ML15092A854
| ML15092A854 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 04/02/2015 |
| From: | NRC/RGN-II |
| To: | Tennessee Valley Authority |
| References | |
| 50-327/15-301, 50-328/15-301 | |
| Download: ML15092A854 (61) | |
Text
ES-401 Site-Specific SRO Written Examination Form ES-401 -8 Cover Sheet U.S. Nuclear Regulatory Commission Site-Specific SRO Written Examination Applicant Information Name:
Date: Facility/Unit: Sequoyah Nuclear Station 1 & 2 Region: I II X lii IV ReactorType: WXCEEIBWEIGEEI Start Time: Finish Time:
Instructions Use the answer sheets provided to document your answers. Staple this cover sheet on top of the answer sheets. To pass the examination you must achieve a final grade of at least 80.00 percent overall, with 70.00 percent or better on the SRO-only items if given in conjunction with the RO exam; SRO-only exams given alone require a final grade of 80.00 percent to pass. You have 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to complete the combined examination, and 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> if you are only taking the SRO portion.
Applicant Certification All work done on this examination is my own. I have neither given nor received aid.
Applicants Signature Results RO/SROOnly/Total Examination Values I I Points Applicants Scores I I Points Applicants Grade I / Percent
- S.
ANSWER KEY REPORT for SQN 1503 SRO NRC EXAM Test Form: 0 Answers
- ID PolntsType 0 015AA2.02376 - 1.00 MCS C 2 022A02.l.777 1.00 MCS B 3 029 02.2.38 678 1.00 MCS A 4 040 A02.4.30 379 1.00 MCS A 5 057AA2.04380 1.00 MCS A 6 077 AA2.0I 381 1.00 MCS C 7 OOIAA2.0282 1.00 MCS B 8 033A02.I.20383 1.00 MCS B 9 061 AA2.06384 1.00 MCS A 10 W/E14E02.2.4485 1.00 MCS C II 01202.4.4986 1.00 MCS B 12 025A2.0587 1.00 MCS C 13 03902.4.5088 1.00 M C 14 063A2.01389 1.00 MCS C IS 103A2.0390 1.00 MCS C 16 02802.1.2591 1.00 MCS B 17 07lA2.0292 1.00 MCS A 18 079A2.0I 393 1.00 MCS A 19 02.1.35394 1.00 MCS D 20 022.1795 1.00 MCS D 21 022214% 1.00 MCS B 22 02.3.13397 1.00 MCS B 23 02.3.6398 1.00 MCS C 24 02.4.38399 1.00 MCS A 1(025 02.4.5 100 1.00 MCS B SECTION 1(25 Items) -- -- - - 25.00 -
Thursday, March 19,2015 12:02:56 PM
- 76. Given the following plant conditions:
0800 - With Unit 1 operating at 100% power, the following annunciators alarm:
- LS-68-53A1B REAC COOL PMP 3 OIL RESERVOIR LEVEL HI/LO, (1-M-5-B, C-5)
- RC PUMP 3 OIL COOLERS OUTLET FLOW LOW (M-27-B-A, D-4)
- RCP #3 Lower Motor bearing temperature is 185°F and rising.
0805 - While the crew is preparing to perform a reactor shutdown, RCP #3 Lower motor bearing temperature reaches 205°F and rising.
- The reactor will NOT trip from either trip switch.
0810 - Reactor power is 10% and lowering.
- RCP #3 Lower Motor bearing is 285° F and rising.
0812 - Reactor power is 4% and lowering.
- RCP #3 Lower Motor bearing is 315°F and rising.
0815 - Both Reactor trip breakers are opened.
Which ONE of the following identifies:
(1) in accordance with FR-S. 1, Nuclear Power Generation I ATWS the earliest time that #3 RCP is allowed to be tripped and (2) based on current plant conditions, the reason 2 RCS loops are required to be OPERABLE in accordance with Tech Spec 3.4.1/bases?
A. (1) 0810 (2) to provide for single failure criteria and still maintain sufficient heat removal capacity B. (1) 0810 (2) to provide sufficient heat removal for a continuous rod withdrawal accident C. (1) 0812 (2) to provide for single failure criteria and still maintain sufficient heat removal capacity D. (1) 0812 (2) to provide sufficient heat removal for a continuous rod withdrawal accident Thursday, March 19, 2015 10:47:00 AM 76
- 77. Given the following plant conditions:
- Unit 1 is operating at 75% power.
- The lA-A CCP is OOS for maintenance.
- Subsequently the 1 B-B CCP trips.
- The following indications are reported:
- PZR level is 40% and slowly lowering
- Tave is on program and stable
- RCP lower bearing and seal water temperatures are 150°F and stable Which ONE of the following completes the statements below?
In accordance with OPDP-8, Operability Determination Process and Limiting Conditions for Operation Tracking, the Immediate Determination of Operability (IDO) for the 1 B-B CCP, (1) be made by an Off-shift SRO.
In accordance with AOP-M.09, Loss of Charging, step 22. Monitor if reactor trip is needed: the reactor (2) required to be tripped at this time.
A. (1) can NOT (2) is NOT B. (1) can NOT (2) is C. (1) can (2) is NOT D. (1) can (2) is Thursday, March 19, 2015 9:48:25 AM 77
- 78. Given the following plant conditions:
- Unit 1 is operating at 50% power.
- Subsequently a loss of all main feedwater occurs.
- The reactor cannot be tripped from the Main Control room.
- 2- mt s1atr, a41.-S/G NR water levels ar% a At)
Which ONE of the following completes the statements below?
An automatic AMSAC signal U) actuated.
In accordance with the FSAR, AMSAC actuation (2) 10 CFR 100 release requirements are met.
A. (1) has (2) will ensure that B. (1) has (2) is NOT credited with ensuring C. (1) has NOT (2) will ensure that D. (1) has NOT (2) is NOT credited with ensuring Thursday, March 19, 2015 9:48:25 AM 78
- 79. Given the following plant conditions:
- Unit 1 is at 100% power, a reactor trip and Safety Injection occurs.
- Priortothetrip, Main Steam Line 1 Rad Monitor, 1-RA-90-421, was in alarm.
- The crew is preparing to transition from E-0, Reactor Trip or Safety Injection.
- The current conditions exist:
- RCS pressure is 1550 psig and lowering slowly.
- SG 1 pressure is 300 psig and lowering slowly.
- SG 2, 3, and 4 pressures are 650 psig and stable.
- Containment Pressure is 2.3 psig and rising slowly.
Which ONE of the following identifies; (1) the first procedure transition required from E-0, and (2) the required EPIP event classification (SED judgement should NOT be used)?
REFERENCE PROVIDED A. (1) E-2, Faulted Steam Generator Isolation.
(2) Alert B. (1) E-2, Faulted Steam Generator Isolation.
(2) Site Area Emergency C. (1) E-3, Steam Generator Tube Rupture.
(2) Alert D. (1) E-3, Steam Generator Tube Rupture.
(2) Site Area Emergency Thursday, March 19, 2015 9:48:25 AM 79
- 80. Given the following plant conditions:
- Both Units are operating at 100% power.
0800 - 120V AC Vital Instrument Power Board (VIPB) 2-Ill is declared INOPERABLE.
1000 - Unit 1 OATC reports all channel status lights on RX Trip SI Status panels are dark.
Which ONE of the following completes the statement below?
At 1000, 12OVACVIPB jJ was lost and in accordance with Tech Specs, Unit-i is required to enter Mode 3 by (2)
REFERENCE PROVIDED A. (1) 1-I (2) 2200 B. (1) 1I (2) 1700 C. (1) 1-lI (2) 2200 D. (1) 1Il (2) 1700 Thursday, March 19, 2015 9:48:25 AM 80
- 81. Given the following plant conditions:
- Unit 1 is operating at 45% power.
- Electric load is 550 MWe.
- A disturbance on the offsite electrical grid has just occurred.
After attempting to adjust the Unit 1 Voltage Regulator with the exciter base adjust, the following plant conditions are noted:
- Unit 1 Generator Hydrogen pressure is 65 psi.
- Unit 1 is at 550 MVARs incoming.
- SDBD lA-A and lB-B are at 6500 V.
- USST load tap changers are in AUTO and functioning correctly.
In accordance with AOP-P.07, Degraded Grid Conditions or Generator Voltage Regulator Malfunctions, which ONE of the following completes the statement below?
The Unit 1 main generator (1) operating within the limits of capability curve and the operators are required to ) to protect the shutdown boards.
REFERENCE PROVIDED A. (1) is (2) place affected shutdown boards on DG using Appendix F of AOP-P.07 B. (1) is (2) manually transfer the affected 6.9KV Unit Boards to ALTERNATE supply using 0-SO-202-3, 6.9KV Unit Station Service Boards C. (1) is NOT (2) place affected shutdown boards on DG using Appendix F of AOP-P.07 D. (1) is NOT (2) manually transfer the affected 6.9KV Unit Boards to ALTERNATE supply using 0-SO-202-3, 6.9KV Unit Station Service Boards Thursday, March 19, 2015 9:48:25 AM 81
- 82. Given the following plant conditions:
- Unit 1 is operating at 75% power.
- The control rods start continuously stepping out at 8 steps/rn in.
- Auctioneered High Tave is observed to be 568.5°F.
- Subsequently, reactor power is now observed to be 73.5% power.
Which ONE of the following identifies the (1) indications that are consistent for this condition and (2) Significance Level of this event in accordance with NPG-SPP-10.4, Reactivity Managernent Program?
Note:
FCV-62-138, Emergency Boration Flow Control Valve REFERENCE PROVIDED A. (1) Red light on handswitch for FCV-62-1 38 LIT; NO flow indicated on emergency borate flow indicator FI-62-1 37A.
