ML041190208
| ML041190208 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 04/02/2004 |
| From: | Maciuska F Rochester Gas & Electric Corp |
| To: | Conte R NRC/RGN-I/DRS/OSB |
| Conte R | |
| References | |
| 50-244/04-301 | |
| Download: ML041190208 (251) | |
Text
Exam ID: LOIT04054 Total Points: 75.00 Exam Date:
==
Description:==
2004 RO Initial Written Exam Student Name:
Date: Grade:
Graded By:
Date:
Approved By:
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Date:
Reviewed By Examinee:
Question 1 C000.1250 (1 point(s))
The unit is operating at 18% power when the following event occurs:
Frequency on Bus 11A and 11B goes to 55 HZ for one (1) second.
Which of the following would be the expected positions for the RCP breakers and the Reactor trip breakers?
RCP Breakers Reactor Trir, Breakers a) Open Shut b) Open Open c) Shut Shut d) Shut Open Answer 1 U'
b) Open Open 1
Question 2 C000.1291 (1 point(s))
L, The plant experienced a stuck open pressurizer PORV and the associated block valve would not close. The operators are currently in procedure ES-1.2, Post LOCA Cooldown and Depressurization. Assuming all other equipment operates as designed, which of the following describes the effects of securing one of three running SI pumps as per the procedure.
- a. RCS pressure decreases, break flow decreases, total SI flow decreases, individual flow from each SI pump increases.
- b. RCS pressure decreases, break flow decreases, total SI flow decreases, individual flow from each SI pump remains the same.
- c. RCS pressure initially decreases, break flow initially decreases. SI flow from the remaining pumps increases and RCS pressure returns to its original value.
- d. RCS pressure decreases, break flow decreases, total SI flow increases. The RCS refills and pressure then increases to near its original value.
-' Answer 2
- a. RCS pressure decreases, break flow decreases, total SI flow decreases, individual flow from each SI pump increases.
2
Question 3 COOO.1252 (1 point(s))
- J Following are large break LOCA, the RHR system has been shifted to Cold Leg Recirculation.
Assuming that the "B" sump screens are partially blocked by debris, which of the following describes the symptom that the operators will see from the Control Room.
Answer 3
3
Question 4 COOO.0919 (1 point(s))
._- Which one of the following describes the conditions for considering CCW lost to a RCP as listed in AP-CCW.2, Loss of CCW During Power Operation, requiring that the RCP be secured?
Answer 4 L
4
Question 5 B004.0030 (1 point(s))
Y During normal 100% power operations, the following conditions occur:
- (B-9) RCP 1A Labyrinth Seal Low Diff Press 15" H20, alarms
- (B-10) RCP 1B Labyrinth Seal Low Diff Press 15" H20 alarms
- (A-4) Regenerative Letdown Outlet Hi Temp 395 degrees F, alarms
- Letdown line flow erratic
- Low pressure letdown line pressure erratic
- "A"RCP seal injection = 0
- "Bl' RCP seal injection = Sgpm
- Charging line flow = 3 gpm
- R13 and R14 are trending up Based upon these symptoms, the failure is:
- a. "A"RCP thermal barrier leak
- b. Charging line leak inside containment downstream HCV-142
- c. "A" RCP seal injection line leak
- d. Letdown line leak inside containment Answer 5
- c. "A"RCP seal injection line leak 5
Question 6 B005.0005 (1 point(s))
W During a plant shutdown to cold shutdown conditions, plant operations was preparing the RCS for loop RTD replacement. As the RCS water level was being lowered, the following conditions occurred:
- A RHR pump in operation
- Flow indication of FI-626 was very erratic
- Safeguards bus 14 current is oscillating
- "B" loop level 10 inches
- Safeguards bus 14 voltage stable at 430 volts
- HCV-626 valve position swinging open and closed
- Core exit thermocouplers are 140°F and increasing
- RCS pressure 0 psig Which of the following conditions is causing these indications:
- a. Steam is forming at the suction of the RHR pump and the resulting cavitation is causing the indications.
- c. Air is being ingested into the RHR suction due to the low loop level and is causing these
- indications.
- d. An electrical malfunction on Bus 14 has caused current to the "A" RHR pump to oscillate which is causing the flow changes.
Answer 6
- c. Air is being ingested into the RHR suction due to the low loop level and is causing these indications.
TC 95-037 6
Question 7 COOO.1287 (1 point(s))
v Given the following conditions:
Plant is being cooled down to Cold Shutdown to begin a refueling outage after 496 days of continuous full power operation.
RCS Temp 300°F RCS Press 350 psig 2 CCW Trains in operation The "A" CCW pump trips Which of the following would the operators observe?
Question 8 C000.1254 (1 point(s))
L Given the following:
Proportional pressurizer heaters are out of service A heatup of the RCS (currently at 485°F) is in progress Pressurizer pressure is currently at 700 psig, backup heaters ON and both pressurizer spray valves manually throttled to 5% open A transformer fault causes a loss of power to the backup pressurizer heaters. What actions are required regarding the pressurizer spray valves and RCS Heatup?
Pressurizer Spray valves.. ..
- a. May remain throttled. The heatup may continue because pressure will continue to rise with the RCS heatup.
- b. Must be closed and the heatup stopped. Pressure will gradually lower due to the spray bypass and heat losses.
- c. Must be closed. The heatup may continue because pressure will continue to rise with the RCS heatup.
L.
- d. May remain throttled if pressurizer level is raised to maintain pressure. The heatup should be stopped because pressure cannot be raised.
Answer 8
- b. Must be closed and the heatup stopped. Pressure will gradually lower due to the spray bypass and heat losses.
8
Question 9 C000.1255 (1 point(s))
.._-_ While operating at 70% power, the following alarms are actuated in the order given.
D-24 Turbine Auto Stop D-I2 Pressurizer Hi Pressure D-4 Pressurizer Hi Level The following plant conditions exist:
Peak Pressurizer Pressure 2360 psi and decreasing Pressurizer Water Level 70% and increasing Rx Power 58%
Turbine Stop Valves Closed Both Rx Trip Breakers Closed No operator actions have taken place Which of the following state the correct response to these conditions:
- a. The Reactor should have tripped on High Przr Pressure. The operator should trip the Rx per the Immediate Action of E-0 Rx Trip or SI.
- b. The Reactor should have tripped on the Turbine Trip. The operator should implement
._ the Immediate Actions of FR-S.l, Response to Rx RestdATWS.
- c. The Reactor should have tripped on the Turbine Trip. The operator should trip the Rx per the Immediate Actions of E-0, Rx Trip or SI.
- d. The Rx should have tripped on High Przr Pressure. The operator should implement the Immediate Actions of FR-S.1, Response to Rx Restart/ATWS.
Answer 9
- c. The Reactor should have tripped on the Turbine Trip. The operator should trip the Rx per the Immediate Actions of E-0, Rx Trip or SI.
9
Question 10 COOO. 1256 (1 point(s))
-.-, Which of the following is a reason that Secondary Plant Chemistry for Chlorides, Sodium and Oxygen must be maintained within limits?
- a. When subjected to the radiation in the Steam Generator, oxygen is converted to Nitrogen- 16 which is highly radioactive.
- b. Oxygen can come out of solution in the condenser causing condenser vacuum problems.
- c. These chemicals can result in degradation of the Condensate Polisher Resins.
- d. These chemicals can accelerate S/G tube degradation possibly leading to a S/G tube leak or rupture.
Answer 10
- d. These chemicals can accelerate S/G tube degradation possibly leading to a S/G tube leak or rupture.
10
Question 11 C000.0646 (1 point(s))
v While trying to establish a heat sink using the S/Gs (FR-H. 1 Response to Loss of Secondary Heat sink) both S/G wide range levels decrease to 45 inches.
What is the next major action used to establish core cooling?
- a. If S/G is hot and dry increase feedwater to maximum.
- b. Trip RCPs and establish bleed and feed.
- c. Start RCP's and initiate bleed and feed.
- d. If core exit thermocouple temperatures are decreasing, initiate cooldown not to exceed 100"Fhr by dumping steam.
Answer 1 1
- b. Trip RCPs and establish bleed and feed.
11
Question 12 C000.1257 (1 point(s))
An SI occurs with a concurrent loss of offsite power. The "A" D/G starts and reenergizes buses 14 and 18. Which of the following are the sequence and time after bus energization that the safeguard loads will energize.
EquiDment Time
- a. "A" SI Pump 5 sec.
"C" SI Pump 15 sec.
"A" RHR Pump 25 sec.
"A" or 'IC" Service Water Pump 35 sec.
"A" CNMT Recirc Fan 45 sec.
"D" CNMT Recirc Fan 55 sec.
"A" MDAFW Pump 65 sec.
- b. "A" SI Pump 5 sec.
"C" SI Pump 10 sec.
"A" RHR Pump 15 sec.
"A" or "C" Service Water Pump 20 sec.
"A" CNMT Recirc Fan 25 sec.
"D"CNMT Recirc Fan 30 sec.
"A" MDAFW Pump 35 sec.
v
- c. "A" SI Pump 5 sec.
"C" SI Pump 10 sec.
"A" RHR Pump 15 sec.
"A" CNMT Recirc Fan 20 sec.
"D" CNMT Recirc Fan 25 sec.
"A"or "C" Service Water Pump 30 sec.
"A"MDAFW Pump 35 sec.
- d. "A" SI Pump 7 sec.
"C" SI Pump 12 sec.
"A" RHR Pump 17 sec.
"A" CNMT Recirc Fan 22 sec.
"D" CNMT Recirc Fan 27 sec.
"A" or "C" Service Water Pump 32 sec.
"A" MDAFW Pump 37 sec.
12
Answer 12
- b. "A"SI Pump 5 sec.
"C" SI Pump 10 sec.
"A"RHR Pump 15 sec.
"A"or "C" Service Water Pump 20 sec.
"A"CNMT Recirc Fan 25 sec.
"D" CNMT Recirc Fan 30 sec.
"A"MDAFW Pump 35 sec.
13
Question 13 COOO.1258 (1 point(s))
_- The following plant conditions exist:
A Reactor startup is in progress Source range channels N3 1 and N32 indicate 1O4 CPS Intermediate range channels N35 and N36 indicate 5 X10-11 AMPS The annunciator E-6 Loss of "A"Inst. Bus has just alarmed.
What actions are required for this condition?
- a. Commence a reactor shutdown to insert all control and shutdown banks, AND Restore power to "A" Inst. Bus from alternate AC power source
- b. Verify reactor trip, AND Isolate Instrument Bus "A"Inverter
- c. Commence a reactor shutdown to insert all control and shutdown banks, AND Isolate Instrument Bus "A" Inverter
- d. Verifj reactor trip, AND Restore power to "A" Inst. Bus from alternate AC power source Answer 13
- d. Verify reactor trip, AND Restore power to "A"Inst. Bus from alternate AC power source 14
Question 14 C000.1259 (1 point(s))
v Which of the following techniques does procedure ER-FIRE-2, Alternate Shutdown for Cable Tunnel Fire, use to ensure long term DC supply.
- a. The "B" DC Train Battery chargers can be back fed from the TSC Diesel through Bus 15 and the Bus 15-16 cross tie.
- b. The "B" DC Train can be cross tied to the "A" DC Train which will still have operable battery chargers.
- c. The TSC Battery can be cross tied to the "B" DC Train and the TSC Diesel can supply the TSC Battery Chargers.
- d. The "B" DC Train Battery Chargers can be manually reenergized by manually reenergizing MCC "D" and manually closing the Battery Charger Supply Breakers.
Answer 14 u c. The TSC Battery can be cross tied to the "B" DC Train and the TSC Diesel can supply the TSC Battery Chargers.
15
Question 15 COOO.1260 (1 point(s))
-4 With the plant operating at 100% power and all systems aligned for normal operation, the following alarm is received.
Instrument Air Lo Press, 100 PSI (Alarm H-8)
The RO reports that IA header pressure is 75 psi and decreasing slowly. According to AP-IA. 1,Loss of Instrument Air, the operators are directed to:
- a. Trip the reactor and go to E-0 if S/G levels cannot be maintained at 52%.
- b. Commence a rapid plant shutdown if RCP seal injection is isolated.
- c. Trip the reactor and go to E-0 if S/G level < 20% and feed flow < steam flow
- d. Commence a rapid plant shutdown until standby air compressors can be started to restore IA pressure.
Answer 15 Y
- c. Trip the reactor and go to E-0 if S/G level < 20% and feed flow < steam flow 16
Question 16 COOO.1261 (1 point(s))
.L Which of the following lists the proper order for restoring cooling (by priority) as directed by FR-H. 1, Response to Loss of Secondary Heat Sink? (Assume both S/G wide range levels are 200 inches and decreasing slowly)
Question 17 B000.094 1 (1 point(s))
v Following a small break LOCA with the RHR pumps inoperable, the operators transition to ECA-1.1, Loss of Emergency Coolant Recirculation. The following plant conditions exist:
RCS Pressure - 150 psig CNMT Pressure - 55 psig RWST Level - 26%
Which one of the following is a correct combination of CNMT Recirculation Fans and Containment Spray Pumps to operate under these conditions:
a) 0 Recirc Fans, 2 Spray Pumps b) 1 Recirc Fan, no Spray Pumps c) 3 Recirc Fans, 1 Spray Pump d) 1 Recirc Fan, 2 Spray Pumps Answer 17
\ c) 3 Recirc Fans, 1 Spray Pump 18
Question 18 B000.002 1 (1 point(s))
v The plant was operating at 100% when an accident occurs causing a Rx trip and Safety Injection.
The following cooldown has been observed:
2100 - 535°F 21 15 - 495°F 2130 - 464°F 2145 - 435°F 2200 - 415°F The crew has progressed through ECA-2.1, Uncontrolled Depressurization of both Steam Generators, to the step which directs initiation of a cooldown at a rate not to exceed 1OO"F/hr.
Which one of the following describes the correct restriction on cooldown rate?
- a. Cooldown can commence now (2200) but cannot go below 395°F degrees prior to 2215. A 100°F /hr rate can commence at 2215.
- b. Cooldown can commence now (2200) at a rate of 100°F per hour with no other restriction.
- c. Must soak for one hour. A cooldown rate of 100°F /hr can commence.
- d. No cooldown until 2215 when cooldown at a rate of 100°F /hr can commence.
Answer 18
- b. Cooldown can commence now (2200) at a rate of 100°F per hour with no other restriction.
19
Question 19 BOO1.OO1O (1 point(s))
d During a plant load increase, with reactor power at 48%, control Bank C group 1 rod G-7 drops.
Prior to the drop it was at 230 steps. While restoring the rod, control rod urgent failure alarm OCCUTS.
Which one of the following explains why the alarm actuated?
- a. All Bank "C" Group 2 rods lift coils deenergized.
- b. All other Bank "C" Group 1 rods lift coils deenergized.
- c. Group "C" rod moving with group I'D" rods withdrawn.
- d. The step counter of the pulse to analog (P/A) converter was not reset to 0.
Answer 19
- a. All bank "C" group 2 rods lift coils deenergized.
20
Question 20 CO 1 1.OO 15 (1 point(s))
v Unit is 100% power. A and B Charging Pumps are running with A pump in Auto and a 40 gpm letdown orifice is in service. Level channels 427/428 are selected for control.
Assuming no operator action, which one of the following describes plant response if the PZR level channel LT-427 fails low?
- a. Charging flow remains constant. PZR level will be maintained at the 100%
power setpoint.
- b. Charging flow remains constant. PZR level will be maintained between the letdown isolation and zero power setpoints.
- c. Charging flow will rise. PZR level will steadily rise to the reactor trip setpoint.
- d. Charging flow will lower. PZR level will steadily rise to the reactor trip setpoint.
Answer 20
- d. Charging flow will lower. PZR level will steadily rise to the reactor trip setpoint.
21
Question 21 B015.0032 (1 point(s))
v The reactor is being shutdown as part of a planned outage, The following conditions exist:
0 Core burnup is 8000 MWDMTU 0 Control rods being inserted in manual 0 Control Bank C presently @ 122 steps 0 N-35 reads 1 E-1 1 amps and slowly decreasing 0 N-36 reads 1.2 E-1 1 amps and slowly decreasing The HCO has just observed the source range high volts has energized, however, neither source range has any indicated counts and both source range SUR meters read "0".
Which of the following is the action that must be taken?
- a. Trip the reactor, go to E-0, Response to Rx trip or safety injection
- b. Defeat the reactor trip for any failed channels by placing the level trip switch in the "BYPASS" position.
- c. Pull control rods to maintain power level as necessary to maintain indication on the Intermediate range meters.
.-. d. Open and hold open the reactor t i p breakers, borate until greater than or equal to 5%
SDM has been achieved.
Answer 21
- d. Open and hold open the reactor trip breakers, borate until greater than or equal to 5%
SDM has been achieved.
TC 95-062 TC 95-063 Note: Question must be checked against cycle curves 22
Question 22 B000.1003 (1 point(s))
- The plant has been operating with a SGTL of 60 GPD in the "B" SG for the last three months, currently doing four hour leak determinations. PPCS alarm R15A5G3 2 75 GPD just alarmed.
A review of leak trend shows the following:
0 1300 leak started increasing above 60 GPD 0 1315 65 GPD 0 1330 70GPD 0 1345 75 GPD and trending up (current time) 0 All radiation monitors operable, consistent trend with R15A5G As per AP-SG. 1, which one of the following states the required actions?
- a. Continue monitoring at 15 minute intervals.
- b. Continue monitoring at one hour intervals.
- c. Reduce power to < 50% in one hour and be in Mode 3 in three hours.
- d. Be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Answer 22
- a. Continue monitoring at 15 minute intervals.
23
Question 23 B000.03 19 (1 point(s))
The shift supervisor has directed evacuation of the control room due to excessive smoke -- there is no f r e in the MCB.
Which one of the following lists the IMMEDIATE ACTIONS required for this evacuation?
- a. Verify reactor trip only.
- b. Verify reactor trip and turbine stop valves closed.
- c. Verify reactor trip and turbine stop valves close, then close both MSIVs.
- d. Verify reactor trip, turbine stop valves closed, and trip both RCPs.
Answer 23
- b. Verify reactor trip and turbine stop valves closed.
24
Question 24 B012.0037 (1 point(s))
v An automatic SI has occurred. Which one of the following lists the conditions necessary to receive a subsequent automatic SI signal?
Answer 24
25
Question 25 COOO. 1262 (1 point(s))
L The plant has been operating for three months at 100% power when an RCS leak occurs that requires Rx trip and safety injection. The following plant conditions are observed:
CET Temp - 556°F RCS Press - 1100 psi PRZR level - 2% steady RCP'S - off SI flow - 250 gpm The crew is performing actions in ES-1.2, LOCA Cooldown and Depressurization when the HCO opens a PORV as directed by procedure. Pressurizer level within 2 minutes increases to 42% before HCO closes the PORV. Which of the following would explain the sudden rise in pressurizer level?
- b. Przr Level Transmitters are being affected by flow through the PORV.
- c. Steam bubble forming in the Reactor Vessel head.
- d. SI Accumulators injecting while PORV was open.
Answer 25
- c. Steam bubble forming in the Reactor Vessel head.
26
Question 26 3000.0067 (1 point(s))
A CAUTION in FR-C.2 "Response to Degraded Core Cooling" has you NOT transition out of FR-C.2 until FR-C.2 is complete even if an Integrity Red Path results during performance of the upcoming procedure steps. Which one of the following explains why you would not transition even though FR-C.2 is an orange path.
A. FR-C.1 "Response to Inadequate Core Cooling and FR-C.2 "Response to Degraded Core Cooling have priority over all other FR procedures except FR-S. 1 "Response to Reactor Restart/ATW S.
B. A transition from FR-C.2 to FR-P. 1 "Response to Imminent Pressurized Thermal Shock Condition" would result in termination of Cooldown and because of low inventory in the RCS you would probably end up with a transition to FR-C. 1.
C. Rules of usage in FRs require completion of an entered FR before transition out and this caution is reminding you of this requirement because at this point in the procedure, an integrity red path will occur.
D. FR-C.2 is addressing an RCS inventory problem and FR-P. 1 provides no procedural guidance to maintain inventory in the RCS.
Answer 26 B. A transition from FR-C.2 to FR-P.l "Response to Immenent Pressurized Thermal Shock Condition" would result in termination of cooldown and because of low inventory in the RCS you would probably end up with a transition to FR-C. 1.
Question 27 B000.1006 (1 point(s))
~
Given the following plant conditions:
A LOCA has occurred An ORANGE Path has developed on Containment Critical Safety Function due to Sump B level e All Auto Actions have occurred and have not been overridden.
In accordance with FR-Z.2, RESPONSE TO CONTAINMENT FLOODING, which one of the following would cause this condition?
- a. Service Water Leak in CNMT
- b. Fire Protection System Leak in CNMT
- c. Component Cooling Water Leak in CNMT
~
- a. Service Water Leak in CNMT
Question 28 C000.1263 (1 point(s))
-. Given the following plant conditions:
0 Crew is currently performing actions of ES-0.1, Reactor Trip Response Conditions for starting a RCP are being verified per ATT-15.0, Attachment RCP Start Which one (1) of the following describes the basis for maintaining a minimum of 220 psid on the RCP seals during RCP startup and operation?
- a. Prevents the #1 RCP seal from becoming a "floating" seal.
- b. Ensures the #1 RCP seal has proper separation between surfaces.
- c. Ensures adequate back pressure is maintained to the #2 RCP seal.
- d. Provides for adequate seal cooling flow from the RCS.
Answer 28
- b. Ensures the #1 RCP seal has proper separation between surfaces.
Question 29 COOO.1264 (1 point(s))
v According to P-3, Chemical and Volume Control System, during a plant shutdown primary chemist requests that H2 besecured to VCT and N2 lined up. Which of the following describes the reason for this request?
- a. To maintain proper back pressure on RCP seals and maintain inert environment in cvcs.
- b. To adjust H2 concentration in RCS and cause a controlled crud burst.
- c. To reduce 02 in the vent header during plant shutdown and ensure sufficient NPSH for the charging pumps.
- d. To maintain proper RCP seal operation and prevent lifting the VCT relief valve 257 during two charging pump operation.
Answer 29
- a. To maintain proper back pressure on RCP seals and maintain inert environment in cvcs.
Question 30 C005.0007 (1 point(s))
v Which one of the following is an interlock associated with operation of MOV-857A, B, and C, SI and CS pump suction from RHR valves?
- a. They cannot be opened if MOV-850A or B RHR suction from CNMT Sump B, are closed with MOV-896A and B SI suction from RWST closed or MOV-897 and MOV-898, SI Recirc to RWST, open.
- b. They cannot be closed if MOV-850A and B RHR suction from CNMT Sump B, are closed with MOV-896A and B SI suction from RWST closed or MOV-897 and MOV-898, SI Recirc to RWST, open.
- c. They cannot be opened if MOV-850A or B RHR suction from CNMT Sump B, are open with MOV-896A and B, SI suction from RWST open or MOV-897 and MOV-898, SI Recirc to RWST, open.
- d. They cannot be closed if MOV-850A and B, RHR suction from CNMT Sump B, are open with MOV-896A or B, SI suction from RWST open and MOV-897 or MOV-898, SI Recirc to RWST, closed.
Y Answer 30
- c. They cannot be opened if MOV-850A or B RHR suction from CNMT Sump B, are open with MOV-896A and B, SI suction from RWST open or MOV-897 and MOV-898, SI Recirc to RWST, open.
Question 3 1 C006.0126 (1 point(s))
L- Which of the following is the correct response to an SI signal with the plant in normal at power lineup?
- a. Main Feed Regulating and Bypass Valves close
- b. SI Pump Suction from the BASTS open
- c. SI Pump Recirc Valves open
- a. Main Feed Regulating and Bypass Valves close
Question 32 C006.0082 (1 point(s))
L Which one of the following describes how the C SI Pump starts with an SI actuation and all buses are energized by off-site power.
- a. Starts on Bus 14 with no time delay. If Bus 14 breaker fails to close, it starts on Bus 16 after a 2 second time delay.
- b. Starts on Bus 14 with a 10 second time delay. If Bus 14 breaker fails to close, it starts on Bus 16 after a 12 second time delay.
- c. Starts on Bus 14 with no-time delay. If a fault occurs on the pump and the Bus 14 breaker trips, the Bus 16 breaker will close after a 37 second time delay.
- d. Start on Bus 14 after a 7 second time delay. If the Bus 14 breaker fails to close, then the Bus 16 breaker will close after a 30 second time delay.
Answer 32
- b. Starts on Bus 14 with a 10 second time delay. If Bus 14 breaker fails to close, it starts
\
on Bus 16 after a 12 second time delay.
Question 33 C000.1265 (1 point(s))
. Which of the following describes the adverse affects of NOT maintaining the Pressurizer Relief Tank (PRT) within design level band?
- a. If the level is too high, the tank will overflow to CNMT sump causing possible false indication of RCS leakage to CNMT.
- b. If the level is too low the radioactive gases that leak from the top of the PRZR would not be adequately scrubbed, thus causing subsequent elevated gaseous activity levels inside CNMT.
- c. If the level is too high, the sparger pipe will be too far underwater rendering the cooling affect of makeup water ineffective.
- d. If the level is too low, there would be insufficient water volume to absorb and condense a design discharge of PRZR safety leading to possible over temperature and overpressure of the PRT.
Answer 33
- d. If the level is too low, there would be insufficient water volume to absorb and condense
-- a design discharge of P E R safety leading to possible over temperature and overpressure of the PRT.
Question 34 COOO.1266 (1 point(s))
L Given the following conditions:
0 The plant is operating at 100% power 0 Annunciator A-13, CCW Surge Tank Lo Level < 41.2% is lit 0 The crew has opened RMW to CCW surge tank MOV-823 and started a RMW pump 0 Component Cooling Water (CCW) surge tank is 4 1% and lowering Which one (1) of the following actions is required by AP-CCW.2, Loss of CCW at Power, if CCW Surge Tank level continues to drop.
- a. Reduce loads on CCW system, isolate letdown, secure CCW to 1 RCP at a time, start a plant shutdown
- b. Isolate letdown, excess letdown, place standby CCW switch in pull-stop and commence an rapid plant shutdown
- c. If level < lo%, isolate letdown, excess letdown, and trip the Rx and go to E-0.
- d. If level cannot be restored to > 50%, trip the Rx,trip both RCP's and go to E-0.
L Answer 34
- c. If level lo%, isolate letdown, excess letdown, and trip the Rx and go to E-0.
Question 35 C000.1267 (1 point(s))
.. Given the following conditions:
0 Reactor power is 90%
0 Pressurizer level is 46%
0 Pressurizer pressure selector switch is in the normal position (430/449)
The operators receive the following alarm:
F-2, "Pressurizer Hi Pressure - 23 10 psi" after a few seconds and additional alarm is received 0 F-10, "Pressurizer Low Pressure, 2185 psi" 0 Both Przr Spray Valves are full open What malfunction caused these alarms and what are the operators' actions in response to the alarms?
- a. PT-430 Pressurizer Pressure failed High, take manual control of HC-43 1K and set at approximately 50%, control pressure manually.
- b. PT-449, Pressurizer Pressure failed High, take manual control of HC-43 1K and set at approximately 50%, control pressure manually.
-- c. PT-430, Pressurizer Pressure failed Low, manually energize B/U heaters and verify spray valves closed.
- d. PT-449, Pressurizer Pressure failed Low, take manual control and close spray valves, verify B/U Heaters on.
Answer 35
- b. PT-449, Pressurizer Pressure failed High, take manual control of HC-43 1K and set at approximately 50%, control pressure manually.
Question 36 C000.1288 (1 point(s))
'- Given the following plant conditions:
e The plant is currently at 25% increasing to 100% at lO%/hour The electricians are performing maintenance on "B" DC Bus Due to a switching error, the DC SUPPLY BREAKER FOR B TRAIN of RPS is inadvertently opened What is the expected plant response and why?
- a. "A"reactor trip breaker only would open due to shunt and UV coil operation on A breaker
- b. Both trip breakers would open due to shunt and UV coil operation on A breaker and UV coil operation on B breaker
- c. Neither breaker is expected to open due to system design that a single failure should not cause a reactor trip
- d. "B" reactor trip breaker only would open due to W coil operation on the B breaker I Answer 36
- b. Both trip breakers would open due to shunt and UV coil operation on A breaker and UV coil operation on B breaker
Question 37 C000.1268 (1 point(s))
-- Given the following conditions:
0 The reactor has just tripped 0 Prior to the trip, reactor power was at 30% with all systems in their normal lineup 0 PRZR pressure channel (PT-431) had previously failed low and was removed form service in accordance with ER-INST. 1,"Blue Channel Attachment PRZR Pressure PT-43 1" 0 Investigation showed a Reactor Protection System bistable failure (actuation) precipitated the Reactor trip.
Which of the following bistable failures would have caused the reactor trip?
- a. Channel 1 Over Temperature Delta-T 405C Over Temp Trip
- b. Channel 2 Turbine Impulse Pressure 486A Turbine Press P 13
- c. Channel 3 Overpower Delta-T 407A Over Power Trip
- d. Channel 4 Nuclear Power Range Instrument Drawers N44A OVERPOWER TRIP HIGH RANGE
-\.
Answer 37
- a. Channel 1 Over Temperature Delta-T 405C Over Temp Trip
Question 38 C000.1269 (1 point(s))
- It is stated in 0-2.2 and P-2 that pressure must be reduced to less than 1992 psig and SI blocked prior to cooling S/G to less than 5 14 psig. Reduce pressure and block SI to:
- c. Allow blocking SI prior to Inadvertent Containment Isolation
- d. Preclude inadvertenvlow press Reactor trip Answer 3 8
- a. Preclude inadvertent SI
Question 39 C006.0081 (1 point(s))
v The plant experienced a small break LOCA while in Mode 1. On SI initiation, the "B" SI pump fails to start and cannot be manually started. Which of the following statements describe the response of the "C" SI pump discharge valves? Assume normal initial equipment alignment for power operations, MOV-871A is "C" SI pump discharge to "A"SI pump header and MOV-871B is "C" SI pump discharge to BI' SI pump header.
a, MOV-871A will close, MOV 871B will remain open.
- b. MOV-871A and B will remain open.
- c. MOV-87 1B will open, MOV-871A will remain closed.
- d. MOV-871B will close, MOV-871A will remain open.
Answer 39
- a. MOV-871A will close, MOV 871B will remain open.
Question 40 BOOO.O 132 (1 point(s))
._ What is the major mitigation strategy of the containment Functional Restoration Procedure FR-2.1, Response to High containment Pressure?
- b. Use CNMT Spray and Recirc Fan Coolers to cool the containment atmosphere.
- c. Place hydrogen recombiners in service to lower CNMT hydrogen concentration to prevent an explosive burn which would further raise pressure.
Answer 40
- b. Use CNMT Spray and Recirc Fan Coolers to cool the containment atmosphere.
Question 41 C026.0028 (1 point(s))
Which one of the following sets of valves receives an open signal on a Containment Spray Actuation?
- a. MOV 896A and B, RWST outlet to SI and CS pumps, and MOV 860A, B,C, and D, CNMT Spray Pump Discharge Valves.
- b. MOV 860A,B,C, and D, CNMT Spray Pump Discharge Valves and HCV 836A and B, CNMT Spray NaOH addition.
- c. MOV 896A and B, RWST outlet to SI and CSpumps and MOV 875A and B, and 876A and B, CNMT Spray Charcoal Filter Douse Valves.
- d. HCV 836A and B, CNMT Spray NaOH addition and MOV 875A and B, and 876A and B, CNMT Spray Charcoal Filter Douse Valves.
Answer 4 1
- b. MOV 860A,B,C, and D, CNMT Spray Pump Discharge Valves and HCV 836A and B, CNMT Spray NaOH addition.
