallel with the remainder of Section 4 4.3 If all four RCP's are stopped Laitiate steps to restart idle RCP's. Refer to SP 1103.06, RC Pump operating Procedure.
If STRCS has initiated only on loss of four RCP's the AIV pumps may be shutdown when RC flow is reestablished. Refer to SP 1106.06, Section 7 AFP Operating Procedure.
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1 PP 1102.03.13
- 1. PURPOSE 4
1.1 Section 4 provides the steps to sa'ke the transition from the plant conditions in EP 1202.01, RPS, SFAS, SFRCS Trip or SG Tube Rupture, to the initial conditions required for Section 5.
1.2 Section 5 provides the steps to take the plant from post trip hot standby conditions to the conditions required for entry into either the plant startup or the plant shutdown and cooldown procedure.
- 2. PRECAUTIONS AND LIMITATIONS 2.1 RX startup is NOT permitted unless the cause of the RX trip is known and corrected. Attachments 1 and 3 must be completed for every reactor trip. If any Technical Specification Safety Limit (Section 2.0) has been exceeded, operation shall not be resumed until authorized by the Consission as per 10 CFR 50.36 Section C. A review of the Computer Post Trip Review is a i useful guide in determining the cause of the RX trip. i 1
2.2 Steam Generator limitations are: l
~
h anzimum cocidown rate is 100*F/hr. !
When cooling down or depressurizing a steam generator, do "NE" exceed a' differential temperature between the RCS cold les and j
, the steam generator upper downconer temperature of 25*F.
N minimum temperature limits of the main and auxiliary feedwater nozzles are 90*F and 40*F, respectively, at hot standby conditions.
For filling SG, refer to SG Secondary Till, Drain, and Layup SP 1106.08. A minimus feedvater temperature of 185'T is recosamended at RCS temperatures exceeding 280*F. !!ax. .iT between SG downcomer and feedwater temperature is 350*F.
For operation below 5 percent power, the main feedwater nozzles must be supplied with a continuous minimum feedwater flow of
>32 gym to reduce thermal cycling. SG 1evel must be maintained '
between 18" and 348" on the startup range level indication when the RCS is in Mode 4 or above.
2.3 h startup feedpump may be operated during the trip recovery provided special requirements outlined in SP 1106.27, Startup Feedpump Operating Procedure, are followed. i 2.4 h CRD Safety Group 1 will always be at its upper limit during dilution except during performance of approved physics testing.
All suberitical boron concentration changes in the RCS will be verified for each predicted change of 30 ppe boron.
D O
f 2 PP 1102.03.13 (TS 2.5 The PRZR heatup and cooldown shall NOT exceed 100*F in one hour 3.4.9) (1.67*F per min.). The PRZR spray shall not be used if the temperature difference between the PRZR and the spray fluid is greater than 410*F.
2.6 Control Rod Safety Group 1 shall be withdrawn to provide tripable reactivity prior to the addition of positive reactivity from a change in reactor coolant temperature, the motion of the APSR's (Group 8), or motion of the control rods (Groups 5-7). The following exceptions to this may be applied: .
2.6.1 The RCS has been borated to the hot standby baron concentration as given in Figure 13 of PP 1101.02, Reactor Operator Curve Book, (or greater) and the unit is being mai:.tained in the hot standby condition (Tave
~530*F).
2.6.2 The RCS has been borated to the cold shutdown boron concentration given in Figure 16 of PP 1101.02 (or greater) and the unit is being cooled down.
2.6.3 Group 1 Control Rods need N01' be withdrawn prior to cooling down from -550 to 530*F provided the cooldown is within the time to reach equilibrium Ie from Figure 1. This time limit is to assure that zenon worth is sufficient to provide the necessary shutdown margin. If the cooldown is NOT started within 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />, the Group 1 Rods should be pulled unless the boron concentration, adjusted for the current zenon worth, is greater than the hot standby baron concentration shown in Figure 13 of PP 1101.02.
Note that the boron concentration is mathematically adjusted by adding 100 ppe boron for each 1% M/K of worth of xenon. For example, if borou concentration is 950 ppmB and xenon worth is -2.4% M/K, the adjusted worth would be 950 + 240 = 1190 ppaB.
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NOTE: Whenever possible, it is desirable to maintain the safety group 1 at its upper limit as an additional safety margin.
2.7 At least two licensed operators shall be present in the CTRM during recovery from reactor trips.
2.8 Notify the Technical Section after a Reactor Trip so that data from the station computer (that is transferred and stored in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> rotating file in the DBAB computer) can be printed before the file cycles and the data lost.
2.9 When the condenser is unavailable for steam dump, (circulating water flow less thma 100,000 gym is either circulating water
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l 3 PP 1102.03.13 loop or condenser pressure greater than 16.9 inches Hg A or '
MSIV's less than 90% open) the ataespheric steam vent valves must be used for steam header pressure /RCS cooldown rate control. l 2.10 Ensure gland sealing steam and auxiliary steam loads are shifted from the main steam header to the Auxiliary Boiler after reactor shutdown to prevent cooldown of the RCS, With a low decay heat .
load present hiSh steam usage from the main steam line could !
reduce steam line pressure and result in high RCS cooldown rates. If Auxiliary Boiler is lost, the asia steam reducing station can be used to prevent loss of condenser vacuum but steam usage must be limited.
2.11 During operation with a positive moderator temperature co' efficient and with boros concec ration greater than 1200 ppa, added caution should be u* + . when changing Tave in order to prevent a Tave transient.
2.12 The RCS (except PZR) temp. and press shall be limited in accordance with the limit lines shown on Figures 1 and 2 PP 1101.01, during haatup, cooldown, criticality, and inservice leak and hydrostatic testing with:
- a. A nas heatup or cooldown of 100*Y if any one hour period per Technical specifications.
CAtTIION: For hastup below 532*T and cooldown below 550*T, in addition .to the Tech spec limit of 100*T/hr heatup or cooldown rate a further resistriction is imposed for allowable number of heatup and cooldown cycles considerations. Whenever the rate is greater than 15*T/hr the heatup rate shoald be trended (tread pen with 100*T/hr grease per line or similar tracking device) OR asaually plotted every five sinutes. The rate should be asistained less than 1.67'T per minute. If the temperature deviates by more than 15'T from tae temperature which would occur at that point in time assuming the rate was asistained at 1.67'T per minute the temperature must be restored to a point between the 100*T per hour heatup line and '
15'T limit point by holding and esistaining the RCS tempesture. In addition a DVR aust be submitted for documentation to ensure a specific evaluation to deteraise the impact upon the allowable naaber of heatup and cooldown cycles is perfossed. This limit applied to all RCS composeats (including the PZR). For further guidance refer to Standias Order #23.
e 1
.9 4 PP 1102.03.13 2.13 Seal injection water flow is required to all reactor coolant pumps when reactor coolant temperature and pressure are above 150*F and 150 psig except when operating in the loss of injection i mode.
2.14 The following valves have wedges that may stick in their seats if closed when they are hot and subsequently cooled down: *
, MU-LA, MU-1B, MU-23, RC-10, RC-11 To prevent separation of the wedge from the valve stem when a valve is closed hot and then cooled down, perform steps as follows:
- 1. Exercise the valve once for every 100*F cooldown, or
- 2. If available, isolate the line with a manual valve and then reopen the Velan valve and continue ecoldown in a '
normal manner.
- 3. If 1 or 2 above can't be performed, attempt to open the valve manually after cooldown. DO NOT ATTDiPT ANY EXCESSIVE FORCE. If valve does not open manually, contact Maintenance for assistance.
I 2.13 Nuclear instrumentation operation and intermediate / source range channel overlap.should be checked during shutdown. At 5 x 10-10 amps on the intermediate range, the source range detectors are energized. When the intermediate range reaches 10*10 amps, the source range indication should be decreasing to provide a ,
mini =u= of one decade overlap.
2.16 The Rapid Feedwater Reductior. (RFR) portion of the ICS will target feedwater flow to abos 4% and bias MFFT speed in the increase direction on a RX tnp. If a RX trip occurs from low power levels, this system say NOT bring the SG's levels to low level limits in the approximately 2 1/2 minutes as intended. A timer in the system will then release W valve control to tracking neraal ICS demand. The MTPT speed control will remain i
biased uyvards (if MFPT is in Auto). The net result of this control should being the SG levels down to low level limits, ,
however, it will take longer than if the Rx trip was from a high power level. Tue RTR is armed if the defeat switch in the ICS (Cab 5, Row 2, Module 8) is on, a MFFT is reset and all four W control valves are in auto.
- 3. RITERENCES (TS) 3.1 Davis-Besse Technical Specifications
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4 5 PP 1102.03.13
, 3.2 NSSS Plant Limits and Precautions, PP 1101.01 3.3 NSSS Setpoints, PP 1101.02 3.4 EP 1202.01, RPS, STAS, STRCS Trip or SG Tube Rupture 3.5 Operational Chemical Control Limits, PP 1101.04 3.6 Plant Prestartup Check, PP 1102.01 (Prestart checklist) 3.7 Reactor Coolant System Operating Procedure, SP 1103.00 Series 3.8 Auxiliary System Operating Procedures, SP 1104.00 Series 3.9 Instrumentation and Control Systems Procedures, SP 1104.00 Series 3.10 Steam System Operating Procedures, SP 1106.00 Series 3.11 Electrical. System Operating Procedures, SP 1107.00 Series 3.12 AD 1839.00, Station Operations 3.13 USAR Section 6 and 7 3.14 Baron Control, SP 1103.04 3.17 Reactivity Balance Calculation 4 PIANT POST TRIP SUPPLEMLYTAL ACTIONS NOTE: Some steps in this section may not be applicable. to the plaat conditions for all trips. They should be marked N/A after getting the Shift Supervisor's concurrence. Include a brief explanation of the reason the step is N/A.
4.1 If the SPAS has initiated, perform Attachment 6 for STAS ekuipment recovery guidelines, in parallel with the remainder of Section 4.
4.2 If the STRCS has initiated for any trip except for loss of four RCP's perform Attachment 7 for STRCS recovery guidelines, in parallel with the remainder of Section 4.
4.3 If all four RCP's are stopped, initiate steps to restart idle RCP's. Refer to SP 1103.04, RC Pump Opersting Procedure.
If SFRCS has initiated only on loss of four RCP's the AFW pumps may be shutdown when RC flow is reestablished. Refer to SP 1106.06, Section 7, AFF Operating Procedure.
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6 PP 1102.03.13 NOTE: If a cooldown is expected, only 3 RCP's ceed to be running.
4.4 If the reactor power shews any sign of an increase, initiate boron addition.
4.5 Stop all but one of the running Condensate Pumps as condensate system flow allows.
4.6 bien S.G. levels reach 35" or when the rapid feedwater reduction 2.5 minute timer completes its cycle, verify the ICS controls at low level limits or take annual control of the feedwater system.
RFR may need to be defeated by going to off or. RFR switch in ICS cabinet, Cabinet 5, Row 2, Module 8.
4.7 If both MFP's are running, stop one of the running MFP's. ,
4.8 After the generator field circuit breaker trips, open the exciter field circuit breaker.
4.9 iM N BOTH of the following conditions are indicated:
- 1. Tave within the post trip range of 550* to 555'T, OR stabilized outside the post trip normal range.
A_ND
- 2. Control of pressurizer level and RCS pressure has been recovered.
TIEN perform the following steps:
- 1. Set pressurizer level setpoint at present pressurizer level.
- 2. Return letdown to service.
- 3. Shift MU pump suction back to MU tank if transferred.
- 4. Stop the second MU pump.
- 5. Maintaia MU tank level between 55" and 87" by batch additions equivalent to the present RC3 boros concentration.
4.10 Verify that the turbine bypass valves are attempting to asintain 1015 peig. If not, take annual control of turbine bypass valves. Pressure is controlled by the individual Steam Generator outlet pressure if the turbine stop valves are closed.
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.- . _ ~_ _ - . _ -- , .
. 4 7 PP 1102.03.14 NOTE: If one or more Main Steam Safety Valves / Atmospheric
' Vent Valves continue to relieve with SG pressure less than 1015 psig, or if all the TBPV's remain closed immediately following a trip, lower the TBPV's setpoint to get on TBPV control and reset Main Steam Safety Valves / Atmospheric Vent Valves. After a reactor trip, a + 145 psi bias will be added to the setpoint on the a
controller. Pay close attention to the SG levels and the pressurizer level during this process.
4.11 Perform the following at the turbine control console (C5713).
- 1. Start the following pumps before they are started automatically.
i a) Motor Suction Pump with the T-G MSP Control Switch (HIS-2400).
b) Turning Gear 011 Pump with the TGOP Control Switch i (NIS-2401).
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i 4.12 Ensure that the steam seals reatta on the turbine as long as vacuum exists in the condenser. The steam seal header pressure !
should be 2.5 to 4.5 psis as read on the TURB STM SEAL HDR PRESS Indicator (PI-2340) located on the MSR and Beater Drains Panel (C5722). If the turbine steam seals are lost, immediately open ,
' ' the condenser vacuum breakers by using COND VACM BRKR (HIS-634) '
located on the Feedwater Panel (C5721). i t
NOTE: i Do NOT break vacuum, except during emergency conditions, '
i until the unit is below its critical speed (900 - 1200 RPM). Examples of emergency conditions are loss of 1
steam seals, loss of lube oil, etc.
4.13 Perform Attachment 4 for equipment on the Feedwater Panel (C5721) and the MSR and Heater Drain Tank Panel (C5722).
4.14 Perform Attachment 5 for the feedwater heater and deserator extraction steam aca-return valves.
4.15 Assign an Equipment /Ana111ary Operator to monitor turbine tube oil temperature. As the turbine speed decreases, the bearing oil temperature should be reduced so that it's 80* to 90*T when rotation stops.
4.16 Verify that the source range nuclear instrumentation is activated when the intermediate rense nuclear instrumentation indicates 5 x 10~10 amps.
i 4.17 Enter in the Operator's Los the last available criticality i
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8 PP 1102.03.13 information including time, rod position, boron concentration, power level, and RCS average temperature.
4.18 Wen the reactor decay heat load has reduced enough that the feedwater requirements are within the range of the SUFP, place the SUFP in servtce and the running MFP in standby. Refer to SP 1106.27 for placing SUFP in service.
4.19 Restore the 345 KV switchyard to the ring bus configuration.
- 1. Request that the Load Dispatcher open ABS 34620.
- 2. Take station house power readings for Daily Reading Sheet 11 AND for Standing Order 20.
- 3. Dispatch an operator to pull close fuses for ABS 34620 if requested by Load Dispatcher. -
- 4. Open the disconnect on TD3 B03-94 AMXG Generator Anti-Motoring to allow a ring bua with the turbine tripped.
- 5. Reset generator ITMR lockout with Load Dispatcher concurrence.
Do NOT reset any lockout other than 86-1A (2A) (3A) (4A) GX until the cause of the lockout has been determined and load dispatcher concurrence.
Verify ABS '34420 is open, reestablish a ring bus by closing the generator breakers.
ACB 34560 closed ACB 34561 closed 4.20 Shift RIM 600 and RIM 609 (MS Line Radiation Monitors) from the analyse mode to the gross mode.
NOTE: - Wen the Rx is shutdown there will be no N-16 gassa present in the RCS, so the MS Line Rad Monitors must be in the gross mode in order to provide early detection of aa OTSG Tube Leak.
4.21 Imatruct CaEF to take a sample of the letdown water between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after the trip (per T.S. Table 4.4-4). An isotopic {
analysis for iodine must be performed (per T.S. Table 4.4-4) and '
if possible, a gross activity determination should also be !
performed.
4.22 Perforu Section 7.2, Shutdown Af ter a Turbine Trip From Power,
- l of SP 1106.15, Moisture Separator Reheater Operating Procedure.
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9 PP 1102.03.13
, 4.23 At least two (2) licensed Reactor Operators must be present in the Control Room and at least one . licensed Senior Reactor Operator must be present at this unit.
NOTE: The SRO License may be one of the two individuals in ,
1 the Control Room.
4.24 Proceed with Section 5.
- 5. STABIIIZING THE PI. ANT AT HOT STANDBY CONDITIONS AND INCREASING THE i
SG LEVELS NOTE: Some steps in this section may M be applicable to the plant conditions for all trips. They should be marked N/A after getting the Shift Supervisor's concurrence.
NOTE: Exact sequence E required except for Steps 5.9 through .
5.16 which must be done in the sequence listed.
Normally conditions will be as follows:
i 4 RCP's on
! RCS pressure controlled at 2155 psi ~
PRZR level 100" to 200" This will
- Turbine header pressure being controlled at g vary if the 1015 psig . trip was from
, Tava approximately 548'T to 555*F _
<257,FP MU taak level >55" SG's on low level limits Investigation of the cause of RX trip initiated !
Startup Transformers supplying house power GE Air Dump has closed IV Her Extraction Non-return valves. and opened extraction line drains One MFFT or StT. P is in operation Both Her Drain Pumps are off Motor Suction Pump, TGOP and Lift Pumps are on Generator Tield Circuit breaker open One Condensate Pump on 5.1 Place the auxiliary boiler in service per SP 1106.04, Auxiliary t
Boiler Operating Procedure. Continue with this procedure as '
the auxiliary boiler is being placed on. When auxiliary boiler is on perform substeps below.
- 1. Transfer Auxiliary Stean Loads to the aux boiler per SP 1106.25, Section 7, Auxiliary Steae System Procedure.
Ensure trap header and flash taak vent is shifted.
- 2. Shutdown the flash taak pumps locally.
l b
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L __
s .*
10 PP 1102.03.13
- 3. Slowly increase pegging steam to the main deaerators to maintain - 2.5 psig steam blanket on deaerator.
4 Establish a drain path from the deaerators to the condenser by opening W 104 and throttling W 33 to maintain enough condensate flow to prevent water hammer in the deaerator .
and connecting lines. Keep the flow low enough to prevent exceeding auxiliary boiler capacity for pegging the deaerator.
5.2 If a MFP is still supplying feedwater, when RI decay heat load has reduced the SG feed requirements to within the range of the SIlFP, place the SUFP in service and place the HTP in standby. ;
Refer to SP 1106.27 for placing the SUFP in service.
)
1 5.3 Shift the gland seal steam supply from the main steam header to !
the auxiliary steam header by performing the following from CIRM '
Panel C5722: . I
- 1. Open the auxiliary steam supply to Gland Steam System drain valve, AS 1934, using HIS 1934.
- 2. Open the auxiliary steam supply to Gland Steam System, GS 2380, using HIS 2380.
- 3. Close main steam supply to Gland Steam System, GS 2384, using HIS 2384.
- 4. Close auxiliary steam supply to Gland Steam System Drain Valve AS 1934.
5.4 When the turbine has come to rest (approximately 90 minutes with Vacuum), perform the following.
- 1. Verify the turbine is on gear.
- 2. T.ockout the Motor Suction pump.
- 3. If the shutdown is expected to last more thac 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, activate blanketing steam per SP 1106.15, MSR procedure.
- 4. Shift He purity analyzer to vent and verify flow is 1 sefs.
- 5. Verify lube oil temperature is 80*F.
- 6. With the generator at rest or on turning gear, there is no positive ventilation of the exciter house. EITHER degas the generator as a safety measure during long duration outages_ OR have temporary fans installed to ventilate the
11 PP 1102.03.13 exciter house AND have daily checks made for !!ydrogen leakage into the exciter house. Contact the Operations Engineer for guidance.