(2) 2 B. (1) Red light on handswitch for FCV-62-138 LIT; flow indicated on emergency borate flow indicator Fl-62-1 37A.
(2) 3 C. (1) Green light oh handswitch for FCV-62-138 LIT; flow indicated on emergency borate flow indicator FI-62-1 37A.
(2) 2 D. (1) Green light on handswitch for FCV-62-1 38 LIT; NO flow indicated on emergency borate flow indicator FI-62-1 37A.
(2) 3 Thursday, March 19, 2015 9:48:25 AM 82
- 83. Given the following plant conditions:
- Unit 1 is preparing to do a reactor startup
- The unit is at normal operating temperature and pressure.
- RTBs are closed for testing.
- Subsequently, both IR NIs are declared INOPERABLE.
Which ONE of the following completes the statements below?
In accordance with AOP-I.01, Nuclear Instrument Malfunction, the crew is required to (1) and In accordance with the bases for LCO 3.3.3.7, Accident Monitoring Instrumentation (PAM), this instrumentation )
A. (1) trip the reactor and GO to E-0, Rx trip or Safety Injection (2) provides sufficient functional capability for protective and ESF purposes during the mitigation of accident and transient conditions B. (1) trip the reactor and GO to E-0, Rx trip or Safety Injection (2) provides information required by the control room operators to take preplan ned manual actions to accomplish safe plant shutdown C. (1) verify the SR detectors are functioning and Place the Level Trip switches for failed channels to BYPASS (2) provides sufficient functional capability for protective and ESF purposes during the mitigation of accident and transient conditions D. (1) verify the SR detectors are functioning and Place the Level Trip switches for failed channels to BYPASS (2) provides information required by the control room operators to take preplanned manual actions to accomplish safe plant shutdown Thursday, March 19, 2015 9:48:25 AM 83
- 84. Given the following plant conditions:
- Unit 1 is at 100% power.
- Unit 2 is in Mode 6.
- 0-RM-90-1 03, Spent Fuel Pit RadMon, is out of service.
- The High Rad relays have been removed.
- Train B rad monitor block switch is positioned to OFF and pushed-in.
- A source check is being performed on 0-RM-90-102, Spent Fuel Pit RadMon.
- Train A rad monitor block switch is positioned to 0-102 and pulled out.
- When the source check is performed, 0-RM-90-102 fails to respond.
- Area surveys are performed as required.
Which ONE of the following identifies...
(1) the status of the following annunciators on 0-M-12-D:
0-HS-90-136A1 HIGH RAD IN CNMT INPUT TO TR A OF SSPS BLOCKED (E-3) 0-HS-90-136A2 HIGH RAD IN CNMT INPUT TO TR B OF SSPS BLOCKED (E-4) and (2) the requirements of LCO 3.9.12, ABGTS met?
A. (1) ONLY 0-HS-90-136A1 HIGH RAD IN CNMT INPUT TO TR A OF SSPS BLOCKED will be LIT.
(2) are NOT B. (1) ONLY 0-HS-90-136A1 HIGH RAD IN CNMT INPUT TO TR A OF SSPS BLOCKED will be LIT.
(2) are C. (1) BOTH of the listed annunciator windows will be LIT.
(2) are NOT D. (1) BOTH of the listed annunciatorwindows will be LIT.
(2) are Thursday, March 19, 2015 9:48:25 AM 84
- 85. Given the following plant conditions:
- Unit 1 has tripped due to a large break LOCA from 100% power.
- RHR pump iA-A was tagged out of service for maintenance.
- Containment pressure is 11 psig.
- RWST level is 23% and slowly lowering.
- When shifting to cold leg recirc using ES-i .3, Transfer to RHR Containment Sump, i-FCV-63-73 Train B RHR Cntmt Sump Suction Valve, fails to open.
- The crew implements ECA-i.i, Loss of RHR Sump Recirculation.
- Both Containment Spray pumps are aligned to the RWST.
Which ONE of the following completes the statements below?
The procedure that takes priority under these conditions is (1) and, based on current plant conditions, the number of Containment Spray pumps required to be operating for this condition is (2)
Note: FR-Z. 1, High Containment Pressure A. (1) FR-Z.1 (2) 1 B. (1) FR-Z.i (2) 2 C. (1) ECA-1.i (2) 1 D. (1) ECA-i.i (2) 2 Thursday, March 19, 2015 9:48:25 AM 85
- 86. Given the following plant conditions:
- Unit 1 is operating at 100% power.
- The reactor fails to trip on a valid automatic trip signal.
- The reactor cannot be tripped from the control room.
- The turbine fails to trip using the turbine trip handswitch on 1-M-2.
Which ONE of the following completes the statements below?
The FIRST required action to be taken due to the failure of the turbine to trip is to Li)
In accordance with EPIP-1, if the reactor is tripped within 5 minutes, the SM is required to (2)
A. (1) close main turbine governor valves using valve position limiter (2) report but not declare the event because the conditions were terminated before the event was declared B. (1) close main turbine governor valves using valve position limiter (2) declare the event and make the required notifications C. (1) close MSIVs and bypasses (2) report but not declare the event because the conditions were terminated before the event was declared D. (1) close MSIVs and bypasses (2) declare the event and make the required notifications Thursday, March 19, 2015 9:48:25 AM 86
- 87. Given the following plant conditions:
- Unit 1 is operating at 100% power.
- Annunciator, LIS-61-195B/A GLYCOL EXP TANK LEVEL LOW-LOW LOW (1-M-6-E, D-6) alarms.
- An operator is dispatched to investigate the alarm, but before a report is received the alarm reflashes.
Which ONE of the following completes the statement below?
The Glycol Expansion Tank Isolation Valves (1-FSV-61-109 and 1-FSV-61-118) will be jJ , and in accordance with LCO 3.6.5.1, ICE BED, the Ice Bed is currently (2)
A. (1) open (2) OPERABLE B. (1) open (2) INOPERABLE C. (1) closed (2) OPERABLE D. (1) closed (2) INOPERABLE Thursday, March 19, 2015 9:48:25 AM 87
- 88. Given the following plant conditions:
- Unit 1 is operating at 100% power
- Condenser rad monitors RM-99 and RM-1 19 are both out of service for repair.
- The following alarm is received:
- 1-RA-421A MN STM LN HI RAD (1-M-30-A, C-8)
- The OATC has taken manual control of charging flow control and has stabilized PZR Level at 60%.
- Current plant conditions are reported as:
- Letdown in service at 75 gpm
- Charging flow is at 102 gpm
- Seal return flow at 12 gpm total Which ONE of the following identifies:
(1) the required section of AOP-R.01, Steam Generator Tube Leak, to mitigate the event and (2) in accordance with NPG-SPP-03.5, Regulatory Reporting Requirements, the latest time that the NRC is to be notified of this event?
REFERENCE PROVIDED A. (1) sect 2.1 S/G Tube Leak Requiring Rapid Shutdown.
(2) 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> B. (1) sect 2.2 Steam Generator Leak Monitoring.
(2) 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> C. (1) sect 2.1 SIG Tube Leak Requiring Rapid Shutdown.
(2) 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> D. (1) sect 2.2 Steam Generator Leak Monitoring.
(2) 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Thursday, March 19, 2015 9:48:25 AM 88
- 89. Given the following plant conditions:
- Unit 1 is at 100% power.
- The following annunciator is received:
- 125V DC VITAL BAT BD I ABNORMAL (1-M-1-C, A-5)
- Battery Board I voltage indicates -132V DC and stable.
- Ground indication is +85\J DC Which ONE of the following completes the statement below?
High battery board jJ caused the main control room alarm.
AND In accordance with NPG-SPP-07.1.4, 11 Work Control Prioritization - On Line, the SRO will initiate a (2) Work Order to MEG.
REFERENCE PROVIDED A. (1) voltage (2) Priority 2 B. (1) voltage (2) Priority 1 C. (1) grounds (2) Priority 2 D. (1) grounds (2) Priority 1 Thursday, March 19, 2015 9:48:25 AM 89
- 90. Given the following plant conditions:
- Unit 1 is operating at 100% power.
- Channel #1 containment HIGH-HIGH PRESS instrument loop failed 2 weeks ago.
- The channel was removed from service in accordance with LCO 3.3.2 ESF Actuation System Instrumentation.
- Subsequently Channel #3 containment pressure transmitter fails HIGH.
Which ONE of the following completes the statement below?
Containment Isolation Phase B will (1) and LCO 3.0.3 be required to be entered?
A. (1) actuate (2) will B. (1) actuate (2) will NOT C. (1) NOT actuate (2) will D. (1) NOT actuate (2) will NOT Thursday, March 19, 2015 9:48:25 AM 90
- 91. Given the following plant conditions:
- Unit 1 tripped from 100% due to a small break LOCA.
- While implementing E-1, Loss of Reactor or Secondary Coolant, the following data is reported by the crew:
- RCS pressure 1200 psig slowly lowering.
- Core exit TCs are 500° F and slowly lowering.
- CNMT pressure 2.0 psig.
- CNMT hydrogen concentration has just been confirmed at 4.2%.
- Hydrogen Recombiner Reference power is 39 KW (data plate)
- The crew is implementing EA-268-1, Placing Hydrogen Recombiners In Service.
Which ONE of the following identifies:
(1) the 25 minute hydrogen recombiner power setting, and (2) the REP classification that would be required for the conditions described?
REFERENCE PROVIDED A. (1) 51 Kw (2) Alert B. (1) 51 Kw (2) Site Area Emergency C. (1) 78Kw (2) Alert D. (1) 78Kw (2) Site Area Emergency Thursday, March 19, 2015 9:48:25 AM 91
- 92. Given the following plant conditions:
- A release of Waste Gas Tank B is in progress.