Question 42 C000.1271 (1 point(s))
Given the following plant conditions:
Reactor power 100% for the last 90 days 0 Steam Dump Mode Selector Switch is selected for Auto Mode (Tavg) 0 ARV's in Auto at 1050 psig Steam pressure transmitter PT-484 Fails High A loss of offsite power and a Rx Trip occurs. With NO operator actions, and after approximately 15 minutes, RCS Tcold will stabilize at which ONE of the following temperatures?
- a. 540°F
- b. 547°F
- c. 552°F
- d. 560°F Answer 42 L
- c. 552°F
Question 43 C056.0066 (1 point(s))
The plant is operating normally at 100% power with condensate pump A in standby, and condensate pumps B and C running. Condensate pump B trips. Which ONE of the following describes plant response?
- a. LP feedwater heaters bypass valve closes due to low MFP suction pressure.
- b. LP feedwater heaters bypass valve opens due to low feedwater heater levels.
- c. Standby condensate pump auto starts when Condensate pump B breaker opens.
- d. Standby condensate pump auto starts on low MFP suction pressure.
Answer 43
- c. Standby condensate pump auto starts when Condensate pump B
._ breaker opens.
Question 44 C056.0067 (1 point(s))
i Which one of the following causes the condensate bypass valve to open when it is in automatic?
- a. Low condensate pump discharge pressure of 200 psig
- b. Low MFP suction pressure of 195 psig
- c. High hotwell level of 40 inches
Answer 44
Question 45 B035.0006 (1 point(s))
- The plant is operating at 48% power when an EHC oil leak results in a turbine trip. With regard to the Main feedwater control valves:
- a. The resulting loss of load may result in RCS temperature in excess of 554 F. This will result in opening of the FRVs until RCS Tavg in .e 554°F or level is > 67%.
- b. ADFCS Will control as necessary to restore level to 52%.
- d. The resulting loss of load will result in a shrink of S/G levels and Rx Trip which causes the FRVs to isolate, thus allowing AFW to restore S/G level.
Answer 45
- b. ADFCS will control as necessary to restore level to 52%.
Question 46 C06 1.0026 (1 point(s))
~. Procedure ER-AFW.1, Alternate Water Supply To The AFW Pumps," provides for alternate sources of water to the SGs. Which of the following lists these sources in their proper order, from most to least preferred?
- a. Service water, city fire water, any source of condensate grade water
- b. Service water, any source of condensate grade water, city fire water
- c. Any source of condensate grade water, service water, city fire water
- d. Any source of condensate grade water, city fire water, service water Answer 46
- c. Any source of condensate grade water, service water, city fire water
Question 47 C063.0045 (1 point(s))
A plant trip from full power and loss of all AC power occurred at 1200 hours0.0139 days <br />0.333 hours <br />0.00198 weeks <br />4.566e-4 months <br />.
Which of the times listed below is the latest that the batteries will be able to supply adequate voltage to expected DC loads given that the proper loads are shed in accordance with UFSAR assumptions.
- a. 1400hours
- b. 1600 hours0.0185 days <br />0.444 hours <br />0.00265 weeks <br />6.088e-4 months <br />
- c. 2000hours
- d. 2400hours Answer 47
- b. 1600 hours0.0185 days <br />0.444 hours <br />0.00265 weeks <br />6.088e-4 months <br />
Question 48 B063.0008 (1 point(s))
- The following plant conditions exist:
0 100'Yopower 0 All electrical systems are in their normal alignments 0 DC Bus A voltmeter on the Main Control Board indicates 34 volts 0 Total 'A' Train battery DC amp load is 80 amps "A" Vital Battery Monitor indicates +1 amp The 1Al Battery Charger Output Breaker is inadvertently opened by the electricians. What voltage will the crew observe on DC Bus "A" voltmeter and what amp load would be indicated on the Vital Battery Monitoring Cabinet for the "A" Battery?
- a. 0 volts, 0 amps
- b. Ovolts, -80 amps C. - 134 volts, +1 amp
- d. - 134 volts, -80 amps Answer 48 C. - 134 volts, +1 amp
Question 49 COOO.1272 (1 point(s))
W Given the following:
0 One of the air receivers for the "1A"Emergency Diesel Generator (EDG) has been tagged out for maintenance for the last 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
Which ONE of the following is the minimum number of normal start cycles that are currently available on the 1A EDG?
- a. 2starts
- b. 3starts
- c. 4starts
- d. 5starts Answer 49
- a. 2starts v
Question 50 C000.1273 (1 point(s))
u The plant has experienced a large break LOCA and a loss of offsite power. Neither emergency diesel started automatically. Following a manual start of 1A EDG and manually loading of Bus 14 and 18 per Attachment 8.5, the HCO observed the following:
0 1A EDG load 2155 kw Which ONE of the following is the LONGEST amount of time the diesel generator can remain at the above conditions without exceeding the machine ratings and what action would be required to restore loading to within limits.
- a. .5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, reduce load by stopping redundant equipment
- b. 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, no action required loading will decrease as the LOCA progresses
- c. 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, reduce loading by stopping redundant equipment
- d. Continuous, no action loading is within limits Answer 50
~b
- b. 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, no action required loading will decrease as the LOCA progresses
Question 5 1 C071.0001 (1 point(s))
Y A Waste Gas Decay Tank is being released. As the HCO is doing his daily RMS plots, he notices R-14reading 7.0 x lo5 cpm. What are the correct actions concerning the Gas Decay Tank?
- a. Terminate the release, have HP resample the Gas Decay Tank that was being released.
Notify the S S that a release above release limits has occurred.
- b. Terminate the release, have HP resample the Gas Decay Tank that was being released, no release above release limits has occurred.
- c. Terminate the release only if R-13 is above the Alarm Setpoint.
- d. Terminate the release only if R-14fails check source and notify HP's.
Answer 51
- a. Terminate the release, have HP resample the Gas Decay Tank that was being released.
L Notify the S S that a release above release limits has occurred.
Question 52 C076.0002 (1 point(s))
Under which one of the following conditions will a service water isolation signal be generated?
- a. SI signal and emergency diesel generator start
- b. Undervoltage on bus 14 or 16 only
- c. Emergency diesel generator automatic start and undervoltage on bus 14 or 16
- d. SI signal with a normal supply breaker open on Bus 14 or 16 Answer 52
Question 53 COOO. 1286 (1 point(s))
-..- , Given the following:
0 Plant operating at 100% power for last 30 days AR-A-2 1, "Comp Cooling HX OUT HI Temp 100°F was just received Which ONE of the following would cause this alarm?
- d. MOV-46 15 "AUX BLDG S W ISOL VLV" going CLOSED
Question 54 COOO.1274 (1 point(s))
c Given the following conditions:
50%power 0 Pressure 2260 slowly increasing e PRZR spray valves closed 0 Letdown Orifice Valves closed Charging flow decreasing Przr Level 54% and increasing Which one of the following malhctions would cause these indications?
- a. PT-449 Pressurizer Pressure Failed Low
- b. LT-428Pressurizer Level Failed Low
- c. Loss of Instrument Air
- d. Pressurizer Pressure Master Controller Failure Answer 54 U
- c. Loss of Instrument Air
Question 55 C103.0016 (1 point(s))
I The plant is in Mode 6 and core alterations are in progress. Which ONE of the following conditions will result in a loss of containment integrity?
- a. Operation of the Containment Purge and Exhaust System.
- b. Movement of maintenance personnel through the personnel air lock doors.
- c. Penetration #2 (S/G inspection) has its blind flanges removed and is sealed with fire barrier foam.
- d. The "A"S/G secondary manways removed and the associated atmospheric relief valve removed for maintenance.
Answer 55
- d. The "A"S/G secondary manways removed and the associated atmospheric relief valve removed for maintenance.
Question 56 B000.0066 (1 point(s))
L- What is the basis for the RCP trip criteria of the E procedures?
- a. Tripping the RCP's during accident conditions is to prevent excessive depletion of RCS water inventory which could lead to a severe core uncovery if the RCP's were tripped later in the accident.
- b. RCP operation may result in masking of an Inadequate Core Cooling Condition resulting in a delayed entry into FR-C. 1, Response to Inadequate Core Cooling.
C. Tripping RCP's early results in a phase separation of RCS mass. This phase separation will then clearly show the void on RVLTS for further verification of ICC conditions.
- d. Tripping RCP's prior to the hotleg saturation temperature being met will ensure natural circulation can be achieved during the LOCA cooldown and depressurization.
Answer 56
- a. Tripping the RCP's during accident conditions is to prevent excessive depletion of RCS water inventory which could lead to a severe core uncovery if the RCP's were L' tripped later in the accident.
Question 57 CO11.0009 (1 point@))
-*- Given the following information:
- Reactor power = 98%
- Pressurizer level = 49%
- "A" charging pump is running in AUTO
- The Tavg input to pressurizer level has failed low Which ONE of the following groups of actions describes the indications the Operator will see?
(Assume no operator action)
- a. "A" charging pump slows down, backup heaters are energized, pressurizer level begins to decrease, Przr level deviation alarm actuates.
- b. "A" charging pump speeds up, backup heaters are deenergized, pressurizer level begins to increase, Przr level deviation alarm actuates.
- c. "A" charging pump slows down, backup heaters are energized, pressurizer level begins to increase, Przr level deviaton alarm actuates.
- d. "A" charging pump speeds up, backup heaters are deenergized, pressurizer level begins to decrease, Przr level deviation alarm actuates.
Answer 57
- a. "A" charging pump slows down, backup heaters are energized, pressurizer level begins to decrease, Przr level deviation alarm actuates.
Question 58 COO 1.0071 (1 point(s))
. Given the following conditions:
During a normal reactor startup, all Control Bank B rods at 36 steps except one rod that is at 24 steps (MRPI Indication). Step counter for Control Bank B shows 36 steps.
Which alarm would activate (be energized):
- a. MRPI system failure (MCB)
- b. Rod Deviation (MRPI CRT)
- c. PPCS rod sequence or rod deviation (MCB)
- d. Rod bottom rod stop (MCB)
Answer 58
- c. PPCS Rod sequence or Rod deviation (MCB)
Question 59 COOO. 1276 (1 point(s))
-- Given the following plant conditions:
0 Reactor power is 7% with a power increase in progress 0 The turbine is latched but has not been loaded onto the grid 0 All power is then lost to Instrument Bus B Which ONE of the following describes the effect of these conditions on the plant?
- a. An automatic reactor trip will occur and the turbine will trip
- b. An automatic reactor trip and safety injection will occur
- c. The turbine will trip and the reactor remains at 7% power
- d. Both the turbine and reactor remain at 7% power, but several control systems have to be operated in MANUAL, Answer 59
- a. An automatic reactor trip will occur and the turbine will trip c
Question 60 COOO.1289 (1 point(s))
si During Post Accident conditions, power is lost to one of the two Core Exit Thermocouples (CETCs) indicating panels. Which of the following describes the effect on the PPCS monitoring of CETCs.
- a. The PPCS display of CETCs will not be affected since the PPCS directly monitors the CETC independent of the Display Panels.
- b. The PPCS display will not be affected. However, the alarm monitoring functions of the display panels will not be available.
- c. Input to the PPCS will be unavailable from the affected channel. Due to the PPCS error checking program, the unaffected CETC will be flagged as questionable data on PPCS.
- d. Input to the PPCS will be unavailable from the affected channel. CETCs from the unaffected panel will continue to be displayed normally.
Answer 60
- d. Input to the PPCS will be unavailable from the affected channel. CETCs from the unaffected panel will continue to be displayed normally.
v
Question 61 C000.1278 (1point(s))
\- A LOCA has occurred. In response to a RED path on the CORE COOLING Critical Safety Function Status Tree, FR-C. 1, "Response to Inadequate Core Cooling," is currently in progress.
Containment hydrogen concentration is 4.5%.
Which of the following states the action that is to be taken in regards to operation of the hydrogen recombiners?
- d. DO NOT operate the hydrogen recombiners since the hydrogen recombiner system will not be effective at this concentration Answer 61
.-, c. DO NOT operate the hydrogen recombiners since they could result in ignition of the hydrogen
Question 62 COOO. 1279 (1 point(s))
v A precaution contained in S-23.2.3, "Containment Mini-Purge System Operation," states:
"Operation of Mini-Purge supply path without opening the exhaust path (depressurization line) may pressurize the containment to 0.4 psig within 10 minutes and should, therefore, be avoided."
What is the high Tech Spec limit on containment pressure and what is the basis for this limit?
- a. 5.4 psig - to ensure CNMT pressure remains less than 60 psig design during steamline break accident inside CNMT
- b. 5.5 psig - to ensure CNMT pressure remains less than 60 psig design limit during large break LOCA accidents
- c. 5 1 psig - to ensure CNMT pressure remains less than 60 psig design limit during steamline break inside CNMT
- d. 5 2 psig - to ensure CNMT pressure remains less than 60 psig design limit during feedline break accident inside CNMT Answer 62 L,
- c. 5 1 psig - to ensure CNMT pressure remains less than 60 psig design limit during steamline break inside CNMT
Question 63 BO450008 (1 point(s))
--. The following plant conditions exist:
- Rx power 95%
- Alarm 1-27 Rotor Eccentrity or Vibration Alarm is lit
- Turbine Bearing Vibrations Bearing 1 - 1.2 mils 7 - 2.5 mils 2 - 1.5 mils 8 - 4.5mils 3 - 2.0mils 9 - 11.0 mils 4 - 1.7mils 5 - 2.8 mils 6 - 3.0mil~
The correct operator response is:
- a. Trip the turbine, go to AP-TURB.1 Turbine trip without Rx Trip
- b. Trip the turbine, go to E-0 Rx Trip or SI.
- c. Reduce turbine load to stabilize vibration.
- d. Adjust generator hydrogen temperature or turbine lube oil temp or exciter cooling to stabilize vibrations.
Answer 63
- d. Adjust generator hydrogen temperature or turbine lube oil temp or exciter cooling to stabilize vibrations.
Question 64 C000.1280 (1 point(s))
L Which one of the following is the limit above which action must be taken to reduce Oxygen Concentration in the Waste Gas Decay Tanks?
- a. Unlimited 2%
- b. Unlimited 4%
- c. 4.1% 5%
- d. 4.1% 20%
Answer 64
- a. Unlimited 2%
Question 65 C078.0006 (1 P O W S ) )
- Which of the following statements best describes automatic response of instrument and service air system when instrument air demand exceeds supply: (Assume the 1C Instrument Air Compressor is in service, systems are split and the Service Air Compressor is running)
- a. The service air system starts supplying instrument air at 105 psig and then the Auto instrument air compressor starts at 90 psig.
- b. The Auto instrument air compressors start at 105 psig and the emergency diesel driven air compressor starts at 90 psig.
- c. When instrument air pressure drops to 115 psig, the auto instrument air compressors Start.
- d. When instrument air pressure drops to 105 psig, the Auto instrument air compressors start and at 90 psig the service air begins to supply instrument air header.
Answer 65
'W d. When instrument air pressure drops to 105 psig, the Auto instrument air compressors start and at 90 psig the service air begins to supply instrument air header.
Question 66 C000.0977 (1 point(s))
\-- Given the following information:
- Reactor defueling operations are in progress.
- The control room has received a report that a fuel assembly has slipped free of the manipulator crane and fallen back onto core.
- Personnel on the refueling phone circuit report that a lot of bubbles are rising from the core area.
Which ONE of the following actions of the Control Room is required to be performed FIRST per RF-65.4, Fuel Handling Accidents.
A. Sound the containment evacuation alarm.
B. Dispatch personnel to verify containment integrity is established.
C. Shift the auxiliary building ventilation lineup to place the charcoal filter in service.
D. Notify the NRC and the local county authorities.
L-Answer 66 A. Sound the containment evacuation alarm.
Question 67 B010.0027 (1 point(s))
._.- Given the following conditions:
0 Reactor power is 50%
0 Pressurizer level is 43%
Pressurizer level selector switch is in the normal position (428/427)
The operators receive the following alarms:
A-4, "Regen Hx Outlet Hi Temp" F-4, "Pressurizer Level Deviation" F-28, "Pressurizer High Level Channel Alert" What malfunction caused these alarms and what are the operators' actions in response to the alalXlS?
- a. LT-428 Pressurizer level failed high; take manual control of charging to increase charging speed, select alternate level channel for control.
- b. LT-428 Pressurizer level failed high; take manual control of charging to reduce charging pump speed, verify backup heaters on.
L c. LT-428 Pressurizer level failed low; take manual control of charging and control pressurizer level, restore letdown.
- d. LT-428 Pressurizer level failed low; take m a n d control of charging and increase charging pump speed, restore proportional and backup heaters.
Answer 67
- a. LT-428 Pressurizer level failed high; take manual control of charging to increase charging speed, select alternate level channel for control.
Question 68 C000.1281 (1 point(s))
With the unit in Mode 1, which ONE of the following would require LCO entry?
- a. RCS Tave at 575°F
- b. Pressurizer Pressure at 2200 psig
- c. Containment Pressure at 0.85 psig
- d. Pressurizer Level at 72%
Answer 68
- b. Pressurizer Pressure at 2200 psig
Question 69 COOO. 1282 (1 P O W S ) )
v The following plant conditions exist during a mid-cycle reactor startup:
0 The MSIVs are closed The reactor is critical below the point of adding heat (POAH) 0 Tavg is at the normal No-Load value 0 RCS Boron is 850 PPM 0 Bank D at 180 steps 0 The RO withdraws control rods 12 steps 0 Startup rate is 0.3 DPM Without further action, which ONE (1) of the following describes the plant response to the rod withdrawal?
When the Point of Adding Heat is reached,
- a. Tavg, power level, pressurizer pressure and leve, will increase until the reactor trips at 10% power.
- b. Tavg, power level, pressurizer pressure and level will increase until the condenser steam dumps open to stabilize power at a higher level.
v c. Tavg, power level, pressurizer pressure and level will increase until the atmospheric steam dumps open to stabilize power at a higher level.
- d. Tavg will increase which will add negative reactivity causing power to decrease, which will drive the reactor sub-critical unless rods are withdrawn M e r .
Answer 69
- c. Tavg, power level, pressurizer pressure and level will increase until the atmospheric steam dumps open to stabilize power at a higher level.
Question 70 C300.0348 (1 point(s))
L Which of the following would be the result of improper control rod bank overlap.
- a. Inadequate Shutdown Margin following a reactor trip.
- b. Criticality would occur with rods below the Rod Insertion Limits.
- c. Power peaking factors may exceed acceptable limits
- d. Reactivity addition rates on a reactor trip may be less than assumed in the Accident Analysis.
Answer 70
- c. Power peaking factors may exceed acceptable limits
Question 71 C000.1283 (1 P O W S ) )
1
- A point source in the Auxiliary Building is reading 500 me& at distance of two (2) feet. Two options exist to complete rework on a valve near this radiation source.
Option 1: Operator X can perform the assignment in thirty minutes working at a distance of four feet fiom the point source.
Option 2: Operators Y and 2,who have been trained in the use of a special extension tool can perf'orm the same task in 75 minutes at a distance of eight feet fiom the point source.
Which of the following options is preferable and consistent with the AL.AFL4 program?
- a. Option 1 as Xs exposure is 32.25 mrem.
- b. Option 1 as Xs exposure is 62.50 mrem
- c. Option 2 as the exposure per person is 39.06 mrem
- d. Option 2 as the exposure per person is 78.12 mrem Answer 71
-i
- b. Option 1 as Xs exposure is 62.50 mrem
Question 72 C000.1284 (1 point@))
L- The Shift Supervisor has directed the plant shutdown based on RCS specific activity exceeding TS 3.4.16 limits.
In the event of a subsequent SGTR, which one of the following actions is designed to limit the release of radioactivity?
- a. RCS is cooled down below 500°F
- b. MSN'sare dosed
- c. SG atmospheric dump valve setpoints are raised
- d. Maximum condensate polishers are placed in service Answer 72
- a. RCS is cooled down below 500°F
Question 73 B000.0002 (1 point(s))
- During a large break LOCA event, plant conditions have been met to transition to ES- 1.3 (Transfer to Cold Leg Recirculation) fiom E-1 (Loss of Reactor or Secondary Coolant). While performing Step 5 of ES-1.3, the STA informs the Shift Supervisor that he has received a red path status tree on core cooling.
Which one of the following describes the proper procedure under these conditions?
- a. Immediately transition to FR-C. 1
- b. Complete ES-1.3 then transition to FR-C. 1
- c. Once in ES-1.3, CSFST no longer apply. Continue in ES-1.3. No transition to FR-C.1 should be made.
- d. Complete ES-1.3 until on cold leg recirc, then transition to FR-C. 1 Answer 73 L- d. Complete ES-1.3 until on cold leg recirc, then transition to FR-(2.1.
Question 74 COOO.1065 (1 point(s))
-- Which of the following describes the requirements for the use of Alarm Response (AR) procedures for single alarms.
- a. AR procedures shall be referenced for every alarm received during normal operations and unexpected alarms during abnormal or emergency events.
- b. AR procedures shall be referenced for unexpected alarms unless the alarm is of a basic nature.
- c. AR procedures shall be referenced for all unexpected alarms which involve systems with Tech Spec operability requirements.
- d. AR procedures need not be referenced if one of the operators verbalizes the alarm to the control room and states whether it is expected or unexpected.
Answer 74
- b. AR procedures shall be referenced for unexpected alarms unless the alarm is of a basic nature.
Question 75 C000.1285 (1 point(s))
---, Due to current plant conditions, the Emergency Coordinator has declared a Site Area Emergency (SAE). You are the Head Control Operator (HCO). From the list below, select the actions that are designated as your responsibilities per EPIP 5-7:
- 1. Monitor plant parameters to maintain the plant in a safe condition
- 2. Provide perspective in assessment of plant conditions and actions to be taken for safety of the plant
- 3. Sound the alarm and make announcements as necessary
- 4. Check that the Control Room Ventilation System is in recirculation mode
- 5. Assist the Shift Supervisor in any assessment functions identified
- a. 1 , 3 , 4 , 6
- b. 1 , 2 , 3 , 4 , 6 v
- c. 1,3,4,5,6
- d. All Answer 75
- a. 1, 3 , 4 , 6
RO Reference Material Index 4
ECA-1.1 Step 4 ER-NIS. 1 AP-SG.l Steps 1-7 P-9 Radiation Monitor Setpoint Table ITS Section 3.9.3 AP-TURB.3 Steps 1-2
EOP : TITLE:
REV: 2 2 ECA-1.1 LOSS OF EMERGENCY COOLANT RECIRCULATION PAGE 6 of 3 2 I' I II 4 Determine CNMT Spray Requirements:
a . Determine number of CNMT s p r a y pumps r e q u i r e d from t a b l e :
CNMT CNMT RWST CNMT REXIRC FANS SPRAY PUMP S LEVEL PRES SURE RUNNING REQUIRED
~
GREATER THAN 60 PSIG - 2 GREATER 0 OR 1 2 THAN BETWEEN 28% 28 PSIG AND 6 0 PSIG 2 OR 3 1 ALL 0
_ _ _ _ _ ~
LESS THAN 28 PSIG I 0 GREATER THAN 60 PSIG 2 BETWEEN 15% 0. 1. 2. OR 3 I 1 BETWEEN 2 8% 28 PSIG AND 60 PSIG ALL 0 LESS THAN 28 PSIG 15%
This S t e p c o n t i n u e d on t h e n e x t p a g e .
1 1 EOP : TITLE:
REV: 2 2 ECA-1.1 LOSS OF EMERGENCY COOLANT RECIRCULATION PAGE 7 of 3 ;
I' I I 3
( S t e p 4 c o n t i n u e d from p r e v i o u s page) b . CNMT s p r a y pumps r u n n i n g - EQUAL b . Manually o p e r a t e CNMT s p r a y TO MINIMUM NUMBER R E Q U I R E D pumps a s n e c e s s a r y .
I F CNMT s p r a y pump(s) must be s t o p p e d , THEN perform t h e following:
- 1) Reset CNMT s p r a y .
P l a c e CNMT s p r a y pump i n PUL STOP.
I F CNMT pressure less than 28 p s i g . THEN c l o s e d i s c h a r g e v a l v e s f o r i d l e CNMT s p r a y pLlmp(s).
o Pump A 3 MOV-860A MOV-860B o Pump B MOV-860C MOV-860D 3
ROCHESTER GAS AND ELECTRIC CORPORATION GINNA STATION CONTROLLED COPY NUMBER I 4 PROCEDURE NO. ER-NIS. 1 REV. NO. 18 SR MALFUNCTION i o -/c -200.3 EFFECTIVE DATE CATEGORY 1.0 REVIEWED BY:
THIS PROCEDURE CONTAINS 4 PAGES
ER-NIS. 1:1 ER-NIS. 1 SR MALFUNCTION 1 .o PURPOSE:
1.1 This procedure provides guidance t o establish operating requirements if one or both source range channels fail when required to be operable.
2.0 ENTRY CONDITIQNS/SYMPTOMS: This procedure may be entered when:
2.1 AR-E-2, Source Range Loss of Detector Vo!tage, is lit when SR should be energized, or, 2.2 Loss of or erratic SR indication, or 2.3 SR HI Voltage aoes not turn off when blocking SR, or 2.4 Source range channels do not reenergize when required.
- ~~
ER-NIS. 1 12 3 .O PRECAUTIONS :
d 3.1 Stop any refueling operation if either source range channel fails.
3.2 If instrument power fuses were pulled and reactor trip or normal shutdown takes place, it is necessary t o reinstall fuses to restore channel.
3.3 If power is less than P-6 and source ranges are not blocked, removal of control power fuses will result in a reactor trip.
3.4 During Plant Shutdown when power is LESS THAN P-6, if the source range does not energize, it may be necessary t o place the level trip to BYPASS, and momentarily remove the instrument pcwer fuses t o reset the crow oar circuit.
3.5 If source ranges will not energize due to 2 or more power ranges being deenergized, then source ranges may be restored by turning off 125 VDC power switches in REACTOR PROTECTION racks RLTR-1 and RLTR-2.
4.0 INSTRUCTI0NS :
4 NOTE: Refer to Tech Spec section 3.3, table 3.3.1-1 , Function #4 and section 3.9.2 for source range operability requirements.
4.1 If any source range is inoperable as a result of failure t o energize, THEN manually energize source range detectors by depressing P-6PERMISSIVE DEFEAT pushbuttons (2 of 2).
4.2 If one channel has failed, then perform the following:
4.2.1 Defeat the reactor trip for the failed channel by placing t h e level trip switch in the BYPASS position.
4.2.2 Defeat high flux at shutdown alarm if necessary.
ER-NIS.1:3 CAUTION DO NOT ADD POSITIVE REACTIVITY UNTIL AT LEAST ONE SOURCE RANGE CHANNEL RESTORED TO OPERABLE.
4.3 If both channels fail or can NOT be energized when required THEN perform the following:
4.3.1 Perform required actions per ITS LCO 3.3.1, Function 4.
4.3.2 Hold open the Reactor Trip Breakers.
4.3.3 Borate the RCS to at least -5% shutdown.
4.3.4 Place RMW Pump switches in PULL STOP. E a RMW pump is required for VCT makeup, THEN ensure BA flow and RMW flow controllers set to blend for a concentration greater than the requirements of Figure 5 %
SDM.
, 4.3.5 Obtain core burnup from PPCS Point ID BURNUP. Use current burnup derived from nuclear power. Refer t o Figure 5 % SDM, attached, for
-3 required boron concentration.
4.3.6 Sample the RCS for Boron Concentration every 1/2 hour until -5% SDM is reached.
4.3.7 WHEN the RCS is borated t o -5% SDM, THEN perform the following:
4.3.7.1 Set makeup control to maintain the present boron concentration.
4.3.7.2 Limit charging flow t o a maximum of 60 gprn.
4.3.7.3 Sample the RCS every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for boron concentration.
4.3.7.4 Do not perform any CVCS demineralizer flushing.
4.4 Notify I&C t o repair the faulty channel(s1.
4.5 After channel has been repaired and checked, restore it t o normal operation.
3
ER-NIS. 1 14 FIGURE 5% SDM NOTE: To obtain core burnup, use PPCS point ID BURNUP BORON CONCENTRATION (PPM) 2000 1800 1600 1400 1200 1000 I I I I I I . . ,I. . . . I! . . I . I
. . I.
' I I I I I I I I I I I I I I 1 I I . . I ~ : I I ~ I 1 1 I I 1 I ' I I I I I 1 I I I ' I : . I I I I I . I 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 CYCLE 3i BURNUP (MWD/MTU)
Containment Penetrations 3.9.3 3.9 REFUELING OPERATIONS Containment Penetrations
.3 3m9-3 LCO 3.9.3 The containment penetrations shall be in the following status:
- a. The equipment hatch shall be either:
- 1. bolted in place with at least one access door closed,
- 2. isolated by a closure plate that restricts air flow from containment, or
- 3. isolated by a roll up door and enclosure building;
- b. One door in the personnel air lock shall be closed; and
- c. Each penetration providing direct access from the containment atmosphere to the outside atmosphere shall be either:
- 1. closed by a manual or automatic isolation valve, blind flange, or equivalent, or
- 2. capable of being closed by an OPERABLE Containment Ventilation Isolation System.
-3 APPLICABILITY: During CORE ALTERATIONS, During movement of irradiated fuel assemblies within containment.
ACTIONS I 1 COMPLETION TIME
~~~~~ ~~
CONDITION REQUIRED ACTION A. One or more containment A.l Suspend CORE penetrations not in ALTERATIONS.
required status.
AND A.2 Suspend movement of immediately irradiated fuel assemblies within containment.
R.E. Ginna Nuclear Power Plant 3.9.3-1 Amendment 80
Containment Penetrations 3.9.3 SURVEILLANCE FREQUENCY S R 3.9.3.1 Verify each required containment penetration is in the 7 days required status.
SR 3.9.3.2 Verify each required containment purge and exhaust 24 months valve actuates to the isolation position on an actual or simulated actuation signal.
3 R.E. G&na Nuclear Power Plant 3.9.3-2 Amendment 80
EOP: TITLE:
REV: 3 AP-SG. 1 STEAM GENERATOR TUBE LEAK PAGE 1 of 32
-3 ROCHESTER GAS AND ELECTRIC CORPORATION GINNA STATION CONTROLLED COPY NUMBER t
(&&A RESPONSIBLE 3
EFFECTIVE DATE CATEGORY 1.0 REVIEWED BY:
EOP: TITLE:
REV: 3 AP-SG. 1 STEAM GENERATOR TUBE LEAK PAGE 2 of 32
-3 A. PURPOSE - This procedure provides the necessary instructions to be taken in the event of a Steam Generator tube leak within the capacity of the charging pumps.
B. ENTRY CONDITIONS/SYMPTOMS
- 1. ENTRY CONDITION - This procedure is entered from:
- a. AP-RCS.l, REACTOR COOLANT LEAK, if S / G tube leak is indicated.
- b. AR-PPCS-1, SGTL INDICATED, when R-15A-5 is increasing for greater than one minute.
C. AR-RMS-15, R15 AIR EJECTOR, AR-RMS-19, R-19 STEAM GEN BLOWDOWN, when SG sample indicates a tube leakrate of greater than 5 gpd.
- d. AR-RMS-31, R31 STEAM LINE A and AR-RMS-32, R32 STEAM L I N E B when other indications of SG tube leakage exist.
- e. Shift Supervisor discretion.
- 2. SYMPTOMS - Symptoms of STEAM GENERATOR TUBE LEAK are:
-3 a. Primary to secondary tube leak rate in one S / G has been verified by sampling to be greater than or equal to 5 gpd.