' I 5.5 Check the EHC first hit panel to determine the cause of the turbine trip.
)
CAUTION: Never reset the EHC trip system before the cause of the trip has been clearly established and the responsible malfunction has been corrected.
5.6 Verify both OTSG's on low level limits and place Steam Generator /
RI Demand, and RI Demand ICS Stations in hand and run down to
=4 a i- .
5.6.1 Place ATc controller in manual set demand @ 50*..
5.6.2 Place both feedwater loop demands to zero. AND verify feedwater flow remains constant.
5.6.3 The operating !EP may be put in manual as needed to prevent OTSG 1evel oscillations.
5.7 Determine from Boron Concentration Control Procedure, SP 1103.04, the feed solutions required to maintain RCS Baron Concentration at its' present value (from primary plant statua board and baronometer) while adding the contraction volume required during RCS cooldown to 530*F.
5.7.1 !!aintain PZR Level @ 100 inches if a Rx startup is
- planned. If a cooldown is expected, maintain PZR
, level @ 200 inches. Any volume above the 100" level i
required for plant startup can be used as contraction
! volume during the cooldown from post trip Tave to 530*F.
5.7.2 Increase !!U tank level to 86". Record the batch sizes and sources below.
I Bt gal Bz gal from from
- 5.8 If a cooldown is planned, begin degasing per SP 1102.12, Hydrogen l Addition and Degasification Procedure to the limits given in
( SP 1102.12. .
5.9 In preparation for withdrawing CRA Safety Rod Group 1, reset j ARTS and then RPS as follows:
l NOII: If the control rods cannot be withdrawn or if the RPS l and/or ARTS cannot be reset at this time, refer to .
Step 2.6.3.
e F
12 PP 1102.03.13 To reset ARTS, perform the following steps at each channel:
- 1. Obtain keys to the ARTS cabinet from the Shift Supervisor. I
- 2. If both MFFT's are tripped, obtain the four test trip bypass switch (TTBS) keys from the Shift Supervisor for all four ARTS channels. Place all four IT3S in the MFP position to block the trip signal from the ARTS to the RPS.
- 3. Verify the 1/5 lights are off.
- 4. Press the reset button and verify the TRIP light goes off. i To reset the R'S, perform the following steps at each channel when the conditions causing the trip have cleared.
- 5. Obtain keys to the RPS Cabinet from the Shift Supervisor. .
- 6. Reset the appropriate trip histables and output memory histables for the parameter (s) that caused the RX trip by depressing the " Reset" toggle switch.
- 7. Reset the Reactor Trip Module (location 2-2-7) by depressing the " Reset" toggle switch on the Reactor Trip Module. The
" Channel Trip" lamp should so dia. :
- 8. Reset the" Output Memory" lamp on the Source Range SUR Bypass /High Voltage Shutoff from NI-3 (NI-4) Bistable (Channel 3 and 4'; location 1-2-9).
- 9. Roset the " Output Memory" lamp on the Fluz 10% Bistable (Channel I and 2: location 1-7-12: Channel 3 and 4, location 1-8-12).
- 10. Close and lock RPS Cabinet doors and retu'ra keys to the '
Shift Supervisor.
Channel 1 Channel 2 Channel 3 channel 4 5.10 Verify component cooling water flow of at least 122 GPM supplied to CRDtis.
CAUTION: Prior to resetting the Control Rod Drive System, ensure the Turbine Bypass Valve H/A stations are in l hand,'ICS 12A & B, as the +145 poi bias will be removed from their setpoint.
, 5.11 After verifying the TBV H/A stations are manual, reset the l Control Rod System, latch safety rod groupe 1 through 4, reset
! the Relative Position indication and withdraw safety group 1 as
} per Control Rod System Procedure, SP 1105.09, Section 4.1.
i
3, '
I
.13 PP 1102.03.13 '
NOTE: Observe count rate while withdrawing control rods.
5.12 Using either the turbine bypass valves (PIC ICS 12A & B) in j manual or the turbine header pressure controller setpoint (PIC ICS 10), slowly reduce turbine header pressure to 870 psig.
NOTE: Step 5.14 can be performed at the same time as this step for a smoother cooldown to 530*F.
\
5.13 Monitor RCS temperature and pressure during cooldown to verify TS 4.4.9.1.1. while cooling down; log the time and pressure and '
temperature every 1/2 hr during cooldown in the RO I,og.
5.14 As turbine header pressure is lowered (and SG level increased if Step 5.16 is done at the same time as this step), RCS temperature
- will decrease from approximately 546*F. Add borated water per Boron Concentration Control Procedure, SP 1103.04, to maintain
- Makeup Tank level at 55 inches if necessary.
5.15 Place the turbine bypass valve ICS station in Auto (PIC ICS 12A and B), with the header pressure setpoint at 870 psig (45%) on 4
5.16 Place the Main Feedwater and Startup Feedwater Control Valves (FIC ICS 35A & B and FIC ICS 33A & B) in hand control and slightly increase feedwater flow to both SG's. Minimize the amount of coolddwn to the reactor coolant system unless this 4
step is being performed at the same time as header pressure is i being reduced. Increase the SG's 1-avel to 250 t 50" on the startup range NOTE 1: Tair step may be performed with Step 5.14.
- 2. If reactor startup is expected within ~10 hours, it is permissfble to remain on low level limit control with Feedwater Valves in AITIO. If the return to power is delayed or if necessary to improve Steam Generator rhanistry, S/G 1evels should be increased to 250 t 50".
5.17 If pcssible, perform an inspection of contaimeent at full temperature and pressure. This inspection will identify leaks and other potential problems. If a cooldown is planned, this '
inspection is highly desirable. As a min 4== the inspection l should include the pressurizer valve room, the top and bottom of l BOTH "D" rings, the I.etdown Cooler ares, the incore closure s
seals and the Decay Heat Valve pit area. The inspection should )
i be made by a team consisting of representatives from Operations, '
Maintenance and Chemistry and Health Physics. The list of
- i. identified problems should be turned in to each department's i supervisor. -
i i
l
,_ r , _ _ .., , . - . . - , .. - - . . -e- - =, ,- - - *- - - "*
I k
14 PP 1102.03.13
, 5.18 Update the Shift Supervisor status board for the due date and time for ST 5061.05.
5.19 If the water in the Steam Generators is out of spec, start the following sequence: fill, soak (approximately two hours), and drain Steam Generators. Continue this procedure until the .
water in the SG's is within spec. If the chemistry is out of limits after eight hours, the systen must be cooled to less than 400*F.
LI21ITS: C1 1.0 ppa sax Sodium ,
2.0 pga sax Cation Conductivity 10.0 paho/cm Silica 2.0 ppa max 5.20 If the time since the reactor trip approaches the time required to reach equilibrium xenon (from Figure 1), a determination ,
should be made as to whether or not the plant is to be cooled down. This is required to assure a 1% shutdown margin after the trip. ,
- 1. If a cooldown is N_OT expected, THEN borate the RCS to the value given in Figure 13 of PP 1101.02 9E If it desired to have a boros concentration below the value given in Figure 13 (for a quick restart), obtain an Estimated Critical Baron (ECB) calibration from the START program and usintain the RCS boroa concentration equal to or about the boros concentration given in the ECB calculation for that hour. When all the Xenos decays, the ECB boron concentration value will be equal to the value given.in Figure 13.
NOTE: If an adjusted baron concentration is used, put an inforestion Tag near the batch controller-indicating how long the boron concentration is good for.
- 2. E a cooldown is expected, THEN borate the RCS to the value given in Figure 15 of PP 1101.02.
NOTE: If Figure 15 is used, .put an Information Tag on the Diamond T-handle indicating that the boron concentration only allows CRA Group 1 to be pulled and still maintain the reactor 1% Ak/k shutdova (1% Ak/k SIUTDOWN VALIE).
3 O
15 PP 1102.03.13 5.21 Complete Attachment 3 Post Trip Review.
5.22 If plant cooldown is expected, de-energize the generator core monitor as per Generator, SP 1106.09.
5.23 If plant cooldown is planned, proceed to Plant Shutdown and Cooldown Procedure, PP 1102.10, Section 5 (Cooldown of NSSS from Hot Standby Condition).
5.24 If it is desired to return the reactor to power from the reactor trip, complete Attachment 1 Checklist for Return to Power Following a Reactor Trip. Then proceed to Plant Startup Procedure, PP 1102.02, Section 7, with the exception that the MODE 2 and MODE 1 checklist need not be completed. Successful completion of the Checklist for Return to Power Following a Reactor Trip will satisfy MODE 2 and 1 requirements.
] At the completion of this section the following conditions should i normally exist.
!
- T approximately 532*F -
- PleIsurizerlevel100 inches. If return to power, 200" if cooldown planned
- RCP combination 2/2
- Group 1 Rod fully withdraw, Groups 2 through 7 fully inserted, and Group 8 at its previous position
- Nonsal I.etdown in Service
- Main feedpump or startup feedpump in service
- OTSG level maintained at 35 to 70% or at low level limits
- Decay Heat being removed by dumping steam to the condenser
- Deserator pegging steam heating feedwater
- Auxiliary boiler supplying Auxiliary Steam Section 5 completed by Data f
l i
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16 PP 1102.03.13
. Checklist for Return to Power Following a Reactor Trip The following checklist must be completed for each reactor trip from power prior to restart.
- 1. Attachment III, " Post Trip Review" has been completed or an SRB review of the trip has been performed.
- 2. Without actually filling out the checklist, look through Mode 2 and Mode 1 Startup Checklists in PP 1102.01, Prestartup Checklist.
Verify the status of these systems is in a condition such that a startup can be made.
NOTE: Refer to TS Table 4.3-1 for RPS surv'illance requirements.
Items 1,10,11, and 12 are required prior to each s ta rtup. Items 1, 10, 11 and 12 have a " Note 1," if not performed in previous 7 days. -
Notify the I&C Engineer or the I&C Shop Foreman that the following Surveillance Tests must be completed prior to plant startup:
2.1 ST 5030.02 (Intermediate Range only) must be done if required by the ST schedule.
2.2 ST 5030.17 (Intermediate Range Prestartup Functional Test) if not performed within previous 7 days.
2.3 ST 5091.01 (Channels 1 and 2, Source Range) if not performed within previous 7 days.
2.4 ST 5030.12 (Functional Test of the Reactor Trip Module Iogic and Control Rod Drive Trip Breakers) if not performed within previous 7 days.
Operations personnel are to perform the following:
2.5 ST 5030.13 (Tunctional Test of Manual Reactor Trip) if not performed within previous 7 days.
2.6 ST 5073.01 (MSIV Valve Test) if not performed within previous 92 days.
2.7 ST 5013.04 (CRD esercising monthly) should be performed during rod withdrawal for startup.
- 3. Verify the unit is not in an ACTION statement of Technical '
Specifications which now would prevent re-entry into MODES 2 and 1.
I I
NOTE: If 1, 2, or 3 cannot be verified, stop at this point in the checklist since the return to power cannot be made.
Attachment- 1 Page 1 of 2 l
17 PP 1102.03.13
. 4. Contact saintenance to replace canvas hoods on any main steam safety valves that say have lifted on the trip.
- 5. If the Operations Engineer and the Technical Engineer have concurred to extend the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> limit on this checklist, so document this extension by filling in the time allowed in addition to the original 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If no concurrence was given, place N/A in the blank.
Operations Engineer Notified By Date Extension Hours
' Technical Engineer Notified By Date Extension Hours
- 6. At least two (2) licensed Reactor Operators must be present in the Catarol Room and at least one licensed Senior Reactor Operator aust be present at this unit.
NOTE: The SRO License say be one of the two individuals in the Control Room.
Shift Supervisor Date
- 7. The Operations F.ngineer (or his designee) and the Plant Manager (or his designee) have given permission for restart.
l
- Plant Manager Notified By Date Operations Engineer Notified By Date-4 This form should be routed to the Operations Engineer for his review.
Reviewed By Operations Engineer Date After the Operations Engineer completes his review, the completed form should be routed to the Technical Section for filing into the unit
- trip files.
Checklist completed: Shift Supervisor Date ,
Attachment 1 Psse 2 of 2
, _. , .g- -- ,, , . - - -----~---r v - - - - - - - - - - - -
r ,
18 PP 1102.03.13 Isolation of Main Steam Line Drains and Loads to Permit Pressure Equalization for Opening MSIV's Isolated By Restored By Main Steam Line No. 1 (MS 101) -
Located 623' Aux. Blda.
Isolate ST 39. MS 106 Isolate ST 132, by 107A Located 603' Turb. 31da.
Close MS 110, MS Line 1 TBV !so Close MS 710A, MS Line 1 TBV Ise Bypass Close MS 12999 or MS 846, w/u Line Located 585' Turb. Blda. '
Close MS 700, MS Line 1 to MPT 1-1 Isolate ST 66, by MS 706 Close MS 708, MS to AS Red. Sta. .
Close MS 2582, 2nd Stage R.H. S/U Drain Isolate ST 101, M.S. Line 1 Drain Trap Close NS 266 or MS 847, ST 101 Bypass NOTE: MS 101 may be opened when AP across the valve is less than 250 paid. Restore all valves and traps to normal S/U position as soon as possible after opening MS 101.
Main Steam Line No. 2 (MS 100)
Located 623' Auz. Bida.
Isolate ST 125, by MS 107 Isolate ST 121, by NS 106A Located 603' Turb. Blda.
Close MS 709, MS Line 2 TSV Iso Close MS 709A, MS Line 2 TBV Iso Bypass Close MS 840, MS to SG Iso Close NS 1299A or MS 843, MS Line 2 w/u Line Located 585' Turb. Blda.
Close MS 707, MS Line 2 to MPT 1-2 Isolate ST 67, by MS 707 Isolate ST 100, MS Line 2 Drain Trap Close MS 138 or MS 841, ST 100 Bypass NOTE: MS 100 any be opened when AP across the valve is less than 250 paid. Restore all valves and traps to normal S/U position as soon as possible after opening MS 100.
Attachment- 2 Page 1 of 1
s .
j 19 PP 1102.03.13 Post Trip Review The following review must be completed for each reactor trip (except normal tripping of CRD during heatups and cooldowns) even if a unit restart is not in progress.
1.1 Plant Pre-Trip Conditions (to be completed by the Shift Technical Advisor and Operations personnel after the plant stabilization is complete). -
(A) Reactor power prior to the trip: %
Note any rumback that occurred:
I (B) List any ICS stations in manual prior to the trip:
l (C) List any testing in progress prior to the trips 4
(D) List any safety systems inoperable prior to the trip:
j (I) List any other abnormal plant conditions contributing to the plant trip (inoperable main feedwater pump, high condenser vacuum, etc.).
Completed By Date -
1.2 Plant Post Trip Conditions (to be completed by the Shift Technical t
Advisor and Shift Supervisor after the plant stabilization is complete).
f Attachment 3
! Fage 1 of 3 a
e
20 PP 1102.03.13
, (A) Did any of the following occur? (Use Control Roon recorders, computer information, or operator observations.)
No
~~
Did the PORV actuate?
Did the pressurizer code safety valves actuate?
Did either steam generator level exceed 82.5%7 -
Did SG level go below 18"?
Was STAS actuated?
Did pressurizer level decrease be19w 8 inches?
Did pressurizer level exceed 300 inches?
Was the Emergency Plan activated?
Did the STRCS actuate?
If any of the above did occur, determine the cause and describe below:
(B) Write a short description of the cause of the trip, the ractor trip sequence of events which resulted in the trip, and say actions taken to prevent recurrence. (Review the Post Trip Review, Alarm Printout, and Sequence of Events Princouts, if available.)
i Shift Technical Advisor Date l
Shift Supervisor Date I i
Attachment- 3 )
Psse 2 of 3
21 PP 1102.03.13
. 1.3 Safety Review of Transient (to be completed by Shif t Technical Advisor and Shift Supervisor). *
(A) Verify no safety concerns
- have been identified in the review of the trip.
- A safety concern is defined as a' safety related system not performing the design function for which it was intended.
Shift Supervisor Date Shift Technical Advisor Date (B) Verify no safety limits exceed during the transient (see Technical Specification 2.1). If any safety Itaits has been exceeded, operation shall not be resumed until authorized by the Commission as per 10CTR50.36 Section C. .
Shift Supervisor Date Shift Technical Advisor Date If the cause of the unit trip cannot be determined, or the Sequence of Events for the reactor trip cannot be determined, or any safety concern identified, a unit restart cannot proceed until a Station Review Board review of the transient has been completed.
After this form is completed, it should be routed to the Operations Engineer for his review.
Operations Engineer Date After the Opersticas Engineer review, his attachment should be routed to the Technical Section to be included in the trip files.
Attachment 3 Fage 3 of 3 0
e
22 PP 1102.03.13
- 1. Press open for main stesa line NRV's.
HIS 209 HIS 210
- 2. Close DT EXT to MSR 1 and 21st stage. ,
HIS 197
- 3. Verify closed or close the following valves:
VALVE NO. CONTROL SWITCH NAME CONTROL SWITCH NO.
ES278 D W HTR 1-4 LPT EXT VLV HIS-278 ES264 D W HTR 1-5 UT EXT VLV HIS-264
-ES377 p W m 2-4 LPT EXT VLV HIS-377 ES370 D W HTR 2-5 KPT EXT VLV EIS-370 GS346 LP W HTR 1-1 SEAL REG VLV HIS-346 GS957 LP W UR 2-1 SEAL REG VLV HIS-957 AS958 CNDS TI.SR TK 1 STM OUT M0/L *EIS-958 s
- This switch will also open the Condensate Flash Tank Vent to 5 peig steam header valve (A33744) if it was E automatically opened.
- 4. Verify open or open the following valves:
i VALVE MO. CONTROL SWITCH NAME CONTROL SWITCH No.
E3304 W HTR 1-5 & 2-5 RPT EX DR HIS-304 GS2167 STM SEAL REG DNP TO HP COND HIS-2167
- 5. Stop Heater Denia Tank Pumps 1-1 and 1-2 usin8 control switches EIS-318 and HIS-342, respectively.
EDP 1 HDP 2 I
- 6. Verify open or open the fo11owin8 valves:
Valve No. Control Switch Name Control Switch No.
MS 2844 & MSR 1 NOIS SET IN HIS-2844 MS 2845 X AROUllD RD 2144 & MSR 1 NOIS SET DRN '
HIS-2144 RD 2144 I
NE 2842 & MSR 2 NOIS SET IN HIS-2843 NE 2843 X AROUND l
Attachment 4 Ps8e 1 of 2
23 PP 1102.03.13 Valve No. Control Switch Name Control Switch No.
RD 2150 & MSR 2 MOIS SEP DR$ HIS-2151 RD 2151 TD 2382 STM LEAD DRN VLV 1 KIS-2382 TD 2383 STM LEAD DRN VLV 2 RIS-2383 TD 2368 STM LEAD DRN VLV 2 RIS-2368 TD 2369 STM LEAD DRN VLV 4 HIS-2369 TD 2381 COMBINED CTRL VLV HIS-2381 MS 138 MN STM 2 TRAP BYPASS HIS-138 MS 266 MS 1 SV! TRAP KIS-266 ES 249 LPT 1 EXT TO W HIS-249 m 1-2 DRN ES 415 I?T 1 EXT TO DEAR HIS-415 HTR 1-3 ES 341 .2T 2 EXT To N HIS-341 ETR 2-2 13 411 LFT 2 EXT TO DEAR IIS-411 IIR 2-3 ES 417 LPT 1 EXT TO W HIS-417 RTR 1-4 ES 252 IFT EXT TO W RIS-232 ETR 1-6 DAN ES 409 LPT 2 EXT TO W HIS-409 RTR 2-4 ES 413 NFT EXT TO W RIS-413 NTR 2-6
- 7. Depress the bearin8 lift pump RESET pushbuttoa (MS 2404A) and start the sia (6) bearin8 lift pumps with the sin MARING LITT FUMPS before they are started autoestically. Control Switches
(#1 RIS-2404; #2, RIS-2405 #3, NIS 2404; #4, NIS-2407; #5, IIS-2404: M,RIS-2409).