- Subsequently, during the release, 0-RM-90-118 Waste Gas Effluent Rad Monitor is declared INOPERABLE.
Which ONE of the following identifies:
(1) the requirement to allow any additional release of the tank and (2) the verification requirements for aligning the discharge valve lineup?
A. (1) A new release package is required for any additional release; (2) independent verification B. (1) A new release package is required for any additional release; (2) concurrent verification C. (1) The existing release package is allowed to be used for any additional release; (2) independent verification D. (1) The existing release package is allowed to be used for any additional release; (2) concurrent verifcation Thursday, March 19, 2015 9:48:25 AM 92
- 93. Given the following plant conditions:
- Unit 1 in Mode 3 with the RCS at normal operating temperature and pressure preparing for reactor startup.
- Alarm PS-32-104 TRAIN AAUX CONTROL AIR PRESS LOW (1-M-15-B, A-4) is actuated.
- Control Air pressure indications are:
- P1-32-200 Control Air Header pressure is 65 psig and lowering.
- P1-32-104 Aux Bldg Control air header A pressure is 65 psig and lowering.
- P1-32-i 05 Aux Bldg Control air header B pressure is 82 psig and rising.
Which ONE of the following identifies both...
- 2) which train(s) ofAFWwiU&lNOPERABLE on Unit 1?
4t45 //i Note:
O-FCV-32-82, Aux. Compsr. A-A Aux. Bldg Iso!.
O-FCV-32-85, Aux. Compsr. B-B Aux. Bldg Iso!.
1-FCV-32-80, Unit 1 Train A Rx Bldg Iso!.
1-FCV-32-102, Unit 1 Train B Rx Bldg Iso!.
Direction U-I AFW Trains Inoperable A. Ensure 0-FCV-32-82, Motor Driven Train A only and 0-FCV-32-85 are closed.
B. Ensure 0-FCV-32-82, Motor Driven Train A and Turbine Driven Train and 0-FCV-32-85 are closed.
C. Ensure i-FCV-32-80 Motor Driven Train A only and 1-FCV-32-102 are closed.
D. Ensure 1-FCV-32-80 Motor Driven Train A and Turbine Driven Train and 1-FCV-32-102 are closed.
Thursday, March 19, 2015 9:48:25 AM 93
- 94. Given the following plant conditions:
- Unit 2 is in Mode 6 with refueling operations in progress.
- The RCCA change fixture is empty.
- One fuel assembly is being moved by the manipulator crane.
- Subsequently:
- LS-78-3 SPENT FUEL PIT LEVEL HIGH-LOW, (2-M-6-D, D-3) alarm is LIT.
- A reactor cavity seal failure is reported to the control room.
Which ONE of the following completes the statement below?
In accordance with AOP-M.04,Refueling Malfunctions, the fuel handling supervisor will direct the crane operator to place the fuel assembly into jJ and in accordance with T.S. 3.9.10, Water Level Reactor Vessel, bases, the reason for the minimum water level above the reactor vessel flange is to (2)
A. (1) the RCCA change fixture (2) limit the dose rate at the surface of reactor cavity B. (1) the RCCA change fixture (2) remove 99% of the assumed 10% iodine gap activity released from a ruptured irradiated fuel assembly C. (1) any available core location (2) limit the dose rate at the surface of reactor cavity D. (1) any available core location (2) remove 99% of the assumed 10% iodine gap activity released from a ruptured irradiated fuel assembly Thursday, March 19, 2015 9:48:25 AM 94
- 95. Given the following plant conditions:
- Both Units are operating at 100% power.
- Maintenance activities require removing the A-A ERCW traveling screen from service to support diving operations.
- Both the J-A and K-A ERCW pumps are removed from service in accordance with 0-SO-67-1, ERCW, and will be tagged as part of the clearance.
Which ONE of the following identifies the MINIMUM required Initial Risk Level classification and operability status of the A Train ERCW Headers in accordance with NPG-SPP-07.3, Work Activity Risk Management Process, and Tech Specs, respectively?
REFERNCE PROVIDED Minimum Required Risk Level Operability Status A. Low A train ERCW is INOPERABLE B. Low A train ERCW is OPERABLE C. High A train ERCW is INOPERABLE D. High A train ERCW is OPERABLE Thursday, March 19, 2015 9:48:25 AM 95
- 96. In accordance with Tech Spec LCD 3.0.6, INOPERABLE equipment may be returned to service for the following reasons:
I. Demonstrate OPERABILITY of the equipment.
II. Demonstate OPERABILITY of other Tech Spec required equipment.
Ill. Troubleshoot equipment to facilitate repair.
A. IONLY B. I and II ONLY C. I and III ONLY D. I, II and Ill Thursday, March 19, 2015 9:48:25 AM 96
- 97. Given the following plant conditions:
- Unit 2 is at 100% power.
- An unscheduled entry into the Unit 2 containment is required to inspect inside the Polar Crane wall.
Which ONE of the following completes the statement below?
The incore detectors are required to be placed in the storage position j) and the Plant Managers permission (2) required to make the containment entry.
A. (1) or inserted to within 10 ft of the core and tagged (2) is NOT B. (1) or inserted to within 10 ft of the core and tagged (2) is C. (1) ONLY (2) is NOT D. (1) ONLY (2) is Thursday, March 19, 2015 9:48:25 AM 97
- 98. Given the following plant conditions:
- Both units are at 100% power.
- Rad Waste water inventory is approaching storage capacity.
- A release of the Monitor Tank is planned.
- Chemistry calculated the non gaseous activity in the tank to be higher than the 7.OE-6 uci/mI value listed in 0-Sl-CEM-077-400.1, Liquid Waste Effluent Batch Release.
- Subsequently, before the release, 0-RM-90-122, Liquid Radwaste Release Monitor, is declared INOPERABLE.
Which ONE of the following identifies the requirements regarding release of the Monitor Tank?
A. Cannot release due to activity levels.
B. Cannot release due to 0-RM-90-122 being INOPERABLE.
C. Can release if ODCM actions are taken. Shift Manager approval is required.
D. Can release if ODCM actions are taken. Shift Manager approval is NOT required.
Thursday, March 19, 2015 9:48:25 AM 98
- 99. Given the following plant conditions:
- A Site Area Emergency has been declared.
- The TSC and CECC have NOT been activated.
At this time, which of the following identifies the limitations, if any, on the delegation of the Site Emergency Director responsibilities in accordance with the Radiological Emergency Plan Implementing Procedures?
Emergency Classification Determination of Escalation Protective Action Recommendations A. Can NOT be delegated Can NOT be delegated B. Can NOT be delegated Can be delegated C. Can be delegated Can NOT be delegated D. Can be delegated Can be delegated Thursday, March 19, 2015 9:48:25 AM 99
SQN 1503 SRO NRC EXAM 100. Given the following plant conditions:
- A Station Blackout has occurred.
- Unit 1 is performing ECA-0.0, Loss of All AC Power.
- Per ECA-0.0, the S/Gs have been depressurized to 160 psig.
- RCS subcooling based on Core exit T/Cs is 10°F.
- lA-A EDG is started and is supplying the lA-A SDBD.
- The crew has reached the last step of ECA-0.0 and is preparing to transition to the appropriate recovery procedure.
- A RED Path exists on the Heat Sink CSF Status Tree.
Which ONE of the following identifies the required recovery strategy?
A. Transition to ECA-0.1, Loss of All AC Power Recovery Without SI Required, and enter FR-H.1, Response to Loss of Secondary Heat Sink when allowed by ECA-0.1.
B. Transition to ECA-0.2, Loss of All AC Power Recovery With SI Required, and enter FR-H.1, Response to Loss of Secondary Heat Sink when allowed by ECA-0.2.
C. Transition to FR-H. 1, Response to Loss of Secondary Heat Sink, and enter ECA-0.1, Loss of All AC Power Recovery Without SI Required, when FR-H.1 is complete.
D. Transition to FR-H.1, Response to Loss of Secondary Heat Sink, and enter ECA-0.2, Loss of All AC Power Recovery With SI Required, when FR-H.1 is complete.
You have completed the test!