- b. Either of the following indicating a leak rate of greater than or equal to 5 gpd increasing for greater than one minute:
o R15A5G OR o Sping (using R15A5 conversion table, Curve Boo-k # 0 6 - 0 0 4 )
-3
EOP : TITLE:
REV: 3 AP-SG. 1 STEAM GENERATOR TUBE LEAK PAGE 3 of 32
-3 STEP H ACTION/EXP
- 1 Monitor PRZR L e v e l - STABLE -
IF PRZR l e v e l d e c r e a s i n g , THEN AT PROGRAM LEVEL s t a r t a d d i t i o n a l c h a r g i n g pumps ana i n c r e a s e speed a s n e c e s s a r y t o s t a b i l i z e PRZR l e v e l .
IF PRZR l e v e l continues t o decrease, c l o s e letdown i s o l a t i o n , AOV-427 and e x c e s s letdown AOV-310.
IF available c h a r g i n g pumps a r e r u n n i n g a t maximum s p e e d w i t h letdown i s o l a t e d , AND PRZR l e v e l is d e c r e a s i n g , THEN t r i p t h e r e a c t o r and go t o E - 0 . REACTOR TRIP OR SAFETY INJECTION.
- 2 Monitor S / G Tube L e a k R a t e :
a . E s t i m a t e SIG t u b e l e a k r a t e :
3 o ChargingILetdown mismatch o A VCT o PPCS P o i n t R15A5G o SPING ( u s i n g R15A5 c o n v e r s i o n t a b l e , Curve Book # 0 6 - 0 0 4 )
b . Check t o t a l RCS t o s e c o n d a r y b. Go t o S t e p 8 .
l e a k r a t e - LESS THAN 1 GALLON PER MINUTE (1440 GPD) 3
LOP : TITLE:
REV: 3 AP-SG. 1 STEAM GENERATOR TUBE LEAK PAGE 4 of 32 r
3 Trend S / G Leak Rate:
- a. While continuing with this procedure, perform Part A of ATT-16.1. ATTACHMENT SGTL
- b. Determine S/G leak rate:
o PPCS point R15A5G
-0R-o SPING (using R15A5 conversion table, Curve Book #06-004)
EOP: TITLE:
REV: 3 AP-SG. 1 STEAM GENERATOR TUBE LEAK PAGE 5 of 32 4 Determine If Shutdown Required:
- a. S/G tube leak rate - GREATER a. Perform the following:
THAN OR EQUAL T O 5 GPD
- 1) Notify higher supervision
- 2) Return to guidance in effect
- b. S/G tube leak rate - GREATER b. Perform the following:
THAN OR EQUAL T O 30 GPD
- 1) Notify higher supervision 2 ) Determine S/G tube leak rate at least once per hour o PPCS point R 1 5 A 5 G
-0R-o SPING (using R 1 5 A 5 conversion table, Curve Book # 0 6 - 0 0 4 )
- 3) IF leak rate is stable OR decreasing f o r 4 consecutive samples. THEN reduce leak rate trending to at least once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
o PPCS point R 1 5 A 5 G
-0R-o SPING (using R 1 5 A 5 conversion table, Curve Book #06-004)
- 4) Return t o Step 1.
This Step continued on the next page.
EOP : IIILt:
REV: 3 AP-SG. 1 STEAM GENERATOR TUBE LEAK PAGE 6 of 3 2 (Step 4 continued from previous page)
I c. S/G tube leak rate - GREATER THAN OR EQUAL TO 75 GPD
- c. Perform the following:
- 1) Notify higher supervision 2 ) Determine S / G leak rate every 15 minutes (IF performing a procedural loop, THEN use trending rates previously determined in Step 5) o PPCS p o i n t R15A5G
-0R-o SPING (using R15A5 conversion table, Curve Book # 0 6 - 0 0 4 )
3 ) Go to Step 5
- d. S/G tube leak rate - STABLE OR d . Perform the following:
INCREASING
- 1) Notify higher supervision
- 2) IF the leak rate spiked to greater than 144 gpd. THEN go to Step 6.
IF the leak rate spiked to less than 144 gpd but has remained greater than 75 gpd for at least one h o u r . THEN go to Step 6.
IF the leak rate spiked to less than 144 gpd @ Jhas J
decreased to less than 75 gpd within one hour. THEN return to Step 4b.
- e. Go to Step 6.
EOP: TITLE:
REV: 3 AP-SG -1 STEAM GENERATOR TUBE LEAK PAGE 7 of 3 2
~
RESPONSE
~~~~ ~
NOT^
5 Determine T r e n d i n g Requirements:
a . S/G l e a k r a t e - INCREASES LESS a . Return t o S t e p 1.
THAN 10% DURING A ONE HOUR PERIOD o PPCS p o i n t R15A5G o SPING ( u s i n g R15A5 c o n v e r s i o n t a b l e , Curve Book # 0 6 - 0 0 4 )
o Grab sample b . Trend S/G l e a k r a t e a t l e a s t once p e r h o u r o PPCS p o i n t R15A5G
-0R-o SPING ( u s i n g R15A5 c o n v e r s i o n t a b l e , Curve Book # 0 6 - 0 0 4 )
c . Review E - 3 , STEAM GENERATOR TUBE RUPTURE.
d . A t l e a s t 24 h o u r s s i n c e o n e - h o u r d . R e t u r n t o S t e p 1.
l e a k r a t e t r e n d i n g began.
e . S/G l e a k r a t e - INCREASES LESS e . R e t u r n t o S t e p 1.
THAN 10% D U R I N G t h e l a s t 2 4 HOURS f . Trend S I G l e a k r a t e a t l e a s t once p e r 4 h o u r s o PPCS p o i n t R15A5G
-0R-o SPING ( u s i n g R15A5 c o n v e r s i o n t a b l e , Curve Book # 0 6 - 0 0 4 )
- g. Return t o S t e p 1 .
EOP: TITLE:
REV: 3 AP-SG.1 - STEAM GENERATOR TUBE LEAK PAGE 8 of 3 2 3 ACTION/EXPECTED RESPONSE 6 Confirm S / G L e a k R a t e :
- a. At least two independent a. IF an instrument failure can be indications - TREND IN THE SAME confirmed, THEN return to DIRECTION guidance in effect. Otherwise return to Step 4 .
o R-31 o R-32 o PPCS point R15A5G OR SPING (using R15A5 conversion table, Curve Book # 0 6 - 0 0 4 )
o R-15 o R-19 o Grab samples (only allowed for confirming leaks less than 1 4 4 gpd which increase 3 at l e s s than 30 gpdlhr)
- b. Notify higher supervision
- c. While continuing with this procedure, perform Parts A B of ATT-16.1. ATTACHMENT SGTL
REV: 3 STEAM GENERATOR TUBE LEAK PAGE 9 of 32 ACTION/EXPECTED RESPONSE t . . * *
- t . . t t t t
- C . t t
- t * * * * * ~ * * * * * * * * * * ~ . . .
- CAUTION MAINTAIN PRZR LEVEL AT 50% TO ACCOMMODATE RCS SHRINKING DURING PLANT SHUTDOWN AND COOLDOWN I
C * ~ . . t t t t
- t t t . t t
- t * * * * * * * * * * * * * * * * * * * . . * .
NOTE: Measured leakrate depends on RCS activity level. which may increase or decrease during power reduction, depending on fuel condition.
Therefore. once the power reduction has begun, R-15A should NOT be used to determine if the rate o f power reduction should be changed.
I 7 I n i t i a t e P l a n t Shutdown
- a. Determine S/G leakrate every 1 5 minutes I o PPCS point R15A5G
-0R-o SPING (using R15A5 conversion t a b l e , Curve Book # 0 6 - 0 0 4 )
- b. Check S / G leak rate - INCREASING b. Perform the following:
LESS THAN 30 GPD/HR
- 1) Reduce power to less than 50%
o Leak increases less than 15 RTP within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of gpd in 30 minutes (R15A5G or exceeding 30 gpd/hr. (Refer SPING) to AP-TURB.5. RAPID LOAD REDUCTION) o Grab samples indicate less than 30 GPD increase in 60 2 ) Be in Mode 3 within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> mi nutes of exceeding 30 gpd/hr.
(Refer t o 0-2.1. NORMAL SHUTDOWN TO HOT SHUTDOWN) 3 ) Go to Step 7g.
This Step continued on the next page.
LOP: TITLE:
REV: 3 AP-SG. 1 STEAM GENERATOR TUBE LEAK PAGE 10 of 3 2 ACTION/EXPEC (Step 7 continued from previous page)
C. Check R15A5 - OPERABLE c. Perform the following:
- 1) Be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of exceeding 7 5 gpd. (Refer to 0-2.1. NORMAL SHUTDOWN TO HOT SHUTDOWN) 2 ) Go to Step 7g.
I Check S / leak rate - HA I . Perform the following:
REMAINED LESS THAN 144 GPD SINCE LEAK INITIATION 1) Be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of exceeding 144 gpd. (Refer to 0 - 2 . 1 , NORMAL SHUTDOWN TO HOT SHUTDOWN)
- 2) Go t o Step 7g.
- e. Check S/G leak rate - REMAINED e. Return to Step 1.
GREATER THAN 75 GPD FOR GREATER THAN ONE HOUR f . Be in Mode 3 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of exceeding 75 gpd (Refer to 0 - 2 . 1 , NORMAL SHUTDOWN TO HOT SHUTDOWN) g - Refer to ITS o LCO 3 . 4 . 1 3 o LCO 3.4.16 o LCO 3 . 7 . 1 4 h . Check reactor IN MODE 3 h. Return to Step 7a.
- i. Go to Step 26
c c P-9: 15 c
Rev. No. 94 EIN Name Release Rate Limit High Alarm Setpoint Warning Alarm Setpoint R- 1 Control Room N/A +
2 mRad/hr (2.OE 00) 1.2E + 00 mRad/hr R-2 Containment N/A 50 mRad/hr (5.OE + 01 ) 3.OE + 01 mRad/hr R-3 Radio Chemistry Lab N/A 2 mRad/hr (2.OE+00) 1.2E + 00 mRad/hr R-4 Charging Pump Room N/A 100 mRad/hr (1.OE + 021 6.OE+01 mRad/hr R-5 Spent Fuel Pool N/A 25 mRad/hr (2.5E + 01 ) +
1.5E 01 mRad/hr
~
R-6 Nuclear Sample Room N/A 50 mRad/hr (5.OE+011 3.OE + 01 mRad/hr I lncore Detector Area I I
~~
R-7 N/A +
100 mRad/hr (1.OE 02) 6.OE + 01 mRad/hr R-8 Drumming Station N/A 30 mRad/hr (3.OE +01) 1.8E +01 mRad/hr R-9 Letdown Line N/A +
200 mRad/hr (2.OE 02) +
1.2E 02 mRad/hr R-1OA Cnmt Vent Iodine (1 fan) 7.88E2 cpm 3.15E2 cpm above bkg 1.60E2 cpm above bkg (2 fan) 8.56E2 cpm 3.42E2 cpm above bkg 1.70E2 cprh above bkg (Minipurge) N/A 1.40E4 cpm above bkg 7.00E3 cpm above bkg 4
R-1OB Plant Vent Iodine 1.82E2 cpm 8.00E1 cpm above bkg 4.00E1 cpm above bkg R-11 Cnmt Vent Particulate I 1 (1 fan) 5:02E4 cpm 2.00E4 cpm 1.00E4 cpm (2 fan) 5.68E4 cpm 2.30E4 cpm 1.20E4 cpm (Minipurge) N/A 2.00E4 cpm 1.00E4 cpm R-12 Cnmt Vent Noble Gas (1 fan) 3.71E6 cpm 1.50E6 cpm 7.50E5 cpm (2 fan) 2.68E6 cpm 1.00E6 cpm 5.00E5 cpm (Minipurge) N/A 1.50E6 cpm 7.50E5 cpm R-13 Plant Vent Particulate 6.27E3 cpm 2.50E3 cpm 1.30E3 cprn R-14 Plant Vent Noble Gas 3.OE5 cpm 1.20E5 cpm 6.OE4 cDm
c P-9: 16 Rev. No. 94
/
EIN Name Release Rate Limit High Alarm Setpoint Warning Alarm Setpoint R-15 Air Ejector & Gland Seal 1.47E5 cpm 5.9E4 cpm 2.94E4 cpm Exhaust R-16 Containment Fan Coolers 3.25E +03 cpm 1.30E +03 cpm 6.50E + 02 cpm R- 17 Component Cooling Water 8.50E + 05 cpm 3.40E+05 cpm 1.70E+ 05 cpm R-18 Liquid Waste Disposal 1.80E -+ 05 cpm 7.20+04 cprn > Bkgnd 3.65E+04 cpm Bkgnd = 1.OOE+03 cpm Setpoint = 7.30E + 04 cpm R-19 Steam Generator Blowdown 1.OOE + 06 cpm 5.00E+03 cpm > Bkgnd 2.63E+03 cpm Bkgnd = 2.50E+02 cpm
+
Setpoint = 5.25E 03 cpm R-20A Spent Fuel Pool Hx 2.04E+04 cpm 8.00E+03 cpm > Bkgnd 4.13+03 cpm Bkgnd = 2.50+02 cpm Setpoint = 8.25E + 03 cpm R-20B Spent Fuel Pool Hx 2.60E + 03 cpm +
1.OOE 03 cpm > Bkgnd +
1.OOE 03 cpm Bkgnd = 1.OOE +03 cpm
+
Setpoint = 2.00E 03 cpm R-21 Retention Tank 2.50E 04cpm +
1.OOE 04 cpm > Bkgnd N/A 8kgnd = 3.00E+02 cpm Setpoint = 1.03E + 04 cpm R-22 High Conductivity Waste 4.60E +04 cpm 1.80E + 0 4 cpm > Bkgnd N/A Tank Bkgnd = 2.50E+02 cpm Setpoint = 1.83E+04 cpm R-23 Condensate Demineralizer N/A 5 mRad/hr 1 mRad/hr Resin Bed A R-24 Condensate Demineralizer N/A 5 mRadlhr 1 mRad/hr Resin Bed 6
P-9: 1 7 Rev. No. 94 EIN Name Release Rate Limit High Alarm Setpoint Warning Alarm Setpoint R-25 Condensate Demineralizer N/A 5 mRad/hr 1 mRad/hr Resin Bed C R-26 Condensate Demineralizer N/A 5 mRad/hr 1 mRad/hr Resin Bed D I I R-27 HCWT & LCWT N/A 5 mRad/hr N/A R-28 Condensate Demineralizer N/A 5 mRad/hr N/A Resin Regeneration Tank R-29 A Containment High Range N/A 1.OOE + 02 R/hr +
1.OOE 01 R/hr R-30 8 Containment High Range N/A +
1.OOE 02 R/hr 1.OOE+ 01 R/hr R-31 A Steam Line 1.OOE-01 mRad/hr 1.00E-01 mRad/hr @ PPCS & DAM N/A 3.00E-01 mRad/hr @ RMS3 R-32 8 Steam Line 1.00E-01 mRad/hr 1.00E-01 mRad/hr @ PPCS & DAM N/A 3.00E-01 mRad/hr @ RMS3 R-33 Nuclear Sample Room Wide N/A 1.OOE + 02 mRad/hr I 5.00E + 00 mRad/hr Range R-34 Cnmt Spray Pump Wide N/A 1.OOE + 02 mRad/hr 1.OOE + 01 mRad/hr Range R-35 PASS Panel Wide Range N/A +
1.OOE 02 mRad/hr 5.00E f 00 mRad/hr N/A .25 mR/hr .20 mR/hr Radiation Monitor N/A .25 mR/hr .20 mR/hr Radiation Monitor
/' /
t P-9: 18 Rev. No. 94 EIN Channel Name Trend Alarm* Release Rate Limit High Alarm Setpoint Warning Alarm Setpoint RM-12A 1 Beta Particulate 100% / minute 1.33 uCi/sec 1.90E-01 pCi 9.00E-02 pCi RM-12A 2 Alpha Particulate N/A 1.33 pCi/sec 3.00E + 02 cpm 2.00E + 02 cpm RM-12A 3 Iodine 131 100% / minute 5.7E-2 pCi/sec 8.00E-3 pCi 4.00E-3 uCi
~~ -~
RM-12A 4 Bkgnd Iodine N/A N/A N/A N/A RM-12A 5 Low Range Gas 40% / minute 2.00E-1 pCi/cc (1 fan) 4.00E-2 pCi/cc (1 fan) 2.00E-2 pCi/cc (1 fan) 1.50E-1 uCi/cc (2 fan) 3.00E-2 uCi/cc (2 fan) 1.50E-2 uCi/cc 12 fanl
- ~ - _ _
RM-12A 6 Area Gamma N/A N/A +
1.OOE 02 mRad/hr 5.00E +00 mRad/hr RM-12A 7 Mid Range Gas N/A 2.00E-1 pCi/cc (1 fan) 2.OOE-1 p C k c (1 fan) 8.00E-2 pCi/cc (1 fan) 1.50E-2 uCi/cc (2 fan) 1.50E-1 uCi/cc (2 fan) 6.00E-2 uCi/cc (2 fan)
I RM-12A 8 Bkgnd Gamma N/A N/A N/A N/A RM-12A 9 High Range Gas N/A 2.00E-1 pCi/cc (1 fan) 2.00EO pCi/cc (1 fan) 2.00E-01 pCilcc (1 fanl 1.50E-1 uCi/cc (2 fan) , 1.50EO uCi/cc (2 fan) I 1.50E-1 uCi/cc (2 fan)
~-
I I I Beta Particulate I 100% / minute I ! - 1- - 1
~
RM-14A 1 1.06EO pCi/sec 4.1E-2 pCi 2.1 E-2 i C 7 RM-14A 2 Alpha Particulate N/A 1.06Eb clCi/sec 3.00E + 02 cpm 2.00E + 0 2 cpm RM-14A 3 Iodine 131 100% / minute 4.60E-2 pCi/sec 1.80E-03 pCi 9.00E-04 pCi
- ~~ ~~ ~ ~ ~
RM-14A 4 Bkgnd Iodine N /A N/A N/A NIA RM-14A 5 Low Range Gas 40% / minute 1.67E-02 pCi/cc 6.68E-03 pCi/cc 3.34E-03 pCi/cc RM-14A 6
~
Area Gamma N/A N/A +
1.OOE 0 2 mRad/hr 5.00E + 00 mRad/hr RM-14A 7 Mid Range Gas N/A 1.67E-02 pCi/cc 3.46E-02 pCi/cc 1.67E-02 pCi/cc RM-14A 8 Bkgnd Gamma N/A N/A N/A N/A RM-14A 9 High Range Gas N/A 1.67E-02 p C i h 1.67E-01 pCi/cc 8.35E-02 pCi/cc
c i P-9: 19 Rev. No. 94 c
DIRECT Alignment (Preferred alignment for normal operation) 1I EIN I Channel I Name I Trend Alarm* I Release Rate Limit I High Alarm Setpoint I Warning Alarm Setpoint RM-15A 5 Low Range Gas N/A 3.14EO pCi/cc 3.14E-02 pCi/cc 3.14E-02 pCi/cc RM-15A 6 Area Gamma N/A N/A 1.OOE + 02 mRad/hr 5.00E + 00 mRad/hr
~~ -~
RM-15A 7 Mid Range Gas N/A 3.14EO pCi/cc 1.26EO pCi/cc 6.3E-01 pCilcc RM-15A 8 Bkgnd Gamma N/A N/A N/A N/A 11RM- 15A I 9 I High Range Gas I NIA I 3.14EO pCilcc I +
1.26E 01 pCi1cc I 6.28E0 pCi/cc I DILUTED Alignment I EIN IIRM-15A I Channel 5 I Name Low Range Gas I Trend Alarm*
N/A I Release Rate Limit 1.56E-02 pCiIcc I High Alarm Setpoint 6.24E-03 pCilcc I Warning Alarm Setpoint 3.1 2E-03 p W c c 11 I I I I I 1
~~
IIRM-lSA 6 Area Gamma NIA I NIA 1 .OOE+ 02 mRad/hr +
5 . O O E 00 mRad/hr ~
RM-15A 7 Mid Range Gas NIA 1.56E-02 pCi!cc 6.24E-02 pCilcc 3.1 2E-02 pCilcc RM-15A 8 Bkgnd Gamma NIA N/A N/A N/A RM-15A 9 High Range Gas N/A 1.56E-02 pCi1cc 1.56E-01 pCiIcc 7.8E-02 pCIIcc
Containment Penetrations 3.9.3 3.9 REFUELING OPERATIONS 3.9.3 Containment Penetrations LCO 3.9.3 The containment penetrations shall be in the following status:
- a. The equipment hatch shall be either:
- 1. bolted in place with at least one access door closed,
- 2. isolated by a closure plate that restricts air flow from containment, or
- 3. isolated by a roll up door and.enclosurebuilding; .
- b. One door in the personnel air lock shall be closed; and
- c. Each penetration providing direct access from the containment atmosphere to the outside atmosphere shall be either:
- 1. closed by a manual or automatic isolation valve, blind flange, or equivalent, or
- 2. capable of being closed by an OPERABLE Containment Ventilation Isolation System.
APPLICABILITY: During CORE ALTERATIONS, During movement of irradiated fuel assemblies within containment.
CONDITION REQUIRED ACTION COMPLETION TIME A. One or more containment A.l Suspend CORE Immediately penetrations not in ALTERAT1ONS.
required status.
AND A.2 Suspend movement of Immediately irradiated fuel assemblies within containment.
R.E. Ginna Nuclear Power Plant 3.9.3-1 Amendment 80
Gontainment renetrarions 3.9.3 I'
SURVEILLANCE FREQUENCY SR 3.9.3.1 Verify each required containment penetration is in the 7 days required status.
SR 3.9.3.2 Verify each required containment purge and exhaust 24 months valve actuates to the isolation position on an actual or simulated actuation signal.
R.E. m n a Nuclear Power Plant 3.9.3-2 Amendment 80
t EOP: TITLE:
REV: 11 AP-TURB. 3 TURBINE VIBRATION PAGE 1 of 9 ROCHESTER GAS AND ELECTRIC CORPORATION GINNA STATION CONTROLLED t o m NUMB&
RESPONSIBLE AGER EFFECTIVE DATE CATEGORY 1.0 REVIEWED BY:
3
EOP : TITLE:
REV: 11 AP-TURB. 3 TURBINE VI BRAT ION PAGE 3 of 9 ACTION/EXPEC
- 1 V e r i f y Turbine Vibration - Perform the following:
ALL BEARINGS LESS THAN 14 MILS
- a. Verify the Turbine tripped. IF Turbine is not tripped, THEN manually trip Turbine.
- b. GO to AP-TURB.1. TURBINE TRIP WITHOUT RX TRIP REQUIRED E-0.
REACTOR TRIP OR SAFETY INJECTION, as required.
EOP : TITLE:
REV: 11 AP-TURB. 3 TURBINE VIBRATION PAGE 4 of 9 RESPONSE NOT OBTAINED NOTE:-IF power r e d u c t i o n i s r e q u i r e d t h e thumb r u l e f o r i n i t i a l boron a d d i t i o n i s -2 g a l / % l o a d r e d u c t i o n . I 2 C h e c k T u r b i n e Vibration:
A a . B e a r i n g s No. 1 t h r o u g h No. 8 - a. Ar'tfempt t o s t a b i l i z e v i b r a t i o n LESS THAN 7 MILS as f o l l o w s :
o IF i n c r e a s i n g turbine speed, THEN s t o p s p e e d i n c r e a s e and evaluate. Evaluate reducing speed t o a n o n - r e s o n a n c e region. (Refer t o 0-1.2) o IF g e n e r a t o r on l i n e , THEN begin reducing load t o s t a b i l i z e v i b r a t i o n s . (Refer t o AP-TURB.5. RAPID LOAD REDUCTION) b . B e a r i n g No. 9 - LESS THAN b . Attempt t o s t a b i l i z e v i b r a t i o n s 8 . 5 MILS as follows:
o A d j u s t g e n e r a t o r hydrogen temperature,
-0R-o Adjust t u r b i n e lube o i l temperature,
-0R-o A d j u s t e x c i t e r cooling: I
-0R-o A d j u s t g e n e r a t o r seal o i l cooling. I
Exam ID: LOIT04053 Total Points: 25.00 Exam Date:
==
Description:==
2004 SRO Initial Exam Student Name:
Date: Grade:
Graded By:
Date:
Approved By:
Date:
Reviewed By Examinee:
\v Question 1 B000.1037 (I point(s))
A large vapor space LOCA has occurred. The operating crew has implemented the appropriate emergency procedures and is currently in E-1 ,Loss of Reactor or Secondary Coolant. The STA is monitoring status trees. The following indications are observed in the Main Control Room:
0 Train "A" CETs indicate 720°F 0 Train "B" CETs are de-energized 0 Thermocouple Map Display on PPCS indicates Average CETs at 730°F 0 RVLIS indicates 45%
0 RCS pressure is 350 psig 0 "A" RCP is running Core cooling is and will be mitigated by performing
- a. INADEQUATE; FR-C. 1,Response to Inadequate Core Cooling
- b. SATURATED; FR-C.3, Response to Saturated Core Cooling
-1
- c. ADEQUATE; E-1,Loss of Reactor or Secondary Coolant
- d. DEGRADED; FR-C.2, Response to Degraded Core Cooling Answer 1
- d. DEGRADED; FR-C.2, Response to Degraded Core Cooling 1
Question 2 C000.0808 (1 point(s))
L Assume the operators have just started a depressurization of the intact S/G's per Step 16 of FR-C. 1, Response To Inadequate Core Cooling with the following indications:
- Core exit TCs at 1250°F and decreasing
- SG pressures 900 psig and decreasing
- RWST level just decreased to 25%
Select the appropriate action for the above conditions.
- a. Continue in FRC.l until directed to ES-1.3, Transfer to Cold Leg Recirculation by step 22.
- b. Transfer to ES-1.3, Transfer to Cold Leg Recirculation as soon as core exit TC less than 1200 degrees F. Initiate cold leg recirculation, then return to FRC.1 step 16.
- c. Complete step 16 ie; SG < 200 psig and Th less than 400 degrees, then transfer to ES-1.3,Transfer to Cold Leg Recirculation. Initiate cold leg recirculation, then return to FRC. 1.
- d. Immediately transfer to ES-1.3, Transfer to Cold Leg Recirculation while continuing SG depressurization. Initiate cold leg recirculation, then return to FRC. 1 step 16.
v Answer 2
- d. Immediately transfer to ES-1.3, Transfer to Cold Leg Recirculation while continuing SG depressurization. Initiate cold leg recirculation, then return to FRC. 1 step 16.97-043 2
Question 3 B000.1038 (1 point(s))
- The plant was operating at 100% power. The BRCP Seal Leakoff Hi Flow annunciator B-18 and the BRCP Labyrinth Seal Lo delta P annunciator B-10 were received. The operators entered AP-RCP. 1 and are preparing to start a plant shutdown per 0-2.1 in accordance with step 4b RNO when annunciator B-4, RCP B Standpipe Hi Level +1 Foot, is received. The HCO reports a calculated leak rate through the #3 seal to be 11 gpm based on CNMT Sump A level increase. Based on the above information, what are the initial reporting requirements for this event?
- a. Notify NY State, Monroe and Wayne Counties per EPIP 1-5, UNUSUAL EVENT BASED ON RCS LEAKAGE. Notify the NRC per 0-9.3, EVENT CLASSIFICATIONS within one hour.
- b. Notify NY State, Monroe and Wayne Counties per EPIP 1-5, UNUSUAL EVENT BASED ON RCS LEAKAGE. Notify the NRC per 0-9.3 within four hours of TS Required Shutdown.
- c. Notify the NRC per 0-9.3 within four hours of TS Required Shutdown.
- d. Notify NY State, Monroe and Wayne Counties per EPIP 1-5, ALERT BASED ON RCS LEAKAGE. Notify the NRC per 0-9.3, Event Classification, within one hour.
L Answer 3
- c. Notify the NRC per 0-9.3 within four hours of TS Required Shutdown.
3
Question 4 B320.0045 (1 point(s))
._-The plant is in CSD during a refueling outage. Loop level has been lowered. S/G nozzle dam installation is in progress. MCB Annunciator A-20 (RHR Loop Low-Flow 400 gpm) alarms.
The RHR Flow Indicator (FI-626) is fluctuating fkom 100 gpm to 400 gpm with the "A"RHR pump running. Which action is required:
- a. Place FCV-626 in manual and reduce RHR flowrate to reduce vortexing as per AP-RHR. 1, Loss of RHR
- b. Stop "A"RHR pump, raise loop level using a charging pump to loop "A"cold leg, vent RHR suction line, then restart "A"RHR pump, as per AP-RHR.2, Loss of RHR at Reduced Inventory Conditions.
- c. Stop "A"RHR pump, raise loop level via gravity feed thru MOV 856, vent RHR suction line, then restart "A"RHR pump as per AP-RHR.2, Loss of RHR at Reduced Inventory Conditions.
- d. Stop "A"RHR pump, vent RHR suction piping, then restart A RHR pump, as per AP-RHR.1, Loss of RHR.
1 Answer 4
- c. Stop "A"RHR pump, raise loop level via gravity feed thru MOV 856, vent RHR suction line, then restart "A"RHR pump as per AP-RHR.2, Loss of RHR at Reduced Inventory Conditions.
Ref: 000025 WA: EKl.01 3.9/4.3 TC # LOR 2003-037 TC # LOR 2003-038 4
Question 5 COOO.1017 (1 point(s))
b Given the following plant conditions:
- Steam Generator tube rupture has occurred with a concurrent loss of offsite power
- All other systems/equipment are available
- The initial cooldown required by E-3 has been completed, and the shift crew is preparing to depressurize the RCS Which ONE of the following statements is correct regarding the effects of the impending depressurization?
- a. Actual liquid mass in the RCS will not change, but indicated PZR level will increase (due to the PZR steam space break phenomenon).
- b. Actual liquid mass in the RCS will decrease due to the response of the charging pumps to the probable bubble which will form in the vessel head, but indicated PZR level will increase.
- c. Actual liquid mass in the RCS will increase, and both indicated and actual PZR level will increase.
u
- d. Actual mass in the RCS will not change, but indicated PZR level will increase due to the formation of a bubble in the reactor vessel head.
Answer 5
- c. Actual liquid mass in the RCS will increase, and both indicated and actual PZR level will increase.
5
Question 6 B000.0170 (1 point(s))
L A LOCA has occurred inside containment. All systems responded as required. The staff is presently at step 18 of E- 1 "Loss of Reactor or Secondary Coolant". Given the following conditions, and assuming all appropriate actions are taken, which one of the below listed procedures will be used to place the plant in cold shutdown?
- SI flow equals 400 gpm and is steady
- RCS pressure is stable at 1380 psig
- CETs stable at 500 degrees F
- Containment conditions are not adverse
- SG levels both 20% and stable
- SG pressures both at 675 psig and stable
- Electrical bus alignment normal for unit post-trip conditions
- RWST level 88% and decreasing slowly
- c. ES-1.3, Transfer to Cold Leg Recirculation
- d. ES-0.2, Natural Circulation Cooldown.
'L Answer 6
Question 7 B000.0380 (1 point(s))
b Immediately following the completion of the immediate actions of E-0, Reactor Trip or Safety Injection, the following conditions exist:
- RCS pressure - 1780 psig
- Core Exit TCs - 551 degrees F
- S/G pressures - (A,B) - 1000 psig, 400 psig & decreasing
- S/G N.R. levels (A,B) - 0%, 0%
- Containment pressure - 6.3 psig
- Pressurizer level - 6% and decreasing
- Total feed flow to S/G A - 0 gpm
- Total feed flow to S/G B - 100 gpm Assuming these conditions exist and cannot be improved as you progress through E-0, which one of the following procedures is entered from E-O?
- a. E-1,Loss of Reactor or Secondary Coolant.
- b. E-2, Faulted Steam Generator Isolation.
- c. ES- 1.1, SI Termination.
- d. FR-H.1, Response to Loss of Secondary Heat Sink.