Attachment 4 Pa8e 2 of 2 P
e
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.=
24 PP 1102.03.13
- 1. Verify that the following valves have automatically closed. This aust be done using either the respective computer points or by local verification. If these valves have not closed, close them using the local control switch.
Local Control Local Control -
Valve No. Computer Pt. Switch Name Switch No.
ES 256 Z517 HPT IST EXT NV-256A T/E NRV, FW HTR 1-6 ES 349 Z515 EPT IST EXT NV-349A G/E NRV, FW NTR 2-6 ES 298A&E E586 DEAER KTR NV-295A -
1-1-3 LP TURB 1-1 EXT ES 9845 N/A DEAR HTR NV-9845 1-1-3 LP TURS 1-1 EXT ES 325A&E Z602 DEAR HTR NV-325A 1-2-3 LP TUR3 1-2 EXT ES 9846 N/A DEAR HTR NV-9846 1-2-3 LP TURS 1-2 EXT ES 264 2493 KP EXT NRV NV-264A FW NTR 1-1-5 CS 377 2600 LPT 3RD EXT NV-377A NRV FW HTR 1-2-4
_ ES 278 2585 LPT 3RD EXT NV-278A NRV TW NTR 1-1-4 ES 370 2495 KPT EXT NRV NV-370A FW KTR 1-2 5 Attachment *$
Fage 1 of 1
25 PP 1102.03.13 STAS INITIATION REC 0VERY GUIDELINE The purpose of this section is:
- To ensure that the SFAS is in the most relible operational condition at all times.
- To act as a guide for recovery from any incident level af ter a real or erroneous STAS actuation.
This section is written strictly as a guide for the operator and is is no way intended to be detailed La actions to be taken. No real detail can be provided since the plaat conditions at the time of the incident are in themselves unpredictable. The intent of this procedure is to remind or instruct the operator how to evaluate the incident, what general actions need to be taken, what problems to look for, and what detailed procedures will be needed for recovery from the various situations. The conditions -
of the reactor, primary and secondary systems, the operator actions during STAS actuation, and the failure of composeats or systems during STAS actuation will also determine the required actions for recovery.
The purpose of the Safety Teatures Actuation System (STAS) is to auto- ,
estically prevent or limit fission product and emersy release from the core, to isolate the containment vessel and to initiate the operation of the EST equipment in the event of a Loss of Coolant Accident (LOCA). To accomplish this punyose, STAS actuated equipment shall NOT be blocked or overriddes emcept as allowed by EP 1202.01, Specific RulT4.
Blocking to re-initiate system operations should be avoided when possible.
The desired method for re-establishing system operations after an erroneous trip is to reset the STAS trips first. In this way, any subsequent STAS trips can actuate the appropriate equipment as needed.
Following a real or erroneous trip of any STAS incident level, the status of the associated equipment is dependent osialy on the incident level (s) actuated. Therefore, this section is divided into subsections by which incident levels occurred. The subsections are:
- 1. Incident Level 1 Occurrence
- 2. Zacident Levels 1 and 2 Occurrence
- 3. Incident Levels 1, 2, and 3 Occurrence
- 4. Incident Levels 1, 2, 3, and 4 Occurrence The corrective action steps listed in the sections do not have to be completed La the order Sives escept as noted. In fact, it would be better if the steps listed were divided amens personnel os shift at the time to speed their completion.
- 1. !acident Level 1 Occurrence Aa facident Level 1 Occurrence will automatically initiate when .
Attachment 6 Page 1 of to e
4 h - _._.____A.
i i l . ,
I .
l l 26 PP 1102.03.13 high radiation (2 times background at 1007. power) is detected by I two out of four containment radiation detectors, or by one out of three detectors when one has been declared inoperable and has been placed in the tripped condition.
cat! TION: !
Prior to any restoration of systems, ensure that the
- conditions warranting this actuation have been cleared, the plaat is in a stable and controlled condition or the fault causing the automatic initiation has been determined and corrected.
The trip can be determined to be real or erroneous by comparing all four STAS chamaels radiation levels and by acting any unusual RCS conditiosa which would indicate a leak exists. Containment radiation
- can also be checked on the wide range indicators on the Post Accident Indicacias Panels.
1.1 STAS Equipment Recovery From Real !aitiation (A) If a real high radiatiori condition does extst, it is probably indicative of a small RCS leak. Follow AB 1203.29, Small RCS Leaks.
(3)
After the unit is shutdows, ao specific recovery is required i
from Incident level 1. Restore actuated equipment listed on Table 1 as required after approval, but de met opea closedconditions.
plaat containment isolation valves ualess required by l 1.2 STAS Equipment Recovery Troe Erroneous !aitiation i
(A) Roset the STAS cabisets is accordance with SP 1105.03,
"$FAS operating Procedure", Section S. This may require placias one of the chaamels with the erroneous input in the tripped condition. De not reset the STAS until the fault cauaias the actuation is cleared.
(3) !
Re-establish the Containment Gas Na Analyser Systes per SP 1105.15 Section 7. ;
NOTE:
Blocking will act be required as per Step 7.1.1 '
of SP 1105.15 if Step (A) above has been completed.
(C) Secure the Emergency Ventilaties Systes per SP 1104.15, Secties 4.
(D) Reetart the Centrol Room Ventilation System per SP 1104.14, Secties 4, as required. ,
(E) Re-establish ICCS Reese Ventilation per SP 1104.16, Section
- 4. Stepe 4.3.14 through 4.3.16.
i Attachment t Page 2 of to l I
27 PP 1102.03.13 (T) Secure the Containment Purge Systes per SP 1104.21, Section 6; or restart per Section 4 as' required.
(G) Restore other STAS actuated equipment as listed on Table 1 i to normal as directed by the Shif t Supervisor.
I
- 2. Incident Levels 1 and 2 Occurrence A combined occurrence of Incident Levels 1 and 2 will automatically ;
initiate when primary plant pressure drops to less than 1650 psig or !
cont 4 Lament vessel pressure raises to greater than 18.4 psia.
CAUTION: Prior to any restoration of systems, ensure that the conditions warrar. ting this actuation have been cleared, the plant is in a stable and controlled condition, or the fault causing the automatic initiation has been determined and corrected. '
The trip can be determined to be real or erroneous by comparing all four STAS channels for the parameter which tripped the SFAS as indicated by the annunciators. If RCS pressure has reduced to 1985 pais, the independent RPS pressure transmitters would have tripped the reactor. Also, if enough reactor coolant was released into contaf ament to provide 18.4 psia, radiation levels should have increased and pressurizer water level should have dropped. The Post Accident Indicating Panels also contain indication of containment i
wide range pressure, water level, and radiation as well as normal sump level, all of which can be used for comparison.
l NOTE: If an STAS Level 2 Trip has occurred and the LDG's are 1
supplying C-1 and D-1 busses Do NOT reset STAS until l offsite power is restored. If STAS is reset and subsequently actuated with an existing loss of offsite power the LDG sequencer will act be reset and all loads will be instan-taneously placed on the EDG, overloading the unit. The sequencer logic will only be reset by closing the essential bus feeder bresker or cross-tie.
2.1 STAS Equipment Recovery From Real Initiation Recovery from this situation will generally be conducted after the establishment of cooldown and depressurization per LP 1202.01, RPS, STAS, STRCS Trip or SG Tube Rupture.
The primary concera during this recovery is the assurance of so further release of fission products or energy from the core and continued integrity of the containment vessel. To ensure this, the plaat must be in a shutdown condition with a reliable source of cooldews and depressurisation in progress. '
Attachment 6 Page 3 of 10 a
e
_ . _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ _ - . _ - - - . _ _ _ - . . . _ _ __A. -
28 PP 1102.03.13
. After approval:
(A) Retura both Keergency Diesel Generators to normal standby conditions per SP 1107.11 "EDG Operating Procedure" if not required for emergency power.
(S) If the condition causing the trip has cleared, reset the SFAS cabinets per SP 1105.03, (STAS), Section 5.
NOTE: Resetting of the STAS cabinets will not change the status of the actuated equipment.
(C) If the SFAS cabinets have been reset, restore other SFAS actuated equipment as listed on Table 1 to normal. De not ,
opea contaissent isolaties valves unless necessary.
2.2 IFAS Equipment Recovery Free Erroneous Incident Levels 1 and 2
- Trip After approval free the Shift Supervisert (A) Roset the SFAS' cabinets per SP 1105.03, "SFAS Operating Procedere", Secties S. This any require placing one of the chaamals with the erreaeous input is the tripped condities.
De met reset the cabinets until the fanit causing the
.actuaties is cleared.
(B) Re-establish letdeum when necessary for RCS investery control.
(C) Stop both DI Pumps and close all four injection valves D2A, R, C, and D.
(D) Retars both Emergency Diesel Generators to seems1 standby coaditions per SP 1107.11, "EDG Operating Procedure".
(E) Re-establish the Costainment Oas Re Analyser System per SP 1105.15, Section 7.
Netts Blocktag will met be required as per Step 7.1.1 of SP 1105.15, if Step (A) above has been completed.
(F) Secare the Emergency Ventilation System per SP 1104.15, Secties 4.
(4) Re-start the Centeel Room Ventilattes System per SP 1104.14, Secties 4, as required.
(E) Re-establish ECCS Rooms Ventilaties per SF 1104.14, Section 4.
.(I) Restore the Costainment Perse System per SP 1104.21.
Attachment 4 Pese 4 et 10
29 PP 1102.03.13 (J) Restore other STAS actuated equipment as listed on Table 1.
(K) If an STRCS trip has occured in parallel with the STAS trip such that the OTSG 1evel control setpoint has been changed to the "HIGH" value, return the setpoint to the
" LOW" value by pressing " LOW" on HIS SP98 for SG1 and BIS SP9A for SG2. Switches located on the STAS valve panel. ,
- 3. Incident Levels 1, 2, and 3 Occurrence A combined occurrence of Incident Levels 1, 2, and 3 will automatically initiate when primary plant pressure drops to 450 psis or containment pressure of 13.4 psia. A comparison of the RCS pressure reading in ,
each STAS Chamael will determine if the trip is from a real incident or free erroneous instrumentation. Also, the RPS has separate RC !
pressure transeitters that will trip the reactor if RCS pressure drops to 1935 psig. If the event is indeed due to a LOCA, containment pressure and radiation levels would be elevated. The Post Accident
~
Indicating Panels also contain indication of containment wide range pressure, water level, and radiation as well as normal sump level, all of which can be used for comparison.
CAUTION: Prior to any restorstion of systems, ensure that the conditions warranting this actuation have been clested, the plaat is la a stable and controlled condition, or the fault causing the automatic ialtiation has been deter-mised and dorrected.
j .
NOTE: If as STAS Level 2 Trip has occurred and the EDG's are supplying C-1 and D-1 busses Do NOT reset STAS until off-
' site power is restored. If SfAT Ts reset and subsequently ;
actuated with an esisting loss of offsite power the EDG 1 sequencer will act be reset and all loads will be instan-taaeously placed on the EDG, overloading the unit. The I
sequencer logic will only be reset by closing the essential bus feeder breaker or cross-tie.
3.1 Recovery From Real Incident Levels 1, 2, and 3 Occurrence.
Recovery from this situation will generally be conducted after the establishment of cooldews and depressurization per EP 1202.01, RPS, STA8, STRCS Trip or 50 Tube Rupture.
The primary concera during this recovery is the assurance of so further release of fission products, to keep the core cool, and the contiamed integrity of the containment vessel. To ensure this, the plaat must be is a shutdows condition with a reliable source of cooldows and depressurization la progress.
After approvals (A) Eigh pressure injection may be stopped or throttled per the Specific Rules sectica of EP 1202.01. 1 l
l Attachment 6 Page 3 of 10 r
1 l__ _ _ _ _1 ____..-_._ _ ______ _ _____---._-_- --- -
30 PP 1102.03.13
' (8) Retura both Emergency Diesel Generators to normal standby condition per SP 1107.11, "EDG Operating Procedure" of not required for emergency power. )
(C) If the condition causing the trip has cleared, reset the STAS cabinets per SP 1104.03 " STAS operating Procedure", .
Sectica S.
(D) If the STAS is reset, restore other STAS actuated equipeest as listed on Table 1 to normal. Do not open containment isolation valves unless necessary.
3.2 STAS Recovery Troe Erroneous Incident I,evels 1. 2, and 3 Occurrence After approval free the Shift Supervisor (A) Reset the STAS cabinets in accordance with SP 1105.03, .
" STAS operating Procedure". Section S. This may require placing one of the chamaels with the erroneous input is the tripped condition. De not reset the STAS until the fault causing the actuation is cleared.
(3) Re-establish seal injection flow by:
(1) Re-opes CC1460 to supply coeling water to the W Pumps; (2) Closing the seal injection flow control valve ustag TIC W19.
(3) Reopen the RCP seal injection valves W66C (D. A, 3).
i (4) Reepea W19 until a flow of 3-5 GPM per seal is established. Open W31 WS9C (D, A, 8) and slowly establish approsimetely 32 GPM. Tramafer head / auto station to auto. l (S) Re-establish letdown when required for RCP inventory costrel.
(C) Stop both DI Pumps and close all four injection valves W2A (3, C, D).
(D) Step both DN P'aupe.
(I) Return both Imergency Diesel Generators to aereal standby condittoa per SP 1107.11. " Emergency Diesel Generator Operating Precedure".
(T) Close CS Valves C81530 and C81531.
Attachment.6 Fase 4 of 10
+.
31 PP 1102.03.13 (G) Restore CCW to normal lineup and close the CCW to DH Coolers outlet valves CC1467 &nd CC1469.
(H) Re-establish the Contatnment Gas Hg Analyzer Systes per SP 1105.15, Section 7.
NOTE: Blocking will not be required as per Step 7.1.1 of SP 1105.15, if Step (A) above has been completed.
(I) Secure the Emergency Ventilation Systes per SP 1104.15, Section 4.
(J) Restart the Control Room Ventilation Systes per SP 1104.14, Section 4 as required.
(K) Re-establish ICCS Rooms Ventilation per SP 1104.16, Section 4
(L) Restore the Containment Purge System per SP 1104.21.
(B) Restore other STAS actuated equipment as listed on Table 1 to normal.
(N) If an STRCS trip has occured in parallel with the STAS trip such that the OTSG tevel control setpoint has been changed to,the "HICX" value, return the setpoint to the
" LOW" value by pressing " LOW" on HIS SP95 for SG1 and HIS SP9A for SC2. Switches located on the STAS velve panel.
- 4. Incijent Levels 1, 2, 3, and 4 Occurrence A coobtned occurrence of Incident Levels 1, 2, 3, and 4 will automatically initiate when containment pressure increases to 38.4 psia. Since the only real Lacident that can cause this large increase in containment pressure is a major LOCA, by a quick observation of RC3 pressure, pressurizer level, and containment radiation levels, the operator can determine if the Lacident is real or erroneous. The Post accident Indicating Panels also contain indication for containment WR pressure which can be checked as a backup.
CAUTION: Prior to any restoration of systems, ensure that the conditions warranting this actuation have been cleased, the plant is La a stable and controlled condition, or the fault causing the automatic initiation has been determined and corrected.
If facident Levels 1 through 4 are due to a real occurrence, the BW8T level will drop withis a retter of hours to the low level setpoint and the DN and CS Pumpe suction will have to be transferred to the emergency sump. Therefore, the recovery from a rest Incident Level 1 throush 4 occurrente is the same as free an Incident Level 1 through S occurrence.
Attachmeat 6 Page 7 of 10
f -
. . . . . . . . . . .. .2 ..
32 PP 1102.03.13 NOTE: If aa SFAS f.evel 2 Trip has occurred and the EDG's are supplying C 1 and D-1 busses DO NOT reset STAS until ,
offsite power is restored. If STA$ is reset and subsequently actuated with an existing loss of offsite power the EDG sequencer will set be reset and all leads will be instaa-taaseusly placed on the EDG, overloading the unit. The
- sequencer logic will only be reset by closing the essential bus feeder breaker or crose-tie.
4.1 Recovery Free Real facident Levels 1, 2, 3, and 4 Occurrence Recovery free this situation will generally be conducted after the establishment of coeldews and depressurisation per EF 1202.01, RFS, SFAS, SFRCS Trip oe SG Tube Rupture.
The primary concera during this recovery is the assurance of se further release of fission products, to keep the core cool and '
the contiamed integrity of the contatament vessel. To ensure this, the plaat east be is a shutdown condities with a reliable source of coeldews and depressuriaation La progress.
After approvat (A) Eigh pressure Lajecties any be stopped er throttled per the Specific Rulee section of EP 1202.01.
(B) If containment prtssure has returned to below 18.4 peia, ,
shat off both C3 Pumpe and close CS !selar. ten Valves C21530 and CS1531.
(C) Return both EDO to normal staedby condition per SP 1107.11
" Emergency Diesel Generator Operating precedure" if set required for emergency power.
(D) If the condition caustas the trip has cleared, reset the SFA8 cabinets per SF 1105.03, "$FAS Operating Procedure",
Secties 5.
(E) If the STA8 has been reset, restere other SFAS actuated equipment as listed es Attachment 1 to aereal. De set eyes Centatament !selaties Valves unless necessary. De set close the containment emergency susy outlet valves if DN/C3 suctien La free the emergency sumy.
4.2 SFAS Equipment Recovery Free Irreaeous !acident Levels 1 through 4 Oecurrence Staee Incident Level 4 closes the MS!V's, the plant trip is a certataty. The operatore efforts must be to step both CS Pumps free spraytag berated water into contatament and reestablish =
Lag CCW to the contatament header.
Attachment *4 Page 4 et to l
4 .
1 i
.33 PP 1102.03.13 j After approval from the Shift Supervisor: !
(A) Push the block pushbuttons by the CS Pump control switch [
- and stop both CS Pumps.
(B) Block and reopes the CCW ! solation Valves CC1407A and
]
8 ud CC1411 A and B. [
i (C) Reset the STAS cabinets is accordance with SP 1105.03, l
" STAS operating Procedure" Sectica 5. This may require
] placing one of the chamaels with the erroneous input is the tripped condition. De set reset the STAS until the fault f caustas the actuation is cleared.
(D) Clear any STRCS trips present, open the MSIVs, and reestablish j condenser vacuus per Attachment 7. l 1
i (E) Stop both MPI Pumps and close all four tajection valves 1
MP2A (3, C, 0). t (T) Stop both DN Pumps.