Thursday, March 19, 20159:48:25 AM 100
References for 1503 NRC SRO Exam
- 1. Steam Tables
- 2. Mollier Diagram
- 3. E-3, Steam Generator Tube Rupture, step 32, rev 21
- 5. 1-FR-0, Curve 1 PTS limit, rev 2 (page 8 of 16)
- 6. 1 ,2-45N779-1 Wiring Diagrams 480V Shutdown Aux Power Schematic Diagram -
sheet 1 rev 5
- 7. 1 ,2-45N779-5 Wiring Diagrams 480V Shutdown Aux Power Schematic Diagram -
sheet 5 rev 19
- 8. Sequoyah EPIP-1 Emergency Plan Classification Matrix, rev 51 (pages 11 and 12 of 49)
- 9. Unit 1 Tech Spec LCO 3.8.2.1 AC Distribution Operating. (1 page. 3/4 8-9)
- 10. AOP-P.07, Degraded Grid Conditions or Generator Voltage Regulator Malfunction, Appendix C, rev 5 (page 37)
- 11. NPG-SPP-10.4, Reactivity Management Program, rev 5 (pages 56 and 57 of 70)
- 12. NPG-SPP-03.5, Regulatory Reporting Requirements, Appendix A, rev 10 (pages 20-34)
- 13. Sequoyah EPIP-1 Emergency Plan Classification Matrix, rev 51 (page 17 of 49)
- 14. NPG-SPP-07.1.4, Work Control Prioritization On Line, Attachment 1 rev 3 (page 36)
- 15. EA-268-1, Placing Hydrogen Recombiners In Service, rev4 (pages 1,4 thru 6,12)
- 16. NPG-SPP-07.3, Work Risk Management Process, Attachment 2 rev 16
SEQUOYAH I EMERGENCY PLAN CLASSIFICATION MATRIX I EPIP-i I Modes 1-4 Modes 1-4 1.1 Fuel Clad Barrier 1.2 RCS Barrier
- 1. Critical Safety Function Status 1. Critical Saf& Function Status i* Potential LOSS LOSS Potential_LOSS Core Cooling Red Core Cooling Orange Not Applicable Pressurized Thermal (FR-C.1) (FR-C.2) Shock Red (FR-P.1)
OR OR Heat Sink RED (FR-H.1) and RHR Shutdown Heat Sink RED (FR-H.1)
Cooling not in service and RHR Shutdown
- OR - Cooling not in service
- 2. Primary Coolant Activity Level - OR -
LOSS Potential LOSS 2. RCS Leakae I LOCA RCS sample activity is Not Applicable 1.1* Potential LOSS greater than 300 iCi/gm RCS leak results in Non Isolatable RCS leak dose equivalent 131 subcooling <40 °F as exceeding the capacity
- OR - indicated on Xl-94-101 of one charging pump in
- 3. Incore Thermocouple Hi Quad Average or 102 (EXOSENSOR) the normal charging
- 1* Potential LOSS alignment Greater than 1200 oF on Greater than or equal to Xl-94-101 or 102 700 °F on Xl-94-101 or OR (EXOSENSOR) 102 (EXOSENSOR)
- OR -
RCS leakage results in
- 4. Reactor Vessel Water Level entry into E-1
- .i* Potential LOSS Not Applicable - OR -
VALID RVLIS level
<42% on Ll-68-368 or 3. Steam Generator Tube Rupture Ll-68-371 with no RCP I1* Potential LOSS running SGTR that results in a Not Applicable
- OR Safety Injection
- 5. Containment Radiation Monitor actuation
- I* Potential LOSS OR VALID reading of Not Applicable greater than:
Entry into E-3 25E+02 R/hr on
- OR -
RM-90-271A and -272A 4.
OR LOSS Potential LOSS VALID RVLIS level Not Applicable 1 .5E+02 RIhr on <42% on Ll-68-368 or RM-90-273A and Ll-68-371 with no RCP 2.1E÷02 R/hron running RM-90-274A - OR -
(see instruction note 4) 5. SED Judgment
- OR - Any condition that, in the judgment of the SM or
- 6. SED Judgment SED, indicates loss or potential loss of the RCS Any condition that, in the judgment of the SM or Barrier comparable to the conditions listed SED, indicates loss or potential loss of the Fuel above.
Clad Barrier comparable to the conditions listed above.
Page 11 of 49 Revision 50
LSEQUOYAH I EMERGENCY PLAN CLASSIFICATION MATRIX EPIP-1 I Modes 1-4 t3 Containment Barrier INSTRUCTIONS
- 1. Critical Safety Function Status Note: A condition is considered to be
!.1.i Potential LOSS MET if, in the judgment of the SED, the Not Applicable Containment Red condition will be MET IMMINENTLY (i.e.:
(FR-Z.1) within two hours). The classification shall OR be made as soon as this determination is Actions of FR-C.1 (Red Path) made.
are INEFFECTIVE (i.e.: core In the matrix to the left, REVIEW the TCs trending up) initiating conditions in all three barrier
- OR -
columns and circle the conditions that
- 2. Containment Pressure I H fdrogen are MET.
!.I* Potential LOSS 2. In each of the three barrier columns, Rapid unexplained pressure Containment Hydrogen IDENTIFY if any Loss or Potential Loss decrease following initial increases to >4% by volume INITIATING CONDITIONS have been increase on PDI-30-44 0145 on H2l-43-200 or 210 MET.
QB 3. COMPARE the number of barrier Containment pressure or sump Pressure >2.8 PSIG (Phase level not increasing on Ll 8) with < one full train of Losses and Potential losses to the 178 and 179 with a LOCA in containment spray Emergency Class Criteria below and progress make the appropriate declaration
- OR -
(i.e.,FG1, FS1, FAt FU1).
- 3. Containment Isolation Status 4. Containment Radiation Monitors are
- Potential LOSS temperature sensitive and can be Containment isolation, when Not Applicable affected by temperatureinduced required is incomplete and a currents. These monitors should be release path to the environment used for trending only for 2 minutes exists. after a Steam Line Break or LOCA.
- OR - Once 2 minutes has expired these
- 4. Containment Bypass monitors can be used for EAL 1.1* Potential LOSS determination.
RUPTURED SIG that is also Unexpected VALID increase Note: MONITOR the respective status tree faulted outside containment (E2 in area or ventilation RAD criteria if a CSF is listed as an and E3) monitors adjacent to INITIATING CONDiTION.
>4 hour secondary side release progress).
outside containment from a SIG Emergency Class Criteria with a SIG tube leak >T/S limits FGI General Emergency (AOP R01 App A)
- OR - LOSS of any two barriers and Potential
- 5. Significant Radiation in Containment LOSS of third barrier
.)* Potential LOSS Not Applicable VALID reading of greater FSI Site Area Emergency than:
5.8E+03 R/hr on LOSS or Potential LOSS of any two RM-90-271A and RM barriers 272A OR FAI Alert 3.4E+03 Rfhr an RM-90-273A and Any LOSS or Potential LOSS of Fuel Clad 4.9E+03 RIhr on barrier RM-90-274A OR (see instruction note 4)
-OR- Any LOSS or Potential LOSS of RCS
- 6. SED Judgment barrier Any condition that, in the judgment of the SM or SED.
indicates toss or potential loss of the Containment Barrier FU1 Unusual Event comparable to the conditions listed above.
LOSS or Potential LOSS of Containment barrier Page 12 of 49 Revision 51
ELECTRICAL POWER SYSTEMS 314.8.2 ONSITE POWER DISTRIBUTION SYSTEMS AC. DISTRIBUTION - OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.1 The following A.C. electrical boards shall be OPERABLE and energized with tie breakers open between redundant boards:
6900 Volt Shutdown Board lA-A 6900 Volt Shutdown Board 1 B-B 6900 Volt Shutdown Board 2A-A 6900 Volt Shutdown Board 28-B 480 Volt Shutdown Board IA1-A 480 Volt Shutdown Board 1A2-A 480 Volt Shutdown Board 181-B 480 Volt Shutdown Board 1 B2-B 480 Volt Shutdown Board 2A1-A 480 Volt Shutdown Board 2A2-A 480 Volt Shutdown Board 281-B 480 Volt Shutdown Board 282-B 120 Volt A.C. Vital Instrument Power Board Channels 1-I and 2-I energized from inverters 1-I and 2-I connected to D.C. Channel l#@.
120 Volt A.C. Vital Instrument Power Board Channels 1-Il and 2-Il energized from inverters 1-Il and 2-Il connected to D.C. Channel ll*#@.
120 VoltA.C. Vital Instrument Power Board Channels 1-Ill and 2-Ill energized from inverters 1.111 and 2-Ill connected to D.C. Channel IlI*#@.
120 VoItA.C. Vital Instrument Power Board Channels 1-lV and 2-IV energized from inverters 1-lV and 2-IV connected to D.C. Channel IV*#@.
APPLICABILITY: MODES 1 2, 3 and 4, ACTION:
- a. With less than the above complement of A.C. boards OPERABLE and energized, restore the inoperable boards to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
- b. With one inverter inoperable, energize the associated Vital Instrument Power Board within 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />s:
restore the inoperable inverter to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
SURVEILLANCE REQUIREMENTS 4.8.2.1 The specified A.C. boards and inverters shall be determined OPERABLE and energized with tie breakers open between redundant boards at least once per 7 days by verifying correct breaker alignment and indicated voltage on the busses.
Two inverters may be disconnected from their D.C. source for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the purpose of performing an equalizing charge on their associated battery bank provided (1) the vital instrument power board is OPERABLE and energized, and (2) the vital instrument power boards associated with the other battery banks are OPERABLE and energized from their respective inverters connected to their respective D.C. source.
- D.C. Channel V may be substituted for any one channel of channels l-IV,
@ The spare inverter for a specified channel may be substituted for one of the two inverters of the same channel.
September 23, 1999 SEQUOYAH UNIT 1 - 314 8-9 Amendment No. 37, 246
SQN DEGRADED GRID OR ABNORMAL VOLTAGE CONDITIONS AOPP.07 Rev. 5 APPENDIX C MAIN GENERATOR CAPABILITY CURVE CAUTION Operation in excess of 500 MVARS incoming may cause trip from loss of field or generator backup relays.