Answer 7
- d. FR-H. 1, Response to Loss of Secondary Heat Sink.
(SRO Transition) 7
Question 8 BO 15.0002 (1 point(s))
\ The following conditions exist when Source Range Channel N-32 indication drops to < 1.O cps:
S.R. Channel N-3 1 = 2 x 1O2 cps RCS dilution in progress in preparation for startup Reactor trip breakers closed Shutdown bank withdrawn Which one of the following is a required action associated with the inoperability of N-32?
- a. Restore within 1 hr or have Rx trip breakers open in next hour
- b. Suspend the RCS dilution and any other positive reactivity addition.
- c. Within one hour open the reactor trip breakers.
- d. No limitation, LCO is satisfied
~L Answer 8
- b. Suspend the RCS dilution and any other positive reactivity addition.
8
Question 9 B000.1040 (1 point(s))
--- Given the following plant conditions:
0 There is welding in progress in the Auxiliary Building in the Charging Pump Room with a continuous fire watch posted. The fire system for Charging Pump Room is disconnected (ZO 1) 0 R-4, Charging Pump Room, radiation alarm is received 0 An announcement is made to evacuate the Charging Pump Room Which ONE (1) of the following describes the actions regarding the maintenance of the fire watch.
- a. The fire watch will be instructed to evacuate the area and re-establish the fire watch as soon as possible.
- b. The fire watch will be instructed to remain in the area for 10 minutes and inform the control room of conditions in the area.
- c. The fire watch will be instructed to secure the fire watch and call security for further instructions.
- d. The fire watch will be instructed to remain in the area for 30 minutes then evacuate and
~-/
re-establish the fire watch as soon as possible.
Answer 9
- a. The fire watch will be instructed to evacuate the area and re-establish the fire watch as soon as possible.
9
Question 10 B004.0014 (1 point(s))
v' While the plant is operating at 100% power, it is determined that AOV 7478 CNMT mini-purge supply fails to meet leakage requirements. Which one of the following statements is correct concerning continued operation?
- a. Close and deactivate AOV 7445 within 1 hr or mode 5 next 36 hrs (mode 3 in 6 hrs)
- b. Close and deactivate AOV-7445 within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or mode 5 next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> (mode 3 in 6 hrs)
- c. Close and deactivate AOV 7445 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or mode 5 next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> (mode 3 in 6 hrs)
- d. Close and deactivate AOV 7445 within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or mode 5 next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> (mode 3 in 6 hrs)
Answer 10 .
- c. Close and deactivate AOV 7445 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or mode 5 next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> (mode 3 in 6 hrs)
L- TC 97-039 10
Question 1 1 B000.1045 (1 point(s))
b The plant has tripped and had a loss of heat sink. The operator entered FR-H. 1, Response to Loss of Heat Sink but was unable to restore Heat Sink or establish Bleed and Feed. A Red Path on Core Cooling occurred and the operator transitioned to FR-C. 1, Response to Inadequate Core Cooling, 20 minutes ago. Efforts to restore core cooling have been unsuccessful. The following conditions exist:
0 R29/30 CNMT Hi Range Radiation 500 R/hr 0 Wind Speed 10 mph 0 Wind Direction 290" Which of the following notifications to the state and counties is correct:
- a. Classification - Site Area Emergency; no protective action necessary
- b. Classification - Site Area Emergency; notify Wayne County that the site will be evacuated
- c. Classification - General Emergency; evacuate Wayne 1,2, Monroe 1, implement KI Plan,shelter all remaining ERPA's
- d. Classification - General Emergency; evacuate Wayne 1,2,3, implement KI Plan, b
shelter all remaining ERPA's Answer 11
- d. Classification - General Emergency; evacuate Wayne 1,2,3, implement KI Plan, shelter all remaining ERPA's 11
Question 12 B000.1046 (1 point(s))
v Following a Large Break LOCA, the operators are in E-1 Loss of Reactor or Secondary Coolant, the HCO notes that CNMT Sump B level indication for 180 inches is illuminated for both trains.
Which of the following statements is correct regarding the 180 inch level.
- a. This is a normal post-LOCA indication. Continue in E-1 Loss of Reactor or Secondary Coolant.
- b. This is an indication of Service Water Leakage into CNMT. The operators will take action per AP-SW.1, SW Leak.
- c. This is an indication of unexpected water entering containment. The operators will take actions per FR-Z.2, Response to High CNMT Level.
- d. This is an indication of unexpected water entering CNMT. The operators will monitor the level but no action is required until level is > 214 inches indicated on B sump.
Answer 12
- c. This is an indication of unexpected water entering containment. The operators will take
~L, actions per FR-Z.2, Response to High CNMT Level.
12
Question 13 B000.1047 (1 point(s))
L' The plant Tech Specs require that sufficient CNMT coolers be in service to limit average containment air temperature to less than 120°F. Which of the following statements describe the basis for this requirement.
- a. Higher CNMT temperatures will result in inadequate cooling of safety related motors in CNMT during normal operations.
- b. Higher CNMT temperatures may result in exceeding the containment design basis for temperature and pressure following a DBA steam line break.
- c. High CNMT temperatures will result in degradation of safety related instrumentation during normal operations
- d. Higher CNMT temperatures will result in inadequate cooling of the MRPI coil stacks and excore nuclear instruments following a DBA LOCA.
Answer 13
- b. Higher CNMT temperatures may result in exceeding the containment design basis for temperature and pressure following a DBA steam line break.
13
Question 14 B000.1048 (1 point(s))
--A The plant is at 100% power with the "B" and "D" CNMT Recirc Fans out of service. A DBA LOCA occurs and CNMT spray fails to automatically actuate. Which of the following predicts the effects on the CNMT of these malfunctions and what action will the operators take in response?
- a. CNMT pressure will exceed 60 psig with no operator action. The operator will start CNMT spray manually per E-0, Reactor Trip or SI.
- b. CNMT pressure will remain less than 60 psig with no operator actions. The operator will start CNMT spray per E-0, Reactor Trip or SI.
- c. CNMT pressure will exceed 60 psig with no operator action. The operator will start CNMT spray per FR-Z. 1, Response to High CNMT pressure on a Red Path.
- d. CNMT pressure will remain less than 60 psig with no operator action. The operator will start CNMT spray per FR-Z. 1,Response to High CNMT Pressure on an Orange Path.
Answer 14 L-
- a. CNMT pressure will exceed 60 psig with no operator action. The operator will start CNMT spray manually per E-0, Reactor Trip or SI.
14
Question 15 B000.104 1 (1 point(s))
- Prior to start up following completion of a reheling outage, the Main Steam Isolation Valves (MSIVs) were tested to ensure a closure time of < 5 seconds and that each MSIV closed to its isolation position on an actual or simulated actuation signal. The Main Steam Non-Return Valves are also tested to verify that they can close.
The basis for performing these surveillances was to limit or mitigate ALL of the following EXCEPT:
- a. Accidents that could result in offsite exposures comparable to 10CFRl 00 limits
- b. The potential for uncontrolled RCS cooldown and positive reactivity restart accident
- c. A turbine overspeed condition following a generator trip at power
- d. Total mass and energy release into containment on a SLB Answer 15
- c. A turbine overspeed condition following a generator trip at power 15
Question 16 COOO. 1290 (1 point(s))
- Given the following plant conditions:
0 125V DC Bus "A" deenergized due to a ground 0 Rx tripped when the "A"DC bus deenergized 0 Small break LOCA occurred, RCP Trip Criteria is met 0 RCS is cooling down uncontrollably Which of the following describe the plant response and the necessary actions to mitigate the event.
Trip "A" RCP by transferring control power per ER-ELEC.2, Response to Loss of "A" or "B" DC Bus.
- b. "B" SI Train starts normally, manually start "A"Train SI equipment per E-0, Reactor Trip or SI. Both RCP's can be tripped from the Control Room.
- c. "B" SI Train starts normally, manually start "A"Train SI equipment per E-0,Reactor Trip or SI. "A" RCP cannot be tripped from the Control Room, trip by transferring control power per ER-ELEC.2, Response to Loss of "A" or "B"DC Power.
L
Answer 16
- c. "B" SI Train starts normally, manually start "A"Train SI equipment per E-0, Reactor Trip or SI. "A" RCP cannot be tripped fiom the Control Room, trip by transferring control power per ER-ELEC.2, Response to Loss of "A"or "B"DC Power.
16
Question 17 C033.0036 (1 point(s))
L., Given the following conditions in the Spent Fuel Pit (SFP):
- It is two weeks following shutdown. Full core is off loaded to SFP for RCS Maintenance.
- SFP cooling system "B" in service
- SFP temperature 102°F
- A leak has developed on the inlet to "B" SFP heat exchanger and cannot be isolated without securing the "B" Heat Exchanger
- Annunciator IC-29, SFP HI TEMP 115°F HI-LO LEVEL 20" 12", has just energized Which of the following describes the effect on SFP cooling without operator action and the necessary operator actions to restore SFP cooling.
- a. SFP pump "B" will continue to run,resulting in continued loss of inventory. The operator will secure the I ' B ' I SFP cooling system and place the "A"SFP cooling system in service.
- b. SFP pump "B" will trip on a low level in the SFP. The operators place the "A"SFP cooling system in service and monitor SFP temperature to determine if the standby SFP cooling system will need to be placed in service.
- c. SFP pump "B" will continue to run,resulting in continued loss of inventory. The operators will secure the "B" SFP Cooling System and place the "A"SFP cooling c
system in service and monitor SFP temperature to determine if the standby SFP cooling system will need to be placed in service.
- d. SFP pump "B" will trip on a low level in the SFP. The operator will place the "A"SFP cooling system in service. The Standby SFP cooling system will not be needed.
Answer 17
- b. SFP pump "B" Will trip on a low level in the SFP. The operators place the "A"SFP cooling system in service and monitor SFP temperature to determine if the standby SFP cooling system will need to be placed in service.
TC #99-054 17
Question 18 B000.1049 (1 point(s))
L Which of the following events requires the Control Room to notify the on shift RP and the Turbine System Engineer.
- a. Turbine Trip performed as part of a Normal (0-2.1) Shutdown
- b. Air Ejector Malfunction which results in a rapid 20% power reduction due to loss of vacuum
- c. Steam Generator Level Control problem resulting in a rapid 40% power reduction due to loss of feedwater
- d. Plant shutdown at 1O%/hour to prepare for condenser tube cleaning Answer 18
- b. Air Ejector Malfunction which results in a rapid 20% power reduction due to loss of vacuum 18
Question 19 B000.1043 (1 point(s))
- The following conditions exist:
0 Reactor Power is 85%
Containment pressure is 0.6 psig Containment temperature is 115°F A containment entry is required to search for a 0.3 gpm UNIDENTIFIED leak inside containment. Which of the following actions, if any, is applicable for this entry?
- a. Reactor power must be reduced to < 60% if entry into the Reactor Cavity is required.
- b. Security will control entry of personnel into containment
- c. A load change may not occur while personnel are inside containment
- d. A Containment Entry Checklist is NOT required for this entry Answer 19
- b. Security will control entry of personnel into containment L
19
Question 20 B000.1044 (1 point(s))
v During power operation Tech Spec LCO 3.2.1 requires that Heat Flux Hot Channel Factor be maintained within the limits set by the COLR.
How can the operators be assured that Heat Flux Hot Channel Factor is being maintained within limits on a continuous basis?
- a. The Heat Flux Hot Channel Factor is controlled by maintaining the core within the limits of AFD, QPTR,and control rod insertion, overlap, and sequencing limits.
- b. The Over Temperature Delta Temperature runback will decrease Turbine and Reactor load and prevent exceeding the hot channel factor limits.
- c. The Heat Flux Hot Channel Factor is not measurable, but inferred from a power distribution map using the incore detectors. The map is done every 3 1 days and if within limits it can be inferred that it has been within limits since last performed.
- d. The Heat Flux Hot Channel Factor is part of the core design and Westinghouse patterns the core design to ensure Heat Flux Hot Channel Factor will not be violated. No direct monitoring by the operators is required.
Answer 20
- a. The Heat Flux Hot Channel Factor is controlled by maintaining the core within the limits of AFD,QPTR, and control rod insertion, overlap, and sequencing limits.
20
Question 21 B310.0032 (1 point(s))
L The shift supervisor determines that emergency maintenance must be started on the "B" SI pump.
Which of the following states the minimum amount of review, approval and documentation that must be accomplished prior to work start.
- a. The shift supervisor directs the maintenance and the required documentation may be completed after the maintainance has been completed.
- b. The work package review and approvals are completed.
- c. The PORC has met and approved the maintenance and the work package has been completed.
- d. The maintenance scheduler has completed the review and approval of the work package.
Answer 21
- a. The shift supervisor directs the maintenance and the required documentation may be completed after the maintenance has been completed
Ref. A- 1603.1 OBJ. RAD06C.02.04 LP RAD06C 21
Question 22 HRS35C-06.03-01 (1 point(s))
-1 The maximum time that can elapse between a tank being sampled for release and the start of the release is:
- a. 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
- b. 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> C. 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
- d. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Answer 22
- d. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 22
Question 23 C029.0032 (1 point(s))
'.-- Given the following:
- A gas decay tank (GDT) release is in progress
- The auxiliary building filter switch is in the OUT position
- The 1A and 1B auxiliary building supply fans trip Which ONE of the following statements is correct concerning the gas release?
- a. It may continue with the above given conditions.
- b. It must be manually terminated
- c. It is automatically terminated by RCV-14 closing
- d. It is automatically terminated by the gas decay tank pump tripping Answer 23
- a. It may continue with the above given conditions.
23
Question 24 B000.0272 (1 point(s))
'- A LOCA has occurred, and the control room operators are performing EOP E-1 ,Loss of Reactor or Secondary Coolant. The STA is manually monitoring the CSFSTs. He checks the frrst CSFST and finds that the CSF is satisfied. He checks the second CSFST, core cooling, and determines that an orange path exists. He then checks the remaining CSFSTs and finds that their CSFs are satisfied. He then announces that the operators should exit E-1 and enter FR-C.2, Degraded Core Cooling.
From the choices below, select the correct appraisal of the STA's performance.
- a. The STA should have called for the transition from E-1 to FR-C.2 as soon as the orange path on core cooling was diagnosed.
- b. The STA should not have called for a transition; E-1 in this instance takes precedence over FR-C.2.
- c. The STA should have consulted with the operators because, in this case, it is at their discretion as to whether to continue in E-1 or to enter FR-C.2.
Answer 24
24
Question 25 B000.1011 (1 point(s))
u Unit was at 100% power when a trip occurred due to a feed line break downstream of "A" Feedwater Met Stop Check Valve.
Following the reactor trip, with no operator actions, which one of the following indications will be observed?
- a. "A"steamline low pressure alarms. "A"SG pressure is lowering; all TDAFW pump flow will be to "B" SG.
- b. "A"steamline low pressure alarms. "A"SG pressure is lowering; all TDAFW pump flow will be to "A"S/G.
C. "A"and "B" steamline low pressure alarms. Both SG pressures are lowering; TDAFW pump flow will be equal to both S/Gs.
- d. "A"and "B" steamline low pressure alarms. Both SG pressures are stable, TDAFW pump flow will be equal to both S/Gs.
L' Answer 25
- b. "A"steamline low pressure alarms. "A"SG pressure is lowering; all TDAFW pump flow will be to "A"S/G.
25
c SRO Reference Material Index 0-9.3 EPIP- 1.O ITS 3.4.13 A-3.3 ITS 3.6.3 EPIP-2.1
ROCHESTER GAS AND ELECTRIC CORPORATION GlNNA STATION CONTROLLED COPY NUMBER 51 PROCEDURE NO. 0-9.3 REV. NO. 53 NRC IMMEDIATE NOTIFICATION 1019 l a 3 EFFECTIVE DATE CATEGORY 1.O REVIEWED BY:
THIS PROCEDURE CONTAINS 22 PAGES c
-~~ ~
u-3.3;I Rev. No. 53 0-9 3 L
NRC IMMEDIATE NOTIFICATION 1.o PURPOSE:
1.1 To ensure that the USNRC is notified of significant events. To ensure that timely and accurate information is transmitted by phone to the USNRC in accordance with notification requirements of 10CFR50.72, 10CFR20.2201,l OCFR20.2202,l OCFR73.71, Technical Specifications and other USNRC commitments.
2.0 REFERENCES
2.1 10CFR20.1906 2.2 10CFR20.2201 2.3 10CFR20.2202 2.4 10CFR50.72 L,,) 2.5 10CFR70.52 2.6 10CFR73.71 2.7 10CFR74.11 2.8 EPIP 1-0 GlNNA STATION EVENT EVALUATION AND CLASSIFI-CATION 2.9 EPlP 1-5 NOTIFICATIONS 2.10 GS-1015 SAFEGUARDS EVENTS/INFORMATlON 2.1 1 NUREG-1022, REVlS]ON 2; EVENT REPORTING GUlDEtlNES 1OCRF50.72 AND 50.73 2.1 2 USNRC IE INFORMATION NOTICE 89-89; EVENT NOTIFICATION WORKSHEETS 2.1 3 USNRC IE INFORMATION NOTICE 85-78; EVENT NOTIFICATION
u - Y .J:L Rev. No. 53 2.14 USNRC IE INFORMATION NOTICE 85-27; NOTIFICATIONS TO THE USNRC OPERATIONS CENTER
-b 3.0 INITIAL CONDITIONS:
3.1 None.
4.0 PRECAUTIONS
4.1 None.
5.0 INSTRUCTIONS
NOTE: State and County Emergency Centers shall be notified within 15 minutes of the initiation of an Unusual Event, Alert, Site Emergency, or General Emergency. Refer t o EPIP 1-5 for guidance and direction.
5.1 General Requirements:
5.1 .I Notification of the USNRC Operations Center should be made via the
.3 Emergency Notification System (red phone) from the Control Room and then the TSC once manned.
e The ENS telephone numbers are:
0 (301) 816-5100
-OR (301) 951-0550 OR 0 (301) 41 5-0550 e Attachment 1 can be faxed t o the Operations Center using the number (301) 81 6-5 7 57. However, notification should be made using the Emergency Notification System.
5.1 .I .1 Notification of USNRC Resident Inspector(s) should be performed per Attachment 2 Primary/Alternate Methods of Notification.
0-9.3~3 Rev. No. 53 5.1.2 If the Emergency Notification System is (inoperative, the licensee shall make the required notifications via commercial telephone service. (Refer to Attachment 2 for alternate methods of notification)
-3 5.1.3 The licensee shall notify the USNRC immediately after notification of the appropriate State or local agencies and not later than one hour after the t h e the licensee declares one of the Emergency Classes.
5.1.4 When making a report the licensee shall identify the Emergency Class declared or shall indicate either paragraph (b) (11, "One-Hour Report," or paragraph (b) (2),"Four-Hour Report," or paragraph (b)(3), "Eight-Hour Report," as the paragraph of this section requiring notification of the Non-Emergency Event.
5.1.5 Follow-UD Notification:
5.1.5.1 In addition to making the initial notification, the licensee shall immediately report:
- a. Any further degradation in the level of safety of the plant or other worsening plant conditions, including those that require the declaration of any other Emergency Classes, if such a declaration has not been previously made.
.3 b. Any change from one Emergency Class to another.
- c. A termination of the Emergency Class.
- d. The results of ensuing evaluations or assessments of plant conditions.
- e. The effectiveness of response or protective measures taken.
- f. Information related t o plant behavior that is not understood.
5.1.6 When requested by the USNRC, an open continuous communication channel with the USNRC Operations Center shall be maintained. The person assigned this function shall be knowledgeable of plant systems and procedures. .
0-9.3~4 Rev. No. 53 5.1.7 The attached Event Notification Worksheet, (2pages), is provided to indicate information that may be requested by the USNRC upon notification. It should be completed where applicable, as the USNRC Headquarters Operations Officer (HOO) is obligated t o complete the form.
Attach the completed form to the associated ACTION form and forward t o PORC Chairman.
5.1.8 Event Notification Worksheet Guidance 5.1.8.1 For Non-Emergency notifications, it may be necessary to report multiple Non-Emergency classifications (i.e. RPS Actuation and ESF Actuation).
5.1.8.2 The information t o be communicated should be concise, factual and specific t o the event. It should not contain prejudgements or non-authenticated root causes or conclusions. Included should be an overall statement regarding overall plant stability at the time of transmittal.
5.1.8.3 The Event Description should include systems affected, actuations and their initiating signals, causes, effect of event on the plant, actions taken and actions planned. Also, min/max Temperatures, Pressures, and/or Levels should be included, as well as pertinent setpoints approached during the transient. Times of significant events should also be included.
5.1.8.4 Whenever' giving Plant status, always include RCS Pressure and
-J Temperature (Le. Plant a t Hot Shutdown, 540°F and 2235 psig).
5.1.8.5 For more complex Events, the Notification can be made simpler by faxing a copy of the Worksheets to the NRC at the time of Notification.
5.1.8.6 For Reactor Trips, a statement shall be made either that "All rods fully inserted on the trip" or how many rods did not fully insert. NRC HOO's are directed t o ask this question.
5.1.8.7 Obtain NRC Event Number from the NRC HOO and fill in the number in the appropriate blank (upper left corner) on the Event Notification Worksheet.
5.1.8.8 When answering questions posed by the NRC HOO, any answer which you are NOT fully confident of should be deferred t o a Follow-up Call.
Questions leading in directions not pertaining t o the Event should be answered by stating that it is not pertinent t o the Event.
0-9.3: 5 Rev. No. 53 5.1.8.9 If the Event Description is not in a Time tine fashion, it may be helpful t o have a Time tine of the Event written down and available when making the Notification.
5.1.8.1 0 Whenever possible, and within the time requirements, the Notification should be deferred until the Day Shift when a Conference Call can be made with the involvement of appropriate Management and Technical Expertise.
5.1 2 . 1 1 The NRC may make follow-up calls on the ENS line following the Notification, for clarification. All Notifications are taped.
5.2 . One-Hour Notifications to USNRC:
5.2.1 One-hour notifications required by 1 OCFR50.72 (a) (3):
Unusual Event {EPIP 1-0, 1-5)
Alert (EPIP 1-0, 1-5)
Site Area Emergency (EPIP 1-0, 1-5)
General Emergency (PIP 1-0, 1-5) 5.2.2 One-hour notifications required by 10CFR50.72 (b) (11 for operating eyents or conditions, if n o t reported as a declaration of an Emergency Class under paragraph (a) (step 5.2.1 ) of this section:
x . 3 See Attachment 3 of this procedure for criteria.
5.2.3 One-hour notifications required by 10CFR20.1906(d) for excess contamination or radiation levels on incoming materials:
See Attachment 4 of this procedure for criteria.
5.2.4 One-hour notifications required by 1 OCFR20.2201 (a)(l )(i) for loss or theft of licensed material when notified by RP:
See Attachment 4 of this procedure for criteria.
5.2.5 One-hour notifications required by 10CFR20.2202 (a) for radiation exposures or radioactive releases when notified by RP:
See Attachment 4 of this procedure for criteria.
0-3.3:tj Rev. No. 53 5.2.6 One-hour notifications required by 10CFR73.71 (a) for loss of special nuclear material or spent fuel when notified by t h e Reactor Engineer:
Compliance with 10CFR73.71 (a) will be accomplished using Procedure GS-1015 and will be reported to t h e NRC with assistance from Security.
See Attachment 5 of this procedure for criteria.
5.2.7 One-hour notifications required by 10CFR73.71 (b) or 10CFR73.71 (c) for significant safeguards events:
\ 9 Compliance with 10CFR73.71 (b) and (c) will be accomplished using Procedure GS-1015, and will be reported to t h e NRC with assistance from Security.
See Attachment 5 of this procedure for criteria.
5.2.8 One-hour notifications required by 10CFR70.52 and 10CFR74.11 for accidental criticality or loss or theft or attempted theft of special nuclear material:
See Attachment 8 of this procedure for criteria.
5.2.9 One-hour notifications required by 10CFR95.57 for issues related to
.J classified information:
See Attachment 1 0 of this procedure for criteria.
5.3 Four-Hour Notifications to USNRC:
5.3.1 Four-hour notifications required by 1 OCFR50.72 (b) (2) for operating events or conditions:
See Attachment 3 of this procedure for criteria.
5.4 Eiaht-Hour Notificaions to USNRC:
5.4.1 Eight-hour notifications required by 10 CFR 50.72(b)(3)for operating events or conditions:
See Attachment 3 of this procedure for criteria.
0-9.3:7 Rev. No. 53 5.5 Twentv-Four Hour Notifications to USNRC:
5.5.1 Twenty-four hour notifications required by 10CFR20.2202 (b) for radiation exposure or radioactive releases:
See Attachment 4 of this procedure for criteria.
5.5.2 Twenty-four hour notifications required by 10CFR26.73 for Fitness-For-Duty events:
Compliance with 10CFR26.73 will be accomplished using Corporate procedures, and will be reported t o the NRC by the Department Manager, Employee Relations.
See Attachment 6 of this procedure for criteria.
5.5.3 Twenty-four Notification required by USNRC IE Bulletin 80-24:
Any service water leak in containment greater than the limit specified in A-3.3 will be reported as a degradation of a containment boundary.
5.6 Fortv-Eiaht Hour Notifications t o USNRC:
5.6.1 Forty-eight hour notifications required by the IS1 Program, Section 11,
- 2) Paragraph 2.8.4, for steam generator tube degradation:
See Attachment 7 of this procedure for criteria.
5.7 Thirtv Dav Notification:
5.7.1 Thirty day notifications required by 10 CFR 20.2201 (a).
See Attachment 9 of this procedure for criteria.
0-9.3:8 Rev. No. 53 TlFICAllON DATE 8 TIME FACILITY or UNIT CAUER'SNAME CAU BACK CIRCLE ORGANIZATION EST LOCAL (sa51 maxi EDST I R.E. GINNA EVENTllME &ZONE RlENT DATE l-Hr Non-Emergency 10 CFR 50.72(b)(1) &Hr Non-Emergwcy 10 CFR 60.72@)(3) cmcE Em EDST (i)(B) Ts Devlatm I(A) De0faded C o n m n ADEG POWEWMODEAFER (locFRso.54x) ADN POWER/MODE BEFORE 6iMB) UnanaMM condltiofi AUNA 4 Hr Non-Emwgency 10 CFR SO=n(b)(O) fii)(Al SwafiedSvstem Ach~atmn AESF
&MA) Safe SiD Cactabilii AlNA Y
I OTHER UNSPECIFIED REOMT- OESCRlPTlON ude: Systems affected. actuaaons 8 their inibahng signals, =uses. effect of event on p m &tons taken or pknnad, ete.
These events require notification of New York State and Monroe and Wayne Counties within 15 minutea of the event classification. P I P 1-5 should be used to perform this notification.
EVENT DESCRIPTION NOTIFICATIONS YES NO BE ANYMING UNUSUALOR NOT UNDERSTOOM YES NO NRC RESIDENT e#--)
DID AU SYSTEMS FUNCTION AS REQUIRED? YES No ern-)
OTHER GOV AGENCIES MODE OF OPERATION ESTIMATED mornow INFO ON BACK?
UNTlL CORRECTED. RESTART DATE:
MEDINPRESS RELEASE 0 YES a NO
0-9.3:9 Rev. No. 53 Similar to NRC Form 361 (12-2000) ADDITIONAL INFORMATION USNRC OPERATlONS CENTER I PLANTSTACK 1 CONDENSEWAIREJECTOR I MAINSTEAMLINE I SGBLOWDOWN I OTHER RADIATION MONITOR READINGS ALARM SETPOINTS LEAK RATE SUDDEN OR LONG-TERM DEVELOPMENT I
TIME COOLANTACW PRIMARY SECONDARY liiK DATE 8 UNITS:
LIST OF SAFETY RELATED EQUIPMENT NOT OPEiwnorwL I
Rev. No. 53 ATTACHMENT 2 USNRC PHONE NUMBERS
- 1. Primarv Notification Method:
3 a. USNRC Operations Center:
Emergency Notification System (Red Telephone) 0 (3011 8 16-5 100 Primary 0 (301) 951-0550 Backup 0 (301) 41 5-0550 Backup 0 (301) 41 5-0553 Backup
- b. USNRC Senior Resident Inspector:
0 Ken Kolaczyk Telephone: (585) 924-51 87 NRC Cell Phone: (484) 868-1491 Personal Cell Phone: (585) 224-6831 If unavailable, notify USNRC Resident Inspector:
Mark Marshfield Telephone: (716) 839-9250 I NRC Cell Phone: (484) 868-2198
-3 I Personal Cell Phone: (716) 5 10-6745
- 2. Alternate Notification Methods: (Commercial Telephone)
- a. USNRC Operations Center:
0 (3011 81 6-5100 or 0 (3011 95 1-0550or 0 (301) 41 5-0550 0 (301) 41 5-0553
- b. USNRC Region 1:
0 (610) 337-5000
- 3. USNRC ODerations Center Fax:
0 (3011-816-51 51
- 4. To report a problem with the Emergency Notification System (red phone):
Call the NRC Headauarters ODerations Officer via commercial teleDhone if able t o contact NRC via commercial telephone, 1OCRF50.72 is n o t entered.
0 (301) 816-5100 or 0 (301) 41 5-0550 0 (3011 951 -0550 or 0 (301) 41 5-0553
Rev. No. 53 ATTACHMENT 3 Page 1 of 4 NOTE: Page numbers refer t o NUREG-1022, Rev. 2 - Event Reporting Guidelines 10CFR50.72 and 50.73.
10CFR50.72 ONE-HOUR NOTIFICATIONS 50.72(b)(I)
NOTE: 10 CFR 50.54(x) states "A licensee may take reasonable action that departs from a license condition or a Technical Specification (contained in a license issues under this part) in an emergency when this action is immediately needed t o protect the public health and safety and no action consistent with license conditions and Technical Specifications that can provide adequate or equivalent protection is immediately apparent."
pp. 38-39 If not reported as a declaration of an Emergency Class under 10 CFR 50.72(a)(3), the licensee shall notify the NRC as soon as practical and in all cases within one hour of the occurrence of any deviation from the plant's Technical Specifications authorized pursuant t o 10 CFR 50.54(x).
10CFR50.72 FOUR-HOUR NOTIFICATIONS pp. 30-33 The initiation of any nuclear plant shutdown required by the plant's Technical Specifications.
pp. 45-52 (A) Any event that results or should have resulted in Emergency Core Cooling System (ECCS) discharge into the reactor coolant system as a result of a valid signal, except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.
pp. 46-52 (B) Any event or condition that results in actuation of the Reactor Protection System (RPSO when the reactor is critical, except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.
Rev. No. 53 ATTACHMENT 3 Page 2 of 4 50.72 (b)(2)(xi)
NOTE: If the Monroe County 911 Center or Wayne County 91 1 Center informs the Ginna Control Room that anv siren(s) islare activated PP. 7 4 AND the activation is confirmed by EPlP 4-3.
Any event or situation, related t o the health and safety of the pp. 24-25 public or onsite personnel, or protection of the environment, pp. 72-75 for which a news miease is planned or notification to other government agencies has been or will be made. Such an event may include an onsite fatality or inadvertent release of radioactively contaminated materials.
10 CFR 50.72 EIGHT-HOUR NOTIFICATIONS pp. 39-43 Any event or condition that results in:
(A) The condition of the nuclear power plant, including its principal safety barriers, being seriously degraded; or (B) The nuclear power plant being in an unanalyzed condition that significantly degrades plant safety.
50.72(b)(3)(iv) pp. 46-52 (A) Any event or condition that results in valid actuation of any systems listed in paragraph (b)(3)(iv)(B) of this section, except when that actuation results from and is part of a pre-planned sequence during testing or reactor operation.