) (G) Retura both Emergency Diesel Generators to aersal standby
. condition per SP 1107.11, " Emergency Diesel Generster '
4 Operating Procedure".
(N) Close CS !ajection valves CS1530 and CS 1531. [
]
4
(!) Restore CCW to aermal lineup and close the CCV to DN !
Coolers outlet Valves CC1447 and CC1449. I t
J (J) Re establish the Coataissent Gas Na Analyser Systes per !
SP 1105.15 Section 7.
i NOTE: Stocking will not be performed as per Step 7.1.1 if Step (C) above has been completed.
(X) Secure the Energency Vesti14 tion System per SP 1104.15, ,
Section 4 1 4
(I.) Restart the Control Rees Emergency Ventilation System per SP 1104.14, Secties 4, as required. f 4
(M) Re-establish ICCS Rees Ventilation per SP 1104.16, Sectica 4 i l (N) Restore the Centeiament Purge System per SP 1104.21.
l *
(0) Restore other STAS actuated equipeest as listed os Table 1 l
- to assual.
0 i
Attachment 6 Page 9 of to
- l
34 PP 1102.03.13 (P) If as STRCS trip has occured in parallel with the STAS trip such that the OTSG 1evel control setpoint has been chassed to "MIGE" value, return the setpotat to the "LOV' value by pressing "LOV' on MIS SP95 for SGI and MIS SP9A for SG2. Switches located on the STAS valve panel. ,
9 V
f Attachneet*4 Page 10 of 10
ACTilATER EQt!!PlflfT TARIJI.ATIOst SFAS IseiJest Level I l
SQWIP PEIS EQtilPIElff SA SIGNAL SA IlOfelAL 10 3 . 33. attenIPT1018 20 0 . POSITloti POSIT 1088 C38-1 II-4294 Emer Vent Fan I SA Illa Start Off l N 5439 N-4248 ECCS Rosa 145 WEAC Iso Viv SA 3115 CloscJ Open W 5444 N-42SR ECCS Roem lei NVEAC Iso Vlw SA IllC Closed Opca l
N 5424 5-429A Emer Vest Faa I Vlw free Ana. RIJg. SA IIIS Closed Various W 5716 M-42SE ECCS Reen 315 Ise Ihmer SA IIIE Closed Various C36-2 N-429A Emer Vest Faa 2 SA Il2A Start Off W 5441 II-4218 ECCS Base 115 WWEAC Ise Viv SA II28 Closed Open W 5442 N-42&B ECCS teen Its WEAC Iso V!v ' SA Il2C Closed Open W 5425 N-429A Emer Vest Faa 2 Viv isan Ana. BlJg. SA 112D Closed Various W 5715 N-4288 ECCS Raea ISS Ise Degr SA Il2E Closed Various CV 54e4 It-429A CTNT Purse Out Iso V1w SA 1213 Closed Closed CV SetIA W-4298 C2NT Air Sample Iso Viv SA 121C CloseJ Open CV 54313 N-6298 CTNT Air Sample Ise Vlw SA 121D CloseJ Open CV SellC N-429B CTNT Air Sample Isa Vlw SA 32tE CloseJ Open CV 54118 N-4298 CTNT Air Sample Ise Viv SA 121F Closed Opea 0 CV Saes N-429A CTNT Perse la Iso Vtw SA 121C closed Closed CV 54@9 N-4294 Neth Pest Rees 4 Fwrge Vlw SA 1218 Closed Closed CV 5816 N-829A Nech Prat Race 4 Purse V1v SA 121I Closed Closed CV SettE N-4298 CTNT Air Sept Ret Isa V!w SA 12tJ Closed Opea Sta-1 N-427A CPrT Ret Fem & W/AC Dmit I SA 121L Various EU 4 IE g
a 8 7 b
ACTtthTES 5(lHIIMaff TASMLATIOff SFA5 Incident level I WP FERS SPIMNET SA SIGHAL SA It0 meal W. 38. MSCRIPfleal IIG. POSITical 70517801f N Sales 35-4298 CIHF Air Sample les VIw SA 5225 Closed Open CW 5404 E-4294 Nech Peet Seen 3 Forge Viv SA 322C Closed Closed CW 5421 N-4294 Mech Pest Beam 3 Phtee Viv SA 3229 Closed Closed CW 5805 N-4294 CINT Purge la Ise Vlw SA I22E Closed Closed M 5887 M-4294 Cast Fmagedhet Ise Vlw SA 322F Closed Closed CW 54544 E-4298 CNET Air Sample lee Vlw SA 522C Closed eyes CV 54908 N-4298 CMfr Air Sample Ise VIw SA B2211 Closed Dyes CW 5elec N-4298 CDer Air Sample Ise VIw SA 322I closed open CV Selm E-4295 C"Ist Air Sample Ret Ise VIw' SA 122J Closed open Ste-2 N-427A CTtse Ret Fan & N/AC thalt 1 SA 322L Stop various SFAS lecidret level 2 F54-1 N-413 W Inj PIIP I SA 2tlA Start Off W2C N-413 W Inj I-I vie '
SA 2538 open closed W2B 15-413 WP Inj I-2 VIw SA 28tc crea closed P54-2 N-433 W Inj Pay 2 SA 212A Start Off W2A N-433 EP Inj I-2 Vlw $4 2I28 Open Closed EP2s15-433 W Inj 2-2 Vlw SA 212C Open Closed C 1-1 5-4294 Cnff Ctr Faa I SA 225A Start Various C 1-3 ERN Cnet Ctr Fee 3 54 22th Slow Various em .* o TD C 1-2 15-4294 Cnft CIr Fan 2 SA 222A Stew Various **
- $ C 1-3 38-4294 Cntt CIr Fan 3
^
SA 2228 Slow Various l-en $$
~
)
be
= ,
O 9
j .
o ACTutTES E4WlftENT TAGNI.ATIGel
- SFAS Incidret Lawel 2 I
BWIP PERS R@! MENT SA SICMAL SA IIGIstAL l Wh. 38. astralFTIeef 31 0 . POSITIC4f Et1SITiosi l
l M3-1 N-e% CC Pump I SA 235A Start ifarious M3-3 N-en CC Pune 3 SA 2318 Start Various CV 5474 N-4298 CTNT Wace Rif Ise V!v SA 23tc Closed Opea
! CV 5478 N-4298 CTIET Vece Elf Ise VIw SA 231D Closed Open l CV 5472 N-4298 CTNT Vern Elf Ise Viv SA 235E Closed Open l CV 5473 . E-4298 CTNT Tata Rif Iso Vlw SA 231F Closed Open l CW 5474 35-4298 CTNT Wace RIf Ise Viv SA 231G Closed Open M3-2 '
N-SM CC Pimp 2
~
SA 232A Start Various M3-3 II-eM CC Fine 3 SA 232R Start various
, CV 5475 N-4298 CInrt veca Rif Ise Vlw SA 232C Closed Open CV 5476 35-4298 CTNT Waca Rif Ise Viv SA 2329 Cleaed Open CV 5877 N-4294 CTNT Vace Rif Ise Viv SA 232E Closed Opca CV 5478 NAM CTNT Veca Rif Ise VIw SA 232F Closed Open CW 5479 35-8298 CBET Veca Rif Ise Vlw SA 232G Closed Open F3-I . N-441 SW Pimp 1 SA 241A Start various F3-3 N-441 W Pump 3 SA 241R Start Various SW I424 N-441 SW Fram CC EK I Ise Viv SA 241C Open Various SW I429 M-841 SW From CC EK 3 Ise V!v SA 241D Open Various F3-2 N-441 SW Pune 2 SA 242A Start Various P3-3 N-443 SW Pimp 3 SA 242R Start Various
(( SW 1434 N-448 SW Free CC NE 2 Ise V!w SA 242C Open Various 4 eg SW 1429 E-44I SW Fram CC ME 3 Ise Viv SA 242D Open Various 7
o
~
CS 1534 N-434 CS I Ise Vlw SA 251A Open Closed !*
A CS 1538 N-e34 CS 2 Iso VIw SA 252A Open Closed
~a -
E 5-1 E-3 Emer RC I SA 261A "
Statt off E 5-2 E-3 Emer RG 2 SA 262A Start off S
y _ _ _ _ _
_ , . _ . , - _,__,_____,,_____,___,_,__m
l ACTUATED EQUllTENT TAbt!!ATION SFAS laciJeat Level 2 EQlllP PEID EQUIPMENT SA SICNAL SA N0kHAL NO. M0. DESCRIl'TIOtf NG. POSITIGN l'QSITION _
IRl2A M-03I BC Letdown Delay Coil Out Viv SA 27tA Closed Opca BR 20l2A M-046 CTNT Norm Samp Iso Viv SA 271D Closed Open RC 240A M-030 BC PR2R Sample Viv SA 271E Closed Closed SW 1399 M-04) SW Iso Viv to Clag Wtr SA 271F Closed Open RC 1773A M-040A RC DT NJr Iso VIv
~
SA 271G Closed Open RC IJ19A M-040A CTNT Vent NJr Iso V!v SA 271H Closed Open SS 607 M-007 SG 1 Sample Iso Vlv SA 2711 Closed Open ICS IIR M-007 SG I Ata San Vest Viv SA 271J Closed Open SS 235A M-040A Przr Qach Tk Sample Iso Viv , SA 271K Closed Closed CF 1544 M-034 CF Tk I N2 0 and Na Fill Iso Viv SA 271L Closed Closed HD 3 M-031 RC Letdown Ni Temp V!v SA 272A Closed Open DR 20125 M-046 CTNT Norm Samp Iso Viv SA 272C Closed Open RC 240B M-030 BC Przr Vapor Sample Viv SA 272D Closed Closed CF 1542 M-034 CF Tk Vest Iso Vlv SA 272E Closed Closed SW 1395 M-04I SW Iso V!v to Clag Wtr SA 272F Closed Closed m BC 1773R M-040A RC DT NJr Iso V!v SA 272G Closed Open **
RC 1719B M-040A CTNT Vest NJr Iso Vlv SA 272H Closed Open SS 594 M-007 SG 2 Sample Iso Vlv SA 2721 Closed Open ICS IIA M-007 SG 2 Ata Sta Vest Viv SA 2723 Closed Open SS 235B M-040A PRZR Qach Tk Sample Iso Viv SA 272K Closed Closed CF 1541 M-034 CF Tk 2 N2 0 and N2 Fill Iso Vlv SA 272L Closed Closed
.g Del 95 M-033 CTNT Emer Sump Vlv SA 281A Closed C!osed ,,
Yg Dil 78 M-033 RWST Out Vlv SA- 281G Open Open **
- Q kN 236 M-019 Na CTNT Iso Viv SA 281H Closed Open ;
. RC 229A M-040A PRZR Qach Tk Out Iso Viv SA 281I Closed Open S n MS 394 M-003 Ma Sta Line I WU Dra Iso Viv SA 28tJ Closed Open *
=
- h e
. - 2_ _,
ACTUATED EqulFMEllT TABULATiest
No. 30. RESCRIPTICII 11 0 . P011371001 POSIT 1001 I RC 232 N-8444 PS2R Qech Tk In Isa Viv SA 282A Closed Open 3C 2298 Il-844A Pt2R Quch Tk Out Ise Viv SA 2825 Closed Open l
CC 1545 N-834 CF Tk Sample Viv SA 2820 Closed Closed
~
311 7A N-633 BWBT out Viv SA 282G Open Open 4 .
IA 2 ell 10-815 CTNT Instr Air Iso Viv SA 282M Closed Open SA 2684 N-615 - CTNT Serv Air Ise Viv SA 2923 Closed Open
. IIS 375 N-ee3 Its San Line 2 IAI Den Ise Viv SA 282J Closed Closed l
i CV 5065 N-429A CTNT Na Dilution In Iso V!v SA 291A Closed closed i IlW 683IA N-Slot RCP STDP Domin Wtr Ise Viv SA 291C closed Cpen CV 5438 M-829A CTNT Na Dilution Out Iso Viv SA 291E Closed Closed CV 5496 N-4294 CTNT N Dilmtion la Iso Viv SA 2928 Closed Closed' ,
- BW 64315 N-8108 BCP STOP Demin Wtr Iso Viv SA 292C Closed Open
- CV 5437 N-829A CTNT Na Dilution Out Iso Viv SA 292E Closed Closed 1
@h E r i
~!E ~
.- ' 8 -
, 5 T C l
) -
j I
i l . .
ACTUATED EQUIPMENT TABULATION SFAS Incident Level 3 EQUIP PEID EQUIPENT SA SIGNAL SA Il0RMAI, 11 0 . 11 0 . DESCRIPTION NO. POSITION POSITION P 42-1 M-033 DIl Pump 1 SA 311A Start Various llV 1467 M-036 CC From Dil Ctr 1 Out Vlv SA 311C Open Various
, NV 2733 M-033 Del Pump 1 Suct Viv Free BWST SA 311D Open Various MV Dill 48 M-033 Dil Clr 1 Out Vlv SA 311E Open Various llV Dill 38 M-033 DN Clr I Bypass Vlv SA 311F Closed Various P 42-2 M-033 Dil Pump 2 SA 312A Start Various llV 1469 M-036 CC From INI Clr 2 Out Vlv SA 312C Open Various XV 2734 M-033 DR Pump 2 Suct Vlv from BWST' SA 312D Open Various IIV Dill 4A M-033 DN Clr 2 Out Viv SA 312E Open Various MV Dill 3A M-033 DN Clr 2 Bypass Vlv SA 312F Closed Various NV 1495 M-036 CC Aux Equip In V!v SA 321A Closed Open NV 1460 M-036 CC Vlv to Emer Inst Air Caps SA 322A Closed Open MU 33 M-031 RC MU Iso Viv SA 331I Closed open MU 38 M-031 RCP Seal ket Iso Vlv SA 332F Closed Open MU 66A M-031 RCP 2-1 Seal In Iso Vlv SA 332E Closed Open MU 66B M-031 RCP 2-2 Seal In Iso Viv SA 33tJ Closed Open Mil 66C M-031 RCP l-1 Seal In 1so Vlv SA 331E Closed open MU 66D M-031 RCP l-2 Seal In Iso Viv SA 332G Closed Open IRI 59A M-031 RCP 2-1 Seal Ret V!v SA 331E Closed Open uH MU 598 M-031 RCP 2-2 Seal Ret Vlv SA 331F Closed Open o IU MU 59C M-031 RCP l-1 Seal Ret Vlv SA 331G Closed Open d' E RCP l-2 Seal Ret Viv on MU 590 M-031 SA 33111 Closed Open
{,n a .
8 t
I I
ACTUATED EQljlPHENT TADULATION ' '
SFAS Incident Level 4 EQUIP P&ID EQUIPMENT SA SIGNAL SA NORMAL .
NO. No. DESCRIPTION NO. POSITION POSITION SFAS Incident Level 4 P'56-1l H-034 CS Pump 1 SA 4llA Start Off P 56-2 H-034 CS Pump 2 SA 412A Start Off
. CC 1411A H-036 CC In Iso V!v to CTNT SA 421A Closed open CC 1407A H-036 CC Out Iso Vlv from CTNT SA 421B Closed Open
, CC 1567A H-036 CC In Iso Viv to CRD SA 421C Closed Open CC 1328 H-036 CC CRD Booster Pump 1 Suct Vlv SA 421D Closed Open CC 1411B H-036 CC In Iso Vlv to CTNT ,SA 422A Closed Open CC 1407B H-036 CC Dut Iso Viv from CTNT -
SA 422B Closed Open CC.1567B H-036 CC In' Iso V!v to CHD SA 422C. Closed Open CC 1338 H-036 CC CRD Booster Pump 2 Suct V!v SA 422D Closed Open MS 101 H-003 Hn Stm Line 1 Iso Viv SA 431A Closed Open p FW 612 H-007 Hn FW l Stop Vlv SA 431C Closed Open e' HS 100-1 H-003 Ha Stm Line 1 WU Iso Viv SA 431E Closed- Closed MS 100 H-003 Hn Stm Line 2 Iso Viv SA 432A Closed Open
. FW 601 H-007 Hn FW 2 Stop Viv SA 432C Closed Open MS 100-1 H-003 Ha Sim Line 2 WU. Iso Vlv SA 432E Closed Closed Uf
- Wc; 5
-. . B 51
~a .
. u r
i l
P' 42 PP 1102.03.13 STRCS INITIATION RECOVERY GUIDELINE The purpose of this section is to act as a guide to restore plant operation to the normal mode of MFW feeding the SGs and the TEVs dumping steam to the condenser. This will allow the AW System to be returned to standby ,
and termination of steam dumping to the atmosphere via the atmospheric vents. The assumptions used in writing this section were that the SGCS actuated on a signal other than a MFW or MS rupture. If a rupture is suspected,-it should be determined if it can be isolated and a normal cooldo*u conducted (possibly on one SG) or consideration should be given to conducting a cooldown on A W and the AVVs. A rupture, or condition such as a stuck open MSSV which prevents restoring normal feed and steaming on one SG, will make the below steps on that SG non-applicable.
- 1. Take control of OTSG pressure using the atmospheric vents to stop secondary side safety valve lifting. ,
1.1 Place both atmospheric vent valves hand / auto stations in
" hand" at zero demand.
1.2 Press both atmospheric vent valves block buttons (HIS-ICS-11D -
and HIS-ICS-11C).
1.3 Press " auto" on HIS-ICS-113 and HIS-ICS-11C.
1.4 Control OTSG pressure as desired to prevent lifting secondary side safety valves. The valves may be placed in " auto" if desired.
- 2. Trip both Main Feed Pump Turbines.
- 3. If condenser vacuum has been lost, open the condenser vacuum breakers and lockout the Me hanical Hogger.
3.1 Open the condenser vacuum breakers using HIS-634 on Panel C-5721.
3.2 Lockout the Mechanical Hogger using HIS-1005 on Control Room Panel C-5721.
- 4. Have an operator start up the Auxiliary Boiler and charge the Auxiliary Steam Header.
4.1 Start up the Auxiliary Boiler per SP 1106.04.
- 5. I.ocate and correct the cause of the loss of normal feedwater if possible. If loss of normal feed was due to a pipe rupture, ensure isolation of the rupture. The cause of loss of normal feed could be one of the following:
5.1 A feed line rupture.
Attachment 7 )
Page 1 of 4 I
.43 PP 1102.03.13 5.2 Loss of both main feed pumps.,
5.3 Inadvertent closure of Main Feedwater Control Valves,
- Startup Control Valves, or Main Feedwater Block Valves.
5.4 Inadvertent SBCS actuation.
i 5.5 Loss of steam pressure control causing SERCS actuation, i.e., a stuck open MSIV. .I
- 6. When the 235 psig steam header is on the Auxiliary Boiler, re-establish seal steam and condenser vacuum.
6.1 Estab1"ish gland steam per SP 1106.03.
6.2 Establish condenser vacuum per SP 1104.35.
- 7. Before normal feedwater control can be accomplished, the SFRCS low level manual trips must be reset. The SUFP aust be started to clear the SFRCS steam to feed .iP trips.
J 71 To reset the manual low SG SFRCS trip, puzh off buttons on SG LVL LOW TRIP BUTIONS (4869 and 4970) on SFRCS manual initiation selection of Control Room Panel C-5721.
7.2 Start the SUFP per SP 1106.27.
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- 8. If normal feedwater cannot be established, a cooldown will have ,
to be conducted using the Auxiliary Feedwater System and the atmospheric vents.