9 87 6 5 4 3 21 01 2 34 5 6 7 8 9 10 0 0 100 POWER FACTOR 100 T
frYPICAL 200 :....*; 200 300 300 400 400 500 500 m z
600 600 m 700 700 0 800 800 900 900 1000 1000 1100 1100 (A 1200 1200 1300 1300 1400 1400 1500 1500 9 7 5 $ 3 2 1 0 1 2 3 4 5 6 7 S 9 10 REACTIVE MVA x 100 REACTIVE MVA x 100 UNDEREXCITED OVEREXCITED Page 43 of 50
I NPG Standard Programs and Reactivity Management Program NPG-SPP-1U.4 Rev. 0005 L Processes Page 56 of 70 5.0 DEFINITIONS (continued)
H. Significance Level 2: Major Reactivity Management Events - PWR PWR Examples:
2.0 Other Reactivity Management Issues Meeting Level 2 Definition Above 2.1 Uncontrolled Rod Withdrawal 2.2 Boron Dilution in the RCS, Spent Fuel Pool, or Refueling Canal That Violates Shutdown Margin Limits 2.3 Failure to Meet Physics Testing Acceptance Criteria 2.4 Multiple Control Rod Drop Event While Critical 2,5 Bypass of Reactivity Control System which Results in Improper Reactivity Control 2.6 Criticality Occurs Outside the Predetermined Acceptance Criteria 2.7 Misconfigured, Misoriented, or Mislocated Fuel Assembly or Control Component in the Reactor that is Corrected or Reanalyzed Prior to Criticality 2.8 Mislocated Fuel Assembly or Control Component in Spent Fuel Pool, Dry Cask, or New Fuel Vault That Violates Reactivity Constraints 2.9 Reactor Trip With Complications Due to Reactivity Management Issues 2.10 Violation of a Core Thermal Power License Limit (NEt Position Statement on the Licensed Power Limit 2i 1 Violation of Fuel Conditioning Rules That Leads to Fuel Failure 2.12 Implementation of a Reactivity Management-Related Product That Results in Violation of the Design or Licensing Basis or Exceeding Reactivity-Related TS limit 2.13 Two or More Control Rods Fail to Insert Following Reactor Trip 2.14 Entry Into Reactivity-Related TS 1 Action Statement and not Corrected Within TS Time Requirements 2.15 Reactivity Anomaly Greater Than TS Limit Reactivity-Related Technical Specifications (TS) are typically, but not limited to those listed in TS sections 3,1 and 3.2, and include Shutdown Margin, Core Reactivity, Moderator Temperature Coefficient. Rod Group Alignment Limits, Shutdown Bank Insertion Limits, Control Bank Insertion Limits, Physics Tests Exceptions. Heat Flux Hot Channel Factor, Nuclear Enthalpy Rise Hot Channel Factor. Axial Flux Difference, and Quadrant Power Tilt Ratio, and Departure from Nucleate Boiling. This applies to actual physical issues, not indication problems.
(PER 248157)
NPG Standard Reactivity Management Program NPG-SPP-10.4 Programs and Rev. 0005 Processes Page 57 of 70 5.0 DEI9NITIONS (continued)
I. Significance Level 3: Minor Reactivity Management Events - PWR PWR Examples:
3.0 Other Reactivity Management Issues Meeting Level 3 Definition Above 3.1 Violation of Fuel Conditioning Rules 3.2 Violation of Core Thermal Power Procedural (Administrative) Limit 3.3 Performance of inaccurate Procedure That Causes Non-Conservative Reactivity Control and Could Potentially Damage Fuel 3.4 Single Control Rod Drop Event 3.5 Mislocated Fuel Assembly or Control Component in Spent Fuel Pool, Dry Cask, or New Fuel Vault (does not Violate Reactivity Constraints)(location only, not orientation) 3.6 Unplanned and Uncomplicated Manual or Automatic Trip 2 3.7 Fuel Cladding Breach Requiring Power or Ramp Rate Restrictions 3.8 Untrippable Control Rod When Critical 3.9 Unplanned Reactivity Change Directly Caused by Equipment Problem or Personnel Error:
- Reactor Power Change 1.0% RTP When >5% RTP
- Reactivity Change 500 pcm When 5% RTP 3.10 Use of a Reactivity Management-Related Product Containing a Technical Error That Does Not Result in Violation of the Design or Licensing Basis or Exceeding Tech Specs 3.11 Unplanned Entry into Reactivity-Related TS 3 Action Statement, corrected within TS Time Requirements 3.12 One Control Rod Fails to Insert Following Reactor Trip 2
While this event is typically already included in other unit or station metrics, it is also included in the reactivity management program to capture challenges to optimal reactivity management performance.
Reactivity-Related Technical Specifications (TS) are typically but not limited to those listed in TS sections 3.1 and 3.2, and include Shutdown Margin, Core Reactivity, Moderator Temperature Coefficient, Rod Group Alignment Limits, Shutdown Bank Insertion Limits, Control Bank lnsertion Limits, Physics Tests Exceptions, Heat Flux Hot Channel Factor, Nuclear Enthalpy Rise Hot Channel Factor, Axial Flux Difference, and Quadrant Power Tilt Ratio, and Departure from Nucleate Boiling. This applies to actual physical issues, not indication problems.
(PER 248157)
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 20 of 100 Appendix A (Page 1 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 1.0 PURPOSE This Appendix identifies reporting requirements; and instructions for determining reportability, preparation, and transmittal of LERs; and notification to NRC for events occurring at TVAs licensed nuclear plants.
2.0 SCOPE WA is required by §50.72 and §50.73 to promptly report various types of conditions or events and provide written follow-up reports, as appropriate. This appendix provides reporting guidance applicable to licensed power reactors.
NOTES
- 1) Appendix B provides additional reporting criteria found in §Part 20, 30, 40, and 70 that may be applicable to events involving byproduct, source or special nuclear material possessed by the licensed nuclear plant. Site Licensing and Site RadCon are responsible for making the reportability determinations for §Part 20, 30, 40, or 70 events associated with their site. Corporate Licensing and Corporate RadChem are responsible for making the reportability determinations for §Part 20, 30, 40, or 70 events associated with all other WA licensed activities. Licensing is responsible for developing (with input from affected organizations) and submitting the immediate notification and written reports to NRC in accordance with §Part 20, 30, 40, or 70 requirements. Reporting requirements for personnel exposure required by §Part 20 are contained in RCTP-105, Personnel lnprocessing and Dosimetry Administrative Processes.
- 2) Appendix C contains the criteria for reporting if events or conditions affecting ISFSI.
WA, as the general licensee of the ISFSI, is required by §72.216 to make initial and written reports in accordance with §72.74 and §72.75. Operations is responsible for making the reportability determinations for §72.74 and §72.75 reports. For any event, condition, or issue having the potential for being reportable, contact Site Licensing for consultation and concurrence on the reportability determination. In no event shall the lack of licensing concurrence result in a failure to meet specified reporting timeframes.
Operations is responsible for making the immediate notification to NRC in accordance with §72.74. Operations is responsible for making the immediate, 4-hour, and 24-hour notifications to NRC in accordance with §72.75. Licensing is responsible for developing (with input from affected organizations) and submitting the written reports required by §72.75.
- 3) Reporting requirements for events or conditions affecting the physical protection of the licensed nuclear plant specified in §73.71 are contained in NSDP-1, Safeguards Event Reporting Guidelines. Responsibilities for reportability determinations and immediate notification requirements are assigned to Site Nuclear Security and Corporate Nuclear Security. Licensing is responsible for developing (with input from affected organizations) and submitting the written reports required by §73.71.
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 21 of 100 Appendix A (Page 2 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.0 REQUIREMENTS NOTES
- 1) Internal management notification requirements for plant events are found in Appendix D. The Operations Shift Manager is responsible for notifying Site Operations Management and the Duty Plant Manager. The Duty Plant Manager is responsible for making the remaining internal management notifications.
- 2) NRC NUREG-1022, Revision 3 and subsequent revisions should be used as guidance for determining reportability of plant events pursuant to §50.72 and §50.73.
A text searchable copy of NUREG-1022 is maintained on the WA NPG Nuclear Licensing Webpage.
- 3) In addition to reviewing the clarifying discussion and examples associated with specific reporting criteria [e.g., discussion of utilization of engineering judgment when evaluating Unanalyzed Conditions in NUREG -1022, Section 3.2.4(B)], NUREG 1022, Section 2, Reporting Areas Warranting Special Mention, should also be reviewed. [Ri]
3.1 Immediate Notification NRC -
WA is required by §50.72 to notify NRC immediately if certain types of events occur. This appendix contains the types of events and the allotted time in which NRC must be notified.
(Refer to Form NPG-SPP-03.5-i or NRC Form 361). Operations is responsible for making the reportability determinations for §50.72 and §50.73 reports. For any event, condition, or issue having the potential for being reportable, contact Site Licensing for consultation and concurrence on the reportability determination. In no event shall the lack of licensing concurrence result in a failure to meet specified reporting timeframes. Operations is responsible for making the immediate notification to NRC in accordance with §50.72.
Notification is via the Emergency Notification System. If the Emergency Notification System is not operative, use a telephone, telegraph, mailgram, or facsimile.
NOTE The NRC Event Notification Worksheet may be used in preparing for notifying the NRC. This Worksheet may be obtained directly from the NRC website (www.nrc.gov) under Form 361, or TVA NPG Form NPG-SPP-03.5-1 may be used.
A. The Immediate Notification Criteria of §50.72 is divided into 1-hour, 4-hour, and 8-hour phone calls. Notify the NRC Operations Center within the applicable time limit for any item which is identified in the Immediate Notification Criteria.
- 8. The following criteria require 1-hour notification:
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 22 of 100 Appendix A (Page 3 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification NRC (continued) 3.
4.
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 23 of 100 Appendix A (Page 4 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification NRC (continued)
C. The following criteria require 4-hour notification:
- 1. §50.72(b)(2)(i) The initiation of any nuclear plant shutdown required by the plants Technical Specifications.
- 2. §5G.72(b)(2)(iv)(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.
- 3. §50.72(b)(2)(iv)(B) Any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.
NOTES
- 1) NPG-SPP-05.14 provides additional instructions regarding addressing and informally communicating events to outside agencies involving radiological spills and leaks.
- 2) Routine or day-to-day communications between TVA organizations and state agencies typically do not constitute a formal notification to other government agencies that would require a report in accordance with §50.72(b)(2)(xi).
- 4. §50.72(b)(2)(xi) Any event or situation, related to the health and safety of the public or onsite personnel, or protection of the environment, for which a news release 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 radioactive contaminated materials.