Rev. No. 53 ATTACHMENT 3 Page 3 of 4 (B) The systems t o which the requirements of paragraph (b)(3)(iv)(A) of this section apply are:
NOTE: Actuation of the RPS when the Reactor is critical is reportable under paragraph (b)(Z)(iv)(B) of this section. (4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> report)
(1 1 Reactor protection system (RPS) including: Reactor scram or reactor trip.
(2) General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves (MSIVs).
(31 Emergency core cooling systems (ECCS)for pressurized water reactors (PWRs) including: high-head, intermediate-head, and low-head injection systems and the low pressure injection function of residual (decay) heat removal systems.
(4) ECCS for boiling water reactors (BWRs) including:
high-pressure and low-pressure core spray systems; high-pressure coolant injection system; low pressure injection function of the residual heat removal system.
(5) BWR reactor core isolation cooling system; isolation condenser system; and feedwater coolant injection system.
(6) PWR auxiliary or emergency feedwater system.
(7) Containment heat removal and depressurization systems, including containment spray and fan cooler systems.
(8) Emergency AC electrical power systems including:
Emergency Diesel Generators (EDGs), Hydroelectric Facilities used in lieu of EDGs at the Oconee Station, and BWR dedicated Division 3 EDGs.
Rev. No. 53 ATTACHMENT 3 Page 4 of 4 50.72 I b)(3)(v) 3 pp. 52-64 Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to:
(A) Shut down the reactor and maintain it in a safe shutdown condition, (B) Remove residual heat, (C) Control the release of radioactive material, or (D) Mitigate the consequences of an accident.
pp. 52-64 Events covered in paragraph (b)(3)(v)of this section may include one or more procedural errors, equipment failures, and/or discovery of design, analysis, fabrication, construction, and/or procedural inadequacies. However, individual component failures need not be reported pursuant to paragraph (b)(3)(v) of this section if redundant equipment in the same system was operable and available to perform the required safety function.
50.72(b)(3)( x i )
PP. 71 Any event requiring the transport of a radioactively contaminated person to an offsite medical facility for treatment.
NOTE: Ifmore than 25% (24 of 96) of the sirens are inoperable for more than one (1) hour, consider the Offsite Notification System inoperable.
50.72( b)(3)(xiii) pp. 75-79 Any event that results in a major loss of emergency assessment capability, offsite response capability, or offsite communications capability (e.g., significant portion of control room indication, Emergency Notification System, or offsite notification system, or more importantly, the lost capability t o alert a large segment of the population for one (1) hour). (Refer t o Attachment 2)
Rev. No. 53 ATTACHMENT 4 Page 1 of 2 IOCFR20 ONE-HOUR NOTIFICATIONS L 2 2 0 1 (a) (1) (i) Any lost, stolen, or missing licensed material in an aggregate quantity equal t o or greater than 1,000 times the quantify specified in appendix C to part 20 under such circumstances that it appears t o the licensee that an exposure could result t o persons in unrestricted areas.
.2202 (a) Any event involving byproduct, source, or special nuclear material possessed by the licensee that may have caused or threatens t o cause any of the following conditions:
(1I An individual t o receive:
(i) A Total Effective Dose Equivalent (TEDE) of 25 rem or more, OR (ii) A lens dose equivalent (LDE) of 75 rem or more, OR (iii) A Shallow-Dose Equivalent (SDE)to the skin or extremities of 2 5 0 rad or more.
(2) The release of radioactive material, inside or outside of a restricted area, so that, had an individual been present for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the individual could have received an intake five times the occupational Annual Limit on Intake (ALII (the provisions of this paragraph do not apply t o locations where personnel are not normally stationed during routine operations).
.1906 (d) The licensee shall immediately notify the final delivery carrier and the NRC Operations Center (301-81 6-51 001,by telephone, when (11 Removable radioactive surface contamination exceeds the limits of 10CFR71.87(i) OR (2) External radiation levels exceed the limits of 10CFR71.47.
3
Rev. No. 53 ATTACHMENT 4 Page 2 of 2 10CFR20 TWENTY-FOUR HOUR NOTIFICATIONS
- ) .2202 (b) Any event involving loss of control of licensed material possessed by the licensee that may have caused, or threatens t o cause, any of the following conditions:
(1) An individual t o receive, in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period:
(i) Total Effective Dose Equivalent (TEDE) exceeding 5 rem, OR (ii) A lens equivalent (LDE) exceeding 15 rem, OR (iii) Shallow-Dose Equivalent (SDE) t o the skin or extremities exceeding 50 rem, OR (2) The release of radioactive material, inside or outside of a restricted area, so that, had an individual been present for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the individual could have received an intake in excess of one occupational Annual Limit on Intake (ALI) (the provisions of this paragraph do not apply t o locations where personnel are not normally stationed during routine operations).
Rev. No. 53 ATTACHMENT 5 10CFR73.71 ONE-HOUR REPORTS
> 73.71 (a) (1 1 Each license subject t o the provisions of 73.25, 73.26, 73.27(c),
73.37, 73.67(e), or 73.67(g) shall notify the NRC Operations Center within one hour after discovery of the loss of any shipment of SNM or spent fuel, and within one hour after recovery of or accounting for such lost shipment.
Part 7 3 APPENDIX G - REPORTABLE SAFEGUARDS EVENTS Pursuant to the provisions of 10CFR73.71 (b) and (c), licensees subject t o the provisions of 10CFR73.20, 73.37, 73.50, 73.55, 73.60, and 73.67 shall report or record, as appropriate, the following safeguards events.
- 1. Events t o be reported within one hour of discovery, followed by a written report within 3 0 days.
(a) Any event in which there is a reason t o believe that a person has committed or caused, or attempted t o commit or cause, or has made a credible threat t o commit or cause:
(1) A theft or unlawful diversion of special nuclear material; or (2) Significant physical damage t o a power reactor or any facility possessing SSNM or its equipment or carrier equipment transporting nuclear fuel or spent nuclear fuel, or t o the nuclear fuel or spent nuclear fuel a facility or carrier possesses; or (3) Interruption of normal operation of a licensed nuclear power reactor through the unauthorized use of or tampering with its machinery, components, or controls including the security system.
(b) An actual entry of an unauthorized person into a protected area, material access area, controlled access area, vital area, or transport.
(c) Any failure, degradation, or the discovered vulnerability in a safeguard system that could allow unauthorized or undetected access to a protected area, material access area, controlled access area, vital area, or transport for which compensatory measure have not been employed.
(d) The actual or attempted introduction of contraband into a protected area, material access area, vital area, or transport.
Rev. No. 53 ATTACHMENT 6 10CFR26.73 TWENTY-FOUR HOUR NOTIFICATIONS 3 26.73 (a) Each licensee subject to this Part shall inform the Commission of significant fitness-for-duty events including:
(1 1 Sale, use, or possession of illegal drugs within the protected area and, (21 Any acts by any person licensed under 10 CFR Part 55 t o operate a power reactor or by any supervisory personnel assigned t o perform duties within the scope of this part -
(i) Involving the sale, use or possession of a controlled substance, (ii) Resulting in confirmed positive tests on such persons, (iii) Involving use of alcohol within the protected area, OR L) (iv) Resulting in a determination of unfitness for scheduled work due t o the consumption of alcohol.
26.73 (b) Notifications must be made t o the NRC Operations Center by telephone within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the discoverv of the event bv the licensee.
26.73 (c) Fitness-For-Duty events shali be reported under this section rather than reported under the provisions of section 73.71.
Rev. No. 53 ATTACHMENT 7 FORTY-EIGHT HOUR NOTIFICATIONS 2 -
IS1 Program, Section 11 Paragraph 2.8.4 If the.number of tubes in a generator falling into categories (a) or (b) below exceeds the criteria, then results of the inspection shall be considered a Reportable Event pursuant t o 10CFR50.73. Oral notification t o the NRC Staff shall be accomplished within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, but no sooner than the next normal working day after the final review of the eddy current results. A written fQlow-up report shall provide a description of 9
investigations conducted t o determine the cause of the tube degradation and corrective measures taken t o preclude recurrence.
Categories (a) and (b) are:
(a) More than 10 percent of the total tubes inspected are degraded (imperfections greater than 20 percent of the nominal wall thickness). However, previously degraded tubes must exhibit at least 10 percent further wall penetration t o be included in this calculation.
(b) More than 1 percent of the total tubes inspected are degraded (imperfections greater than the repair limit).
Rev. No. 53 ATTACHMENT 8 10CFR70.52 AND 74.1I ONE-HOUR REPORTS Each licensee shall notify t h e NRC Operations Center within one hour after discovery of any case of accidental criticality or any loss, other than normal operating loss, of special nuclear material.
Each licensee who possesses one gram or more of contained uranium-235, uranium-233, or plutonium shall notify the NRC Operations Center within one hour after discovery of any loss or theft or unlawful diversion of special nuclear material which t h e licensee is licensed to possess or any incident in which an attempt h a s been made or is believed to have been made to commit a theft or unlawful diversion of such material.
Reports required under 73.71 need not be duplicated under t h e requirements of this section.
Each licensee who possesses one gram or more of contained uranium-235, uranium-233, or plutonium shall notify t h e N R C Operations Center within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of discovery of any loss or theft or other unlawful diversion of special nuclear material which t h e licensee is licensed to possess, or any incident in which an attempt has been made to commit a theft or unlawful diversion of special nuclear material. The requirement to report within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of discovery does not pertain to measured quantities of special nuclear material disposed of a s discards or inventory difference quantities.
Reports required under 73.71 need not be duplicated under requirements of this section.
Rev. No. 53 ATTACHMENT 9 10CFR20.2201 THIRTY DAY NOTIFICATION
--Y3 20.2201 (aHl )(ii) Within 30 days after the occurrence of any lost, stolen, or missing licensed material becomes known to the licensee, all licensed material in a quantity greater than 10 times the quantity specified in appendix C to part 20 that is still missing at this time.
Rev. No. 53 ATTACHMENT 10 10CFR95.57 ONE-HOUR NOTIFICATION 3, 95.57(a) Any aileged or suspended violation of the Atomic Energy Act, Espionage Act, or other Federal statutes related t o classified information (e.g.,
deliberate disclosure of classified information t o persons not authorized t o receive it, theft of classified information). Incidents such as this must be reported within one (1) hour of the event followed by written confirmation within 30 days of the incident.
ROCHESTER GAS AND ELECTRIC CORPORATION GINNA STATION 3 CONTROLLED COPY NUMBER 4 1 PROCEDURE NO. EPlP 1-0 REV. NO. 32 GlNNA STATION EVENT EVALUATION AND CLASSIFICATION TECHNICAL REVIEW
+-$5 EFFE TlVE DATE CATEGORY 1.O REVIEWED BY:
4 THIS PROCEDURE CONTAINS. 40 PAGES
4.0 PRECAUTIONS
4.1 For emergency events involving the Emergency Operating Procedures, classification should only be made after the diagnostic steps of E-0 have been completed.
4.2 In the event that multiple "Initiating Conditions" are identified, the SS/EC shall review each condition and classify according to the highest Emergency Classification Level obtained.
4.3 During any event, the entire procedure should be reviewed for possible reclassification of the event.
4.4 See Definitions (Attachment 2) for terms used in this procedure.
4.5 Any time a current set of conditions is identified which requires an Emergency Classification, the event shall be classified and declared, even if the condition identified is quickly corrected.
4.5.1 Conditions which depend on delayed evaluation results, Le., chemistry, RP analysis, etc., shall be classified and declared as soon as the results are known.
5.0 PREREQUISITES
5.1 Entry to this procedure may be directed by various other plant procedures or at the discretion of the SS/EC.
6.0 ACTIONS
6.1 In the event of an abnormal condition the Control Room Personnel will:
6.1.1 Perform the immediate responses defined in the appropriate plant procedures.
6.1.2 Identify the initiatina conditions using either the guidelines of the EAL wallchart or Attachment 1 of this procedure.
6.1.3 Implement applicable Emergency Plan procedures based on Appendix guidelines.
6.1.3.1 EPlP 1-4, General Emergency 6.1.3.2 EPlP 1-3,Site Area Emergency 6.1.3.3 EPlP 1-2, Alert 6.1.3.4 EPlP 1-1, Unusual Event
.i)
6.2 Periodically re-evaluate the condition after initial cfassificationof accident using t h e EAL wall chart or Attachment 1.
At the conclusion of the event, refer to EPIP 3-4,Emergency Termination and Recovery.
6.4 Any time previous initiating conditions are identified that would have warranted an Emergency Classification but they are no longer in effect at the time of identification,and do not require further evaluation or analysis, the event will be classified,but not declared.
6.4.1 Conditions which are corrected, but may require further safety evaluation or analysis, will be classified and declared.
6.4.2 The NRC will be notified any time an event is classified. This will be made by means of the NRC Emergency Notification System (ENS) phone using procedure 0-9.3 "NRC Immediate Notification".
6.4.3 The Plant Manager and Corporate Nuclear Emergency Planner (or their alternates) shall also be informed of this notification as soon as possible for notifications to Wayne County, Monroe County and New York State. For these notifications, there is no 15 minute requirement.
7.0 AlTACH MENTS
- 1. Detailed Accident Classification
- 2. Definitions
- 3. Barrier loss/potential loss
w EPlP 1-0:4 EPlP 1-0 EMERGENCY ACTION LEVELS (EALS)
INDEX 1.O CRITICAL SAFETY FUNCTION STATUS TREES (CSFST) 5.0 RADIOACTIVITY RELEASE/ AREA RADIATION 1.1 Sub-criticality CSFST Status 5.1 Effluent Monitors 1.2 Core Cooling CSFST Status 5.2 Dose Projections/ Environmental Measurements 1.3 Heat Sink CSFST Status 5.3 Area Radiation Levels 1.4 Integrity CSFST Status 1.5 Containment CSFST Status 6.0 ELECTRICAL FAILURES 6.1 Loss of AC Power Sources 6.2 Loss of DC Power Sources 2.0 REACTOR FUEL 2.1 Coolant Activity 7.0 EQUIPMENT FAILURES 2.2 Failed Fuel Detectors 7.1 Technical Specification Requirements 2.3 Containment Radiation 7.2 Safety System Failures 2.4 (6) Refueling Accidents 7.3 Loss of Indications/ Alarms/ Communication Capability 3.0 REACTOR COOLANT SYSTEM (RCS) 8.0 HAZARDS 3.1 RCS Leakage 8.1 Security Threats 3.2Primary to Secondary Leakage 8.2 Fire 3.3 RCS Subcooling 8.3 Man-Made Events 8.4 Natural Events 4.0 CONTAINMENT 4.1 Containment Integrity Status 9.0 OTHER 4.2Steam Generator Tube Rupture 4.3 Combustible Gas Concentrations NOTE: Changes to this attachment are required to be reflected on the EAL wall chart.
Attachment 1, Rev. 32
c b EPlP 1-05 1.O CRITICAL SAFETY FUNCTION STATUS TREES STATUS 1.1 Sub-critlcality CSFST Status GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 1.1.3 1.1.2 RED path in F-0.1, RED path in F-0.1, SUB-CRITICALITY SUB-CRITICALITY AND -
Mode Amlicabilitv:
Actual or imminent entry into - (1) Power Operations either: - (2) Startup
- RED path in F-0.2, CORE - (3) Hot Shutdown COOLING OR
- RED pathn F-0.3, HEAT SINK Mode AoDlicability
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown Attachment 1, Rev. 32
I' c
EPIP 1-0:6 1.2 Core Cooling CSFST Status GENERAL EMERGENCY I SITE AREA EMERGENCY I ALERT I UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPIP 1-3 PROCEED TO EPIP 1-2 ! PROCEED TO-EPIP 1-1 1.2.2 1.2.1 RED path in F-0.2, ORANGE or RED path in CORE COOLING F-0.2,CORE COOLING AND -
Mode Auulicabilitv:
Functional restoration - (1) Power Operations procedures not effective - (2) Startup within 15 minutes. - (3) Hot Shutdown Mode ADulicabilitv: - (4) Hot Standby
- (1)Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby 1.3 Heat Sink CSFST Status GENERAL EMERGENCY SITE AREA EMERGENCY I ALERT I UNUSUAL EVENT PROCEEDTO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPIP 1-2 PROCEED TO EPIP 1-1 1.3.1 RED path in F-0.3,HEAT SINK Mode ADdicabilitq
- (1) Power Operations
- (2)Startup
- (3) Hot Shutdown I
- (4) Hot Standby Attachment 1, Rev. 32
c c EPlP 1-0:7 1.4 Integrity CSFST Status GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEEDTO EPlP 1-1 1.4.1 RED path on F-0.4, INTEGRITY Mode ADDlicabilitv:
- (1) Power Operations
- (2) Startup
- (3)Hot Shutdown
- (4) Hot Standby 1.5 Containment CSFST Status GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 1.5.1 RED path on F-0.5, CONTAINMENT resulting from loss of reactor coolant Mode Amlicabilitv:
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
L c c EPlP 1-0:8 2.0 REACTOR FUEL 2.1 Coolant Activity GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEEDTO EPlP 1-2 PROCEED TO EPlP 1-1 2.1.3 2.1.2 2.1.1 Coolant sample activity Coolant sample activity Coolant sample activity:
>300 pCi/gm of 1-131 >300 pCi/gm of 1-131 >loo% of 1OO/E-Bar pCi/gm equivalent equivalent. total specific activity AND Mode ApDlicabilitv: -
OR Any of the following: - (1) Power Operations >1.O pCi/gm 1-131
- RED path on F-0.4, - (2) Startup equivalent and entry into INTEGRlTY - (3) Hot Shutdown conditions of Tech. Spec.
- Primary system leakage - (4) Hot Standby section 3.4.16.b.
>46 gpm -
Mode Amlicabilitv:
- RCS subcooling <EOP - (1) Power Operations figure MIN SUBCOOLING - (2) Startup due to RCS leakage - (3) Hot Shutdown
- Containment radiation - (4) Hot Standby monitor R-29/30 reading
>1OR/hr Mode ADDlicability;
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32 I
c i/
w EPlP 1-0:Q 2.2 Failed Fuel Detectors I GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 2.2.3 2.2.2 2.2.1 Letdown line monitor R-9 Letdown line monitor R-9 Letdown line monitor R-9
>1OWhr >10R/hr. >2R/hr AND Taw >500°F AND -
Mode Atmlicability; Mode Apolicabilitv:
any of the following: - (1) Power Operations - (1) Power Operations
- RED path on F-0.4, - (2) Startup - (2) Startup INTEGRITY - (3)Hot Shutdown - (3)Hot Shutdown
- Primary system leakage - (4) Hot Standby
>46gpm
- RCS subcooling <EOP figure MIN SUBCOOLING due to RCS leakage
- Containment radiation monitor R-29/30 reading
>1OR/hr
-Mode Aonlicabiliw
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
c c c EPlP 1-0:lO 2.3 Containment Radiation GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO PIP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 2.3.3 2.3.2 2.3.1 Containment radiation Containment radiation Containment radiation monitor R-29/30 reading monitor R-29/30reading monitor R-29/30 reading
>1000R/hr >I OORlhr >1 ORlhr due to RCS leakage.
Mode ADDlicabilitY: Mode Aoolicabilitv: -
Mode AmIicabilitK
- (1) Power Operations - (1) Power Operations - (1) Power Operations
- (2) Startup - (2) Startup - (2) Startup
- (3) Hot Shutdown - (3) Hot Shutdown - (3) Hot Shutdown
- (4) Hot Standby - (4) Hot Standby - (4) Hot Standby Attachment 1, Rev. 32
c c c EPlP 1-0~11 2.4 Refueling Accidents or Other Radiation Monitors I
GENERAL EMERGENCY PROCEED TO EPlP 1-4 I SITE AREA EMERGENCY PROCEED TO EPlP 1-3 2.4.2 ALERT PROCEEDTO EPlP 1-2 2.4.1 UNUSUAL EVENT PROCEED TO EPlP 1-1 Confirmed sustained Spent fuel pool ( reactor cavity alarm on any of the during Refueling) water level following radiation cannot be restored and monitors resulting from maintained above the spent an uncontrolled fuel fuel pool low water level alarm handling process. setpoint
- R-2 Containment Area -
Mode ADDlicabilitK Monitor - All
- R-5 Spent Fuel Pit
- R-12 Containment Noble Gas Mode ADplicability:
- All 2.4.3 Report of visual observation of irradiated fuel uncovered.
Mode AmlicabilitK
- All Attachment 1, Rev. 32
EPlP 1-0~12 3.0 REACTOR COOLANT SYSTEM 3.1 RCS Leakage GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO PIP 1-2 PROCEED TO PIP 1-1 3.1.3 3.1.2 3.1.1 RVLIS cannot be maintained Primary system leakage Unidentified or pressure
>77% with no RCPs running >46gpm boundary leakage OR -
Mode Aimlicabilitv: greater than 1Ogpm With the Rea= - (1) Power Operations OR Vessel head removed, it - (2) Startup Identifiedleakage greater is reported that water - (3) Hot Shutdown than 25gpm level in the Reactor - (4) Hot Standby -
Mode Amlicebilitv:
Vessel is dropping in an - (1) Power Operations uncontrolled manner and - (2) Startup core uncovery is likely - (3) Hot Shutdown mode Amlicabilitx - (4) Hot Standby
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby
- (5) Cold Shutdown
- (6) Refueling Attachment 1, Rev. 32
bd CI EPlP 1-0~13 3.2 Primary to Secondary Leakage SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-3 PROCEED TO PIP 1-2 PROCEED TO EPlP 1-1 3.2.2 3.2.1 Unisolable release of Unisolable release of secondary side to secondary side to atmosphere atmosphere with primary (See 3.1.2 above) with primary to secondary to secondary leakage leakage greater than
>46 gpm. 0.lgprn in the affected S/G Mode Amlicabilitv: -
Mode Aoolicabilitv:
- (1)Power Operations - (1)Power Operations
- (2) Startup - (2) Startup
- (3) Hot Shutdown - (3)Hot Shutdown
- (4) Hot Standby - (4) Hot Standby 3.2.3 Unisolable release of secondary side to atmosphere with primary to secondary leakage PO. 1 gpm in the affected steam generator AND - EITHER
- Coolant activity 2300 pCi/gm of 1-1 31 equivalent OR
- Letdown linemonitor R-9
>lO Rhr Mode ADplicabilitv:
- (1)Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
ir u t EPlP 1-0~14 3.3 RCS Subcooling I
GENERAL EMERGENCY PROCEED TO EPlP 1-4 I SITE AREA EMERGENCY PROCEED TO EPlP 1-3 3.3.1 ALERT PROCEED TO EPlP 1-2 !
UNUSUAL EVENT PROCEED TO PIP 1-1 RCS subcooling <EOP figure MIN SUBCOOLING due to RCS leakage Mode Atmlicabilik
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
c b EPlP 1-0:15 4.0 CONTAINMENT 4.1 Containment Integrity Status
~ ~~
GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEEDTO PIP 1-2 PROCEED TO EPlP 1-1 4.1.4 4.1.2 4.1.1 Safety injection signal due to Rapid uncontrolled Both doors open on LOCA with less than decrease in containment containment airlock minimum operable pressure following initial OR containment heat increase due to LOCA. Inability to closecontainment removal equipment of OR pressure relief or purge valves LOSS of primaycooiant which results in a radiological RECIRC SPRAY inside containment with release pathway to the CNMT FANS PUMPS containment pressure or environment PRESS OPER REQ'D sump level response not OR c 28 psig 2 NIA consistent with LOCA CI or CVI valve(s) not closed 228 psig 2 1 conditions. when required which results in
<2 2 -
Mode Aodicabilitv: a radiological release pathway AND - (1) Power Operations to the environment one or more of the following - (2) Startup OR fuel clad loss indicators: - (3)Hot Shutdown Rapid uncontrolled pressure
- Coolant activity >300 pCi/gm - (4) Hot Standby decrease following initial (Continued on next page) increase due to steam line of 1-131 equivalent break.
- Containment radiation -Mode Atwlicabilitv:
monitor (R-29/30) reading
>1OOR/hr
- (1) Power Operations
- Letdown monitor R-9 reading
- (2)Startup
>10R/hr
- (3) Hot Shutdown
- (4) Hot Standby
- RED path in F-0.2, CORE COOLING
-Mode. Amlicabilitv:
- (1) Power Operations
- (2)Startup
- (3)Hot Shutdown
- (4)Hot Standby (Continued on next page)
Attachment 1, Rev. 32
t b c EPIP 1-0~16 4.1 Containment integrity Status
~
GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 4.1.5 4.1.3 EITHER EITHER:
Rapid uncontrolled decrease CI or CVI valve(s) not in containment pressure closed when required following initial increase due to following confirmed LOCA LOCA OR OR Loss of prirnavcoolant inside Inability to i s o G any primary containment with containment system discharging outside pressure or sump level containment response not consistent with -
AND LOCA conditions Radiological release pathway p J to the environment exists as a one or more of the following result.
fuel clad damage indicators: -Mode Aoolicabilitv:
- ORANGE or RED path in - (1) Power Operations F-0.2, CORE COOLING - (2) Startup
- RED path in F-0.3, HEAT - (3) Hot Shutdown SINK - (4) Hot Standby
- Coolant activity
>300p Ci/grn of 1-131 equivalent
- Containment radiation monitor R-29/R-30 reading
>1 OOR/hr
- Letdown line monitor R-9 reading >I ORkr Mode ADDlicabilitv:
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby (Continued on next page)
Attachment 1, Rev. 32
ir i b EPlP 1-0~17 4.1 Containment Integrity Status GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEEDTO EPlP 1-1 EITHER CI or CVI valve(s) not closed when required following confirmed LOCA OR Inability to isolate any primary system discharging outside containment AND Radiological release pathway to environment exists as a result AND one or more of the following fuel clad damage indicators:
- ORANGE or RED path in F-0.2,CORE COOLING
- RED path in F-0.3, HEAT SINK
- Coolant activity
>300p Ci/gm of 1-131 equivalent
- Containment radiation monitor R-29/30reading
>1 OOR/hr
- Letdown monitor R-9 reading >1 OR/hr Mode ADolicabilitv:
- (1) Power Operations
- (2) Startup
- (3)Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
i /"
(4 EPlP 1-0~18 4.2 Steam Generator Tube Rupture with Secondary Release GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 4.2.2 1.2.1 Unisolable secondary side line Unisolable secondary side line break with SIG tube rupture as break with SIG tube rupture as identified in E-3 "Steam identified in E-3 "Steam Generator Tube Rupture". Generator Tube Rupture" AND Mode Applicabilitv:
one or more of the following - (1) Power Operations fuel clad damage indicators: - (2) Startup
- ORANGE or RED path in - (3) Hot Shutdown F-0.2,CORE COOLING - (4) Hot Standby
- RED path in F-0.3, HEAT SINK
- Coolant activity
>300 pCiIgm of 1-131 equivalent
- Containment radiation monitor R-29/30reading
>1 OOWhr
- Letdown monitor R-9 reading >10R/hr Mode AoPlicabili&
- (1) Power Operations
- (2) Startup
- (3)Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
3 EPlP 1-0:19 4.3 Combustible Gas Concentrations GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 4.3.1
>4% hydrogen concentration in containment Mode Amlicabilitv:
- (1) Power Operations
- (2) Startup
- (3)Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
/'
c EPlP 1-0:20 5.0 RADIOACTIVITY RELEASE/ AREA RADIATION 5.1 Effluent Monitors GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPIP 1-1 5.1.4 5.1.3 5.1.2 5.1.1 A valid reading on one or more A valid reading on one or more A valid reading on one or A valid reading on one or more of the following monitors for of the following monitors for more of the following monitors of the following monitors for
>15 minutes >15 minutes for >15 minutes >60 minutes unless sample
- R12A7 6.00E+1 pCi/cc - R12A7 6.00E+O pCi/cc - R12A7 6.00E-1 pCi/cc analysis can confirm release
- R 14A7 5.33E0 @/cc - R14A7 5.33E-1 pCi/cc - R14A7 5.33E-2 pCi/cc rates are less than two times
- R15A9 1.15E+2 pCi/cc - R15A9 1.15E+1 pCi/cc - R15A7 1.15E+O pCi/cc release rate limits within the 60 minute time limit.
- I331132 reading with the - R31/32 reading with the - R18 Offscale High with no
- R11 following condition: following condition: isolation 1 ARV 1.90E+2 mR/hr 1 ARV 1.90E+1 mR/hr - R20A Offscale High
- 1.00E5 cpm with one fan' 1 Safety 9.51E+1 mR/hr 1 Safety 9.51EO mR/hr - R20B Offscale High - 1.14E5 cpm with two fans' 2 Safeties 4.76E+1 mR/hr 2 Safeties 4.76E0 mR/hr - R21 Offscale High with no
- R12 3 Safeties 3.17E+1 mR/hr 3 Safeties 3.17E0 mR/hr isolation
- 7.42E6 cpm with one fan*
4 Safeties 2.38E0 mR/hr - R22 Offscale High with no
- 5.36E6 cpm with two fans' 4 Safeties 2.38E+1 mR/hr - R13 1.25E4 cpm unless dose assessment can unless dose assessment can isolation R31/32 reading with the
- R14 6.40E5 cpm confirm releases at the site confirm releases at the site - R15 2.94E5 cpm boundary are below the following within the 15 minute boundary are below the following within the 15 minute following condition:
1 ARV 1.90EO mR/hr
- R18 3.60E5 cpm with no isolation limit limit 1 Safety 9.51 E-1 mR/hr - R20A 4.08E4 cpm 1000 mR TEDE 100 mR TEDE 2 Safeties 4.76E-1 mR/hr - R20B 5.20E3 cpm
- 5000 mR CDE thyroid - 500 mR CDE thyroid 3 Safeties 3.17E-1 rnR/hr - R21+* 5.00E4 cpm with no
- 1000 mR/hr external exposure - 100 mR/hr external exposure 4 Safeties 2.38E-1 mR/hr isolation rate 5000 mWhr thyroid exposure -
rate 500 mR/hr thyroid exposure unless dose assessment can confirm releases at the site
- R22" 9.20E4 cpm with no isolation for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of inhalation Mode Amlicabilitv: -
rate for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of inhalation Mode Aoolicabilitv:
boundary are below
- 10 mR TEDE or - R31/32 reading 0.2 mR/hr with 1 ARV or 1 Safety open.
- All - All - 10 mR/hr external exposure Mode ADulicabilitv:
rate within the 15 minute limit
- All Mode Auulicabilitv:
- All During containment purge
'* R-21 and R-22 have no remote indications in the Control Room or on PPCS. MCB annunciators AA-2 or K-27 may indicate a possible release; however, local observation must be performed. Attachment 1, Rev. 32
c c r EPlP 1-0:21 5.2 Dose Projections/ Environmental MeasurementdReleaseRates GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEEDTO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 5.2.5 5.2.4 5.2.2 5.2.1 Dose projections or field Dose projections or field Confirmed sample Confirmed sample surveys resulting from actual surveys resulting from actual analysis for gaseous or analysis for gaseous or or imminent release which or imminent release which liquid release rates in liquid release rates in indicate doseddose rates in indicate dose rates in excess excess of two hundred excess of two times release excess of 1000mR/hr external of 1OOmR/hr external exposure times release rate limits for rate limits for >60 min exposure rate at the Site rate at the Site Boundary or >I5 min -
Mode ADDlicabilitv:
Boundary or beyond beyond -
Mode Apdicabilitv: - All OR OR - All Dose projections or field Dose projections or field 5.2.3 surveys resulting from actual surveys resulting from actual Dose projections or field or imminent release which or imminent release which surveys resulting from actual indicate ~5000mRhr thyroid indicate ~5OOmR/hrthyroid or imminent release which exposure dose rate at the Site exposure dose rate at the Site indicate 21OmR/hr external Boundary or beyond Boundary or beyond exposure rate at the Site OR OR Boundary or beyond Dose projections or field Dose projections or field OR surveys resulting from actual surveys resulting from actual Dose projections or field or imminent release which or imminent release which surveys resulting from actual indicate ~1OOOmRTEDE dose indicate 21OOmR TEDE dose or imminent release which at the Site Boundary at the Site Boundary indicate 21OrnR TEDE dose or beyond or beyond the Site Boundary or beyond OR OR Dose projectiGs or field Dose projections or field -
Mode Amlicabilitv:
surveys indicate 25000mR surveys resulting from actual - All CDE thyroid dose at the Site or imminent release which Boundary or beyond. indicate 1500mR CDE thyroid dose at the Site Boundary or
-Mode Amlicabilitv: beyond.