- 9. If cooldown using the AFPs is required for an extensive period such that the CST water is exhausted, the automatic shift to service water should be verified or ==nn=11y initiated if CST level falls below three feet.
9.1 Four pressure switches (two for esch AFP) automatically l
shift AFP suction to service water on low AFP suction of
'2 psig. If ==nn=1 initiation is necessary, open SW 1382 .
' _(SW to AFP 1-1 suction and SW 1383 (SW to AEP 1-2 suction) .
and close W 786 (AFP 1-1 suction valve) and W 790 (AFP 1-2 suction valve).
- 10. If the SFRCS trips could be reset, restore normal OTSG heat removal by continuing with the following steps
- 11. Place the turbine bypass valves in hand and close the turbine
! yy __- - bypesa valves %.,.7 ,,..._ g . _1__.._,,,,.,..,.-w.,,.
- 12. Open the Main Steam Non-return Valves MS 209 and MS 210.
12.1 Press open on HIS 209 mad HIS 210 on Control Room Panel C-5722.
j Attachment 7 l
Page 2 of 4 ,
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44 PP 1102.03.13 1
- 13. Press the closed buttons for MSIV 100 and MSIV 101. Then reset the SFRCS solenoids for MSIV 100 and MSIV 101.
1 13.1 HIS 100 and HIS 101 are located on Control Room Panel C-5717.
- 13.2 The STRCS resets for MSIV 100 and MSIV 101 are located on the north wall of the Control Room Cabinet Room. Both resets must be pushed for esch MSIV. t
Valves MS 100-1 and MS 101-1.
I
- 15. If the dP across the MSIVs is greater than 250 psig and stable, isolate the main steam line traps and drains per Attachment 2 of this procedure. Restore the lineup after MSIVs are open. ,
15.1 Main Steam Isolation Valve dP for Line 1 is determined by j comparing OTSG 1 pressure SP123 to turbine header pressure SP16B on the front consoles.
15.2 Main Steam Isolation Valve dP for Line 2 is determined by comparing OTSG 2 pressure SP12A to turbine header pressure SP16A on the front console.
- 16. When the dP across the MSIVs is less than 250 psid,. place the i atmospheric vent valves in hand and then open MS 100 and MS 101.
I
- 17. Using the hand / auto stations, take control of steam generator pressure with the turbine bypass valves and close the atmospheric ;
vent valves. '
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stations in hand and close them. Reset the main feedwater valves and startup feedwater valves SFRCS trips.
- 18.1 Reset the Startup Feedwater Valves SP7A and SP7B SFRCS 4
trips by pushing the nset pushbuttons on the west wall of the control Room Cabinet Room. ,
18.2 The Main Feedwater Valves SP6A and SP6B SFRCS 'tirips are i
reset by pushing reset pushbuttons located 603' elevation,
,, ;,, east)aall of the Turbine Building at SP6A and SP68.
18.3 Reset the MFW Block Valves FW 779 and FW 780 by placing i their control switches to 0FF then back to AUTO.
- ~
- 19. When the decay heat load is low enough to prevent running out. to
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- such esGbusa main fie5/ateYfIBw to f.hs OTSGe'.~This' any ' ~ ~ ~~~~~'-
Attachment- 7 ;
Page 3 of.4 I
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3-45 PP 1102.03.13 require from one to two hours after reactor shutdown depending on the power history. ,
19.1 SUFP is rated for 300 gym at 900 psig. Ensure AFW flow to both OTSGs is less than 300 gpa prior to shutting down AFPs.
19.2 Establish MFW flow to OTSGs by opening FW 601 and FW 612, Main Feedwater Stop Valves, and then throttling open SP7A and SP78, Startup Feedwater Valves, from their ICS stations.
Run the AFW governors to the low speed stops in manual.
- 20. When OTSG 1evels are being maintained by the SUFP alone, shutdown the AFPs per SP 1106.06, Section 7.
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POST TRIP REVIEW GUIDELINES July 3, 1984 Purpose The purpose of this booklet is to provide guidance on the performance of a !
review of a plant transient or trip. This is intended as generic guidance only and is not intended to cover every possible event. Each event should be reviewed on an individual basis with the scope of review determined by ,
the type of event. ,
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. e s .g Transient analysis is basically divided into four phases:
I
- 1. Data Collection '
- 2. Data Analysis .
- 3. Support of Outside Organizations
- 4. Report Preparations and Review These guidelines will discuss each of the four phases.
- 1. DATA COLLECTION i-1.1 Information Available The capability to record and recall the plant information necessary to assist in the determination of the cause or causes of unscheduled reactor trips currently exists at Davis-Besse 1
Unit 1. Digital indications (e.g., on/off, open/close, etc.)
i and key analog information are recorded by various transient monitoring systems during a reactor trip for subsequent analysis. -
The Plant Process Computer records and displays both digital and analog information. The Data Acquisition and Display System j
(DADS) located in the Technical Support Center also provides a
- means for recording and displaying analog information. An additional source of analog information used to support post trip efforts comes from the Control Room strip chart recorders.
i These systems provide the primary sources of information used 1
for trip analysis at Davis-Besse Unit 1.
Plant Process Computer The Plant Process Computer monitors digital and analog informa-tion from all major plant systems. Approximately 2,500 digital
- points and 2,000 analog points are fed into the computer. Some
! of this information is manipulated and stored for plant performance I
monitoring purposes, and all of the information is available to the Control Room operator in various display formats. Three functions of the Plant Process Computer provide information useful for transient analysis efforts. These functions include the Sequence of Events Monitor, the Post Trip Review, and the Alarm Printout.
The Sequence of Events (SOE) Monitor is designed to provide a sequential list of important plant events. All inputs to this function are digital. The list of monitored points is provided as Enclosure 1. A change of state of any of these digital points is recorded in the SOE file along with the time of occurrence. The time of occurrence listed with the event is
, based on computer clock time and recorded to the nearest five milliseconds. The SOE file can hold up to 256 records. Once i- the SOE file is filled, subsequent events replace the oldest
-recorded event in the file. The first event to be recorded in the file triggers an indicator to the operator that an SOE .
monitored event has occurred. This indication is cleared and the SOE file is emptied when the operator requests a printout of
(. i n e e i
er w
. 'o s .g the SOE file. Enclosure 2 illustrates the format of information presented in the SOE printout.
9 The Post Trip Review function is designed to record selected analog information for a period of time before and af ter a reactor trip. The list of parameters monitored by this function is provided in Enclosure 3. The most recent 15 minutes of historical values for these parameters is maintained in 4 rolling file. In the event of a reactor trip, this colling file is frozen and data for the next 15 minutes is recorded. An indication that the Post Trip Review function has been initiated is provided to the operator. The operator may then request the Post Trip Review printout which clears the file. The Post Trip Review printout provides parametric data in engineering units given at 15 second intervals from 15 minutes prior to the trip until 15 minutes after the trip. Enclosure 4 provides a sample of one segment of a Post Trip Review printout. Note that some of the parameters monitored have scan intervals of more than 15 seconds. Consequently, some data may be repeated in successive 15 second records. The parameters monitored for the Post Trip Review function were chosen as a part of the original plant process computer design. The variables monitored are key parameters of the major primary and secondary systems which could indicate abnormal trends that may lead to, or result frou, a reactor trip. Normally inoperative safety systems are not monitored by this function. The scan intervals selected for the parameters were based on the anticipated rates of change.of the ,
individual parameters, and multiplexing hardware and memory
- capacity limitations that existed at the time of the initial design.
The Alarm Printout function provides an historical listing of both digital and analog information recorded when.the monitored parameters enter a predetermined alarm state. Essentially, all digital and analog input points are sonitored for alarm status.
Alarm messages are recorded as they occur on the alarm printer along with the time of occurrence. No operator action is required to initiate the Alarm Printout. All digital points are scanned once per second, and a change of point status is identified on the alarm printer. Analog points are scanned at varying intervals (either 1, 5,15, 30, or 60 second intervals) and are compared at each scan to a predetermined alarm value. Each time the parameter exceeds the alarm limit or returns to within limits, the event is recorded on the Alarm Printout. An example of a section of the Alarm Printout is provided in Enclosure 5.
The Plant Process Computer consists of redundant MODCOMP Classic 7870 CPUs, The CPUs are powered from separate uninterruptable instrumentation buses YAU and YBU. The uninterruptable buses are supplied from the station battery backed 250 volt DC power supply system through an inverter. Power can also be supplied to the bus from a nonessential regulated instrumentation bus -
through a static transfer switch within the inverter. The redundant CPUs were installed during the 1982 Refueling Outage 4
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. ~ s as a part of the overall project to upgrade the Plant Process Computer system. The multiplexers providing inputs to the processors will be replaced in future outages. The multiplexers l are currently supplied from YBU, consequently, a loss of YBU will interrupt all three transient monitor functions of the Plant Process Computer. The DADS will still be functional. As the multiplexers are replaced, they will be equipped with
- redundant power supplies. '
Data Jequisition and Display System (DADS)
The DADS, located in the Technical Support Center, was designed as a part of the emergency response facilities at Davis-Besse
, Unit 1. The primary function of the system is to provide information to emergency response personnel in the Technical Support Center to assist in evaluating plant status in an
. accident situation. Consequently, those variables important to determining the safety status of plant systems and the proper functioning of, safety systems are inputs to the DADS.
While the DADS receives inputs from numerous sources, such as the Meteorological Tower 'and the Plant Process Computer, the inputs of importance to the transient monitoring function are supplied through a separate multiplexer (the Validyne). The list of parameters supplied by this multiplexer is provided in 4 Enclosure 6. The scan rate for these variables is approximately once per second. Data is recorded at that rate for a period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a rolling file. Access to information in this data ,
file is possible in'several formats. Individual points or i groups of points can be examined by a CRT or a line printer
] output. Additional output formats are being developed and will include the use of a printer / plotter to provide graphical i trends.
The Prime Comupter stores information from both the MODCOMP and Validyne inputs. These values can be called up and printed out per Section 1.2. The power supply for the multiplexer located in the station is YAU. The power supply for the DADS computer system is independent of the station electrical system. The Davis-Besse Administration Building (DBAB) which houses the Technical Support Center and the DADS, is supplied from a '
construction feeder independent of the three 345 KV lines connected to the station grid. The DBAB electrical system
. supplies an emergency response facilities bus which can also be fed by an emergency diesel generator through an automatic transfer switch. The emergency response facilities bus in turn feeds an uninterruptable distribution network. Power to the uninterruptable distribution network is backed up by a battery driven system through a static transfer switch which assures continuous operation of the DADS computer system. The emergency battery system is charged from the emergency response facilities bus.
. g 1 .
Strip Chart Recorders In the event that the Plant Process Computer and the DADS are unable to perform their transient monitor functions, the Control Room strip chart recorders act as a oackup source of information for transient analysis. Due to the compressed time scales of the strip chart recorders, the information cannot be used for sequence of events determination and the limited number of
- parameters recorded make determination of the cause of a tran-sient very difficult. However, the parameters that are recorded are important major system parameters such as pressurizer level, Reactor Coolant System (RCS) pressure, steam generator levels, feedwater flows, etc. The information available on the strip chart can be very useful in assuring that major system upsets did not occur as a result of the transient. Strip chart recorders are also useful in recognizing long term trends that may be indicative of problems leading to, or resulting from, a transient.
1.2 Technical Section Function '
It has become a Technical Section function to collect all the available plant data and'have copies given as soon as possible to the Assistant Station Superintendent (Steve Quennoz), Opera-tions (Dale Miller), NRC Resident Inspector (Walt Rogers), and I&C (acting I&C Engineer). This job normally requires a trip to the Control Room to retrieve the alarms (at least 20 minutes prior to trip and for an hour after), the SOE printout and the Post Trip Review (may have to ask the operators to print out).
If possible, attempt to set up a post trip meeting which includes operators from the shift that was on. Copies of the Reactor Operator Log and Unit Log should also be obtained when completed (usually not until the day after the trip).
If possible, talk with the operators which are on shif t. The purpose of this interview is to record pertinent information as seen by the operator during a transient condition. The interview should be conducted as soon as possible after the event.
Typical questions are:
- 1. Briefly describe plant conditions prior to the trip.
(Include Integrated Control System (ICS) mode and pertinent testing, operations, or maintenance in progress or recently completed.)
- 2. What was the first indication or alarm which keyed you to a problem? What actions did you take as a result of these indications?
- 3. Were any alarms or indications out of service or did any fail during the course of the transient? Did any indications or alarms mislead you? Could the Control Room alarms or controls have been relocated in such a manner to have aided your actions on this transient?
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- 4. Did existing plant procedures provide adequate action for this transient? Was it necessary to take action
. beyond their scope.
- 5. What additional information or guidance do you feel ,
would have assisted you during the transient?
- 6. Summarize the transient including both indications and -
actions. Discuss any equipment problems observed.
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The data from the Prime Computer must be manually hard copied within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the trip as follows: -
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- 1) Go to the Technical Support Center Computer Room and turn on the orange line printer (the "run" light should i
i be "on", the "off" light should be lit unless the printer is in the act of printing).
l 2) Turn on a Technical Support Center Rastek terminal and push reset button located at the rear of the keyboard.
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- 3) At. the Ramtek terminal:
(NOTE: two runs, one of 35 minutes length and 30 seconds interval, and a second of 5 l j minutes at I second interval provide the best data)
I l ENTER: IDGIN_TSC MIT: f 3function key (hard copy)
MIT: f gfunction key (to obtain Validyne data) OR f 2functi n key (for selected it00CollP points) l ENTER: point number i
ENTER: P (to output to line printer) l l ..
ENTER: beginning hours and minutes HMHH l ENTER: starting time using HHHH format Run 1: use 5 minutes before trip l (normally use 5 minutes before trip)
Run 2: use 1 minute before trip l l
ENTER: number of minutes wanted to display l ENTER: how long in HHHH Run 1: use 30 minutes l (normally 30 minutes) ,
Run 2: use 5 minutes l l ;
ENTER: interval desired in seconds l ENTER: interval in minutes or <CR) for 30 seconds Run 1: use 30 seconds l Run 2: use I second l l
ENTER: point number or "ALL" for all Validyne l I points l l
Data will now be printed
- l Data will now be printedh
- 4) To exit, enter LO OIf data does not print, do not repeatedly attempt to request printouts since all requests will be remembered and printed when !'
the system returns to working order. Call for assistance from Computer personnel.
i
. 's The Prime data can be displayed on the Ramtek terminal and a video copy of the display obtained on the Tektronix hard copy
. printer.
- 1) Go to the TSC, turn on Tektronix Video copy printer and let wa rm up.
- 2) Turn on a Ramtek terminal and press reset button located at
- the rear edge of the keyboard.
- 3) At the Ramtek:
ENTER: LOGIN , LARRY _ SMART 1 ENTER: DIS ENTER: OB ENTER: SEGJDISPLAYS ENTER: 4 (to plot data vs. time)
ENTER: 1 (for CRT display) '
ENTER: 2 (to access 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> circular file data)
ENTER: 1 (always)
HIT: Return if data displayed looks OK when presented for review ENTER: Point number (NOTE: If a Validyne point is requested, V must prefix the point number, i.e., VT801 RCP 2-1 Tc VZ675 MN FW S/0 CTRL VLV 1)
, Data will now be displayed and updated on the terminal.
- 4) To obtain a video copy of the Ramtek display:
With the display finished updating, press the black button
.beside the terminal and the video copy will be automatically ta ken.
If it is desired to freeze the display during updating, the terminal can be frozen by hitting " control" "S" (simultaneously).
To resume updating:
HIT: " control" "Q" (simultaneously)
- 5) To exit prograe:
HIT: " Break" key E.VTER: . "Q" ENTER: LO
.s The printer / plotter is being programmed to have a fixed set of plots (see Enclosure 10 for list) be printed by manual command.
Presently, only Larry Konopka can use this feature. This will, in the future, be the primary method of data retrieval. Details of use will be added later.
- 2. DATA ANALYSIS Data analysis is the most difficult part of the post trip review process. Every analysis is different since every event is dif(erent.
Some points need to be checked for almost every event, and the following provides an indication of the extent of the review required.
The SOE ahd Alarm Printout must be reviewed to verify the safety systems operated as required. This means verifying not only why some channels tripped, but also verifying that all channels that should have tripped did trip. Enclosure 7 provides a liac of all SOE points and what causes the SOE to initiate. Enclosure 8 has a list of ,
specific points to be checked.
The plots must be reviewed to determine if the overall plant response was acceptable. After a trip, the main feedwater control valves are closed, the startup feedwater valves are targeted to approximately 20% open, and the main feed pump speed is increased to target (approxi-mately 4600 RPM) by the rapid feedwater reduction system. Steam generator levels should be maintained at 3S inches (and rapid feedwater reduction startup feedwater valve. target released). The main steam safety valves should rescat at approximately 960 PSIG and Tave should tend towards $51*F. Pressurizer level should reach a minimum of 10-20 inches if originally at full power (higher if originally at lower power).
RCS pressure should not fall below 1800 PSIG unless problems occur with main steam safety valves (MSSV)s resetting or makeup flow is inadequate. Cold leg temperature will most likely rise for the first 10-20 seconds frem the drastically increasing steam generator pressure, but will then tend toward 550*F. Since 100% FP is 48'F aT (Th - Tc),
the post trip ST is approximately 2-3*F for the first 20 minutes (dependent on decay heat load).
The drastic changes in steam generator pressure will cause momentary glitches in the steam generator level transmitters. These are to be expected since the level transmitters are just aP indicators.
High deaerator levels have been a problem post trip. It appears the Demerator Level Control Valve #2 fails to close and the equalizing valve caused both deaerator levels to increase. Monitor both deaerator levels and the time the condensate pumps are reduced to one operating.
All turbine bypass valves should normally open initially after the trip and then close during the MSSV blowdown. The atmospheric vents should open when steam generator pressure rises above 1025 PSIG (providing no Steam and Feedwater Rupture Control System (SFRCS) actuation).
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.g RCS pressure, pressuricer level, and RCS Tave should have nearly identical curve shapes until the makeup pumps have added significant volume (1-2 minutes). RCS pressure is the most sensitive indicator
' of RCS temperature; the RTDs and thermowells response time, as well as the loop transport time, adds a significant time delay (5-15
! seconds) in the sensing of actus1 Tave during a rapid coolant te,pera-ture change.
One additional caution is necessary on using the out-of-core power range NIs. These detectors are monitoring core neutron leakage, which is affected drastically by changes in cold leg temperature (approximately .5% FP per *F). If Tc increases 6'F, indicated core power will increase 3% without any actual change in core power.
The analysis performed depends largely on the transient. A closure of one main steam isolation valve (MSIV) requires a much more detailed review than a " screwdriver" trip. An imbalance trip requires a detailed core physics review, while an electro-hydraulic control (EHC) induced transient may require a significant review of the
- secondary plant. Common sense and an inquisitive attitude must be maintained throughout the review, Murphy's Law definitely applies to nuclear power; Don't assume anything worked like it should.
- 3. SUPPORT OF OUTSIDE ORGANIZATIONS The Technical Section provides support to the TAP Team and places information on NETWORK to provide information to outside organizations.
The B&W Resident Engineer (Jim Albert) has his own method of communica-tion with other B&W plants (ELEX) which can also be used as the
~
method of communication between B&W units.