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 24 of 100 Appendix A (Page 5 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification - NRC (continued)
D. The following criteria require 8-hour notification:
NOTE With the exception of Events or Conditions that Could Have Prevented Fulfillment of a Safety Function, ENS notifications are required for any event that occurred within three years of discovery, even if the event was not ongoing at the time of discovery.
- 1. §50.72(b)(3)(ii)(A) Any event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded.
- 2. §50.72(b)(3)(ii)(B) Any event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety.
- 3. §50.72(b)(3)(iv)(A) Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B) [see list below], except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.
- a. The systems to which the requirements of paragraph §50.72(b)(3)(iv)(A) apply are:
NOTE Actuation of the RPS when the reactor is critical is also reportable under §50.72(b)(2)(iv)(B) above.
(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).
(3) 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 (BWR5) including: core spray systems:
high-pressure coolant injection system; low pressure injection function of the residual heat removal system.
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page25of 100 Appendix A (Page 6 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification NRC (continued>
(5) BWR reactor core isolation cooling 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).
NOTE For systems within scope, the inadvertent TS inoperability of a system in a required mode of applicability constitutes an event or condition for which there is no longer reasonable expectation that equipment can fulfill its safety function. Therefore, such events or conditions are reportable as an Event or Condition that Could Have Prevented Fulfillment of a Safety Function.
- 4. §50.72(b)(3)(v) 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.
NOTE According to §50.72 (b)(3)(vi) events covered by §50.72(b)(3)(v) 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 this paragraph if redundant equipment in the same system was operable and available to perform the required safety function.
- 5. §50.72(b)(3)(xii) Any event requiring the transport of a radioactively contaminated person to an offsite medical facility for treatment.
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 26 of 100 Appendix A (Page 7 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.1 Immediate Notification - NRC (continued)
- 6. §50.72(b)(3)(xiii) 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).
E. Follow-up Notification (50.72(c))
With respect to the telephone notifications made under paragraphs (a) and (b) [5O.72 (a) and §50.72 (b), respectively] of this section [5O.72], in addition to making the required initial notification, during the course of the event:
- 1. Immediately report:
(i) Any further degradation in the level of safety of the plant or other worsening plant conditions including those that require the declaration of the Emergency Classes, if such a declaration has not been previously made; or (ii) Any change from one Emergency Class to another, or (iii) A termination of the Emergency Class.
(1) Immediately report:
(i) The results of ensuing evaluations or assessments of plant conditions, (ii) The effectiveness of response or protective measures taken, and (iii) Information related to plant behavior that is not understood.
(2) Maintain an open, continuous communication channel with the NRC Operations Center upon request by the NRC.
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 27 of 100 Appendix A (Page 8 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.2 Twenty-Four Hour Notification - NRC Any violation of the requirement contained in specific operating license conditions, shall be reported to NRC in accordance with the license condition.
3.3 Two-Day Notification NRC -
§50.9(b) The NRC shall be notified of incomplete or inaccurate information which contains significant implications for the public health and safety or common defense and security.
Notification shall be provided to the administrator of the appropriate regional office within two working days of identifying the information. Licensing is responsible for determining reportability (with input from affected organizations) and notifying NRC in accordance with
§50.9.
3.4 Sixty-Day Verbal Report
§50.73(a)(2)(iv)(A) requires that any event or condition that resulted in manual or automatic actuation of the specified systems be reported as a Licensee Event Report (LER [Refer to Appendix A, Section 3.5]). This CFR section also allows that in the case of an invalid actuation, other than actuation of the reactor protection system when the reactor is critical, an optional telephone notification may be placed to the NRC Operations Center within 60 days after discovery of the event instead of submitting a written LER.
A. Verbal Report Required Content:
If the verbal notification option is selected (NUREG 1022, Revision 3, Section 3.2,6,,
System Actuation), instead of an LER, the verbal report:
- 1. is not considered an LER.
- 2. Should identify that the report is being made under §50.73(a)(2)(iv)(A).
- 3. Should provide the following information:
- a. The specific train(s) and system(s) that were actuated.
- b. Whether each train actuation was complete or partial.
- c. Whether or not the system started and functioned successfully.
Ij NPG Standard Programs and Regulatory Reporting Requirements NPG-SPP-03.5 Rev. 0010 L Processes Page 28 of 100 Appendix A (Page 9 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.4 Sixty-Day Verbal Report (continued)
NOTE Licensing will ensure that the information that is provided to NRC during the Sixty-Day Verbal Report is verified in accordance with NPG-SPP-03.10.
B. Verbal Report Development and Review Licensing will:
- 1. Develop (with input from responsible organization) the response (Le., report summary) to address the required input.
- 2. Ensure that the reporting details are approved by site vice president or his designee prior to making the verbal report.
C. Telephone Report Timeliness Operations will make the 60-day telephone report promptly after the response is approved by the site vice president or his designee.
3.5 Written Report - NRC A. A report on a Safety Limit Violation shall be submitted to the NRC, the NSRB, and the Site Vice President if required by Technical Specifications.
B. Any violation of the requirements contained in the Operating license conditions in lieu of other reporting requirements requires a written follow-up report if specified in the license.
C. Reporting Radiation Injuries
- 1. §140.6(a) requires, as promptly as possible, submittal of a written notice [e.g.,
report] in the event of:
- a. Bodily injury or property damage arising out of or in connection with the possession or use of the radioactive material at the licensees facility
[location]; or
- b. In the course of transportation; or
- c. In the event any radiation exposure claim is made. (Refer to RCDP-9, Radiological and Chemistry Control Radiological Exposure Inquiries)
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 29 of 100 Appendix A (Page 10 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)
- 2. The written notice shall contain particulars sufficient to identify the licensee and reasonably obtainable information with respect to time, place, and circumstances thereof, or the nature of the claim.
D. Licensee Event Reports A written report shall be prepared in accordance with §50.73(a)(i) for items in the 60-day report criteria or Technical Specifications. The report shall be complete and accurate in accordance with the methods outlined in this procedure. The completed forms shall be submitted to the USNRC, Document Control Desk, Washington, DC 20555. NUREG 1022, Revision 3, contains the instructions for completion of the LER form. Licensing is responsible for developing (with input from affected organizations) and submitting the written reports (or optional telephone reports [refer to Appendix A, Section 3.4)) required by §50.73.
NOTE Unless otherwise specified in the reporting criteria below, an event shall be reported if it occurred within three years of the date of discovery regardless of the plant mode or power level, and regardless of the significance of the structure, system, or component that initiated the event.
E. Report Criteria
- 1. §50.73(a)(2)(i)(A) The completion of any nuclear plant shutdown required by the plants Technical Specifications.
2 §50.73(a)(2)Q)(B) Any operation or condition which was prohibited by the plants Technical Specifications, except when:
- a. The Technical Specification is administrative in nature;
- b. The event consisted solely of a case of a late surveillance test where the oversight was corrected, the test was performed, and the equipment was found to be capable of performing its specified safety functions; or
- c. The Technical Specification was revised prior to discovery of the event such that the operation or condition was no longer prohibited at the time of discovery of the event.
- 3. §50.73(a)(2)(i)(C) Any deviation from the plants Technical Specifications authorized pursuant to §50.54(x).
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 30 of 100 Appendix A (Page 11 of 15>
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)
- 4. §50.73(a)(2)(ii)(A) Any event or condition that resulted in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded.
- 5. §50.73(a)(2)(ii)(B) Any event or condition that resulted in the nuclear power plant being in an unanalyzed condition that significantly degraded plant safety.
- 6. §50.73(a)(2)(iii) Any natural phenomenon or other external condition that posed an actual threat to the safety of the nuclear power plant or significantly hampered site personnel in the performance of duties necessary for the safe operation of the nuclear power plant.
- 7. §50.73(a)(2)(iv)(A) Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) [see list in Section 3.5E.8 below], except when
- a. The actuation resulted from and was part of a pre-planned sequence during testing or reactor operation: or
- b. The actuation was invalid and (i) Occurred while the system was properly removed from service or (ii) Occurred after the safety function had been already completed, NOTE In the case of an invalid actuation, other than actuation of the reactor protection system (RPS) when the reactor is critical, a telephone notification to the NRC Operations Center within 60 days after discovery of the event may be provided instead of submitting a written LER (50.73(a)). [Refer to Appendix A, Section 3.4]
- 8. §50.73(a)(2)(iv)(B) The systems to which the requirements to paragraph (a)(2)(iv)(A) of this section apply are:
- a. Reactor protection system (RPS) including: reactor scram or reactor trip.
- b. General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves (MSIVs).
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 31 of 100 Appendix A (Page 12 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report - NRC (continued)
- c. 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.
- d. EGGS for boiling water reactors (BWRs) including: core spray systems; high-pressure coolant injection system; low pressure injection function of the residual heat removal system.
- e. BWR reactor core isolation cooling system.
- f. PWR auxiliary or emergency feedwater system.
- g. Containment heat removal and depressurization systems, including containment spray and fan cooler systems.
- h. Emergency ac electrical power systems, including: emergency diesel generators (EDGs).
- i. Emergency service water systems that do not normally run and that serve as ultimate heat sinks.
- 9. §50.73(a)(2)(v) Any event or condition that 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.
NOTE Events reported above 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 this criterion if redundant equipment in the same system was operable and available to perform the required safety function
[5O.73(a)(2)(vi)].
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 32 of 100 Appendix A (Page 13 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued) 10, §50.73(a)(2)(vii) Any event where a single cause or condition caused at least one independent train or channel to become inoperable in multiple systems or two independent trains or channels to become inoperable in a single system designed 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.