- All Mode ADDlicabilitc
- All Attachment 1, Rev. 32
.. I EPlP 1-0:22 5.3 Area Radiation Levels GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO PIP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO PIP 1-1 5.3.2 5.3.1 Sustained area radiation Any sustained direct area levels > 15 mWhr in radiation monitor readings either Control Room > 100 times alarm or OR off-scale high resulting from Central Alarmxation and an uncontrolled process.
Secondary Alarm Station Mode ADDlicabilitv:
Mode Aoplicabilitv: - All
- All 5.3.3 Sustained abnormal area radiation levels > 8 Rlhr within any of the following areas:
- Containment
- Auxiliary Building
- Turbine Building
- Emergency Diesel Bldg.
- Screen house
- Standby Auxiliary Feedwater Building AND Access is required to establish or maintain Cold Shutdown
-Mode Aoplicabilitv:
- All Attachment 1, Rev. 32
c EPlP 1-0:23 6.1 Loss of AC Power Sources GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPIP 1-3 PROCEED TO EPIP 1-2 PROCEED TO EPlP 1-1
~~
6.1.5 6.1.4 6.1.2 6.1.1 Loss of all safeguards Loss of both trains of AC Loss of both trains of AC Loss of ability to supply bus AC power busses for greater busses for greater than 15 power to the safeguard AND EITHER: than 15 minutes minutes trains from offsite circuits power restoration to any -Mode Acmlicabilitv: Mode AoolicabiIitv: 751 and 767 for greater than safeguards train is not likely in - (1) Power Operations - (5) Cold Shutdown 15 minutes 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> - (2) Startup - (6) Refueling -
Mode ADDlicabilitv:
OR - (3) Hot Shutdown - (D) Defueled - AI1 Actual orEminent entry into - (4) Hot Standby 6.1.3 ORANGE or RED path Available safeguards train on F-0.2, CORE AC power reduced to COOLING only one of the following
-Mode Amlicabilitv: sources for >I5 minutes.
- (1) Power Operations - EDG 1A (BUS14)
- (2) Startup - EDG 18 (BUS16)
- (3) Hot Shutdown - Station Auxiliary
- (4) Hot Standby Transformer 12A
- Station Auxiliary Transformer 128 Mode Amlicabilitv:
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
EPlP 1-0:24 6.2 Loss of DC Power Sources GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO PIP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 6.2.2 6.2.1 408vdc bus voltage c108vdc bus voltage indications on 125vdc indications on 125vdc batteries 1A &NJ 16 for >15 batteries 1A AND 16 for minutes. >15 minutes.
Mode Armlicabilitv: -
Mode Aodicabilitv:
- (1) Power Operations - (5) Cold Shutdown
- (2) Startup - (6) Refueling
- (3) Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
'j '3 EPlP 1-0:25 7.0 EQUIPMENT FAILURES 7.1 Technical Specification Requirements GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEEDTO EPlP 1-2 PROCEED TO EPlP 1-1 7.1.1 Plant is not brought to the required operating mode within Technical Specifications LCO Required Action Completion Time Mode Aoplicabilitv:
- (1) Power Operations
- (2) Startup
- (3) Hot Shutdown
- (4) Hot Standby Attachment 1, Rev. 32
b EPlP 1-0~26 7.2 Safety Failures or Control Room Evacuation GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEEDTO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 7.2.5 7.2.2 7.2.1 Entry into AP-CR.1 "Control Turbine failure generated Report of main turbine failure Room Inaccessability" missiles results in any visible resulting in casing AND structural damage to plant penetration or damage to Control of core cooling vital equipment. turbine seals or generator cannot be established -
Mode Applicability seals per AP-CR. 1 "Control - (1) Power Operations -
Mode ADPlicabilitv:
Room Inaccessibility" - (2) Startup - (1) Power Operations within 20 minutes - (3) Hot Shutdown - (2) Startup Mode Auplicabilitv: - (4) Hot Standby - (3) Hot Shutdown
- (1) Power Operations 7.2.3 - (4) Hot Standby
- (2) Startup Entry into AP-CR.1 "Control
- (3) Hot Shutdown Room Inaccessability"
- (4) Hot Standby -
Mode Auplicabilitv:
- (5) Cold Shutdown - (1) Power Operations
- (6) Refueling - (2) Startup
- (3)Hot Shutdown
- (4) Hot Standby
- (5) Cold Shutdown
- (6) Refueling 7.2.4 Reactor coolant temperature cannot be maintained <2OO0F I Mode Aoolicabilitv:
- (5) Cold Shutdown
' (6) Refueling I
Attachment 1, Rev. 32
PIP 1-027 7.3 Loss of Indicatlons/CommunlcatlonCapability GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 7.3.4 7.3.3 7.3.1 Loss of annunciators or Unplanned loss of annunciators Unplanned loss of annunciators indications on any of the or indications on any of the or indications on any of the following Control Room Panels following Control Room Panels following Control Room Panels
-A for greater than 15 minutes for greater than 15 minutes
- AA -A -A
-c -B -B
-D -C -c
-E -D -D
-F -E -E
-G -F -F AND -G -G Complete loss of ability -
AND -
AND to monitor any critical increased surveillance is increased surveillance is safety function status required for safe plant required for safe plant
-AND operation operation A plant transient in EITHER -Mode Apdicabilitv:
progress - A plant transient in - (1) Power Operations
-Mode ARDlicabilitv: progress - (2) Startup
- (1) Power Operations OR - (3) Hot Shutdown
- (2) Startup - PPCSTunavailable - (4) Hot Standby
- (3) Hot Shutdown -Mode ADDlicabilitv: 7.3.2
- (4) Hot Standby - (1) Power Operations Loss of all communications
- (2) Startup capability affecting the
- (3)Hot Shutdown ability to either:
- (4) Hot Standby - perform routine operations OR
- Notify offsiteagencies or personnel Mode ADRlicabilitv:
- All Attachment 1, Rev. 32
EPlP 1-0~28 8.0 HAZARDS 8.1 Security Threats GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEEDTO EPlP 1-2 PROCEED TO EPiP 1-1 B.1.4 8.1.3 B.1.2 B.l.l Security event which intrusion into plant security Intrusion into plant Protected Bomb device or other indication results in: vital area by an adversary Area by an adversary of attempted sabotage
- Loss of plant control OR OR discovered within plant from the control room Any security event which Any security event which Protected Area OR represents actual or likely represents an actual or OR
- LOSS ofemote failures of plant systems substantial degradation of the Notification o f n y credible site shutdown capability needed to protect the public level of safety of the plant. specific security threat by the Mode ADolicabilitv: -
Mode Aoplicabiiitv: -Mode ARDlicabilitK Security Shift Supervisor
- All - All - All or outside agency (NRC, military or law enforcement)
Mode Apolicabilitv:
- All Attachment 1, Rev. 32
i
/'
!:,.J
'W' EPlP 1-0:29 8.2 Flre or Explosion GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 0.2.2 3.2.1 Fire or explosion in any of the Confirmed fire in any of the following plant areas which following plant areas not results in extinguished within 15 minutes EITHER of control room notification visible damage to plant - Intermediate Building equipment or structures - TSC needed for safe shutdown - Service Building OR - Contaminated Storage LOSS of a safetysystem Building
- Intermediate Building - Control Building
- TSC - Containment Building
- Service Building - Auxiliary Building
- Contaminated Storage - Turbine Building Building - Emergency Diesel
- Control Building Building
- Containment Building - Standby Auxiliary
- Auxiliary Building Feedwater Building
- Turbine Building . - Screen House
- Emergency Diesel -
Mode Amlicabilitv:
Building - All
- Standby Auxiliary Feedwater Building
- Screen House Mode Applicabilitv:
- All Attachment 1, Rev. 32
L c/
EPlP 1-0~30 8.3 Man-Made Events GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO PIP 1-4 PROCEED TO EPlP 1-3 PROCEED TO EPlP 1-2 PROCEED TO EPlP 1-1 3.3.4 8.3.1 Vehicle crash or projectile Vehicle crash into or impact which precludes projectile which impacts personnel access to or plant structures or systems damages equipment in the within Protected Area following plant vital areas Boundary
- Control Building -Mode Amlicabilitv:
- Containment Building - All
- Auxiliary Building 8.3.2
- Intermediate Building Report by plant personnel of
- Emergency Diesel Building an explosion within Protected
- Standby Auxiliary Area Boundary resulting in Feedwater Building visible damage to permanent
- Screen House structures or equipment Mode ADplicabiliW:
- All Mode ADDlicabilitv:
- All 3.3.5 6.3.3 Report or detection of toxic or Report or detection of toxic or flammable gases within the flammable gases that could following plant areas, in enter or have entered within concentrations that will be Life the ProtectedArea Boundary threatening to plant personnel in amounts that could affect or precludes access to the health of plant personnel or equipment needed for safe safe plant operation plant operations a3
- Control Building Report by local, county or
- Containment Building state officials for potential
- Auxiliary Building evacuation of site personnel
- Intermediate Building based on offsite event
- Emergency Diesel Building -
Mode Applicabilitv:
- Standby Auxiliary - All Feedwater Building
- Screen House Mode ADDlicabilitv:
- All Attachment 1, Rev. 32
c i W'
PIP 1-0:31 8.4 Natural Events GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO PIP 1-2 PROCEED TO PIP 1-1 3.4.4 3.4.1 Earthquake felt in plant by Earthquake felt in plant by any_plant
. operations personnel any plant operations personnel AND- -
AND Confirmation of earthquake of Confirmation of earthquake of an intensity greater than 0.089 an intensity greater than 0.01g per ER-SC.4 "Earthquake per ER-SC.4 "Earthquake Emergency Plan" Emergency Plan" Mode Aoolicabilitv: Mode Aoolicabilitv;
- All - All 3.4.5 3.4.2 Sustained winds >75mph Report by plant personnel of OR tornado striking within plant Tornado strikesone of the Protected Area Boundary following plant vital areas -
Mode Aoolicabilitv:
- Control Building - All
- Containment Building (Continued on next page)
- Auxiliary Building
- Intermediate Building
- Emergency Diesel Building
- Standby Auxiliary Feedwater Building
- Screen House Mode Aoolicabilitv:
- All (Continued on next page)
Attachment 1, Rev. 32
IJ (3
EPlP 1-0:32 8.4 Natural Events GENERAL EMERGENCY SITE AREA EMERGENCY UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO PIP 1-2 PROCEED TO EPlP 1-1 8.4.6 B.4.3 Any natural event which results Deer Creek flooding over in a report of visible structural entrance road bridge handrail damage or assessment by OR Operations personnel of LaElevel>252 ft actual damage to equipment OR needed for safe plant operation scree6iiouse Suction in any of the following plant Bay water level s 19 feet or areas: 1; 17.5 feet by manual level
- Control Building measurement
- Containment Building -
Mode Aimlicabilitv:
- Auxiliary Building - All
- Intermediate Building
- Emergency Diesel Building
- Standby Auxiliary Feedwater Building
-Screen House Mode ADDlicabilitv:
- All 8.4.7 Flood water accumulating on screen house operating floor m
Lake level >253 ft OR ScreG House Suction Bay water level s 16 feet or
~ 1 4 .feet 5 by manual level measurement Mode Acmlicabilitv:
- All Attachment 1, Rev. 32
c I EPlP 1-0:33 9.0 OTHER GENERAL EMERGENCY SITE AREA EMERGENCY ALERT UNUSUAL EVENT PROCEED TO EPlP 1-4 PROCEED TO EPlP 1-3 PROCEED TO PIP 1-2 PROCEED TO EPlP 1-1 9.1.7 9.1.5 3.1.3 9.1.I In the opinion of the Shift In the opinion of the Shift Any event, which in the Any event, which in the Supervisor or Emergency Supervisor or Emergency opinion of the Shift opinion of the Shift Supervisor Coordinator, events are in Coordinator, events are in Supervisor or Emergency or Emergency Coordinator, progress which indicate progress which indicate actual Coordinator, that could cause that could lead to or has led to actual or imminent core or likely failures of plant or has caused actual a potential degradation of the damage and the potential systems needed to protect the substantial degradation of the level of safety of the plant for a large release of public. Any releases are not level of safety of the plant -Mode AoDlicabilitv:
radioactive material in expected to result in -Mode Annlicabilitv: - All excess of EPA PAGs exposures which exceed - All 9.1.2 outside the site boundary EPA PAGs 3.1.4 Any event, which in the Mode Annlicabilitv: Mode Armlicabilitv: Any event, which in the opinion of the Shift
- All - All opinion of the Shift Supervisor Supervisor or Emergency 9.1.8 9.1.6 or Emergency Coordinator, Coordinator, that could lead Any event, which in the Any event, which in the that could lead or has led to a to or has led to a potential loss opinion of the Shift opinion of the Shift Supervisor oss or potential loss of either of containment (Attachment 3)
Supervisor or Emergency or Emergency Coordinator, bel clad or RCS barrier -Mode APnlicabilitv:
Coordinator, that could or has that could or has led to either: (Attachment 3) - (1) Power Operations led to a loss of any two fission - Loss or potential loss of -
Mode ADDlicabilitv: - (2) Startup product barriers and loss or both fuel clad and RCS - (1) Power Operations - (3) Hot Shutdown potential loss of the third barrier (Attachment 3) - (2) Startup - (4) Hot Standby (Attachment 3) OR - (3) Hot Shutdown Mode Anolicabilitv: - L o s E r potential loss of - (4) Hot Standby
- (1) Power Operations either fuel clad and RCS
- (2) Startup barrier in conjunction
- (3) Hot Shutdown with a loss of containment
- (4) Hot Standby (Attachment 3)
Mode Andicabilitv:
- (1) Power Operations
- (2) Startup
- (3)Hot Shutdown
- (4) Hot Standby -~
Attachment 1, Rev. 32
ATTACHMENT2 Rev. 32 DEFINITIONS V
Actuate To put into operation; to move into action; commonly used to refer to automated, multi-faceted operations. "Actuate ECCS".
Adversary As applied to security EA&, an individual whose intent is to commit sabotage, disrupt station operations or otherwise commit a crime on station property.
Adverse Meteorology Low wind speed a b low dispersion of effluents.
Alert Events are in progress or have occurred which involve an actual or potential substantial degradation of the level of safety of the plant.
Any releases are expected to be limited to small fractions of the EPA ProtectiveAction Guideline exposure levels.
Available The state or condition of being ready and able to be used (placed into operation) to accomplish the stated (or implied) action or function. As applied to a system, this requires the operability of necessary support systems (electrical power supplies, cooling water, lubrication, etc).
CadCannot be The current value or status of an identified parameter relative to that determined specified cadcannot be ascertained using all available indications (direct and indirect, singly or in combination).
U Can/Cannot be The value of the identified parameter@)i d s not able to be kept maintained abovehelow specified limits. This determination includes making an above/below evaluation that considers both current and future system performance in relation to the current vdue or trend of the parameter(s). Neither implies that the parameter must actually exceed the limit before the action is taken nor that the action must be taken before the limit is reached.
Can/Cannot be The value of the identified parameter(s) i d s not able to be returned to restored above/below above/below specified limits after having passed those limits. This determination includes making an evaluation that considers both current and future systems performances in relation to the current value and trend of the parameter(s). Does not imply any specific time interval but does not permit prolonged operation beyond a limit without taking the specified action.
As applied to loss of electrical power sources (ex.:power cannot be restored to any vital bus in 54 hrs) the specified power source cannot be returned to service within the specified time. This determination includes making an evaluation that considers both current and future restorationcapabilities. Implies that the declaration should be made as soon as the determination is made that the power source cannot be restored within the specified time.
Classified Identify an EAL that corresponds to plant conditions
Close To position a valve or damper so as to prevent flow of the process fluid.
To make an electrical connection to supply power Conf irdConf irmation To validate, through visual observation or physical inspection, that an assumed condition is as expected or required, without taking action to alter the as found configuration.
Control Take action, as necessary, to maintain the value of a specified parameter within applicable limits; to fix or adjust the time, amount, or rate of; to regulate or restrict.
Core Failure Fission product release to containment atmosphere that results in a reading of > 1000 REM/HR on containment area monitor R-2, R-29 or R-30.
Declared Use of the New York State Radiological Emergency Data Form in procedure EPlP 1-5 to notify offsite agencies of a classified event.
Decrease To become progressively less in size, amount, number, or intensity.
Discharge Removal of a fluidgas from a volume or system.
ECCS High and low pressure safety injection Accumulators Enter To go into.
Establish To perform action necessary to meet a stated condition. Establish communication with the Control Room.
Evacuate To remove the contents of; to remove personnel from an area.
Exceeds To go beyond a stated or implied limit, measure, or degree.
Exist To have being with respect to understood limitations or conditions.
Facility The Protected Area of the plant. The area within the security fence Failed Fuel An increase in primary coolant activity reflected by an unexplained increase on failed fuel monitor (R-9) which exceeds its high alarm setpoint. If R-9 reading unavailable or unreliable, the failed fuel condition would be verified by a primary sample analysis.
Failure A state of inability to perform a normal function.
Fire The observance of flames if any doubt exists due to excessive smoke, inaccessible location, a fire should be assumed to be present.
General Emergency Events are in progress or have occurred which involve actual or imminent substantial core degradation or melting with potential loss of containment integrity. Releases can be reasonably expected to exceed EPA Protective Action Guideline exposure levels offsite for more than the immediate site area.
Hazards Aircraft crash, explosion, missiles, toxic gas, flammable gas, or turbine blade failures.
If Logic term which indicates that taking the action prescribed is contingent upon the current existence of the stated condition(s). If the identified conditions do not exist, the prescribed action is not to be taken and execution of operator actions must proceed promptly in accordance with subsequent instructions.
Increase To become progressively greater in size, amount, number or intensity.
h 9 Indicate To point out or point to; to display the value of a process variable; to be a sign or symbol.
Initiate The act of placing equipment or a system into service, either manually or automatically. Activation of a function or protective feature (i.e. initiate a manual trip).
Injection The act of forcing a fluid into a volume or vessel.
Inoperable Not able to perform its intended function.
Intrusion The act of entering without authorization.
LOCA Entry into E-1.
Loss Failure of operability or lack of access to.
Loss of all Total loss of wind speed, wind direction and temperature from the Meteorological primary weather tower onsite and of wind direction and wind speed Indications from the back up weather tower located at Station 13A (accessible using E f l P 2-2),and all off-site sources available to the on-shift RP Tech.
Loss of Secondary Entry into E-1.
Coolant Maintain Take action, as necessary, to keep the value of the specified parameter within the applicable limits.
Monitor Observe and evaluate at a frequency sufficient to remain apprised of the value, trend, and rate of change of the specified parameter.
Notify To give notice of or report the occurrence of; to make known to; to inform specified personnel; to advise; to communicate; to contact; to relay.
OBE Operating Basis Earthquake. An earthquake having 0.089 peak ground acceleration.
3 Open To position a valve or damper so as to allow flow of the process fluid.
To break an electrical connection which removes a power supply from an electrical device.
To make available for entry or passage by turning back, removing, or clearina awav.
Operable Able to perform it's intended function.
Perform To carry out an action; to accomplish; to affect; to reach an objective.
Periodically As plant conditions change.
Plant Building Turbine Building, Sew. Building, Containment, Aux. Building, Standby Aux. Feed Building or the Screen House, Contaminated Storage Building or Upper Radwaste Storage Building.
Primary System The pipes, valves, and other equipment which connect directly to the reactor vessel or reactor coolant system such that a reduction in reactor coolant system pressure will effect a decrease in the steam or water pressure being discharged through an unisolated break in the systern.
Radiation Monitor Any permanent or temporary area or process monitor.
Remove To change the location or position of.
Report To describe as being in a specific state.
Require To demand as necessary or essential.
Restore Take the appropriate action required to return the value of an identified parameter to within applicable limits.
3
'v Rise Describes an increase in a parameter as the result of an operator or automatic system.
Safe Shutdown Minimum equipment required by Appendix "R"procedures.
Equipment Sample To perform an analysis on a specified media to determine its properties.
SGTR Entry into E-3.
Shutdown To perform operations necessary to cause equipment to cease or suspend operation; to stop. "Shutdown unnecessary equipment."
Site Area Emergency Events are in progress or have occurred which involve actual or likely major failures of plant functions needed for protection of the public.
Any releases are not expected to result in exposure levels which exceed EPA Protective Action Guideline exposure levels except near the site boundary.
Sustained Prolonged. Not intermittent or of transitory nature.
Sustained Winds The five minuted average based on a PPCS reading from the 150 foot or 250 foot Met Tower wind speed indicator.
SSE Safe Shutdown Earthquake. An earthquake having 0.29 peak ground acceleration.
TEDE Total Effective Dose Equivalent.
Thyroid Dose - Thyroid dose is assumed to be the same as Committed Dose Equivalent (CDE).
J Trip - To de-energize a pump or fan motor; to position a breaker so as to interrupt or prevent the flow of current in the associated circuit; to manually activate a semiautomatic feature.
- To take action to cause shutdown of the reactor by opening the reactor trip breaker.
Total Loss of All - Total loss of Condensate, Mainfeed, all Auxiliary Feedwater and Standby Auxiliary Feedwater.
Feedwater Uncontrolled - An evolution lacking control but is not the result of operator action.
Unexplained - A condition where parameters/condition exist that are not normal for current plant status and are not a result of operator action.
Unmonitored - A release of radioactive material to the environment which does not Release pass through an area or process monitor.
Unplanned - Not as an expected result of deliberate action.
Until - Indicates that the associated prescribed action is to proceed only so long as the identifiedcondition does not exist.
Unusual Event - Events are in progress or have occurred which indicate a potential degradation of the level of safety of the plant. No releases of radioactive material requiring offsite response or monitoring are expected unless further degradation of safety systems occurs.
Valid - Supported or corroborated on a sound basis.
Vent - To open an effluent (exhaust) flowpath from an enclosed volume; to reduce pressure in an enclosed volume.
Verify - To confirm a condition and take action to establish that condition if required. "Verify reactor trip, verify SI pumps running."
Vital Areas - Areas of the plant containing equipment or machinery that could affect the safe operation or shutdown of the plant.
Whole Body - Whole body dose is assumed to be the same as Total Effective Dose Dose Equivalent (TEDE).
3
L L EPlP 1-0:39 Attachment 3 Rev. 32 BARRIER LOSWPOTENTIAL LOSS Fuel Cladding Potential Loss Loss ORANGE path in F-0.2, CORE COOLING RED path in F-0.2,CORE COOLING RED path in F-0.3, HEAT SINK Coolant activity > 300 @Ucc of 1-131 Core Exit Thermocouple Readings> 700 "F Core Exit Thermocouple Readings > 1200 "F RVLlS <77% w/ no RCPs running Containment rad monitor reading >lo0 Whr Emergency CoordinatorJudgment Letdown Monitor (R-9) reading > 10 Whr Emergency Coordinator Judgment RCS
_ L Potential Loss Loss RED path on F-0.4, INTEGRITY RCS subcooling < EOP Fig. MIN SUBCOOLINGdue to RCS leakage RED path on F-0.3, HEAT SINK Unisolablesecondary side line break with SG tube rupture as identified in E-3"Steam GeneratorTube Rupture" Primary system leakage > 46 gpm Containment radiation monitor reading > 10 Whr Emergency CoordinatorJudgment Emergency CoordinatorJudgment Page 1 of 2
c c c EPlP -0~40 Attach..i nt3 Rev. 32 BARRIER LOSS/POTENTAIL LOSS Conta Loss RED path F-0.5,CONTAINMENT Rapid uncontrolled decrease in Containment Pressure following initial increase Either: Loss of primary coolant inside containment with containment pressure or Core exit thermocouples >1200 O F sump level response not consistent with LOCA conditions, Le.
OR unexpected changes occur in these parameters that are not explainable Core exit thermocouples ,700 OF with RVLlS <77% (no RCPs) due to operator actions or automatic system actions.
AND Restoration procedures not effectivewithin 15 minutes Safety injectionsignal due to LOCA with <the minimumcontainment Either:
cooling safeguards equipment operating: CI or CVI isolation required and CI or CVI valve(s) not closed when CNMT pressure <28 psig: 2 CNMT Recirc Fans required OR CNMT pressure 228 psig: 2 CNMT Spray Pumps Inability to Isolateany primary system discharging outside containment OR AND 2 CNMT Recirc Fans Radiological release pathway to the environment exists and 1 CNMT Spray Pump Containment pressure 60 pslg and increasing Release of secondary side to atmosphere with primary to secondary leakage greater than tech spec allowable of 0.1 GPM per steam generator
->4 Ihydrogen concentrationin containment Both doors open on containment airlock OR Inability to close containment pressure relief or purge valves which results in a radiologicalrelease pathway to the environment OR CI or CVI valve(s) not closed when required which results in a radiological release pathway to the environment Containment radiation monitor reading >I OOO FUhr Emergency Coordinator Judgment Emergency Coordinator Judgment Page 2 of 2
RCS Operational LEAKAGE 3.4.1 3 3.4 REACTOR COOLANT SYSTEM (RCS)
RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:
- a. No pressure boundary LEAKAGE;
- b. 1 gpm unidentified LEAKAGE; C. 10 gpm identified LEAKAGE; and
- d. 0.1 gpm total primary to secondary LEAKAGE through each steam generator (SG)when averaged over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
APPLICABILIN: MODES 1,2,3, and 4.
CONDITION REQUIRED ACTION COMPLETION TIME
~ ~
A. RCS LEAKAGE not within A.l Reduce LEAKAGE to within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> limits for reasons other limits.
than pressure boundary LEAKAGE.
B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. AND OR 8.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> RCS pressure boundary LEAKAGE exists.
3 R.E. Ginna Nuclear Power Plant 3.4.1 3-1 Amendment 80
RCS uperaliuriai LEHMUL 3.4.13 SURVEfLLANCE FREQUENCY d --------_--_---------------------.
SR 3.4.13.1 - NOTE -
Only required to be performed during steady state operation.
Perform RCS water inventory balance. Once during initial 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of steady state operation I72 hours thereafter
-~
SR 3.4.13.2 Verify steam generator tube integrity is in accordance In accordance with with the Steam Generator Tube Surveillance the Seam Program. Generator Tube Surveillance Program
-3 3
R.E. Ginna Nuclear Power Plant 3.4.13-2 Amendment 80
GINNA STATION ,.
CONTROLLED COPY NUMBER 39 PROCEDURE NO. A-3.3 REV. NO. 13 I .
CONTAINMENT INTEGRITY PROGRAM
-3 1
RESPON EM, AGER i / 20 0 3 EFFECTIVE DATE CATEGORY 1 .O REVIEWED BY:
3 THIS PROCEDURE CONTAINS 28 PAGES
A-3.3: 1 A-3 3 CONTAINMENT INTEGRITY PROGRAM d 1 .o PURPOSE:
1.1 TOdelineate the Containment integrity program as required by Technical Specification Chapters 3.6 and 3.9, and Generic Letter 88-1 7 for Modes 1, 2, 3 and 4, during core alterations and movement of irradiated fuel assemblies within Containment, and reduced inventory conditions, respectively.
2.0 REFERENCES
2.1 Improved Technical Specification LCOs 3.4.1 3, 3.6.1, 3.6.2, 3.6.3, and 3.9.3.
2.2 Generic Letter 88-17, Loss of Decay Heat Removal.
2.3 Updated Final Safety Analysis Report, Section 6.2.4.
2.4 Design Analysis DA-NS-93-002-21, EWR No. 10084, Containment Isolation System Review.
u) 2.5 Letter from R.C. Mecredy, RG&E t o A.R. Johnson, NRC -
Subject:
AOV-745, MOV-749A and MOV-749B, dated 7/9/90.
2.6 Inter-Office Correspondence, John Cook and Mark Flaherty to PORC,
Subject:
Containment Integrity During Refueling, dated 2/20/92.
2.7 0-1.1 B - Establishing Containment Integrity.
2.8 0-2.3.1A - Containment Closure Capability in 2 Hours During RCS Reduced Inventory Operation.
2.9 PTT-23 Series.
2.1 0 5-30.7, Containment Isolation Valve Verification.
2.1 1 PT-39, Primary System Leakage Evaluation Inservice Inspection.
2.1 2 0 - 1 5.2, Required Valve Lineup for Reactor Head Removal.
A-3.3:2 2.1 3 6720379 1 3, Containment Isolation Auxiliary Relay Cabinet System Schematic Diagram A l ,
2.1 4 672037945, Containment isolation Auxiliary Relay Cabinet System L J Schematic Diagram A2.
2.1 5 672037946, Containment Isolation Auxiliary Relay Cabinet System Schematic Diagram B1.
2.1 6 672037947, Containment Isolation Auxiliary Relay Cabinet System Schematic Diagram B2.
2.1 7 RG&E IOC, 11/1/96,
Subject:
"As-Found Testing of CLIC's and CLOC's", M. Flaherty t o G . Joss.
2.1 8 10CFR50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-cooled Power Reactors".
2.1 9 ANSI N45.4-1972.
2.20 ANSVANS 56.8-1 9 9 4 "Containment System Leakage Testing Requirements".
2.21 ANS-56.2, ANSI N271-1976 "Containment Isolation Provisions for Fluid
..I Systems " .
2.22 Nuclear Energy Institute NE1 94-01, Revision 0, 7/26/95 "Industry Guideline for implementing Performance-Based Option of 10CFR50, Appendix J".
2.23 USNRC Regulatory Guide 1 .163,9/95 "Performance-Based Containment Leak-Test Program".
2.24 ASME/ANSI OMa-1988, OM-1 0.
2.25 A-52.1 6, "Operator Workaround/Challenge Control".
2.26 Design Analysis DA-ME-95-088.
2.27 Safety Evaluation NSL-0000-SE019.
2.28 10CFR50, Appendix A "General Design Criteria for Nuclear Power Plants", Criterion 57.
2.29 PCR 2002-0035, "Permanent Installation of Safety Injection Makeup
.$ Pump".
A-3.3:3 I 2.30 PCR 1996-013, "Cap Sample Lines In Penetrations P-203b, P - 2 0 3 ~ ~
I P-305af P-124b".
-3 3.O INSTRUCTIONS :
3.1 The containment integrity program is designed t o provide assurance that the necessary Containment isolation boundaries are available for all required plant conditions. This program is organized to address three plant conditions:
- a. Containment Integrity during Refueling.
- b. Containment Integrity during Reduced RCS Inventory.
- c. Containment Integrity in Modes 1, 2, 3 and 4.
The requirements for each of these conditions is discussed below along with the treatment of closed systems.
3.2 Cont ai nm ent I nt egr ity d uring Refueling .
3.2.1 During core alterations and movement of irradiated fuel assemblies within Containment, each penetration must have a single barrier to the release of radioactive material. This single barrier may consist of any one .of the f 01 Io w ing alternatives :
- a. A closed system inside or outside Containment such that a "direct access" release path to t h e outside atmosphere is not provided.
- b. A closed manual or automatic isolation valve, blind flange, or
" equiva 1e nt .
- c. An automatic isolation valve that closes on a Containment Ventilation Isolation (CVI) signal from high Containment radioactivity.
3.2.2 It is not intended that the barriers provided for Containment isolation during refueling be restricted t o barriers tested t o the requirements of Appendix J to 10CFR50. The basis for refueling integrity is to prevent the release of radioactivity resulting from a fuel handling event during refueling operations. Since there is no potential for Containment pressuri-zation, any device which provides an atmospheric pressure boundary is sufficient (Le., provides "equivalent" protection).