Within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of the event, the Technical Section should make an I
entry on NETWORK to the other B&W units describing the event. If the event has significance beyond the B&W design (such as failure mechanism of MSSVs), an entry should also be made on NETWORK to all operating units.
~'
The Technical Section is responsible for telling the B&W Resident Engineer if a TAP Team site visit is desired. A TAP Team should be
, called in for most involved transients, but no site visit is necessary for a well understood transient. When requesting a site team, ask for personnel qualified in the area of the equipment involved in the i
transient; i.e., if ICS operation is in question, ask for an ICS
" expert".
The Technical Section representative acts as a liaison for the B&W TAP Team. The entrance interview should be well prepared with all information necessary to analyze the event provided to the team.
They should be provided with:
- 1) An oral review of the transient details known
- 2) All plots, alarms, SOE, post trip review, and operator logs W
9
- 3) Names, work extension, and schedule of personnel who were on shift during transient
- 4) A work area - typically a conference area in the DBAB
- 5) Escorts as required into the protected area After the draft report is prepared, we have Duplicating make 10-12
- copies. An exit interview is then set up with Steve Quennoz, Bernie Beyer I&C Engineer, Dale Miller, Louis Simon, other available operators, Shift Technical Advisors, Jim Albert, and the Technical Section representative. The draf t report is then reviewed and several days given to receive comments.
If the TAP Team was not called in, only the NETWORK entry need be completed. Section 4 describes the details of report preparation to be followed.
- 4. REPORT PREPARATION AND REVIEW A TAP report will be prepared for all unscheduled reactor trips at Davis-Besse. . Reports may also be prepared for other significant events. The purpose of the report is to provide transient event informatica for all members of the 177 FA Owners Group. The opera-tional experience shared in this program will lead to improved plant reliability and a better understanding of the plant's performance by all participants.
The format of the report should be as follows:
I. Executive Summary A. < Plant Name, Data, Time of Trip B. Brief Description C. Root Cause D. Performance Anomalies E. Lessons Learned II. Transient Assessment A. Sequence of Events B. Plant Performance
- 1. Pre-trip Review
- 2. Initiating Event
- 3. Plant Post-trip Response
. 4. Operator Actions / Procedural Adequacy C. Safety Considerations D. Assessment Conclusions E. Annotated Plots The " Executive Summary" section should be a single page containing the following information: plant name, date and time of trip, brief description of the event, including initial power level, root cause of the transient, any performance anomalies, and lessons learned.
. .w The " Sequence of Events" section should contain those major events or conditions which delineate the progressive course of the transient.
It normally contains a combination of the SOE, alarms, and Reactor Operator Log.
The " Pre-trip Review" section should contain a statement of the plant conditions prior to the transient. Examples to be included would be power level, ICS status, maintenance or testing in progress, and -
equipment deficiencies.
The " Initiating Event" section should describe the sequence of events and plant conditions leading up to transient initiation. Try not to be repetitive with other sections.
The " Plant Post-trip Response" section should include a discussion of the response of the NSS and B0P from a process point of view; i.e.,
Tave, reactor coolant pressure, pressurizer level, feedwater flow, OT5G level, and main steam pressure. These parameters should be plotted versus time and annotated to indicate major events, departures, '
etc., to support the text of this section. Also, this section should include a discussion of performance of components and their departures from the expected. Proposed corrective actions and corrective actions previously completed should be included in the text of this section.
Th,e " Operator Action / Procedural Adequaev" section should include information concerning specific operator actions taken during the transient which have not been included in any previous sections.
Additionally, procedures followed during the transient, and any information which would be beneficial to other operators should be included. This section is of major interest to other operators regarding the TAP report and should be as detailed as possible.
Operator interviews, operator logs, computer printout and plant procedures provide good source material. This section should provide an evaluation of the shif t operator's ability to use the procedures to mitigate a plant transient. Avoid repetition of earlier sections when possible.
The " Safety considerations" section should include the basis for which safety, as it relates to the transient, has been considered.
Those bases may include plant design requirements, Final Safety Analysis Report (FSAR) accident analysis, or other information.
The " Assessment Conclusions / Corrective Actions" section should be a summary of the significant aspects of the transient, including departures from expected component and plant performance, suggested /
actual corrective actions, and any preventative measures if not already discussed in the Plant Post-trip Response section. For component failures, list name, model and serial number, manufacturer name, date of installation, etc. Try to give this section a positive, "we're fixing it" cone instead of a "dink sheet".
b The " Annotated Plots" section should consist of a number of parameter versus time plots annotated with trip times and other important occurrences (pump starts / stops, emergency Safety Features Actuation System (SFAS) initiation, power operated relief valve (PORV) lif ts, main steam relief valve (MSRV) / MSSV lif ts, etc.) The Abnormal Transient Operator Guidelines (ATOG) P-T plot should be included in this section.
After the report has been reviewed in the exit meeting and modified by the Technical Section, it is sent out for review (see Laura for distribution). After the date that the comments were due (usually two weeks), the report comments are incorporated, and it is then sent to the Station Review Board (SRB). After SRB review and comment incorporation, the report will be sent to B&W with the cover letter signed by the Technical Section TAP representative. B&W will place the report in the booklets and distribute to all participating utilities.
The data is then stored in the trip files (along with the Attachment 3
- to PP 1102.03 from Operations). Revisions are not normally made to TAP reports, but can be completed if serious errors exist.
This completes the post trip review guidelines - these are only guidelines and are not cast in concrete. Enclosure 9 includes a checklist for post trip review which may be used to ensure no items are missed.
-V~
9 e
9 SEQUENCE OF EVENTS POINTS LIST Auxiliary Transformer 11 Trouble Bus A Electrical Fault Bus B Electrical Fault
- Bus A to Transformer AC Breaker Bus C2 Trouble Bus D2 Trouble Control Rod Drive (CRD) Trip Confirm CRD Channel AC Any Trip Device ,
CRD Channel BD Any Trip Device Electro Hydraulic Control Emergency Trip System Low Pressure Emergency Diesel Generator 1 Trouble Emergency Diesel Generator 2 Trouble Essential Bus C1 Trouble Essential Bus D1 Trouble Essential Transformer CE 1-1 Trouble (typical CE 1-1, DF 1-1, CE 1-2),
DF 1-2)
Generator and Main Transformer Overall Differential Trip Generator Overcurrent Trip Generator Reverse Current Power Trip Generator Field Failure Generator Out of Step Generator Underfrequency Generator Differential Generator Ground Current Enclosure 1 Page 1 of 3
'o Main Feed Pump Turbine (MFPT) 1 Trip (typical MFPTs 1 and 2)
Main Transformer Sudden Pressure Change Moisture Separator Reheater 1 High Level Turbine Trip Moisture Separator Reheater 2 High Level Turbine Trip ,
Reactor Protection System (RPS) Channel 1 Flux / Delta Flux / Flow Trip (typical Channels 1 through 4)
RPS Channel 1 High Flux / Number of Reactor Coolant Pumps (RCPs) Running Trip (typical Channels 1 through 4)
RPS Channel 1 Reactor Coolant (RC) Pressure / Temperature (typical Channels 1 through 4)
RPS Shutdown Bypass High Pressure Trip (typical Channels 1 through 4) ,
RPS Channel 1 Containment High Pressure Trip (typical Channels 1 through 4)
RPS Channel 1 RC High Pressure Trip (typical Channels 1 through 4)
RPS Channel 1 RC Low Pressure Trip (typical Channels 1 through 4)
RPS Channel 1 Channel Trip (typical Channels 1 through 4)
RPS Channel 1 High Flux Trip '(typical Channels 1 through 4)
RPS Channel 1 RC High Temperature Trip (typical Channels 1 through 4)
RPS Startup Rate Rod Withdrawal Inhibit RC Pressurizer Low Level Heater Interlock RCP 1-1 Motor Trouble (typical RCPs 1-1, 1-2, 2-1, and 2-2)
Safety Features Actuation System (SFAS) Channel 1 Borated Water Storage Tank (BWST) Level Low (typical Channels 1 through 4)
SFAS Channel 1 Containment Pressure > 38.4 psia (typical Channels 1
, through 4)
SEAS Channel 1 Containment Pressure > 18.4 psia (typical Channels 1 through 4)
SFAS Channel 1 RC Pressure < 1650 psig (typical Channels 1 through 4)
SFAS Channel 1 RC Pressure < 450 psig (typical channels 1 through 4)
Enclosure 1 Page 2 of 3 I
.. = ,
SFAS Channel 1 Containment Radiation High (typical Channels 1 through 4)
Steam and Feedwater Rupture Control System (SFRCS) Full Trip !
SFRCS Differential Pressure Half / Full Trip Steam Generator (SG) 1 '
(typical SGs 1 and 2) i Startup Transformer 01 Trouble -
, Startup Transformer 02 Trouble Switchyard Oscillograph Started 4
Switchyard Bus J Differential Switchyard Breaker 34563 Open/ Closed (typical five breakers) a Turbine Generator Mechanical Trip Solenoid Turbine Trip i -
Turbine Generator Master Turbine Trip i '
. Turbine Generator Mechanical . Trip Valve Trip i ;
l Turbine Generator Master Trip Solenoid Trip i
j Turbine Bypass Valve 1-1 Open/ Closed (typical six valves)
[
l l Unit Seismic Instrumentation Started '
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Enclosure 1 Page 3 of 3 l
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- 1: 2etal:e95 - 09o3 - SFRCS FULL TRIP 1=19
, 6: 23: 41: 905 2038 T-G Ma3fFH TURE THIP ik!P 8:2o: 41: 9u0 x030 T-G MASTER TRIP SWLENeluS tw!P i32e:st: 945- u t e! -- CR0 Cn b/0 ANY 1 RIP DEVICE -
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--t:2 :u2: 1 e5 - 10 3 3 - 1-G *ECH TWIP SdLENd1D Tuke Th!P T41w 8: 20:u2:185 2032 T-G MICH THIP VLV Thlp
- 2o:se: 420 P362 Enc E*EW TRIP SYS Lwa PWESS T419
- 8: 27:11:540 - Ju26 - GEN REVENSE par Th!>
- 27:11:5e5 1026 Savo ACb 3u561 e8Eu
- 27:11:5e5 x025 Savu ACs 34500 cars
-i:27:13:e30 - Ju26- - GEN-REVERSE PnN New-5: 27:32: 95 Yo60 TURu uYPass vLv t-1 hc 6: 27:32: 485 Y0eo Yupe eYeaSS VLv t-1 CLe5 1:27:50:m30 - Yu63 - TuWn uYkass vLv P-1 NC -
1: 27:$2: 5 Yoe3 TUR5 $YFa$$ VLV 2-1 CLw$
- 33: 1:415 09o3 SFRCS FULL IRtp t,a==
6: 33:182730 unal- WP5 Su kATE w vt b aTHuant l ev la !,7 Immr 1: 3u: 3:lo5 hout WPs su waTE Hoo NTH 04at th*Is!T Nac i:13:27:755 202e SaVU acu 3u5o1 C L v.5 3:13:32:620- zu25 - SavD ach 34560 LLes
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Enclosure 2 Page 1 of 1
. s ,
e, POST TRIP REVIEW POINT LIST Auxiliary Feed Pump Turbine 1 Speed (typ'ical Pumps 1 and 2)
Channel 1 Power Range Flux (typical Channels 1 through 4)
Channel 1 Power Range Delts Flux (typical Channels 1 through 4)
Condensate Pump Flow Control Rod Drive Group 5 Position (typical Groups 5 through 8)
Deaerator 1 Storage Tank Level (typical Demerators 1 and 2)
Generator Gross Megawatts High Pressure Condenser Pressure High Pressure Condenser Hotwell Level High Pressure Turbine First Stage Turbine End Pressure High Pressure Turbine First Stage Generator End Pressure
- High Pressure Turbine Side 1 Inlet Temperature High Pressure Turbine Side 2 Inlet Temperature Low Pressure Condenser Pressure Main Feedwater Average Flow Loop 1 (typical Loops 1 and 2)
Main Feedwater Temperature (typical Loops 1 and 2)
Main Feedwater Compensated Flow (typical Loops 1 and 2)
Main Teedwater Pump Turbine 1 Speed (typical Pumps 1 and 2)
Pressurizer Average Level Pressurizer Pressure Reactor Coolant Makeup Tank Level Reactor Coolant Makeup Flow Reactor Coolant Pump (RCP) Seal Injection Flow i
i Enclosure 3 Page 1 of 2 i
l '
- ' . . . e _ _ _ . _ ___
.~
a RCP 1-1 Discharge Cold Leg Narrow Range Temperature (typical RCPs 1-1 and 2-1)
Reactor Coolant System (RCS) Loop 1 Hot Leg Narrow Range Temperature (typical Loops.1 and 2)
RCS Average Temperature RCS Loop 1 Hot Les Narrow Range Pressure (typical Loops 1 and 2)
RCS Average Not Les Total Flow RCS Letdown Boron Concentration Safety Features Actuation System (SFAS) Channel 1 Containment Pressure SFAS Channel 1 Containment Radiation Core Power SFAS Channel 3 Borated Water Storage Tank Level Steam Generator (SG) 1 Full Range L.,evel (typical SGs 1 and 2)
SG 1 Startup Level (typical SGs 1 and 2)
SG 1 Operate Level (typical SGs 1 and 2)
^
SG 1 Outlet Temperature (typical SGs 1 and 2)
SG 1 Outlet Pressure (typical'SGs 1 and 2)
SG 1 Feedwater Pressure (typical SGs 1 and 2)
Enclosure 3 Page 2 of 2 i
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i Enclosure 4 Page 3 of 3 1
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10::c:ts ucaw emyt www ea 4 In w uT Dn3 ew 0 37 1, 10r:0:20 sm:. 74,1 ge n 7 was E9n en vg3 mits) -9,17 of Enclosure 5 Page 1 of 1
~
1
. l DATA ACQUISITION AND DISPLAY SYSTEM RECORDED POINTS Auxiliary Feedwater Flow to Steam Generator (SG) 1 (typical SGs 1 and 2)
Auxiliary Feed Pump 1 Discharge Pressure (typical Pumps 1 and 2)
Auxiliary Feed Pump Turbine 1 Speed (typical Pumps 1 and 2) -
Containment Hydrogen Concentration Containment Spray Fump 1 Discharge Flow (typical Pumps 1 and 2)
Containment Normal Sump Level Containment Wide Range Level Containment Wide Range Pressure Containment Atmosphere Particulate Radiation Containment Atmosphere Iodine Radiation Containment Atmosphere Noble Gas Radiation Containment Atmosphere Noble Gas Mid to High Range Radiation Containment Wide Range Radiation
~
Unic Vent Particulate Radiation Unit Vent Iodine 131 Radiation Unit Vent Xenon 133 Radiation Generator Gross Megawatts High Pressure I'njection 1-1 Flow (typical Lines 1-1, 1-2, 2-1, and 2-2)
Incore Outlet Temperature (typical 16 sensors)
Low Pressure Injection Pump 1_ Flow (typical Pumps 1 and 2)
Main Feedwater Temperature to Integrated Control System Main Feedwater Control Valve Position Loop 1 (typical Loops I and 2)
Main Feedwater Startup Control Valve Position Loop 1 (typical Loops 1 and 2)
Enclosure 6 Page 1 of 2
Main Feedwater Compensated Flow Loop 1 (typical Loops 1 and 2)
Reactor Coolant Makeup Tank Level Reactor Coolant System (RCS) Hot Leg Flow Loop 1 (Loops 1 and 2)
RCS Pressurizer Compensated Level RCS Pressurizer Quench Tank Level RCS Pressurizer Quench Tank Pressure RCS Hot Leg Wide Range Pressure Loop 1 (typical Loops 1 and 2)
. RCS Average Narrow Range Temperature RCS Calculated Hot Leg Subcooled Margin Channel A RCS Calculated Hot Leg Subcooled Margin Channel B '
RCS Hot Leg Wide Range Temperature Loop 1 (typical Loops I and 2)
-s RCS Pressurizer Temperature RCS Pressurizer Power Operated Relief Valve Position RCS Pressurizer Pressure Relief Valve Position (typical Valves 1 and 2)
Reactor Coolant Pump (RCP) 1-1 Discharge Cold Leg Wide Range Temperature (typical RCPs 1-1, 1-2, 2-1,' and 2-2)
Reactor Protection System (RPS) Auctioneered Average Power RPS Channel 1 Power Range Flux (typical Channels 1 through 4)
RPS Channel 1 Source Range Flux (typical Channels 1 and 2)
RPS Channel 3 intermediate Range Flux (typical Channels 3 and 4)
Safety Features Actuation System (SFAS) Channel 1 Borated Water Storage Tank Level Steam Generator (SG) 1 Outlet Steam Temperature (typical SGs 1 and 2)
SG 1 Operate Level (typical SGs 1 and 2)
SG 1 Startup Range Level (typical SGs 1 and 2)
SG 1 Outlet Pressure (typical SGs 1 and 2)
I l
i Enclosure 6 Page 2 of 2 S
?' ,
SOE PolNT INDEX
- I POINT INSTR. SET AI.AHit NO. NO. DESCRIPTOR PolNT CONDITION (S)
ASSO QS-RCl-1 RPS CH 1 Flux-DFlux-Flow BSTEL -32.25% 1 0.25% HPS Cil I $/A$/ Flow Trip A851 QS-NI6 RPS CH I HI Flux /No RCP DN BSTBL ' l. One pump operating in RPS Cil 1 Power / Pumps Trip 1sistatsles each loop 5 $4.25 1 .25% trips of RTP
- 2. Two pumps operating in one loop and no pump operating in other loop, no pumps operating, or only one pump operating 5 0.0% of RTP A852 QS-RC2B2 RPS CH I RC Press-Temp BSTBL 12.6 T/ifot -5644 PSIG HPS CH I RC Press-Temp Trip 1 4.0 PSI A856 QS-RCI-2 RPS CH 2 Flux-DFlux-Flow BSTBL -13.57% 1 0.12% RPS Cil 2 $/A$/ Flow Trip A857 QS-NIS RPS CH 2 HI-Flux /No RCP DN HSTHL 1. One pump operating in HPS Cil 2 Power / Pumps Trip flistatales each loop i 54.25 1 .25% trips of RTP
- 2. Two' pumps operating in one loop and no pump operating in other loop, no pumps operating, or only'one pump operating e 5 0.0% of RTP A858 QS-RC2A2 RPS CH 2 RC Press-Temp BSTBL 12.6 T/Ilot -5644 PSIC 1 HPS Cil 2 RC Press-Temp. Trip 4.0 PSI A862 QS-RCI-3 RPS CH 3 Flux-DFlux-Flow BSTBL 7.86% 1 0.14% HPS Cil3 $/at/ Flow Trip Euclosure 7 Page I of 17
POINT INSTR. .