- 11. §50.73(a)(2)(viii)(A) Any airborne radioactivity release that, when averaged over a time period of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, resulted in airborne radionuclide concentrations in an unrestricted area that exceeded 20 times the applicable concentration limits specified in Appendix B to Part 20, table 2, column 1.
- 12. §50.73(a)(2)(viii)(B) Any liquid effluent release that, when averaged over a time period of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, exceeds 20 times the applicable concentrations specified in Appendix B to Part 20, table 2, column 2, at the point of entry into the receiving waters (i.e., unrestricted area) for all radionuclides except tritium and dissolved noble gases.
- 13. §50.73(a)(2)(ix)(A) Any event or condition that as a result of a single cause could have prevented the fulfillment of a safety function for two or more trains or channels in different 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.
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 33 of 100 Appendix A (Page 14 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)
NOTE Events covered above may include cases of procedural error, equipment failure, and/or discovery of a design, analysis, fabrication, construction, and/or procedural inadequacy. However, licensees are not required to report an event pursuant to this criterion if the event results from a shared dependency among trains or channels that is a natural or expected consequence of the approved plant design or normal and expected wear or degradation [50.73(a)(2)(ix)(B)].
14, §50.73(a)(2)(x) Any event that posed an actual threat to the safety of the nuclear power plant or significantly hampered site personnel in the performance of duties necessary for the safe operation of the nuclear power plant including fires, toxic gas releases, or radioactive releases.
- 15. 10 CFR 73, Appendix G, paragraph I If a one hour notification is made in Appendix A, section 3.1.B.4 of this procedure, then a written notification to the NRC is required within 60 days.
- 16. For reporting a defect found installed in the Plants Safety Related Equipment, Radioactive Wastes System, and Special Nuclear Material within an LER, §Part 21 NRC Reporting of Defects and Noncompliance, see Appendix G in this procedure.
- 17. SQN and WBN only (Non-radiological environmental reporting requirements to the NRC, as required from SQN and WBN Tech Spec (TS), Appendix B.)
- a. WBN or SQN shall record any occurrence of unusual or important environmental events. Unusual or important events are those that potentially could cause or indicate environmental impact causally related with station operation. The following are examples:
(1) Excessive bird impaction events; (2) Onsite plant or animal disease outbreaks; (3) Unusual mortality of any species protected by the Endangered Species Act of 1973; (4) Fish kills near the plant site;
NPG Standard Regulatory Reporting Requirements NPG-SPP-03.5 Programs and Rev. 0010 Processes Page 34 of 100 Appendix A (Page 15 of 15)
Reporting of Events or Conditions Affecting Licensed Nuclear Power Plants 3.5 Written Report NRC (continued)
(5) Unanticipated or emergency discharges of waste water or chemical substances that exceeds the limits of, or is not authorized by, the NPDES permit and requires 24-hour notification to the County or State of Tennessee:
WNón1y (6) Identification of any threatened or endangered species for which the NRC has not initiated consultation with the Federal Wildlife Service (FWS).
(7) Increase in nuisance organisms or conditions in excess of levels anticipated in station environmental impact appraisals.
- b. SQN TS Appendix B compliance guidance is provided in the flowchart in NPG-SPP-05.5, Environmental Control, Appendix B.
- c. WBN TS Appendix B compliance is met through the procedures referenced in NPG-SPP-05.5.
- d. Once an unusual or important event has occurred, the required actions are:
(1) Refer to NPG-SPP-05.5, Environmental Control, Section Compliance with the NRC Appendix B to the Facility Operating License, for additional guidance.
(2) If required, SON or WBN Site Licensing shall make a written report to the NRC in accordance with the NRC Non-routine Report, TS Appendix B, Subsections 5.4.2, within 30 days, in the event of a reportable occurrence in which a limit specified in a relevant permit or certificate issued by another Federal, State, or local agency is exceeded.
[yEQUOYAH EMERGENCY PLAN CLASSIFICATION MATRIX I EPIP-1 L
Refer to Fission Product 1) and Continue in This Column.
Refer to Fission Product Barrier Matrix (Section 1) and Refer to Fission Product Barrier Matrix (Section 1) and Continue in This Column. Continue in This Column.
Refer to Fission Product Barrier Matrix (Section 1) and Refer to Fission Product Barrier Matrix (Section 1) arid Continue in This Column. Continue in This Column.
RCS unidentified or pressure boundary leakage RCS Identified leakage > 25 GPM.
>10 GPM.
- 1. Identified RCS leakage (as defined by Tech, Spec.)
- 1. Unidentified or pressure boundary leakage (as 1, > 25 GPM as indicated by (a orb or C):
1, defined by Tech. Spec)> 10 GPM as indicated by (a or b): 2, a. St-OPS-068-137,0 results or RCS Flow Balance 2, Calculation (AOPR.05, Appendix I or J)
OR 4 b. Level rise in excess of 25 GPM into PRT, RCDT 4 or CVCS holdup lank (Refer to Tl28).
- b. With RCS temperature and PZR level stable, the VCT level on Ll-62-129 or Ll62-130 is dropping at OR a rate> 10 GPM.
- c. RCS leakage through a steam genoralor to the secondary system (primary to secondary Refer to Shutdown Systems Degradation (Section 6.3). leakage).
Refer to Shutdown Systems Deoradation (Section 6.3).
Page 17of49 Revision 51
NPG Standard Work Control Prioritization - On Line NPG-SPP-07.1.4 Programs and Rev. 0003 Processes Page 36 of 37 Attachment I (Page 1 ofl)
On Line Prioritization Matrix WORK TYPE COMPONENT CLASSIFICATION WORK SIGNIFICANCE High Critical Component:
Maint Rule High Risk significant sytem function affected; significant threat to station reliability; regulatory compliance issue (EP,NEIL,00CM, ENV. impacts) that requires immediate compensatory action Significant Personnel Safety/Operator Workaround Critical Component:
Regulatory compliance issue (EP, NEIL ,ODCM, ENV.
impacts) with <30-day response required or compensatory action required.
Operator Burden/Control Room Deficiency Noncritical Component:
Regulatory issue (EP,NEIL,ODCM, ENV.
impacts) deficient or nonconforming condition Run to Failure Components, Minor Safety Issue Building & Structures and Support Systems; Grounds/Tools NORMAL SCHEDULING GUIDANCE Red (1 00-90) = Begin immediately and work around the clock (Emergency Work/Emergent)
Yellow (89-70) Schedule at earliest opportunity within T-3 Orange (69-42) = Schedule within 13 weeks or at next available system week within the 13-week matrix White (41-19) = Schedule as resources allow within the normal process Green (18-1) = Work only when time allows (fill-in activity) o Exceptions to priority guidance will be controlled and approved by the WC Manager.
- Control Room lit annunciators shall be initially coded as 2 (Operator Workaround / Significant degradation with System Operable). If the annunciator can be defeated, then defeat it and prioritize the condition via this matrix.
- Leaking fittings will be coded based on the risk to their associated component.
TENNESSEE VALLEY AUTHORITY SEQUOYAH NUCLEAR PLANT EOI PROGRAM MANUAL EMERGENCY ABNORMAL PROCEDURE EA-268-1 PLACING HYDROGEN RECOMBINERS IN SERVICE Revision 4 QUALITY RELATED PREPARED/PROOFREAD BY: W. T. LEARY RESPONSIBLE ORGANIZATION: OPERATIONS APPROVED BY: JA. DVORAK EFFECTIVE DATE: 1 May 02 REVISION DESCRIPTION: Revised to correct Step number reference error introduced in previous revision. This is a non-intent change.
r SQN PLACING HYDROGEN RECOMBINERS N SERVICE Rev. 4 1,2 Page4ofl2 42 Placing Hydrogen Recombiner in Service
- 1. SELECT applicable unit:
- Uniti
- Unit2
- 2. SELECT recombiner to be placed in service:
- Train A
- TrainB
- 3. RECORD containment pressure from one of the following instruments: [M-6j INSTRUMENT PAM PRESSURE q PDI-30-45 YES LI PDI-30-44 YES LI PDI-30-43 NO LI PDI-30-42 NO LI
- 4. IF LOSS OF OFFSITE POWER has occurred, THEN PERFORM the following:
- a. IF 480V Reactor Vent Boards have NOT been energized, THEN ENSURE all breakers OPEN on 480V Reactor Vent Boards.
- b. ENSURE 480V Reactor Vent Boards ENERGIZED USING EA-201-2, Restoring 480V Busses.
[480V Rx Vent Bd A-A and B-B, Compt 38]
- 5. CHECK POWER AVAILABLE light LIT [M-1O].
SQN EA-268-1 PLACING HYDROGEN RECOMBINERS IN SERVICE Rev. 4 1,2 Page5ofl2 4.2 Placing Hydrogen Recombiner in Service (Continued)
- 6. ENSURE POWER ADJUST potentiometer set at 000:
I TRAIN I POTENTIOMETER I POSITION A XS-83-5003 000 B XS-.83-5004 000
- 7. PLACE POWER OUT SWITCH in up position (on) and CHECK red light on switch plate LIT.
- 8. DETERMINE Pressure Factor USING Appendix A, Ice Condenser Containments Recombiner Power Correction Factor vs. Containment Pressure, and RECORD below:
Pressure Factor
- 9. RECORD reference power from Hydrogen Recombiner Data Plate (Ref. Power): [M10J Reference Power KW.
- 10. CALCULATE required hydrogen recombiner power setting:
- a. CALCULATE power setting in KW:
X KW.