3.2.3 Containment integrity for refueling is verified through performance Of 0-15.2.
Containment Integrity During Reduced RCS Inventory.
Containment integrity during reduced inventory conditions is provided by maintaining available'one barrier for each penetration. Since there is a potential for Containment pressurization during loss of core cooling, this barrier should be one of the t w o barriers used for normal Containment isolation in Modes 1, 2, 3 and 4. All penetrations are required to be capable of being closed within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following a loss of RHR.
3.3.2 Containment integrity during reduced RCS inventory is verified through performance of 0-2.3.1 A .
3.4 Containment Integrity in Modes 1, 2 , 3 and 4.
3.4.1 Reference 2.4 provides the design basis for the Containment isolation configuration and testing. Any change to this procedure, including Attachment A, must be reviewed by Nuclear Safety and Licensing.
3.4.2 Attachment A provides a listing for each penetration of the valves and other boundaries required for Containment integrity in Modes 1,2, 3 and
- 4. These boundaries are leak tested per Appendix J to 10CFR50 except where specific exemptions have been approved. This table is organized 3 as follows:
3.4.2.1 Svstem - description of the system which penetrates Containment.
3.4.2.2 LLRT Proc. - Applicable local leak rate test procedure which depicts Containment boundaries using a drawing as an aid for Technicians and Operators (typically a PTT series procedure).
3.4.2.3 Penetration No. - unique identification number for the penetration.
3.4.2.4 Valve/Boundarv - Containment isolation valves or boundaries for the penetration.
3.4.2.5 Isolation Position - A t w o character designation used t o define the t w o barriers which are available for each penetration. This is used since many process lines have multiple branch lines prior to entering or exiting Containment. The first character defines the branch line which the Containment isolation valve or boundary isolates. The second character defines the isolation barrier which the valve provides (i.e., first or second). As an example, Penetration 1 07 lists the following Containment boundaries: (See Attachment A and B) 1728 a1 1723 a2
3.4.2.5 (cont'd) -I AOV 1 7 2 8 is one Containment barrier while AOV 1 7 2 3 is a second barrier.
-3 Note that V-1072 is not listed for Penetration 107 a s a valve/boundary because it is a test connection. In accordance with ANSI/ANS-56.8, test connections are exempt from 10CFR50 Appendix J leak testing requirements. Test connections are controlled by PTT-23Af Containment Isolation Valve Test Connection Boundary Control. Test connections between primary Containment isolation valves must be administratively secured closed and normally consist of a double barrier (e.g. two valves in series, one valve with a niljple and cap: one valve and a blind flange).
NOTE: Certain penetrations have test connections (used for downstream vent or test pressurization during LLRT's) which consist of a sinale barrier which has been analyzed and found t o be acceptable. This issue is documented in DA-NS-93-002-21, EWR No. 1 0 0 8 4 , , "Containment Isolation System Review".
In Modes 1 , 2 , 3 and 4 , AOV-1728 and AOV-1723 must be operable and capable of being closed. If AOV 1728 were inoperable, then AOV 1723 is the preferred valve t o be closed in accordance with LCO 3.6.3.
3 Conversely, AOV 1728 is t h e preferred valve to be closed if AOV 1723 were inoperable.
As an example, Penetration 124d has multiple branch lines and lists the following Containment boundaries: (See Attachment A and C) 1572 a1 1573 a2 1574 a2 In Modes 1, 2, 3 and 4, all three valves must be operable and capable of being closed. If manual valve 1 5 7 2 were inoperable, then BOTH manual valves 1573 and 1 5 7 4 must be closed in accordance with LCO 3.6.3.
However, if 1 5 7 3 were inoperable, only 1572 must be closed (valve 1 5 7 4 is not affected).
3.4.2.6 Valve TvDe - type of Containment isolation valve (e.g., MOV).
3.4.2.7 Notes - Specific notes related to the Containment isolation valve or boundary.
3
3.4.2.8 Maximum Isolation Time - Maximum allowed closure time in seconds for ,.
those valves which receive a Containment isolation signal. Maximum allowed closure times are derived from T.S. 3.6.3, "Containment Iso 1at ion Boundaries ", Bases .
3.4.2.9 Isolation Sianal Train - specific isolation train(s) for those valves which receive a Containment isolation signal.
3.4.3 Prior t o heatup into Mode 4, Containment integrity is verified through performance of procedure 0-1.1 B, PTT-23A, 'PT-39 and S-30.7. Closed systems inside and outside Containment (CLIC's and CLOC's), are verified through the required system lineups.
I .
3.4.4 When a valve/boundary in Attachment A is inoperable, ITS Section 3.6.3 should be entered. ExamDle: Penetration 401, S/G "A" pressure transmitter, PT-469 will be replaced. PT-469 isolation valve V-11028 is closed and LCO 3.6.3 Condition C is entered. An A-52.4 shall be submitted t o address Containment boundary PT-469 being unavailable with V-11028 closed, and the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> completion time stipulated in LCO 3.6.3 Required Action C1 is satisfied. VL'l1028 would have to be verified closed once per 31 days.
3.4.5 When a valve/boundary has been rendered inoperable from activities (calibrations, testing, etc.) which effectively cause the valve/boundary t o be bypassed, an A-52.4 shall be submitted t o track this condition until the valve/boundary has been restored t o an operable status (see Attachment E for an example of a bypassed valve/boundary).
3.5 Closed Systems:
3.5.1 Closed systems inside (CLIC) and closed systems outside (CLOC)
Containment are used for several penetrations as a Containment isolation boundary. All piping for these penetrations up t o and including the first available isolation valve on all branch lines provides one Containment boundary. The integrity of these closed systems as a boundary is typically confirmed by normal system operation or periodic test. Since these closed systems are exempt from t h e . testing requirements contained in Appendix J t o 10CFR50, except as noted below, the allowable leakage (e.g. packing leaks and heat exchanger tube leaks) has been based upon the guidance of ASME/ANSI OMa-l988,OM-10 for the size of isolation valve associated with the closed system. This guidance allows a leakage rate of 0.5 cmm Der inch of nominal valve diameter. The only exception is for systems controlled b y Technical Specification 5.5.2, Primary Coolant Sources Outside Containment, which provides more prescriptive requirements.
NOTE: For the purpose of evaiuating small leaks (drips, slight weepage, etc.), 1 drop per second is approximately .05 gph.
4 3.5.1.1 When the allowable leak rate for a component associated with a CLlC or CLOC has been exceeded the CLlC or CLOC itself has a leak rate in excess of the allowable limit, an A-52.4 shall be initiated (note - this applies to components associated with a CLIC/CLOC and not to components which are a boundary in series with the CLIC/CLOC).
3.5.1.2 In MODES 1,2, 3 and 4,if a component or CLIC/CLOC leakage has been quantified and determined t&be t h a j the associated allowable leak rate an ACTION Report shall also be initiated and assigned t o the IST Engineer for disposition.
3.5.2 When a closed loop boundary is altered, the closed loop can be maintained by administrative controls provided that closed loop leakage is maintained within requirements of the applicable 3.5.2 System substep. Administrative controls can be component holds, procedure signoffs, test tags or other types of documented measures which maintain the closed loop as a n operable Containment boundary. See Attachment D for an example of an altered but operable closed loop.
Whenever a closed loop boundary has been altered (even under administrative controls), an A-52.4 shall be submitted to track this condition until the closed loop has been restored to its normal configuration.
3.5.2.1 Service Water System (Penetrations 201a, 201 b, 209a, 209b, 308,31 1, 3 1 2, 31 5, 31 6, 31 9,320 and 323) - All piping inside containment for these penetrations up to and including the first available isolation valve on all branch lines provide one Containment boundary. The integrity of this piping is verified by normal system operation and Containment leakage detection systems.
Allowable leakage for the Service Water CLIC's are as follows:
Pen Svstem Leak Rate 201a/209b SW to/from Rx Compartment Cooler A 1.25 gpm 209a/201 b SW to/from Rx Compartment Cooler 8 1.25 gpm 319/308 SW to/from Fan Cooler A 4.0 gpm 31 6/31 1 SW to/from Fan Cooler 6 4.0 gpm 320/315 SW to/from Fan Cooler C 4.0 gpm 312/323 SW to/from Fan Cooler D 4.0 gpm
3.5.2.2 Component Cooling Water System (Penetrations 134a, 1 2 4 ~ 125,126, ,
127, 128, 130, and 131) - All piping inside Containment for these penetrations up t o and including the first available isolation valve on all branch lines provide one Containment boundary. The integrity of this piping is verified by normal Component Cooling Water system operation and Containment leakage detection systems. Penetration 1 24c (Excess Letdown Heat Exchanger cooling return) is normally isolated by a closed air operated valve, AOV-745, but the CLlC remains pressurized from ccw supply.
Allowable leakage for the Component Cooling Water CLlCs are as follows:
Pen Svste+ 9 Leak Rate 124a/c CCW to/from Excess Ltd Hx 1 .O gpm 127/126 CCW to/from RCP A 2.0 gpm 128/125 CCW to/from RCP B 2.0 gprn 1 31 /130 CCW to/from Rx Supt Cooling 3.0 gpm 3.5.2.3 Steam Generator (Penetrations 119,123b, 206b, 207b, 321, 322, 401 ,
402,403, and 404) - The steam generator tubes, shell and all connected piping inside Containment for these penetrations up t o and including the first available isolation valve on all branch lines provide one Containment boundary. The integrity of this piping is verified by normal system operation and Containment leakage detection systems.
Primary to secondary steam generator tube leakage is limited per LCO 3.4.13 to 0.1 gpm.
Allowable leakage for the Steam Generator CLIC's are as follows:
NOTE: For Main Steam and Main Feedwater lines, allowable leakage will be limited t o that allowed for the Standby Auxiliary Feedwater and Steam Generator Blowdown systems (i.e. more conservative limit due t o smaller diameter)
Pen Svstem Leak Rate 119 SAFW to SG A 1.5 gpm 123b SAFW to SG B 1.5 gpm 40 1 MS from SG A 1.5 gpm 402 MS from SG B 1.5 gpm 403 MFW to SG A 1.5 gpm 404 MFW to SG B 1.5 gpm 206b SG A Sample ,375 gpm 207 b SG B Sample .375 gprn 321 SG A Blowdown 1.5 gpm 322 SG B Blowdown 1.5 gpm
3.5.2.4 Charging System (Penetrations 1 0 0 , 102, 1 0 6 , and 1 1 0 a ) - All piping outside Containment from the penetration up to the discharge of the three positive displacement pumps, including the first available isolation valve on all branch lines, provide o n e Containment boundary. The integrity of this piping is verified by normal system operation and by observation during operator rounds.
Allowable leakage f o i t h e Charging CLOC's are a s follows:
- Pen Svstem Leak Rate 100 Charging to RCS Loop B 1 .O gpm 102 Alt Charging to Loop A 1 .O gpm 106 RCP A Seal Wtr Inlet 1.0 gpm 110a RCP B Seal Wtr inlet 1 .O gpm 3.5.2.5 Safety I jection System (Penetrations 101 j 1 13)- All piping outside Containment from check valves 889A/B and 870A/B to the discharge of each Safety Injection pump, including t h e first available isolation valve on all branch lines, provide one Containment boundary. The integrity of this piping is verified by system lineups and by the quarterly pump tests.
Allowable leakage for the Safety Injection CLOC's is specified in PT-39, "Leakage Evaluation of Primary Coolant Sources Outside Containment".
~J 3.5.2.6 Containment Spray System (Penetrations 105 and 109) - All piping outside Containment from check valves 862A/B to MOVs 860A/B/C/D, including t h e first available isolation valve on all branch lines, provide one Containment boundary. The integrity of this piping is verified by system lineups and by the quarterly pump tests.
Allowable leakage for the Containment Spray CLOC's is specified in PT-39, "Leakage Evaluation of Primary Coolant Sources Outside Containment".
3.5.2.7 Residual Heat Removal (Penetrations 11 1, 1 4 0 , 141, and 142) - All piping outside Containment including t h e first available isolation valve on all branch lines provide one Containment boundary. The integrity of this piping is verified by the quarterly pump tests and by normal system operation during shutdown.
Allowable leakage for the Residual Heat Removal CLOC's is specified in PT-39, "Leakage Evaluation of Primary Coolant Sources Outside Containment".
3
3.5.2.8 Containment Hydrogen Monitoring System (Penetrations 3 3 2 a , 3 3 2 b ,
and 3 3 2 d ) - All piping outside Containment inciuding the first available isolation valve on all branch lines provide one Containment boundary.
The integrity of this piping is verified by periodic 10CFR50 Appendix J leak rate testing.
-1)
Allowable leakage for the Hydrogen Monitoring CLOC's (A&B units) is specified in PTT-23.
3.5.2.9 Charging System [Seal Water Return] (Penetration 108) - All piping outside Containment from MOV-313 to the VCT, including the first available isolation valve on all branch lines, provides one boundary. The integrity of t h i s piping is verified by normal system operation and by observation during operator rounds.
Allowable leakage for the Seal Water Return CLOC is 1.5 gpm.
3.5.3 During periods when either PT-944 or PI-944 are not available to provide narrow range containment pressure, containment pressure may be obtained locally at Penetration 3 0 5 d . Attachment F provides a diagram of the means by which containment pressure is obtained at Penetration 3 0 5 d . Procedure 0-11 directs this evolution and ensures containment integrity is maintained a t all times Penetration 3 0 5 d is being used. The associated quick disconnect is n o t a containment isolation boundary.
-J 4.0 RECORDS:
4.1 None.
3
\
LLRT Proc. 1 I Valve/
Boundary Isolation Position Valve Type Notes Max Isol.
Time (secs.1 Isol.
Signal Train Steam Generator PTT-23.53.1 pi. NA Blind Flange 1 -- .-
c--
Inspection/Maintenance &
NA a2 Blind Flange 1 I --
PTT- 23.5 3.4 Fuel Transfer Tube PTT-23.54 SAC05 a1 ,a2 Blind Flange 3 Charging Line t o Loop B PTT-23.8 '- 100 CLOC a2 a1 a2 Manual Check NA 6
4 Safety Injection Pump 6 PTT-23.19 101 8708 a1 Check -
Discharge 8898 a1 Check -
CLOC 885%
a2 bl NA Manual -5 12407 b2 Manual 6 PT-923 b2 NA 8
- 2817C 281 7J cl c2 Manual Check 41 41 Alternate Charging t o PTT-23.10 Cold Leg A
- 102 3838 CLOC a1 a2 Check NA - 4 Construction Fire PTT-23.49 103 NA a1 Welded Cap -
- 5129 a2 Manual 9 Containment Spray PTT-23.18A 105 862A a1 Check Pump A CLOC a2 NA 10 2829 NA Manual 2 869A bl Manual 6. 1 3 2856 b2 Manual 6, 1 3 2825 cl Manual _-
2825A c2 Manual 6 864A dl Manual I -
859A d2 Manual 12 8598 d2. Manual 12 859C d2 Manual - 12 Reactor Coolant Pump A PTT-2 3. SA 106 304A a1 Check Seal Water Inlet
- CLOC a2 NA 4 Sump A Discharge to PTT-2 3.23 107 1728 a1 AOV Waste Holdur, Tank - 1723 a2 AOV Reactor Coolant Pump PTT-23.11 108 31 3 a1 MOV Seal Water Return
- CLOC a2 NA Containment Spray PTT-23.188 109 862% a1 Check Pump B CLOC a2 NA 2830 NA Manual 8698 bl Manual 2858 b2 Manual 2826 cl Manual 2826A c2 Manual 8648 dl Manual 859A d2 Manual
- 8598 859C d2 d2 Manual Manual Reactor Coolant Pump B P l T - 23.9 B 110a 3048 a1 Check Seal Water Inlet CLOC a2 NA PTT-23.19 llOb 879 a l , a2 Manual Safety injection Test Line - I
ATTACHMEF ' A 1 I 1 I '
System Proc.
Valve1 Boundary Isolation Position I Valve Type I Notes I Max Isol.
Time I .
Isol.
Signal Train (sets.)
Residual Heat Removal I N/A I 111 720 a1 MOV 17 - -
2840 a1 Manual 6. 1 7 - -
2847 a1 Manual 6, 1 7 -- --
2848 a1 Manual 6,,17 - ---
2853 a1 Manual 6, 1 7 - --
959 a2 AOV 35 - A.
-B I
CLOC a2 . NA 16, 36 37 1 a2 AOV . 36 60 A. B Letdown t o P l T -23.6 112 200A a1 AOV ,.. 11 60 --
Nonregenerative Heat 2008 a1 AOV 11 60 _-
Exchanger 202 a1 AOV, . 11 60 -
203 a1 Relief . 38 -
371 a2 AOV 36 60 A, B CLOC (RHR) 427 a2 NA AOV 16, 36 11 NA A. B 870A a1 Check Check 889A a1 CLOC a2 NA 5 -
I 885A bl Manual I
12406 b2 . . Manual 6 PT-922 Car, PT-922) b2 b2 .
. NA NA 8
Standby Auxiliary N/A 119 CLlC a1 NA 18 -- ---
Feedwater Line to 9704A a2 . MOV - -- -
Steam Generator A 9723 -a2 Manual I - -- -
Nitrogen t o PlT-23.46 120a 8623 a1 Check - -- -
Accumulators 846 a2 AOV -- 60 A. B Pressurizer Relief Tank PTT-23.1 120b 546 . a1 Manual -- - -
t o Gas Analyzer 539 a2 AOV - 60 A. B Makeup Water t o PlT-23.3 121a 529 a1 Check -- - -
Pressurizer Relief Tank 508 a2 AOV __- 60 A. 8 Nitrogen t o Pressurizer PTT-23.2 121b 528 a1 Check -- -
Relief Tank 547 a2 Manual .- - -
Containment Pressure PlT-23.17A 121~ 1 8 19 A a1 Manual - - -
Transmitter PT945 and PT945 a2 NA 8 - _-
PT946 1 8 19B bl Manual - - -
Pf946 b2 NA 8 - -
Reactor Coolant Drain 1600A NA sov 11 -
Tank to Gas Analyzer 1655 a1 Manual - - -B 1789 a2 AOV I 60 A Standby Auxiliary CLlC a1 NA 18 -
1 Feedwater tine to 97048 a2 MOV Steam Generator B 9725 Manual 9724 Excess Letdown Heat PTT-23.30 124a CLlC Exchanger Cooling 743 Water Supply Post Accident Air PTT-23.5OC 124b Samole to Fan C Excess Letdown Heat PTT-23.30 124~ CLlC a1 NA 19 - -
Exchanger Cooling Water Return 745 a2 AOV 20 - -
39
ATTACHMENT A Max Isol.
System LLRT Pen. Valve1 Isolation Valve Notes Isol. Signal Proc. No. Boundary Position Type Time Train Isecs.)
Post Accident Air PlT-23.5OC 124d 1572 a1 Manual - I - --
Sample t o Common 1573 a2 Manual --- -- --
Return 1574 a2 Manual --- -- --
Component Cooling PTT-23.29 125 CLlC a1 NA 19.39 - ---
Water from Reactor 7598 a2 MOV - I Coolant Pump B Component Cooing PTT-23.28 126 CLlC a1 NA 19. 3 9 - -
Water from Reactor 759A a2 MOV - -
Coolant Pump A Component Cooling PTT-23.26 127 CLlC a1 NA 19 -
Water t o Reactor 749A a2 MOV 39 Coolant Pump A Component Cooling PlT-23.27 128 CLlC a1 NA 19 - .-
Water t o Reactor 7498 a2 MOV 39 - -
Coolant Pump B Reactor Coolant Drain PTT-23.20 129 1793 a1 Manual - - -
Tank and Pressurizer 1713 a2 Check - - -
Relief Tank t o 1787 bl AOV - 60 B Containment Vent 1786 b2 AOV - 60 A Header Component Cooing PlT-23.24 130 CLlC a1 NA 19,39 - I Water from Reactor 81 4 a2 MOV 60 B Support Cooling Component Cooling PTT-23.24 131 CLlC a1 NA 19, 3 9 - --
Water t o Reactor 813 a2 MOV 60 A Support Cooling Containment Mini-Purge PTT-23.34 132 7970 a1 AOV - 5 A. B Exhaust 7971 a2 AOV --- 5 A, B Car, a2 NA 29 I - -
Residual Heat Removal NIA 140 70 1 a1 MOV 17 -
- I Pump Suction from Hot 2763 a1 Manual 6 Leg A 2786 a1 Manual 6 -
I CLOC a2 NA 16 Residual Heat Removal PTT-23.5A 141 850A a1 MOV 21 - -
Pump A Suction from CLOC a2 NA 16 - -
Sump B 1813A b l . b2 32 -- -
Residual Heat Removal PTT-23.5B 142 8508 a1 MOV 21 -
Pump B Suction from CLOC a2 NA 16 - -
Sump B 18138 b l , b2 kov 32 -
Reactor Coolant Drain PTT-23.22 143 1721 a1 AOV 60 A. B Tank Discharge Line 1003A a2 AOV - 60 A 10038 a2 AOV - 60 B
1709G a2 Manual 6 -
1722 a2 Manual 38 - -
Reactor Compartment NIA 201 a CLlC a1 NA 28 - -
Cooling Unit A Supply 475 7 a2 Manual 23 - -
4775 a2 Manual - - -
Reactor Compartment RSSP-2.8 201b CLlC a1 NA 28 - --
Cooling Unit B Return 4636 a2 Manual 22 -
4658 a2 Relief 38 -
4776 a2 Manual - - -
PI-21 41 a2 NA - --
Cap (PI-2141) a2 NA - -- -
ATTACHMENT A Max Isol.
System LLRT Pen. Valve/ Isolatton Valve Notes Isol. Signal Proc. No. Boundary Position Type Time Train (secs.1 Hydrogen Recombtner B PTT-23.51 B 202a 10768 a1 Manual - --
(Ptlotl 10211s1 a2 sov - 5 A, B Hydrogen Recombtner B PTT-23.5 1B 202b 10848 a1 Manual - - ---
(Main) 10213 S l a2 sov -_ 5 A. 0 Containment Pressure PTT-23.178 203a 1819C a1 Manual --- - -
Transmitter Pl947 and PT947 a2 NA 8 -
PT948 18190 bl Manual - -
I I
PT948 b2 NA 8 --
Post Accident Air PTT-23.508 203b DEACTIVATED VIA PCR 1996-013 DURING RFO 2 0 0 3 Samole from Fan D Post Accident Air PlT-23.508 203c Sample from Common DEACTIVATED VIA PCR 1996-01 3 DURING RFO 2 0 0 3 Header Purge Supply Duct PTT-23.35.1 204 ACD93 al, a2 Blind Flange - - -
5869 NA AOV 25 - A. B Hot Leg Loop 8 Sample PlT-23.12C 205 955 NA AOV 11 - A. B 9560 a1 Manual - I 966C a2 AOV - 60 A. B Pressurizer Liquid Space PTT-23.128 206a 953 NA AOV 11 - A, B Sample 956E a1 Manual -- -- --
9668 a2 AOV --- 60 A, B Steam Generator A PT-8.10 206b CLlC a1 NA 18 -- -
Sample 5735 a2 AOV 39 60 A. B 5749 a2 Manual -- - --
Pressurizer Steam Space PTT-23.12A 207a 95 1 NA AOV 11 A, 8 I
Sample 956F a1 Manual - -
966A a2 AOV I 60 A, B Steam Generator B Sample PT-8.10 207b CLlC a1 NA 18 - -
5736 a2 AOV 39 60 A. 8 5754 a2 Manual - - -
Reactor Compartment N/A 209a CLlC a1 NA 28 -
Cooling Unit E Supply 4635 a2 Manual 23 - I I
4637 a2 Manual --- -- --
Reactor Compartment RSSP-2.8 209b CLlC a1 NA - -
I Cooling Unit A Return 4638 a2 Manual 22 -
4758 a2 Manual - -
I 4759 a2 Relief 38 PI-223 2 a2 NA -- - -
Cap (PI-2232) a2 NA 28 -- -
Oxygen Makeup t o Recombiners A & B PTT-23.5 1C 210 1080A a1 a2 Manual sov 1021451 5 A, B 10214s NA sov 11 - A. B 1021551 a2 sov - 5 A, B 10215s NA sov 11 - A. B Purge Exhaust Duct PlT-23.36.1 300 ACD92 a l , a2 Blind Flange -- - -
5879 NA AOV 25 - A. B Auxiliary Steam Supply to Containment N/A 301 NA a l , a2 NA 27 - -
Auxiliary Steam Condensate Return N/A 303 NA a l , a2 NA 27 - -
Max Isol.
System LLRT Pen. Valve/ Isolation Valve Notes Isol. Signal Proc. No. Boundary Position Type lime Train (secs.)
Hydrogen Recombiner A PTT-23.51 A 304a 1076A a1 Manual - -
(Pilot) 10205S1 a2 sov -- 5 A, B Hydrogen Recombiner A PTT-23.5 1A 304b 1084A a7 Manual -- - -
(Main) 10209s1 a2 sov I 5 A, B containment Post PTT-23.50A 305a DEACTIVATED VIA PCR 1996-013 DURING RFO 2003 Accident Air Samole Containment Air Sample PTT-23.14 305b 1599
~~ ~~
Containment Post PTT-23.50A 305C 1557 Accident Air Sample 1558 1559 Containment Post PTT-23.50A 305D 1560 a1 Manual - - -
Accident Air Sample 1561 a2 Manual 1 -
1562 a2 Manual -- 1 -
Containment Air Sample PTT-23.15 305E 1596 a1 Manual - -
a2 AOV - 60 A. B Fire Service Water I PTT-23.52 I 307 I 9229 a1 Check -__ 1 -
I I I 9227 a2 AOV 40 -__ -
Service Water from Fan RSSP-2.4 a1 NA 28 - 1 Cooler A a2 Manual 22 - --
a2 Manual -- -. -
a2 Relief 38 --- -
FIA-2033 a2 NA --- - I -
CapsCWFIA-2033) a2 NA - --- -
TIA-2010 a2 NA --- _-- i Mini-Purge Supply PTT-23.44 309 7478 a1 AOV - 5 B 7445 a2 AOV -_ 5 A Instrument Air t o PTT- 23.32 a1 Check - - _-
Containment a2 AOV - 60 A, B Service Air t o PTT-23.33 310b 7226 Containment 7141 Service Water from Fan R SS P- 2.4 31 1 CLlC Cooler 6 4630 4634 4656 FIA-2034 Caps(s)(FIA-2034)
I I I TIA-2011 Service Water to Fan Cooler 0 NIA 31 2 CLlC a1 a2 NA Manual 28 23 - -
4642 4646 a2 Manual Manual -
12500K a2 PI-2144 a2 NA - --
Leakage Test PTT-23.42 313 SAT02 a1 Blind Flange - -
Depressurization CapiBlind Flg) a1 NA - -
7444 a2 Manual 26 --
Service Water from Fan RSSP-2.4 31 5 CLlC a1 NA 28 -
Cooler C 4643 a2 Manual 22 4647 a2 Manual - -
I .
4659 a2 Relief 38 FIA-2035 a2 NA - _- -
Caps(2)(FIA-2035) a2 NA - - --
a2 NA _-- -- --
I Max Isol.
System Valve1 Isolation Valve Notes Isol. Signal Proc. Boundary Position Tvpe lime Train (secs.)
Service Water t o Fan Cooler 6 NIA I 316 CLlC 4628 a1 a2 NA Manual 28 23 4632 a2 Manual -
PI-21 3 8 a2 NA -
Leakage Test Supply P l T -2 3.43 31 7 SAT01 a1 Blind Flange --
Cap (Blind flg) a1 NA I 7443 a2 Manual 26 Deadweight Test N/A 31 8 NA a l . a2 NA 27 Service Water t o Fan N/A 31 9 CLlC a1 NA 28 Cooler A 4627 a2 Manual 23 4631 a2 Manual PI-2142 a2 NA --
Service Water t o Fan Cooler C I NIA I 320 CLIC 4641 a1 a2 NA Manual 28 23 4645 a2 Manual -
12500H a2 Manual -
PI-2 1 36 a2 NA -
Steam Generator A PT-8.9 321 CLlC at NA 18 Blowdown 5738 a2 AOV 39
~
5752 a2 Manual _-
Steam Generator B PT-8.9 322 CLlC at NA 18 Blowd o w n 5737 a2 AOV 39 I I 5756 a2 Manual _-
I I CLlC a1 NA 28 4644 a2 Manual 22 4648 a2 Manual -
4660 a2 Relief 38 FIA-2036 a2 NA NA Caps(21(FIA-2036) a2 TIA-2013 a2 NA -
Demineralized Water to 841 9 a1 Check -
Containment 841 8 a2 AOV --
Hydrogen Monitor 922 a1 sov -
Instrumentation Line 924 a1 sov -
CLOC a2 NA 31 7452 bl b2 Manual NA Cap(7452)
Hydrogen Monitor PTT-23.45 332b 923 a1 sov -
Instrumentation Line CLOC a2 NA 31 7456 bl b2 Manual NA I I Cap (7456)
Containment Pressure PTT-23.17C 332c 1819G a1 Manual -
Transmitters PT944, PT944 a2 NA 8 PT949, and PT950 1819E bl Manual --
PT949 b2 NA 8 1819F cl Manual -
PT950 c2 NA 8 I I Hydrogen Monitor PlT-23.45 3324 92 1 a1 sov --
Instrumentation Line CLOC a2 NA 31 7448 bl Manual -
I I Cap (7448) b2 NA --
ATTACHMENT A -
Isol.
System LLRT Pen. Valve/ Isolation Valve Signal Main Steam from Steam Proc.
-No.
40 1 Boundary Position Type Train CLlC a1 NA Generator A 341 1 a2 Relief 3413A a2 Manual 3455 a2 Manual 3505A a2 MOV 3505C a2 Manual 3509 a2 Relief 351 1 a2 Relief 3513 a2 Relief 3515 a2 Relief 3517 a2 AOV 3521 a2 Manual 361 5 a2 Manual 3669 a2 Manual 11027 a2 Manual 11029 a2 Manual 11031 a2 Manual PS-2092 a2 NA PT-468 a2 NA PT-469 a2 NA PT-469A a2 NA PT-482 a2 NA
- End Caps a2 NA Main Steam from Steam Generator B NIA 402 1 CLlC a1 NA 3410 a2 Relief 341 2A a2 Manual 3456 a2 Manual 3504A a2 MOV 3504C a2 Manual 3508 a2 Relief 3510 a2 Relief 3512 a2 Relief 3514 a2 Relief 3516 a2 AOV 3520 a2 Manual 3614 a2 Manual 3668 a2 Manual 11021 a2 Manual 11023 a2 Manual 11 0 2 5 a2 Manual PS-2093 a2 NA PT-478 a2 NA PT-479 a2 NA PT-483 a2 NA End C a m a2 NA 1
-eedwater Line to NIA 103 CLlC a1 .NA Steam Generator A 3993 a2 Check 3995x a2 Manual 4000C a2 Check 4003 a2 Check 4003A a2 Manual 4011A a2 Manual 4099E a2 Manual 8651 a2 Manual
- eedwater Line to NIA IO4 CLlC a1 NA Steam Generator 6 3992 a2 Check 3994E a2 Manual 3994x a2 Manual 40000 a2 Check 4004 a2 Check 401 2A a2 Manual 4004A I a2 Manual I 8650 1 a2 Manual
Max Isol.
System LLRT Pen. Valve/ Isolation Valve Notes Isol. Signal Proc. No. Boundary Position Type Time Train (secs.)