SET ALAkti
- NO. NO. DESCRIPTOR POINT CONDITION (S)
A863 QS-NI8 RPS CH 3 HI Flux /No RCP ON BSTBL 1. One pump operating in RPS CH 3 Power / Pumps Trip Bistables each loop 1 54.25 1 .25% trips of RTP
- 2. Two pumps operating in one loop and no pump operating in other loop, no pumps operating, or only one pump operating
$ 0.0% of RTP
-A865 QS-RC2B1 RPS CH 3 RC Press-Temp BSTBL 12.6 T/ Hot - 5644 PSIG 1 RPS CH 3 RC Press-Temp Trip 4.0 PSI A869 QS-NCl-4 RPS CH 4 Flux-DFlux-Flow BSTBL 32.25% 1 0.25% RPS CH 4 (/a(/ Flow Trip A870 QS-NI7 RPS CH 4 HI Flux /No RCP ON BSTBL 1. One pump operating in RPS CH 4 Power / Pumps Trip Bistables each loop 1 54.25 i .25% trips of RTP -
- 2. Two pumps operating in one loop and no pump operating in other loop, no pumps operating, or only one pump operating 5 0.0% of RTP A872 QS-RCA1 RPS CH 4 RC Press-Temp BSTBL 12.6 T/ Hot -5644 PSIC i RPS CH 4 RC Press-Temp Trip 4.0 PSI 1061 IS-6500 Bus A Elec Fault N/A Over current condition on the 13.8 KV Bus A or a ground f ault
. on the 13.8 KV Bus A 1069 IS-65001 Bus B Elec Fault N/A Over current on the 13.8 KV Bus B or a ground fault on the 13.8 KV Bus B
~
Enclosure 7 Page 2 of 17
-- . .- . . - . ._ ~. _ . - _ _ - - - - -. - _ _ . -- - . . . _ - _ - - . - . . -
d' .
POINT INSTR. SET NO.
Al.Akit f, NO. DESCRIPTOR POINT CONDITION (S)
I421 IDS-6400 CEN DIFF 1500 primary amperes (main An unhalance of current flowing into transformer high side and out of the generator windings.
amperes) Trips turbine and main generator breakers 34560 and 34561.
1425 IS-64006 CEN Ground Current Relay alarms.for generator The alarm is caused by the flow of
- , neut ral current of 0.853
! ground fault current in the generatur i
primary ampers or snore up neutral when it re.sches a pre:.et to a maximum of 7.4 primary limit due to a ground fault in the ampers for a solid ground stator or on the generator 25,000 voit on the generator 25,000 voit leads.
terminals 1426 IDS-6405 CEN & ltN XFHR Overall Diff Trip 346 primary ampers (main A quantitative difference of currents ,
transformer high side flowing in the generator stator i amperes) windings, the two 345 KV air circuit breakers, main transformer and #11 !
2 Auxiliary Transformer. Trips turbine and main generator breakers 34560 and '
i 34561.
l 1427 KS-6400B GEN Negative Phase Seq Negative Phase Sequence When poly phase currents are unbalanced 1
Relay: Alarms for a nega- or contain negative phase sequence 1
tive phase sequence pickup components above a given amount,
' current of 1575 primary Trips generator main breakers 34560 amperes (main transformer and 34561 for generator negative
, high side amperes) , phase sequence protection.
1 I428 IS-6400A GEN Overcurrent 1. With voltage restraint: The current in the turbine genera- i
- 50,000 primary amperes tor circuit has reached a predeter-
- (main transformer high mined value for system fault backup s
side ampers) protection. Trips generator main
- 2. Zero voltage restraint: breakers 34560 and 34561 for genera-12,500 primary ampers tor overcurrent protection.
(main transformer high side ampers) '
i 1
1 .
Enclosure 7 Page 3 of 17 i 1
1
e .
-POINT INSTR. SET ALARN NO. NO. DESCRIPTOR POINT CONDITION (,S) I 1844 IS-6108 SWVD Bus J Diff N/A Bus J Elect Fault J428 JS-6400A GEN Reverse Pwr At 25,200 KW in, relay times Hotoring occurs as a result of a out for 25 seconds and then deficiency in the prime mover input initiates trip to the a-c generator. When this input _
cannot supply all the losses, then the s deficiency is supplied by absorbing i real power from the system. Trips turbine and main generator breakers 34560 and 34561.
L680 LSH-140 MSR 1 HI.Lvl Trub Trip Lvl increases to 3"-5" from Increasing level in HSR drain line bottom of tank L690 LSM-164 MSR 2 HI Lvl Turb Trip Lvl increases to 3"-5" from lacreasing level in HSR drain line bottoes of tank L770 LSLL-RCl4 RC PRZR Lo Lvl Htr 40 inches ,
- Low pressurizer level L862 QS-7640 SFAS Sump Recire Logic L511 8 feet water This alarm is generated when any two of the four SFAS BWST low level histables trip. The alarm is pro-vided to tell when SFAS level 5 allows the transfer to the emergency sump to occur.
L864 QS-7641 SFAS Sump Recirc Logic L512 8 feet water This alarm is generated when any two of the four SFAS WST low level bistables trip. The alarm is provided to tell
. when SFAS level 5 allows the transfer to the camergency sump to occur.
Enclosure 7 Page 4 of 17
- POINT INSTR. , SET ' ALARN .
NO. No. IESCRIPTOR POINT CONDITION (S)
L866 QS-7642 SFAS Sump Recire Logic L513 8 feet water This alarm is generated when any two of the four SFAS BWST low level histables trip. The alarm is' pro-vided to tell when SFAS level 5 allows the transfer to the emergency sump to occur.
L868 QS-7642 SFAS Sump Recirc Logic,L514 ~ 8 feet water This alarm is generated when any two of the four SFAS BWST low level histables trip. The alarm is pro-vided to tell when SFAS level 5 allows the transfer to the emergency sump to occur.
P683 PSH-6405 MN XFMR 1 Sudden Press N/A' The alarm is caused by a sudden change J
in XFHN Tank pressure, possibly accom-panied by an are in the XFHR. The s turbisse generator and reactor may trip.
P701 QS-2686 SFRCS DP Half / Full Trip, SG 1 177 PSIG High steam to feedwater I)P P702 QS-2685 SFRCS DP Half / Full Trip, SG 2 177 PSIG High steam to feedwater DP P857 PS-nil 5-2 RPS CH 1 CTNT HI Press 3.175 PSIC i 0.2 PSIG RPS CH I CTNT Press HI Trip P858 PSh-RC2B2 RPS CH 1 RC HI Press 2285.0 PSIG 1 4.0 PSIG RPS CH I RC Press ill Trip i
P859 PSL-RC2B2 RPS CH I RC LO Press BSTBL 1998.4 PSIG 1 4.0 PSIG RPS CH I RC Press I.ow Trip P862 PS-nil 5-1 RPS CH 2 CTNT HI Press 3.175 PSIG i 0.2 PSIG RPS Cil 2 CTNT Press XI Trip P863 PSL-RC2A2 RPS CH 2 RC LO Press BST8L 1998.4 PSIG 1 4.0 PSIC RPS CH 2 RC Press Low Trip i P864 PSH-RC2A2 RPS Cil 2 RC HI Press 2285.0 PSIG 1 4 0 PSIC RPS CH 2 RC Press Hi Trip l
4 i
Enclosure 7
. l Page 5 of 17 l I
6
t.
PolNT INSTR- SET NO. Al.ARH .~
NO. DESCRIPTOR '
POINT CONDITION (S)
P867 PS-mil 5-4 RPS CH 3 CTNT MI Press 3.175 PSIG i 0.2 PSIG RPS CH 3 CTNT Press Ili Trip '
] .P868 PSH-RC2B1 RPS CH-3 RC NI Press '2285.0 PSIG 1 4.0 PSIG RPS CH 3 RC Press ill Trip P869 PSL-RC2Bt RPS CX 3 RC LO Press BSTBL .1998.4.PSIG 1 4.0 PSIG RPS CH 3 RC Press Low Trip i
~P872 PS-nil 5-3 RPS CH 4 CTNT.NI Press 3.175 PSIC i 0.2 PSIG RPS CH 4 CTNT Press 111 Trip P873 PSH-RC2Al RPS CH 4 RC 181 Press '
2285.0 PSIC i 4.0 PSIG RPS CH 4 NC Press XI Trip
- P895 PSHit-2000A SFAS CH 1 CTNT Press > 38.4 PSIA 23,6 PSIG 1 0.4 PSIG SFAS CH I CTNT Press lil Hi Trip P896 PSH-2000A SFAS CH 1 CTtR Press > 18.4 PSIA 3.5'PSIG 1.0.5 PSIC SFAS Cil I CTNT Press til Trip P898 PSNH-2001A SFAS CH 2 CTNT Press > 38.4 PSIA 23.6 PSIG 1 0.4 PSIC SFAS Cil 2 CTHT Press HI Ill Trip P899 PSH-2001A SFAS CH 2 CTtR Press > 18.4 PSIA 3.5 PSIC.1 0.5 PSIG SFAS Cil 2 CTifT Press ill Trip P901 PSMH-2002A SFAS CH 3 CTNT Press > 38.4 PSIA 23.6 PSIG i 0.4 PSIG
. SFAS CH 3 CTtIT Press. til 111 Trip P902 PSH-2002A SFAS CH 3 CTNT Press > 18.4 PSIA 3.5 PSIG 1 0.5 PSIG SFAS Cil 3 CTHT Press ll! Trip P904 PSHH-2003A SFAS CH 4 CTNT Press > 38.4 PSIA 23.6 PSIG 1 0.4 PSIG SFAS Cil 4 CTHT Press ill 111 Trip P905 PSH-2003A SFAS CH 4 CTNT Press > 18.4 PSIA 3.5 PSIG 1 0.5 PSIG
,. SFAS Cil 4 CTNT Press til Trip P911 PSL-RC284 SFAS CH I RC < 1650# 1650.0 PSIG 1 25 PSIG SFAS Cil I RC Press Low Trip -
P912 PSLL-RC2B4 SFAS CH I RC < 400# 450 PSIG 1 25 PSIG SFAS CH I RC Press Low Trip P914 PSL-RC2A4 SFAS CH 2 RC < 1650# 1650.0 PSIG 1 25 PSIG SFAS Cal 2 RC Press Low Trip P915 PSLL-RC2A4 SFAS CH 2 RC < 400# 450 PSIC i 25 PSIG SFAS CH 2 NC Press Low Trip l
Enclosure 7 !
Page 6 of 17 i
2
e-POINT INSTR. SET ALAkti
- MO. MO. DESCRIPTOR PolNT CONDITION (S)
P917 PSL-RC253 SFAS CM 3 RC < 1650# 1650 PSIG 1 25 PSIC SFAS CH 3 RC Press Low Trip P918 - PSLL-RC2B3 SFAS CH 3 RC.< 400# 450 PSIG 1 25 PSIC SFAS Cil 3 RC Press Low Trip P920 PSL-RC2A3 SFAS CH 4 RC < 1650# 1650 PSIG 1 25 PSIG SFAS CH 4 RC Press Low Trip P921 PSLL-RC2A3 SFAS CH 4 RC < 400# , 450 PSIC i 25 PSIC SFAS CH 4 RC Press Low Trip Q015 QS-6411 Aux XFHR 11 TRBL N/A 1. A sudden pressure in the XFilR due to a fault
- 2. A ground fault on the XFHR secondary, or in backup pro-tection breakers HX11A and NXIIB
- 3. A phase overcurrent on the XFHR primary, or in backup protection breakers HXilB and ilXIIB
.. 4. A differential relay operation caused by a fault in the trans-former or its connections to the 13.8 KV buses QO37 IS-6503 Bus A to XFHR AC BRKH N/A 1. A bus lockout on Bus A.
- 2. A primary or secondary graund fault on XFHR AC.
- 3. A differential or overcurrent on XFHR AC.
Q041 IS-6504 Bus B to XFHR BD BRKR N/A 1. A bus lockout on Bus B.
- 2. A primary or secondary ground
- faulL on XFRH BD.
- 3. A differential or overcurrent on XFHR BD.
Q050 IS-6521 Bus C2 TRBL N/A Bus overcurrent sensed by the partial differential overcurrent or ground relay scheme Enclosure 7 Page 7 of 17 POINT lilSTR. SET 11 0 . No. Al Akti ,
DESCRIPTOR POINT CONDIT10N(S)
Q058 IS-6522 Bus D2 TRBL N/A Bus overcurrent sensed by the partial differential overcurrent or ground relay scheme Q180 CRD-SW9 CRD CN A/C Any Trip Device N/A 1. Breakers A or C Trip
- 2. Electronic Trip C
- 3. WE Current Sensor A
- 2. Electronic Trip D
- 3. WYE Current Sensor B
- 4. Neturn SCR Trip D Q266 CRD-SW4 CRD Trip Confirm N/A Any reactor trip Q396 QS-6221A EfER DG 1 Locked Out or TRBL N/A -
- 2. Lockout Relay 86-2 operation (will trip AC 101 breaker aval shutdown the engine)
- 3. Emergency Diesel Generator Voltage Regulator Switch in the OFF position Q401 QS-6231A EFER DG 2 Locked Out or TRBL N/A 1. Lockout Nelay 86-1 operation (will trip AD 101 breaker and short the field for No. 1-2 DG)
- 2. Lockout Relay 86-2 operation 3
(will trip AD 101 breaker and shutdown the engine)
- 3. Emergency Diesel Generator Voltage Regulator Switch in the off position.
Enclosure 7 Page 8 of 17 I
t
.m. . __ _ _ _ _ ._ ....m._ _ _ _ _ ._
FolllT IllSTR. SET Al.AkN ' -
10 0 . 11 0 IIESCRIPTOR POINT _ m ulTION(S)
Q414 IS-6519 ESSEN Bus Cl TRSL N/A I. Phase overcurrent on bus Cl
- 2. Ground overcurrent on Bus Cl Q417 IS-6520 ESSEN Bus D1 TRRL N/A 1. Phase overcurrent on Bus DI
- 2. Ground overcurrent on Bus DI
-Q430 IS-6529 ESSEN XHNt CEl-1 TRBL s N/A Automatic tripping of 4.16 KV feeder Breaker ACICEll for the following:
- 1. Transformer Cround (5IN/ ICE)
- 2. Bus Overcurrent (94-1)
- 3. Feeder Overcurrent (50-51)
- 4. Feeder Ground (SOCS)
Q432 IS-6530 ESSEN XRNt DF1-1 TRRL N/A ' Automatic tripping of 4.16 KV Feeder breaker AI)lDFil for essential Unit Substation F1
.. and 480V breaker BDF11 for the following:
- 1. Transformer Ground (SIN /II)F)
- 2. Bus Overcurrent (94-1)
- 3. Feeder Overcurrent (50-51)
- 4. Feeder Ground (50GS)
Q435 IS-6532 F9tFM XFMR CEl-2 TkBL N/A Automatic tripping of 4.16 KV Feeder breaker ACICE12 for essential Unit Substation FI and 480V breaker BCE12 for the following:
- 1. Transformer Cround (SIN /2CE)
- 2. Bus Overcurrent (94-1)
- 3. Feeder Overcurrent (50-51)
- 4. Feeder Ground (SOCS)
. Enclosure 7 Page 9 of 17
e-Follfr IllSTR. .
SET
- 11 0 . 11 0 . DESCRIPTOR ALAkN J' POINT COIIDITION(S)
Q437 IS-6532 ESSEN XFISt DFI-2 TNBL N/A Automatic tripping of 4.16 KV Feeder Breaker ADIDF12 for essential Unit Substation F1 ansi 480V breaker 50F12 for the following:
I. Transformer Ground (SIN /2DF)
- 2. Bus Overcurrent (94-1)
- 3. Feeder Overcurrent (50-51)
- 4. Feeder Ground (50GS)
Q444 ES-64004 GEN Field Failure A typical alare point is h.ossofexcitationbyanabnor-632,310 KVA power flow mally low value or failure of into the generator generator field current, which causes reactive power flow from
, the system into the machine.
Trips turbine and main generator breakers 34560 and 34561.
Q451 KS-6400A GEN Out-of-Step - Gen. Out of step relay: A phase angle measuring device that Alarms at a pickup of 0.162 functions between two voltages, two primary ohns and 30,000 currents or between voltage anel primary amperes (main current. Trips generator main transformer high side breakers 34560 and 34561 for gener .
ampers). ator loss of synchronism.
Q613 QS-2731 19'PT I 1. 5925 RPM 1. MFPT 1-1 Over Speed frip
- 2. 40 PSIG 2. NFPT l-1 Thrust Brg Wear Trip
- 5. 12.5" NgA 5. MFPT l-1 Exhaust Hi Press Trip
- 6. N/A 6. MFPT 1-1 Manual Trip
, 7. 1500 PSIG 7. MFPT 1-1 Disch HI Press Trip Enclosure 7 Page 10 of 17 34
i l
POINT INSTR.
NO. NO.
SET AIAkti '
DESCRIPTOR PolNT CONI)! TION (S)
Q634 QS-2732 MFPT 2 1. 5925 RPt1 1. MFPT l-2 Over Speed Trip
- 2. 40 PSIG 2. MFFT l-2 Thrust Brg Wear Trip
- 5. 12.5" liga 5. flFPT l-2 Exhaust til Press Trip
- 6. N/A 6. MFPT l-2 H.snual Trip
- 7. 1500 PSIG 7. MFPT l-2 Isisch til Press Trip Q783 QS-6515A RCP l-1 MTR TRBL N/A 1. Motor Overcurrent
- a. Phase, Time and Instantaneous
- b. Phase, Extremely Inverse Time
- 2. Instantaneous Ground Fault
- 3. Phase Imbalance
- a. Phase, Time at:d Instaataneous
- b. Phase, Extressely Inverse Time
- 2. Instantaneous Ground Fault
- 3. Phase Imbalance
N/A 1. Motor Overcurrents
- a. Phase, Time and Instantaneous
- b. Phase, Extremely Inverse Time
- 2. Instantaneous Ground Fault
- 3. Phase Imbalance
- 4. Bus Protection I.ockout Enclosure 7 Page 11 of 17 a
PolNT INSTR. SET ALAkti .'
WO. NO. DESCRIPTOR POINT CONI)! TION (S)
Q801 QS-6518A RCP 2-2 HTR TRBL N/A 1. Hotor Overcurrents
- a. Phase, Time and Instantaneous
- b. Phase, Extremely Inverse Time
- 2. Instantaneous Ground Fault
- 3. Phase imbalance
- 4. Bus Protection 1.ockout Q810 RPS-TR-B RPS CH 1 CH Trip ~ N/A Wen the channel trip relay in the RPS Channel 1 Reactor Trip flodule is deenergized Q818 RPS-TR-A RPS CH 2 CH Trip N/A W en the channel trip relay in the RPS Channel 2 Reactor Trip Hodule is deenergized Q822 RPS-SHBHP RPS Shutdown Bypass High Press 1820 PSIC (+0, -1.6 PSIC) Wen a channel is in shutdown bypass and the RPS Shutdown Bypass liigh Pressure Bistable trips Q826 RPS-TR-D RPS CH 3 CH Trip N/A Wen the channel trip relay in the
. RPS Cil 3 Reactor Trip tiodule is deecergized Q834 RPS-TR-C RPS CH 4 Cll Trip N/A Wen the channel trip relay in the CH 4 Reactor Trip flodule is deener-gized Q841 RPS-SRI RPS Stl Rate Rod VrilDRWL INillBIT 1. > 2 DPH in the Source Range W en the control rods are inhibited (NI 1, 2) with reactor from beir.g withdrawn by the Nuclear power less than lxto-* amps Instrumentation on the Intermediate Range (NI 3,4).
- 2. > 3 DPH on the Intermediate Range (NI 3, 4) with reactor power less than 10*4 on the
. Power Range (NI 5, 6, 7, 8).