Pressure Factor Reference Power Setting (4.2.8.) (4.2.9.) E
- b. RECORD above calculated power setting in the 25 Minute Table, KW Reading column in Step 11. LI
(%3 w;
c.,l .w LJLJ LE1 0 0 0 0 0
z z z z w Eoo Eoo c_) 1) 5: LU LU LU W LU -
z - D D i D C
-c U)L() Lf)1()
w WWc?)c) JWC)c) coco ac co JcOcO
. J 1 <0 55 <0 55 <0 55 <0 55 0 w LU D
o w W LU LU w N C;-
D Z Z ()ct D
2 w D LU LU o W W oo C) C) oo -C, 2 LU C0 LU . 0u?? , ,
0 C) co co Co Co CO C) CO a. C) o coco chcb chc,S thth thu xx xx xx x a. 0. 0.
0 00 z 2 2
2 2
_I C%J 0
x> woo
°° woo
°° woo
°° woo zçz
- 0) _j oz C <u) oo INCN (JCN Cl)
N w4:
SQN EA-268-1 PLACING HYDROGEN RECOMBINERS IN SERVICE Rev. 4 1,2 Pagel2ofl2 APPENDIX A Page 1 of 1 ICE CONDENSER CONTAINMENTS RECOMBINER POWER CORRECTION FACTOR VS. CONTAINMENT PRESSURE Curves applicable for Pre-LOCA Containment pre-LOCA Containment temperature 110°F in lower pressure of 15.0 psia compartment and 75°F in upper compartment 0
0 0
0 U
C, tJ, C) 0 1.2 14.7 16.7 18.7 20.7 22.7 24.7 (psia) 0 2 4 6 8 10 (psig)
Post-LOCA Containment Pressure
NPG Standard Work Activity Risk Management Process NPG-SPP-07.3 Programs and Rev. 0016 Processes Page 22 of 37 Attachment 2 (Page 1 of 5)
Risk Characterization Nuclear Safety Risk Characterization If the work involves, or has the potential to affect (close proximity), any of the Consider following: [List is not all inclusive, consider other possibilities] characterizing the risk as HIGH 1.1 Nuclear fuel, Control Rods, RCS Boron concentration, RCS temperature, RCS pressure or RCS flow, reactor power. If unsure, contact Operations or Reactor Engineering. [>10% RTP (Other than for Rod Alignment or routine testing)]
1 .2 Fission Product Barriers, Irradiated Fuel Channel or Cladding, Reactor Vessel or piping, Primary Containment, Secondary Containment, Core Operating Thermal limits.
1 .3 Activity, if performed incorrectly, would cause a loss, or defeat, of a safety system, Offsite Power Source or Emergency Diesel Generator.
1 .4 Any physical activity performed on or near protected train equipment or trip sensitive equipment (inside established boundaries), that would cause a plant transient or loss of an Engineered Safety Feature (ESF).
(e.g., building a scaffold over a protected diesel or activity could cause internal flooding or water spray in safety related equipment areas.)
1.5 Concurrent Work on multiple Reactor Protection System (RPS)
Channels/Trains or concurrent work on multiple ESF Trains (On Line).
1.6 RED or ORANGE in EOOS (On Line) Risk Model.
1.7 Fire Risk Insights in EOOS (On Line) Ris Model are elevated AND work is planned/has potential to last more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
1.8 RED or ORANGE in ORAM (Shutdown) Risk Model.
1 .9 Exceeding 50% of Technical Specification Allowable Out-of-service Time (AOT).
1.10 Reduced or Mid Loop Inventory Condition (PWR).
1.11 Primary, Secondary, or Control Bay Habitability containment penetration work online on valves, piping, or local leak rate testing, posing a threat to containment.
1.12 Work on Instrument or Control air that reduces operational margin or system breech 3/4 inch diameter, or reduction in capacity to less than 50%.
NPG Standard Work Activity Risk Management Process NPG-SPP-07.3 Programs and Rev. 0016 Processes Page 23 of 37 Attachment 2 (Page2of5)
Nuclear Safety Risk Characterization If the work involves, or has the potential to affect (close proximity), any of the Consider following: [List is not all inclusive, consider other possibilities] characterizing the risk as HIGH 1 .13 Significant Hydrogen Water chemistry system out of service time (BWR only).
1.14 Impacts the Spent Fuel Pool ability to maintain integrity, ability to control temperature (when time to 200°F is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />), or ability to provide make-up inventory. Higher risk during outages with core offloaded to fuel pool (higher heat load).
Personal Safety Risk Characterization If the work involves, or has the potential to affect (close proximity), any of the Consider following: [List is not all inclusive, consider other possibilities] characterizing the risk as HIGH 2.1 Requires working on live unguarded, un-insulated conductors energized at> 600 volts.
2.2 Will be performed on a fluid system and a non-positive isolation will be used (e.g., check valves, Rx Vessel Level).
2.3 Requires entry into a Permit Required Confined Space that: Contains a known hazardous atmosphere OR an activity that will require entry into a permit required confined space AND includes the use of hazardous material in the area.
2.4 Requires work in an area with wet bulb temp> 120 deg F.
2.5 Will be performed on a system that requires a breach that will directly expose personnel to hazardous chemical or gasses such that purging, flushing, or ventilating alone will not remove the hazard.
2.6 Will require free climbing to perform the work (if not covered by procedure).
2.7 Requires digging, trenching, or excavating near underground lines energized > 600 volts.
2.8 Will require a freeze seal application using portable N2 tanks.
2.9 Requires diving activities.
NPG Standard Work Activity Risk Management Process NPG-SPP-07.3 Programs and Rev. 0016 Processes Page 24 of 37 Attachment 2 (Page 3 of 5)
Personal Safety Risk Characterization If the work involves, or has the potential to affect (close proximity), any of the Consider following: [List is not all inclusive, consider other possibilities] characterizing the risk as HIGH 2.10 Requires Furmaniting type activities on high energy system
(> 500 psig or> 200 deg F) 2.1 1 Will breach (working on any pressure retaining parts of the component or system) an un isolable high energy (> 500 psig or> 200 deg F) or a chemically hazardous system.
2.12 All lifting or rigging activities characterized as a High Hazard lift as defined by TVA Safety Manual Section 721, rigging.
2.13 Activities with unusual personnel safety exposure (e.g., divers, storage tanks and protection from implosion and explosion).
Radiological Safety Risk Characterization If the work involves, or has the potential to affect (close proximity), any of the Consider following: [List is not all inclusive, consider other possibilities] characterizing the risk as HIGH 3.1 Is in a Very High Radiation Area.
3.2 Is in a Locked High Radiation or High Radiation Area and Estimated cumulative dose> 1000 mrem, OR estimated dose to any individual
> 500 mrem.
3.3 Activities with significant ALARA implications (>230 mrem), when recommended by ALARA.
3.4 Involves Nuclear Diving activities in a radioactive system.
3.5 Involves Radiography 3.6 Requires a special/non-routine Primary Containment or Drywell entry at power.
3.7 Activities performed in the SRM/IRM drive motors that could result in retraction of the drive/shuttle tube assembly if performed incorrectly (BWR only).
NPG Standard Work Activity Risk Management Process NPG-SPP-07.3 Programs and Rev. 0016 Processes Page 25 of 37 Attachment 2 (Page 4 of 5)
Environmental Safety Risk Characterization If the work involves, or has the potential to affect (close proximity), any of the Consider following: [List is not all inclusive, consider other possibilities] characterizing the risk as HIGH 4.1 Involves non-isolated system breaches of Condensate, Feed water, SG, SGBD systems (On-Line) (PWR Only).
4.2 Involves a breach of systems containing concentrated acids, bases, or hypochlorite systems with potential for significant draining and/or waste generation ( 200 gallons) 4.3 Involves the potential to release un-monitored gasses or liquids to the environment in excess of established limits of reportability.
4.4 Involves the removal of SGBD ability for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (On-line, PWR Only).
4.5 Involves the removal of primary sampling capability for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (PWR Only).
4.6 Involves the removal of RWCU system capability for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (BWR Only).
NPG Standard Work Activity Risk Management Process NPG-SPP-07.3 Programs and Rev. 0016 Processes Page 26 of 37 Attachment 2 (Page 5 of 5)
Generation Safety Risk Characterization If the work involves, or has the potential to affect (close proximity), any of the Consider following: [List is not all inclusive, consider other possibilities] characterizing the risk as HIGH 5.1 Places the plant in a single point vulnerability such that one failure of a single component, outside the scope of the work activity, can directly lead to a reactor trip, turbine trip, or power reduction greater than 10% RTP. (Example: Making an EHC pump unavailable for standby operation and having the operating EHC pump trip). Sis and some Pis are performed to support licensing requirements and can be excluded from single point vulnerability consideration.
5.2 Involves work that could challenge condensate, feedwater and feed/condensate control system operating margin at power OR a single (normal or redundant) major component important to turbine generation. (Example: Turbine Controls, Feedwater controls, vital condensate or feed system component with On Line generation impact) 5.3 Involves lifting and landing of energized leads for safety related, RPS, ESF or other potential trip circuits/instruments without approved procedural guidance.
5.4 Involves maintenance or testing on LCO or Critical Components while the redundant equipment is degraded or while equipment is out of the working Division (I or II) or Train window.
(e.g. BFN testing or outages on Main Bank Battery Boards qualifies, since different divisions for each units are affected.)
5.5 Any activity that has potential to reduce Main Condenser Vacuum on an operating unit.
5.6 Maintenance on equipment in the 500Kv or 161Kv switch yard, Transformer yard, or Capacitor Bank yard (generation or offsite, in service, trip or protective relay/logic aligned for normal service) that affects power distribution/ electrical line-up.
5.7 Access to the 500Kv or 161Kv switchyard, Transformer yard or Capacitor bank yard that has the potential to contact energized components.
5.8 Significant Reduced Margin activities (for example, components in maintenance rule al, or approaching al).
5.9 Board Transfers that could directly challenge nuclear/industrial safety or generation.