Personnel Hatch PT-22.3 & 1000 NA a1 NA - - --
PT- 2 2.2 NA a2 NA - - --
Equipment Hatch PT-22.4 & 2000 NA a1 NA --- - _--
PT-22.1 NA a2 NA -- -- -.-
Attachment A Notes This Penetration is closed by a double-gasketed blind flange on both ends. Both flanges are necessary for Containment integrity purposes since the test connections between the . t w o gaskets for each flange do not meet the requirements of ANSI-56.8. Therefore, the innermost gasket for each flange (i.e., gasket closest to Containment wall) provides a single Containment barrier.
This valve is a Containment isolation valve however, due t o the installed downstream welded flange 1 O C F R 5 0 , Appendix J testing is not required. This valve is normally maintained locked closed t o provide additional assurance of Containment integrity, The end of the fuel transfer tube inside Containment is closed by a double-gasketed blind flange to prevent leakage of spent fuel pit water into the Containment during plant operation. Each gasket provides a single Containment isolation barrier. This flange also serves as protection against leakage from the Containment following a loss-of-coolant accident.
The charging system is a closed system outside Containment (CLOC).
Verification of this closed system as a Containment isolation boundary is accomplished via normal system operation (= 2235 psig).
.3 The safety injection system is a closed system outside Containment (CLOC).
Verification of this closed system as a Containment isolation boundary is accomplished via inservice and/or shutdown leakage checks. (Safety Injection Pump discharge pressure is =: 1500 psig)
This valve is not locked closed; however, the valve is maintained closed by testing and system lineup procedures and has a "Boundary Control Tag" per PTT-23A. This provides equivalent assurance of proper valve position.
NOTE (7)was deleted from Rev 11 via PCN 2003-4540.
The pressure transmitter assembly, by its design, provides a Containment pressure boundary. Since the transmitter provides direct indication t o the control room, operators would be aware of its failure. Therefore, the transmitter's root valve(s) is normally maintained open.
This penetration was only utilized during initial plant construction and is maintained inactive. Since there is no test connection between 51 29 and the threaded cap, all observed leakage during testing is applied t o 51 29. Therefore, the outside cap is not a CIS.
14
Attachment A - NOTES (Cont'd) 4 (10) The Containment spray system is a closed system outside Containment (CLOC).
Verification of this closed system as a Containment isolation boundary is accomplished via inservice and/or shutdown leakage checks. (Containment Spray pump discharge pressure is = 285 psig) d (11) This valve receives a Containment isolation signal; however, credit is not taken for this function since the valve is inside the missile barrier or outside the necessary class break boundary. Therefore, this valve is not a Containment isolation valve and not subject t o 10 CFR 5 0 Appendix J testing nor Le0 3.6.3.
The Containment isolation signal only enhances Containment isolation. AOV-200A, 2008,and 202 do not receive CI signals but go ctosed from AOV-427 close signal.
(12) Both Containment spray test fines have a locked closed manual valve that leads t o a common line with t w o normally closed manual valves. The valves in this common line may be opened during a pump test since necessary Containment isolation is maintained (see Safety Evaluation NSL-0000-SEO? 5).
(13) The test line and root valves for the pressure indicators can be opened during testing of the CS pumps since manual valves 8 6 8 A/B are closed, thus providing the necessary Containment boundary for the short duration of the test.
(14) The second isolation barrier (CLOC) is provided by the volume control tank and connecting piping per letter from D.D. Dilanni, NRC, t o R.W. Kober, RG&E,
- dated January 30, 1987. This barrier is not required t o be tested.
(15) Only one isolation barrier is provided since there are t w o Event V check valves in the SI cold legs, and two checkvalves and a normally closed motor-operated valve in the SI hot legs. This configuration was accepted by the NRC during the SEP (NUREG-0821, Section 4.22.2).
(16) The residual heat removal lines for this penetration are a closed loop outside Containment (CLOC). Verification of this closed system as a Containment isolation boundary is accomplished via inservice and/or shutdown leakage checks. (Residual Heat Removal pump discharge pressure is = 175 psig)
(1 7) Appendix J Containment leakage testing is n o t required per letter from D.M.
Crutchfield, NRC, to J.E. Maier, RG&E, dated May 6 , 1981.
(18) The Main Steam, Main Feedwater, Standby Auxiliary Feedwater and S/G Blowdown penetrations take credit for the steam generator tubes and shell as a closed system inside Containment (CLIC).Verification of this closed system as a Containment isolation boundary is accomplished via normal power operation ( ~ 7 5 0psig). The isolation valves outside Containment for these penetrations do not require Appendix J testing.
Attachment A - NOTES (Cont'd)
(19) The component cooling water lines inside Containment for this penetration are a closed loop inside Containment (CLIC). Verification of this closed system a s a Containment isolation boundary is accomplished via inservice and/or shutdown leakage checks. (Component Cooling Water pump discharge pressure is = 85 psig)
( 2 0 ) Operations is instructed to manually close AOV 745 following a Containment isolation signal t o provide additional redundancy.
(21 S u m p lines are in operation and filled with fluid following a n accident; therefore, 10CFRSO, Appendix J leakage t e q i n g is not repuired for this penetration. See letter from D.M. Crutchfield, NRC, to J.E. Maier, RG&E, dated May 6, 1981.
(22) This manual valve is subjected to a n annual hydrostatic leakage test t > 60 psig) and is not subject t o 10CFRSO, Appendix J leakage testing. See NUREG-0821, Section 4.22.3.
(23) The Service Water System operates a t a higher pressure than t h e Containment accident pressure (60 psig) and is missile protected inside Containment.
Therefore, this manual valve is used for flow control only and is not subject to 1 OCFR50, Appendix J leakage testing. See NUREG-0821, Section 4.22.3.
(24) This valve does not receive an automatic Containment isolation signal but is normally open a t power since it either improves t h e reliability of a n essential standby system or is required for power operation. However, this valve can either be closed from the control room or locally w h e n required.
(25) The flanges and associated double seals provide Containment isolation and ensure that Containment integrity is maintained for all modes of operation above cold shutdown. When the flanges are removed during cold shutdown conditions, Containment integrity is provided by t h e valve. This valve is not required to be operable above cold shutdown and d o e s not require 10CFR50, Appendix J leakage testing, nor a maximum isolation time.
(26) Valves 7443 and 7444 are maintained locked closed and are in series with a blind flange.
(27) This penetration is decommissioned and welded shut.
(28) The service water system piping inside Containment for this penetration is a closed system inside Containment (CLIC). Verification of this dosed system as a Containment isolation boundary is accomplished via inservice andlor shutdown leakage checks. (Service Water Pump discharge pressure is = 60 psig under non-accident conditions)
Attachment A - NOTES (Cont'd)
(29) This end cap is used for flow balancing. However, it cannot be opened above cold shutdown without first performing a safety evaluation.
I (30) NOTE (30) was deleted per NRC letter dated August 30, 1993 via PCN 93-I 4377.
(311 Acceptable isolation capability is provided for these instrument lines by t w o isolation boundaries outside Containment. One of the boundaries is a Seismic Category I closed system which is subject to Type C leakage testing under 10 CFR 5 0 Appendix J.
(32) There is no second Containment barrier for this branch line. This is addressed by Safety Evaluation NSL-0000-SE015.
(33) These end caps include those found o n the sensing lines for PS-2092, PT-468, PT-469, PT-469A, and PT-482 (Penetration 401 1 and PS-2093, PT-479, and PT-483 (Penetration 402).
(34) This check valve can be open when Containment isolation is required in order t o provide necessary feedwater or auxiliary feedwater t o the steam generators.
The check valve will close once feedwater is isolated to the affected steam generator (NUREG-0821, Section 4.22.1).
AOV 959 is not a Containment isolation valve since it does not perform a Containment isolation function as defined by I OCFR50, Appendix J, Section I1.B. This AOV is continuously pressurized above the peak Containment accident pressure by the head of the RHR pumps acting in the safety injection mode. This pressure head is available throughout the post accident period regardless of any single active failure. Since A O V 959 receives a Containment isolation signal, and t o provide additional assurance of the RHR CLOC integrity, the fuses for AOV 9 5 9 are removed with boundary control tags in place t o maintain this valve closed. Manual valve 9 5 7 is also maintained closed t o provide additional assurance of Containment integrity; however, neither valve 957 nor AOV 959 are Containment isolation valves subject t o LCO 3.6.3.
(36) AOV 371 and the RHR CLOC are Containment isolation valve boundaries for both penetrations 111 and 1 12.
I (37) NOTE (37) was deleted per NRC letter dated August 30, 1 9 9 3 via PCN 93-I 4377.
(38) This valve provides a Containment boundary and is inferred tested during the applicable 10CFR50 Appendix J test or ASME hydrostatic leakage test.
(39) This valve is subjected t o ASME hydrostatic leakage test ( > 60 psig) and is not J) subject t o 10CFR50, Appendix J leakage testing.
Attachment A - NOTES (Cont'd)
(40) Containment Isolation Signal was removed per TSR 94-1 38.
(41) This valve was added in accordance with PCR 2002-0035 and is only used for L
manual operation of the Safety injection Accumulator Makeup Pump. This valve is normally isolated by an in-line, closed, manual valve (V-2810).
3
ATTACHMENT B FOR INFORMATION ONLY ,.
3 I
r 10003.
I 1072 NOTE: Valve is used os o test connection, t h e r e f o r e i t i s i!
EXEMPT f r o m l o c o l leokrote a1 '
testing.
/
A I ,
1728 AilX BiDG P10-7 i
. ,,- \,
10036
ATTACHMENT C FOR INFORMATION ONLY P124d CONTAIN M EN T
I i, --- -----
-i L AUX 6LDG I
a1 1572
/Lc:
I a2 1
9
, 4 1573 NOTE: Volve is not used as a test a2 connection, therefore it is NOT exempt from local leakrate 1574 testing.
I.LC i
ATTACHMENT D FOR INFORMATION ONLY I
l v j I C !
i~ I I i i 1
,;:+ 1 1 2c
- I m
7
.n, ,
w i
1c _!,2691 I
To VCT i
9 2 RV284 I
1.. ' '., I 287
- Ii i
S E
D I! ;
.. L
...I L
d B 5 I f.., ,. . 1 I,.\', j I
I A
M I
i 2aa i P a$$ !
To VCT iI ! I E I - RV283 I N ip3:y i,,.'&-
i! ;:
IC I
i' 1
"./]
1.' ',
29 1 I
I
\
E R
I
-.-J
Example:
V - 2 8 7 will be h e l d closed to p r o v i d e t h e i s o l a t i o n b o u n d a r y f o r r e m o v a l a n d r e p l a c e m e n t of C h a r g i n g P u m p A d i s c h a r g e r e l i e f valve, RV-285. C h a r g i n g CLOC h a s b e e n a l t e r e d s u c h that b o u n d a r y i s n o w V-287 and n o l o n g e r d i s c h a r g e of C h a r g i n g Pump A . Provided that c h a r g i n g s y s t e m CLOC l e a k a g e has been v e r i f i e d t o b e 5 1.0 gpm, CLOC r e m a i n s o p e r a b l e a n d a n A-52.4 will t r a c k t h i s c o n d i t i o n until t h e CLOC i s restored t o its n o r m a l c o n f i g u r a t i o n .
ATTACHMENT E FOR INFORMATION ONLY
- 4) a2 CIB
./ n...,
( PT "
\ 945 ,
"7" k 1 V/J
,,*" -'\, 1 81 9B I bl i
\.
a 18188
~2 OPEN PIPE I I i TC/J I Example:
p121C 8 V - 1 8 1 9 A ( a l ) will be closed by I&C
' calibration procedure to allow use 1 o f downstream test connection f o r 1 injection of test signal f o r calibration o f PT-945 (a2). PT-945 boundary i s bypassed a n d m a d e inoperable by this activity. A n A-52.4 shall be submitted to t r a c k this condition until the boundary h a s . been restored t o operable status.
NOTE: Penetration 121c r e m a i n s operable, only t h e PT-945 boundary is inoperable.
-3
ATTACHMENT F PEN 305d, ALTERNATE SOURCE FOR OBTAINING CNMT PRESSURE WHEN PT-944/Pl-944 OUT OF SERVICE L1)
/
- Quick-disconnect installed at Pen 305d is utilized to locally obtain CNMT pressure by use of temporary HEISE pressure module and digital meter. Valve V-1560 and f V - 1 5 6 2 are positioned as required in accordance with 0-11 to convey CNMT f pressure to pressure module connected to permanently installed quick-disconnect I downstream of V-1562.
Containment Isolation Boundaries 3.6.3 5 3.6 3.6.3 CONTAINMENT SYSTEMS Containment Isolation Boundaries LCO 3.6.3 Each containment isolation boundary shall be OPERABLE.
- 1. Not applicable to the main steam safety valves in MODES 1,2, and 3.
- 2. Not applicable to the main steam isolation valves (MSIVs) in MODE 1, and in MODES 2 and 3 with the MSlVs open or not deactivated.
- 3. Not applicable to the atmospheric relief valves in MODES 1 and 2, and in MODE 3 with the Reactor Coolant System average temperature (Tavg)2 500°F.
............................................. I .
APPLICABILIW. MODES I, 2,3, and 4.
- NOTE -
- 1. Penetration flow path(s), except for Shutdown Purge System valve flow paths, may be unisolated intermittently under administrative controls.
- 2. Separate Condition entry is allowed for each penetration flow path.
3, Enter applicable Conditions and Required Actions for systems made inoperable by containment isolation boundaries.
- 4. Enter applicable Conditions and Required Actions of LCO 3.6.1, "Containment," when isolation boundary leakage results in exceeding the overall containment leakage rate acceptance criteria.
R.E. Ginna Nuclear Power Plant 3.6.3-1 Amendment 80
Containment Isolation uounaanes 3.6.3
. ~~ ~
/,
CONDIT1ON REQUIRED ACTION COMPLETION TIME 3 A.
4.1 Isolate the affected penetration flow path by use 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
- NOTE - of at least one closed and Only applicable to de-activated automatic penetration flow paths valve, closed manual valve, which do not use a closed blind flange, or check valve system as a containment with flow through the valve isolation boundary.
. secured.
One or more penetration flow paths with one containment isolation 4.2 boundary inoperable ------------------
except for mini-purge - NOTE -
valve leakage not within Isolation boundaries in high radiation areas may be limit.
verified by use of administrative means.
Verify the affected Once per 31 days penetration flow path is for isolation isolated. boundaries outside containment AND Prior to entering MODE 4 from MODE 5 if not performedwithin the l previous 92 days for isolation boundaries
' inside containment 3
R.E. Ginna Nuclear Power Plant 3.6.3-2 Amendment 80
Containment Isolation Boundaries 3.6.3
~ __-
CONDITION REQUIRED ACTION COMPLETION TIME B. B.1 Isolate the affected 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> penetration flow path by use
- NOTE - of at least one closed and Only applicable to de-activated automatic penetration flow paths valve, closed manual valve, which do not use a closed or blind flange.
system as a containment isolation boundary.
One or more penetration flow paths with two containment isolation boundaries inoperable except for mini-purge valve leakage not within limit.
C. c.1 Isolate the affected 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
penetration flow path by use
- NOTE - of at least one closed and Only applicable to de-activated automatic penetration flow paths valve, closed manual valve, which use a closed
-3 system as a containment isolation boundary.
or blind flange.
- - - - - - - - - - - - - - - - - - AND One or more penetration flow paths with one containment isolation boundary inoperable.
I RE. Ginna Nuclear Power Plant 3.6.3-3 Amendment 80
Containment Isolation Boundaries 3.6.3 CONDITION I REQUIRED ACTION COMPLETION TIME c) c.2
- NOTE -
Isolation boundaries in high radiation areas may be verified by use of administ rative means.
Verify the affected Once per 31 days penetration flow path is for isolation isolated. boundaries outside containment Prior to entering MODE 4 from MODE 5 if not performedwithin the previous 92 days for isolation boundaries inside containment D. One or more mini-purge D.l Isolate the affected 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> penetration flow paths penetration flow path by use with one valve not within of at least one closed and leakage limits. de-activated automatic valve, closed manual valve, or blind flange.
RE. Ginna Nuclear Power Plant 3.6.3-4 Amendment 80
Containment Isolation Boundaries 3.6.3 CONDITION REQUIRED ACTION COMPLETION TIME D.2 Verify the affected Once per 31 days .
penetration flow path is for isolation isolated. boundaries outside containment Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days for isolation boundaries inside containment
\3 E. One or more mini-purge E.l Initiate action to evaluate Immediately penetration flow paths overall containment leakage with two valves not within rate per LCO 3.6.1.
leakage limits.
-, AND E.2 Isolate the affected 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> I penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.
F. Required Action and I F.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met. -
AND F.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> R.E.Ginna Nuclear Power Plant 3.6.3-5 Amendment 80
Containment Isolation Boundaries 3.6.3 SURVEILLANCE REQUIREMENTS 3 SURVEILLANCE FREQUENCY SR 3.6.3.1 Verify each mini-purge valve is closed, except when 31 days the penetration flowpath(s) are permitted to be open under administrative control.
- 1. Isolation boundaries in high radiation areas may be verified by use of administrative controls.
- 2. Not applicable to containment isolation boundaries which receive an automatic containment isolation signal.
Verify each containment isolation boundary that is 32 days located outside containment and not locked, sealed, or otherwise secured in the required position is performing its containment isolation accident function except for containment isolation boundaries that are open under administrative controls.
SR 3.6.3.3 - NOTE -
3 1. Isolation boundaries in high radiation areas may be verified by use of administrative means.
- 2. Not applicable to containment isolation boundaries which receive an ailtomatic containment isolation signal.
Verify each containment isolation boundary that is Prior to entering located inside containment and not locked, sealed, or MODE 4 from otherwise secured in the required position is MODE 5 if not performing its containment isolation accident function, performed within the except for containment isolation boundaries that are previous 92 days open under administrative controls.
SR 3.6.3.4 Verify the isolation time of each automatic In accordance with containment isolation valve is within limits. the Inservice Testing Program
~- ~~ ~
SR 3.6.3.5 Perform required leakage rate testing of containment In accordance with mini-purge valves with resilient seals in accordance the Containment with the Containment Leakage Rate Testing Program. Leakage Rate Program.
R.E. Ginna Nuclear Power Plant 3.6.3-6 Amendment 80
Containment Isolation Boundaries 3.6.3 SURVEILLANCE I FREQUENCY SR 3.6.3.6 Verify each automatic containment isolation valve that 24 months is not locked, sealed, or otherwise secured in the required position actuates to the isolation position on an actual or simulated actuation signal.
RE. Ginna Nuclear Power Plant 3.6.3-7 Amendment 80
RUL'HkSTER GAS AND ELECTRIC L'UHPUHAI I W N GINNA STATION CONTROLLED COPY NUMBER&
PROCEDURE NO. EPIP 2-1 REV. NO. 21 PROTECTIVE ACTION RECOMMENDATIONS TECHNICAL REVIEW b EFFEC VE ATE CATEGORY 1.O THIS PROCEDURE CONTAINS 15 PAGES
EPlP 2-1:1 EPlP 2-1 i b PROTECTIVE ACTION RECOMMENDATIONS 1.o PURPOSE:
1.1 The purpose of this procedure is to provide guidance to the Emergency Coordinator or EOWRecovery Manager in making protective action recom-mendations to offsite authorities.
2.0 RESPONSIBILITY
2.1 The Shift Supervisor, Emergency Coordinator (TSC) or EOF/Recovery Manager is responsible for making protective action recommendations to Wayne County, Monroe County and New York State, depending on command and control status.
2.2 The decision to implement any protective actions is solely the responsibility of the local authorities.
3.0 REFERENCES
Developmental References 3.1.1 Nuclear Emergency Response Plan 3.1.2 EPA-400, Manual of Protective Action Guides and Protective Actions for Nuclear Incidents (19911 3.1.3 Evacuation Travel Time Estimates - Ginna Emergency Planning Zone, September 1992.
3.1.4 NUREGIBR - 0150 Response Technical Manual (RTM-93) 3.1.5 Food and Drug Administration (FDA) Potassium Iodide as a Thyroid Blocking Agent in Radiation Emergencies, December 2001.
3.1.6 NUREG-1633, Assessment of the Use of Potassium Iodide (KI) as a Supplemental Public Protective Action During Severe Reactor Accidents.
I 3.1.7 NRC RIS 2003-12 Clarification of NRC Guidance for Modifying Protective Actions 3.2 Implementing References L) 3.2.1 EPlP 1-0, Ginna Station Event Evaluation and Classification
EPlP 2-112 3.2.2 EPlP 1-5, Notification 3.2.3 EPlP 2-3, Emergency Release Rate Determination 3.2.4 EPlP 2-4, Emergency Dose Projections - Manual Method 3.2.5 EPIP 2-18, Control Room Dose Assessment 3.2.6 EPIP 2-5, Emergency Dose Projections - Personal Comput M th d 3.2.7 EPlP 2-6, Emergency Dose Projectbns - MIDAYProgram
4.0 PRECAUTIONS
None
5.0 PREREQUISITES
None.
6.0 INSTRUCT10NS
NOTE: PROTECTIVE ACTION RECOMMENDATIONS (PARS) WILL ONLY
.J REFLECT RG&E RECOMMENDATIONS, NOT ACTIONS IMPLEMENTED BY OFFSITE OFFICIALS.
6.1 Obtain the event classification using EPlP 1-0.
6.2 UNUSUAL EVENT. ALERT and SlTE AREA EMERGENCY.
6.2.1 Report on EPlP 1-5, Attachment 3a, Item 7:
A. No need for protective actions outside the site boundary.
6.3 GENERAL EMERGENCY 6.3.1 Protective Action Recommendations shall be issued with the initial declaration of a General Emergency.
6.3.2 Using Attachment 1, Page 1 of 2, and the current wind direction, determine the initial ERPAs to be evacuated. The Counties will implement their KI plans for any evacuated ERPA. Any ERPA not evacuated will be sheltered.
i) 6.3.3 Record in EPIP 1-5, Attachment 3a, Item 7 the Protective Actions Recommended.
EPIP 2-1:3 I NOTE: ONCE AN ERPA HAS BEEN RECOMMENDED TO EVACUATE, THAT I RECOMMENDATION WILL CONTINUE. AN ERPA PAR STATUS CANNOT 3 BE CHANGED FROM EVACUATE TO SHELTER.
6.3.4 Re-evaluate the PARs based on the following to determine if secondary PARs are required or if initial PARs need to be modified.:
- a. Dose Assessment*
- b. Survey Team data*
- c. EPA Protective Action Guidelines (Attachment 2)
- d. Wind shifts .b d
- = If exposures in non-evacuated areas indicate that evacuation is warranted, use Attachment 1 page 2 of 2 to expand Protective Action Recommendations to an evacuated area of 5 mile radius and 10 miles downwind.
6.3.5 The Evacuation Travel Time Estimate information (Attachment 3) is used by offsite agencies to determine the correct Protective Action Decision (PAD).
6.3.6 If the EPA guidelines for evacuation or sheltering are exceeded beyond the 10 mile emergency planning zone and protective actions are required, specify the areas using roads, rivers, bodies of water or town boundaries.
-3 7.0 ATTACHMENTS:
- 1. Evacuation Areas by Zones.
- 2. Projected Dose to the Population and Recommended Actions.
- 3. Evacuation Travel Time Estimates.
- 4. Emergency Response Planning Areas (ERPAs).
EPlP 2-1:4 Attachment 1, Rev. 21 Page 1 of 2 EVACUATION AREAS BY ZONES PROTECTIVE ACTION RECOMMENDATIONS BY ERPA FOR GENERAL EMERGENCY CLASSIFICATION Wind From (Degrees) Initial Protective Action Recommendations (Evacuation based on 2 mile radius & 5 miles downwind)
N 349 to 11 Evacuate: W (1,2,3) and implement KI plan Shelter: All remaining ERPAs NNE 12 to 33 Evacuate: W (1,2) M (1) and implement KI plan Shelter: All remaining ERPAs NE 34 to 56 Evacuate: W (1,2) M (1) and implement KI plan Shelter: All remaining ERPAs ENE 57 to 78 Evacuate: W (1,2) M (1) and implement KI plan Shelter: All remaining ERPAs E 79 to 101 Evacuate: W (1,2) M (1) and implement KI plan Shelter: All remaining ERPAs ESE 102 to 124 Evacuate: W (1) M (1) and implement KI plan Shelter: All remaining ERPAs SE 125 to 146 Evacuate: W (1) and implement KI plan Shelter: All remaining ERPAs
-3 SSE 147 to 168 Evacuate: W (1) and implement KI plan Shelter: All remaining ERPAs S 169 to 191 Evacuate: W (1) and implement KI plan Shelter: All remaining ERPAs ssw 192 to 213 Evacuate: W (1) and implement KI plan Shelter: All remaining ERPAs sw 214 to 236 Evacuate: W (1,3) and implement KI plan Shelter: All remaining ERPAs wsw 237 to 258 Evacuate: W (1,3) and implement KI plan Shelter: All remaining ERPAs W 259 to 281 Evacuate: W (1(3)and implement KI plan Shelter : All remaining ERPAs WNW 282 to 303 Evacuate: W (1,2,3) and implement KI plan Shelter: All remaining ERPAs NW 304 to 326 Evacuate: W (1,2,3) and implement KI plan Shelter: All remaining ERPAs NNW 327 to 348 Evacuate: W (1,2,3) and implement KI plan Shelter: All remaining ERPAs
c GENERAL EMERGENCY CLASSIFICATION Atta&t
. 2-1:5 1, Rev, 20 Wind From (Degrees) Initial Protective Action Recommendations Secondary Protective Action Recommendations (Evacuation based on 2 mile radius & 5 miles downwind) (Evacuation based on 5 mile radius & 10 miles downwind)
N 349 to 11 Evacuate: W (1,2,3) and implement KI plan Evacuate: W (1, 2,3,5,6,7) M (1, 2,4,5) and implement KI plan Shelter: All remainingERPAs Shelter: All remaining ERPAs NNE 12 to 33 Evacuate: W (1,2) M (1) and implement KI plan Evacuate: W (1,2,3,6,7) M (1,2,3,4,5,6,7,9) and implement KI plan Shelter. All remaining ERPAs Shelter: All remaining ERPAs Evacuate: W (1,2) M (1) and implement KI plan Evacuate: W (1,2,3,7) M (1,2,3,4,5,6,7,8,9) and implement KI plan Shelter: All remaining ERPAs Shelter: All remaining ERPAs Evacuate: W (1,2) M (1) and implement KI plan Evacuate: W (1,2,3,7) M (1,2,3,4,5,6,7,8,9) and implement KI plan Shelter: All remaining ERPAs Shelter: All remaining ERPAs E 79 to 101 Evacuate: W (1,2) M (1) and implement KI plan Evacuate: W (1,2,3) M (1,2,3,4,6, 7,8,9) and implement KI plan Shelter: All remaining ERPAs Shelter: All remaining ERPAs
~ ~-
ESE 102 to 124 Evacuate: W (1) M (1 and implement KI plan Evacuate: W (1,2,3) M (1,3,6,8,9) and implement KI plan Shelter. All remaining ERPAs Shelter: All remaining ERPAs SE 125 to 146 Evacuate: W (1) and implement KI plan Evacuate: W (1, 2,3) MU) , and implement KI plan Shelter. All remaining ERPAs Shelter: All remaining ERPAs 1 7 SSE 147 to 168 Evacuate: W (1)
Shelter: All remaining ERPAs and implement KI plan I Evacuate: W (1 I 2,3)
Shelter: All remaining ERPAs
. MU) and implement KI plan I
I
~~
S Evacuate: W (1) and implement KI plan Evacuate: W (1,2,3) M (1) and implement KI plan Shelter. All remaining ERPAs Shelter: All remaining ERPAs
~ ~~ ~ ~ ~-
ssw 192to 213 Evacuate W (1) and implement KI plan Evacuate: W (1,2,3) M (1) and implement KI plan Shelter. All remaining ERPAs Shelter: All remaining ERPAs sw 214 to 236 Evacuate: W (1,3) and implement KI plan Evacuate: W (1,2,3,4) M (1) and implement KI plan Shelter: All remaining ERPAs Shelter: All remalnlng ERPAs wsw 237 to 258 Evacuate: W (1,3) and implement KI plan Evacuate: W (1,2,3,4,5) M (1) and implement KI plan Shelter: All remaining ERPAs Shelter: All remaining ERPAs Evacuate: W (1 I 3) and implement KI plan Evacuate: W (1,2,3,4,5,6) M (1) and implement KI plan Shelter: All remaining ERPAs Shelter: All remaining ERPAs WNW 282 to 303 Evacuate: W (1 ,2,3) and implement KI plan Evacuate: W (1, 2,3,4,5,6,7)M (1) and implement KI plan Shelter: All remaining ERPAs Shelter: All remaining ERPAs NW 304 to 326 Evacuate: W (1,2,3) and implement KI plan Evacuate: W (1I 2,3,4,5,6,7)M (1 , 2) and implement KI plan Shelter: All remaining ERPAs Shelter: All remaining ERPAs NNW 327 to 348 Evacuate: W (1,2,3) and implement KI plan Evacuate: W (1,2,3,4,5,6,7) M (1,2,5) and implement KI plan I I
c c 2-1:6 Attachment 2, Rev, 20 Page 1 of 1 PROJECTED DOSE TO THE POPULATION AND RECOMMENDED ACTIONS PROJECTED DOSE TO THE RECOMMENDED ACTIONS COMMENTS POPULATION Total Whole Body < 1 REM* No planned protective actions. Local authoritie! None.
or State may issue an advisory to seek shelter and await further instructions. Monitor environmental radiation levels.
Total Whole Body 2 1 REM* Conduct evacuation. Evacuation (or for some situation, Monitor environmental radiation levels and sheltering**) should be initiated at one Committed Dose Equivalent to the thyroid adjust area for mandatory evacuation based on REM. Seeking shelter would be an (child) 2 5 REM. these levels. alternative if evacuation were not Control access. immediately possible.
Implement KI plan.
Project Dose (REM) to Emergency Team Workers Total Whole Body 25 REM Control exposure of emergency team members None.
to these levels except for lifesaving mission. L (Appropriate controls for emergency workers include time limitations, respirators and stable
~~~
iodine.)
Total Whole Body 75 REM Control exposure of emergency team members None.
performing lifesaving missions to this level.
(Control of time of exposure will be most effective.)
NOTES:
- The sum of the effective dose equivalent resultingfrom exposure to external sources and the committed effective dose equivalent incurred from all significant inhalation pathways during the early phase.
- Sheltering may be the preferred protective action when it will provide protection equal to or greater than evacuation, based on consideration of factors such as source term characteristics and temporal or other site-specific conditions.
trip z-I:~
Attachment 3, Rev. 21 Page 1 of 8 EVACUATION TRAVEL TIME ESTIMATES J 1. When discussing an evacuation, use this attachment to resolve conflicts.
- 2. 1992 Permanent Resident Population Estimates EPRA Population -
ERPA Pooulation w-1 3207 M-1 2421 w-2 5395 M-2 435 w-3 1200 M-3 258 w-4 2092 M-4 6681 w-5 3855 M-5 1253 W-6 2425 M-6 6943 w-7 4924 M-7 4750 M-8 3033 M-9 3285
- 3. Use the following curves to assist in estimating evacuation decisions.
Fiaure Weather Conditions Time of Week 2 41 Summer, Good Weather Midweek, Midday 43 Summer, Rainy Weather Midweek, Midday 45 Summer, Good Weather Midweek, Evening 49 Summer, Good Weather Weekend, Midday 53 Winter, Good Weather Midweek, Midday 55 Winter, Rainy Weather Midweek, Midday 57 Winter, Snowy Weather Midweek, Midday
I EPlP 2-1:8 Attachment 3,Rev. 21 Page 2 of 8 I
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.'.. 0 1 2 3 4 5 6 7 WAYNE CO.
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EPlP 2-1 114 Attachment 3, Rev. 21 Page 8 of 8
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