Enclosure 7 Page 12 of 17
~
PolNT INSTR. SET
- AIANN .
MO. MO. DESCRIPTOR '
PolNT CONHITION(S)
Q963 QS-SFRCS SFRCS Full Trip 1. High or low current indi- I. Loss of 4 Reactor Coolant Pumps.
cation on all 4 NCP's.
- 2. Less than 612 PSIC. 2. Low steam header pressure.
- 3. Greater than 177 PSIC. 3. High steam to feedwater I)P due to loss of fee.lwater.
- 4. Less than.26.5" '
- 4. Low steam generator level.
Q981 QS-6401 SU XHet 01 TRBL s
- 1. Sudden Pressure 8 PSIG I. A sudden pressure in the XFHR
- 2. Phase overcurrent 144.3 A due to a fault (AP310I.07)
(86.2 NVA) 2. A ground fault on the XFilR
- secondary or hackup protection for breakers HX01A and ilX01B
- 3. A phase overcurrent on the XFHR primary or backup protection for breakers llX01A and ilXolB
- 4. A differential relay operation caused by a fau!L in the trans-former or its connections to the 13.8 KV Busses Q984 QS-6402 SU XFMR 02 TRBL 1. Sudden Pressure 8 PSIG l. A sudden pressure in the XFilH
' 2. Phase overcurrent 144.3 A due to a fault (AP3101.07)
(86.2 HVA) ~
- 2. A ground fault- on the XFr!R secondary or backup protection for breakers llX02A and IIX028
- 3. A phase overcurrent on the XFilH primary or Isackup protection
- for breakers HXO2A and I!X028
- 4. A differential relay operation caused by a fault in the trans-
- former or its connections to
- the 13.8 KV Busses Enclosure 7 Page 13 of 17
POINT IIISTR.
SET AI.ARH .
11 0 . NO. DESCRIPTUR
- POINT CONDITION (S) i R793 MSif-MIS RPS CN 1 N!. Flux I. 104.75 + 0 .5% of Rated ideen any one of the four NPS Over-Thermal Power with four power Trip Bistables Trip pumps operating
- 2. 79 + 0 .5% of Rated Thermal Power with three pumps operating R802 NSil-NI5 RPS CN 2 NI Flux 104.75 + 0
. ' l. .5% of Nated 14 en any one of the four NPS Over- ;
Thermal Power with four power Trip Bistables Trip pumps operating 4
- 2. 79 + 0 .5% of Rated Thermal Power with three f pumps operating
+
i R811 NSN-MIS RPS CN 3 M1 Flux 1. 104.75 + 0 .5% of Rated- Mien any one of the four NPS over-Thermal Power with four power Trip Bistables Trip pumps operating !
j
- 2. 79 + 0 .5% of Nated Thermal Power with three pumps operating
{ R$17 NSN-MI7 RPS CN 4 NI Flux i
1.104.75 t 0 .5% of Rated Wien any one of the four RPS over-i Thermal Power with four power Trip Bistables Trip pumps operating !
k 2. 79 + 0 .5% of Rated i
]
Thermal Power with three pumps operating ;
! R832 RSMN-2004 SFAS CH 1 CTtff RAD lil 1. Modes I, 2, 3, 4: SFAS Cil I CTHT RAD 111 Trip jl 15 HR/HR or 1.8 x BKGND 1 10% BKGNO -
1 '
l 2. Mode 6: 2 HR/NR '
l R834 RSilN-2005 SFAS CN 2 CTHT RAD 111 1. Hodes I, 2, 3, 4: SFAS CH 2 CTNT RAD ll! Trip
]
1 25 HN/liR or 1.8 x BKGNI) !
1 10% BKGNO
- 2. Mode 6: 2 HR/HR j 4
1 Enclosure 7 l l'
P.sge 14 of 17 l
l I i !
i I
- . _ ---~ , , - - - - -- - -. .- _ _ _ , , , . . _ . ._ _
POINT lllSTR. SET
- AIAkN '
11 0 . 11 0 . DESCRIPTOR
- PolNT COIIDIT,10N(S)
?
RS36 RSitN-2006 SFAS CN 3 CTNT kAD NI 1. Modes I. 2, 3, 4: SFAS CN 3 CTNT RAD NI Trip 25 Net /lin or 1.8 s SKGND ' .
i 10% BEGIID
- 2. Mode 6: 2 MR/NR RS38 RSilli-2007 SFAS CN 4 CTNT RAD MI 1. Modes 1, 2, 3, 4: SFAS CN 4 CTtfr RAD NI Trip s 15 Mit/NR or 1.8 x BEG 86D i
1 101 BKGIID
- 2. Mcde 6: 2 MR/IIR S426 .SSL-6400 GEN Under Frequency Under frequency relay 81U1 & When the system load exceeds system 81U2 are set for 58.2 Na and generation. Trips generator main 0.5 seconds. Both contacts breakers 34560 and 34561 for gener-are in series so that both ator under frequency protection.
under f requency relays must operate to trip.
T856 TSit-RC3R2 RPS CN 1 RC NI Temp 616.8 *F i 0.2 *F -
RPS CN I RC Temp NI Trip 7857 TSN-RC3A4 RPS CN 2 RC NI Temp 616.8 *F i 0.2 *F RPS CN 2 kC Temp NI Trip 7858 TSN-RC354 RPS CN 3 BC NI Temp 616.8 *F i 0.2 *F RPS CN 3 RC Temp NI Trip T859 TSN-RC3A2 RPS CN 4 RC NI Temp 616.8 'F 1 0.2 *F RPS CN 4 RC Temp NI Trip X014 QS-6044 SWYD ACB 34563 N/A SWYD ACB 34563 Trip X015 QS-6045 SWYD ACB 34564 N/A SWYD ACB 34564 Trip 1024 QS-6117R SWYD Oscillograph Started N/A Electrical fault on 345 KV lines
- (may also be caused by operating 345 KV breakers).
X025 QS-6041 SWVD ACR 34561 N/A ACB 34560 Trip X026 QS-6042 SWYD ACB 34561 N/A ACB 34561 Trip X027 QS-6043 SWYD ACB 34562 N/A SWYD ACB Trip ,
Enclosure 7 Page 15 of 17
~
I 1 **
POINT INSTR.
- 30. HO.
DESCRIPTOR SET Alagog .-
PolNT CONDIT1011(S)
XS30 QS-2230 T-G Ilester Trip Solenoids ' N/A h a one or both master trip solenoids are deenergized E032 QS-2213 T-G Neck Trip VLV Overspeed trip of 1101 1. Excessive turbine generator (1980 RPN) speed
- 2. h awat mechanical trip actuated i
(fromat standard)
- 3. Mechanical trip solenoid cuer-gized by one of the following:
- a. Control Room ENC t rip buttou
! b. Haster trip solenoid valve tripped I
XO33 2S-2211 T-G Neck Trip Solenoid Trub Trip N/A' '. Energizing the mechanical trip Solenoid X038 QS-2293A T-G Naster Turb Trip Turbine master trip buss Turbine tripped energized YO60 ZS-SP1381 Turb Bypass VLV l-1 N/A idben the valve changes position Clos /NC YO61 ZS-SP1382 Turb Bypass VLV l-2 N/A W e the valve changes position Clos /NC Yo62 ZS-SP1383 Turb typass VLV l-3 N/A h a the valve changes position Clos /NC YO63 2S-SP13Al Turb Bypass VLV 2-1 N/A h a the valve changes position
. Clos /NC YO64 ZS-SP13A2 Terb typass VLV 2-2 N/A ha the valve changes sw>sition Clos /NC
~
Euclosure 7 Page 16 of 17 40 b
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SOE/ ALARM ANALYSIS If Reactor Protection System (RpSi Trip:
(1) Each channel has SOE points on both the trip parameter and the verification of a channel trip. Check both.
(2) Verify on SOE, when second channel tripped, the following was received indicating trip occurred:
Q180 "CRD CH A/C ANY TRIP DEVICE" " TRIP" Q181 "CRD CH B/D ANY TRIP DEVICE" " TRIP" Q266 "CRD TRIP CONFIRM" " TRIP" (3) Verify the trip parameter makes sense; for example, you should not get a pressure temperature trip when T hot is less than 606*F. *
(4) On SOE after the trip depressurizes the primary, all four RPS channels should receive low pressure trips. This is the time to confirm which RPS channels had not tripped (the channel trip only comes in once on SOE).
(5) on alarms, verify:
Q185 "CRD MTR PWR" "0FF" Q186 "CRD PROGRAMMER LAMP FAULT" "YES" Check Turbine Generstor:
(1) On SOE verify:
X030 "T/G MASTER TRIP SOLENOIDS" " TRIP" l J428 " GEN REVERSE POWER" " TRIP" I after X025 "SWYD ACB 34560" "0 PEN" ] 30
. X026 "SWYD ACB 34561" "0 PEN" ] seconds (2) On slara printout verify 2498 - Z501 "NPT GOV VLV 1-4" " CLOSED" Z506, Z508 "HPT $T98 VLV 1-4" " CLOSED" 2510,2512,)
Z591, 2576,] "LPT 1, 2 RET STOP VLVS 1-4" " CLOSED" 2578, 2593 ]
' "LPT 1, 2 RIV 1-4" " CLOSED" X070 "TURE EXT AIR DUMP RELAY VLV" " TRIP" Q379 " ENC ELECTRICAL" "TRBL"
. Enclosure 8 Page 1 of 4
MD Primarv
. (1) On alarms, check time of second makeup pump on Q754 ol Q759 "RC MU PMP 1 (2)" "0N" (2) On alarms, check high makeup F741 "RC MU FLOW" "HIGH" (3) On SOE, check pressurizer heater cutoff if < 40" L770 "RC PRZR LO LVL HTR" " TRIP" Then return to normal Miscellaneous (1) On alarms, check atmospheric vent positions 1961 and 1969 "SG 1, 2 ATM STM VENT VLV" "0 PEN" when > 1025 PSIG (2) On SOE or alarms, check TBV positions YO60, YO65 "TUR8 BYPASS VALVE 1, 2 3" "NC" when > 1015 s PSIG (3) On alarms, check for deserator hi level trips L359, L360 " DEAR STRG TX 1, 2 HI LVL" " TRIP" (4) On alarms, check condensate pumps reduction Q164, Q171, Q174 "CNDS PMP 1, 2, 3" "0FF" STRCS Presently, only three SFRCS inputs are connected to the SOE monitor; these are:
Point 40 STRCS Full Trip Point 62 SFRCS DP Half / Full Trip SG 1
, Point 63 STRCS DP Half / Full Trip SG 2 The only way to tell the input parameter on which SFRCS tripped is to review the alare printout. Note: When it references Channel 1 or 2, it is Actuation Channel 1 or 2, not M Channel 1, 2, 3, or 4.
Q847 SFRCS SG 1 ! sol
' Q844 STRCS SG 2 Isol Q963 SFRCS Full Trip Q692 SFRCS Na Sta Low Press Trip, Ch 2 Q693 STRCS Na Sta Low Press Trip, Ch I L446 SFRCS SG Lvl Half / Full Trip, Ch 1 L496 STRCS SG Lvl Half /Tull Trip, Ch 2 P671 STRCS DP Malf/ Full Trip, Ch 1 P640 STRCS Na Sta Lise Low Press, Ch 2 P641 STRCS Na Sta Line Low Press, Ch 1
, Enclosure 8 Page 2 of 4
, .. ' \
Q847 STRCS SG 1 Isol
-Q848 STRCS SG 2 Isol Q963 SFFCS Full Trip Q692 SF*tCS Mn Sem Low Press Trip, Ch 2
- Q693 SFRCS Mn Stm Low Press Trip, Ch 1 L886 STRCS SG Lvl Half / Full Trip, Ch 1 L896 SFRCS SG Lvl Half / Full Trip, Ch 2 P671 SFRCS DP Half / Full Trip, Ch 1 P680 SFRCS Mn Sem Line Low Press, Ch 2 P681 :iFRCS 'in Sta Line Low Press, Ch 1
,, P684 SFRCS Mn Sta Low Press B1k, Ch 2
. P685 SYRCS Mn Stm Line Low Press B1k, Ch 1 P691 SFRCS DP Half / Full Trip, Ch 1 P692 SFRCS DP Half / Full Trip, Ch 2 The SFRCS alarms have several flaws: (1) They only tell the status of actuation channels, not individual logic channels. As happens all too of ten, a power supply is lost to one logic channel, initiating all the alarms for that actuation channel which prevents proper ,
analysis of the trip. (2) Not enough indication is provided of a full trip. Only Q693 is provided to verify a full trip, and it does not tell which channel. ,
The stroking of the SFRCS valves should be verified within the proper time interval. The following is a list of the STRCS valves, the computer points, and the stroke times.
CPT RESPONSE TIME f..
- ICS118 ***' ' Z961 10 seconds
- ICS11A 2969 10 seconds J MS101-1 2685 to seconds t MS100-1 2o48 10 seconds MS394
"' 2684 10 seconds
- MS375 Z6d7 to seconds
/ ' SP7A "
- 2680 [use plots) 12 seconds
- e . - SP73 * ' " ' 2675 [u'se plots 1 12 seconds
- FW612
- r- ~- 2674 15 seconds
- O FW601 e *** 6 2679 15 seconds
- MS106 *' s" 2003 36 seconds L M5107 2006 40 seconds
-a- s MS106A 2004 38 seconds MS107A 2007 34 seconds e , M5101 2683 5 seconds
, #L HS100 Z686 5 secor.ds TURBINE TRIP SEE SOE i
AF3872 r. & :- 5 2010 34 seconds
- 8 AF3870 /* et~ *' s 2008 34 seconds
. .. 1 AF3871 : ' 8 2011 33 seconds Enclosure 8 Page 3 of 4 e
. .* e
- . o AF3869 '- 8- + -
2009 34 seconds
. FW779 NONE N/A FW780 NONE N/A '
. AF599 Z970 10.5 seconds
! AF608 Z962 13.5 seconds l .
Sf63 2678 [use plots) e S?6A Z673 [use plots) ,
(
3 Per USAR 7.4.1.3.10-9, auxiliary feedwater pumps will be at full speed within 40 seconds from the time of signal initiation. *
'I
- i.
- Pet.USAR 7.4.1.3.10-9
- Anticipatory Reactor Trip System (ARTS)
] There are presently no ARTS SOE paints.
l The ARTS computer alarus presently available are:
i Q001 ARTS In From MFPT* ,
Q003 ARTS In From T-G*
4 Q004 ARTS Test Trip
- I Q777 ARTS Trip
- l Q778 Rx Pwr > 15% and Rx T-G Trip * ;
p Q779 Rx T-G Trip
- f l
- Note that these come in when any ggg channel trips on the parameter.
Therefore, if a channel was tripped hours before, no new alars will j be received when the second channel trips the plant.
t '
] Menos have been written to Engineering requesting separate ARTS.
channel alares and SOE points.
i <
l i i
i s
t
, l a
l Enclosure 8 -
Page 4 of 4 r
.* r POST TRIP REVIEW CHECKLIST Item Comments 1.0 SOE, Post Trip Review, alarms reviewed, operators interviewed, post trip meeting 1.1 Prime printout delogged 1.2 Plots completed 1.3 Copies of data distributed 2.0 Data Analysis 2.1 SOE describes sequence RPS trip sequence delineated -
Q180, Q181, and Q266 came in when second channel tripped RPS trip makes sense All four RPS channels tripped on low pressure after trip Verify turbine trip (X030)
After 30 seconds, verify auto trans (J428, X025, X026)
Check pressurizer heater cutoff (L770)
Check TBV positions (YO60 - YO65)
Check STRCS, SFAS, ARTS operation, including valve operation time 2.2 Ala rms Read over all alarms (approximately 20 minutes prior to and approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after)
Verify Q185, Q186 for reactor trip Verify turbine operation:
GOV VLVS Z498-Z501 . CLOSED STOP VLVS Z506, 2508, Z510 Z512 CLOSED RHT STOP VLVS Z591, Z576, Z578, 2593 CLOSED RHT VLV Z580, 2581, Z594, Z596 CLOSED AIR DUMP RELAY X070 TRIPPED EHC ELECT Q379 TRSL 2nd Makeup Pump On Time (Q754 or Q759)
F741 RC MU FLOW "HIGH" Check atmospheric vents (Z961, Z969)
Check deserator high level trips (L359, L360)
Check condensate pump reduction time (Q168, Q171, Q174)
Time Enclosure 9
~
Page 1 of 3
e .-
a ,. . i*
t Check alarms for SFRCS and ARTS
. 2.3 Data Analysis RER operated properly Tave near 552*F Pressurizer level not lost (not < 8")
MSSV reset > 960 psig RCS pressure minimus > 1800 psig Review deserator level af ter trip 1
Safety systems operated as designed l ICS operated as expected *
! 3.0 Support of Outside Organizacions a
1 NETWORK entry made TAP Team called in/not called in Entrance meeting data complete (if required)
- 4.0 Report Preparation 4
Report out for comments Comments incorporated and sent to SRB '
Final report sent to B&W i
TRANSIENT COMRENTS:
i i e
i
) l l
1 I
i Esclosure 9 Page 2 of 3
-47
, s-
, s' ?
2 @ s Enclosure 9 Page 3 of 3
.jef 60 *
%' .g g POST TRIP PLOTS PLOT NO.
1 F674 MN FW 1 FLOW 0-7000 KPPH L883 SG 1 SU LVL 0-250" Z673 MN FW 1 CU POSITION 0-100% .
2675 SU FW 1 CU POSITION 0-100%
P932 SG 1 STEAM PRESS 600-1100 2 F679 MN FW 2 FLOW 0-7000 KPPH L893 SG 2 SU LVL 0-250" Z678 MN FW 2 SU POSITION 0-100%
Z680 MN FW 2 CU POSITION 0-100%~
P936 SG 2 OUT PRESS 600-1100 3 J427 GEN GROSS POWER 0-1000 MVe R790 RPS AUCT AVE PWR 0-110% -
R795 RPS CH 1 PWR RANGE 0-110%
R804 RPS CH 2 PWR RANGE 0-110%
4 T782 RC LOOP 2'EG WR TEMP 520-620*F T753 .
RC LOOP 1 E G WR TEMP 520-620*F T781 RCP 1-1 DISCH WR TEMP 520-620*F T821 RCP 2-1 DISCH WR TEMP 520-620'F 5 F874 AFV FLOW TO SG #1 0-1000 GPM S008 AFP #1 SPEED 0-5000 RPM F875 AIV FLOW TO SG #2 0-1000 GPM S018 AFP #2 SPEED 0-5000 RPM 6 ' P725 RC LOOP 1 E G PRESS 1400-2400 PSIG L768 PRESS COMP LE12L 0-J00" T709 RCS AVE NR TEMP 520-620*F MODCOMP 7 'S657 MFP #1 SPEED 0-6000 RPM S667 MFP #2 SPEED 0-6000 RPM L352 DEAR 1 STR TK LVL 6-16' L356 DEAR 2 STR TK LVL 6-16' MODCOMP 8 Q190 - GROUP 7 ROD POSITION 0-100%
R794 NI6 D FLUX -25 to +25 R803 NI 5 D FLUX -25 TO +25 R813 NI 8 D FLUX -25 TO +25 R819 NI 7 D FLUX -25 TO +25 SNB/003 Eqclosure 10 l Page 1 of 1 L___
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