ML082110241
| ML082110241 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 07/29/2008 |
| From: | Stoddard D Virginia Electric & Power Co (VEPCO) |
| To: | Reyes L NRC/RGN-II |
| References | |
| 50-338/08-301, 50-339/08-301 | |
| Download: ML082110241 (131) | |
Text
{{#Wiki_filter:Post-Examination Comments (Green Paper) AJ 0 e. ./1-1 4 IJ /tJ .It C)rLl./lJt:: dM8-J.6/ Licensee Submitted Post-Examination Comments [~ttached [ ] None
VIR(;INIA Er.. ECTRIC AND P(}WER C()MPANY RJ(_~I-IM()Nr), VIR(;INI.,:\ 23261 July 2,2008 Mr. Luis A. Reyes Serial No. 08-0386 Regional Administrator NAPS/JHL United States Nuclear Regulatory Commission Docket Nos. 50-338 Region II 50-339 Sam Nunn Atlanta Federal Center License Nos. NPF-4 61 Forsyth St., SW, Suite 23T85 NPF-7 Atlanta, Georgia 30303
Dear Mr. Reyes:
VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION) NORTH ANNA POWER STATION UNITS 1 AND 2 OPERATOR LICENSE EXAMINATION COMMENTS On June 24, 2008, the written examination for initial reactor operator and senior reactor operator candidates was administered at North Anna Power Station. The attachments to this letter provide the information- requested in NUREG-1 021, ES-501, Initial Post-Examination Activities, Section C.1.a. In addition, comments for consideration on the written examination were prepared as outlined in NUREG-1 021, ES-403, Grading Initial Site-Specific Written Examinations, Sections C.1, D.1, and 0.2. The attachments to this letter are being provided to Mr. Mark Bates, NRC Chief Examiner. Prompt consideration of these comments and recommendations will assist in completing the license examination process. If you have any questions, please contact Mr. C. A. McClain at (540) 894-2446. Very truly yours, Daniel G. Stoddard, P.E. Site Vice President Attachments Commitments made in this letter: None
cc: Document Control Desk (without attachments) U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Mr. Malcolm Widmann, Chief (without attachments) Operator Licensing and Human Performance Branch Division of Reactor Safety Region II Sam Nunn Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, Georgia 30303 Mr. Mark Bates, Chief Examiner U. S. Nuclear Regulatory Commission Division of Reactor Safety Region II Operator Licensing and Human Performance 'Branch Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303 NRC Senior Resident Inspector (without attachments) North Anna Power Station
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #5 (KIA 006 K2.02) Test Key Answer:
"lH1; breaker is open."
One of the distractors for this question states the following:
"lH1; breaker is closed."
The Test Key Answer is based on 1-0P-3.3, UNIT SHUTDOWN FROM MODE 4 TO MODE 5 which states, "Verify all ReS loop Hot Leg temperatures (Th) are less than 350 0 F", at which time the accumulator discharge isolation valve breakers are opened. 1-0P-3.3 does not provide a Step with a specific lower limit of temperature for when the action is required to be completed, or verified completed by. TS 3.4.12 requires power removed from the Accumulator isolation valve operators when applicability is met for Low Temperature Overpressure Protection (LTOP) system. TS 3.4.12 Applicability is MODE 4 when any RCS cold leg temperature is ~ 280 0 F, MODE 5, and MODE 6 when the reactor vessel head is on. The breakers for the Accumulator Discharge Isolation Valves are normally locked OFF (open) when the Unit is operating and are required to be placed in ON (closed) in accordance with 1-OP-3.2, UNIT SHUTDOWN FROM MODE 3 TO MODE 4, in preparation for closing the valves once RCS pressure is lowered to 950 psig. Since 1-0P-3.3 only requires the action be taken to open the accumulator discharge isolation valve breakers when temperature is less than 350 0 F waiting until 325 0 F to initiate the action would not constitute a procedural violation. There is not a hold point on cooldown upon procedure entry or prior to performing the subject substep and in practice the specific temperature value for when the action would be completed is somewhat dependent on cooldown rate and other outage activities. Further the question only asks "its required breaker position for the current plant conditions", but does not specify in accordance with 1-0P-3.3. In the absence of a lower value of temperature in 1-0P-3.3 for which the action is required to be completed to take the breakers to OFF (open), one reverts to the TS requirement of having the breaker offby the time RCS temperature is :s 280 0 F and concludes that they are not "required" to be repositioned yet since the temperature given in the stem was 325 0 F. Since the question does not specify "in accordance with 1-0P-3.3" or "in accordance with TS-3.4.12," both choices are considered acceptable and correct.
References:
1-0P-3.2 & 1-0P-3.3; TS 3.4.12
DOMINION 1-0P-3.2 North Anna Power Station Revision 67 Page 35 of 60 5.28.3 Flush the hot spots in the B PZR spray line as follows:
- a. Fully open l-RC-PCV-1455B and maintain full open as long as plant conditions permit.
- b. Adjust the spray valve(s) to maintain the cooldown within the limits established in Attachment 1.
5.29 Place the following breakers in ON, but DO NOT close the associated valves:
- l-EE-BKR-IHI-2N-L3, A SI Accumulator Discharge Isol Valve CB I-SI-MOV-1865A
- l-EE-BKR-IHI-2N-N3, B SI Accumulator Discharge Isol Valve CB I-SI-MOV-1865B
- l-EE-BKR-IJI-2N-K4, C SI Accumulator Discharge Isolation Vv CB I-SI-MOV-1865C NOTE: Steam Dump Valve manual actuators are reverse acting.
5.30 Manually open D through H Steam Dump Valves locally as required to maintain desired cooldown rate. The manual actuator must be used. The valves shall be jacked open one at a time so the OATC can make any necessary adjustments using Band C Steam Dump Valves. (Reference 2.4.6) 5.31 Maintain 6 to 10 gpm to each RCP by adjusting Seal Injection, as required, using 1-0P-8.10, Seal Injection Flow Adjustment. (Reference 2.4.16)
DOMINION 1-0P-3.2 North Anna Power Station Revision 67 Page 37 of 60 5.36 WHEN RCS pressure lowers to 950 psig, THEN close the following SI Accumulator Discharge MOVs, but do NOT open the breakers for the MOVs:
- I-SI-MOV-1865A, A SI ACCUMULATOR DISCHARGE ISOLATION VALVE
- I-SI-MOV-1865B, B SI ACCUMULATOR DISCHARGE ISOLATION VALVE
- I-SI-MOV-1865C, C SI ACCUMULATOR DISCHARGE ISOLATION VALVE CAUTION To minimize thermal stress, prevent exceeding heatup and cooldown rates in the Pressurizer, and maintain uniform chemistry, PRZR spray should be initiated slowly and maintained continuously. (Reference 2.4.11)
NOTE: The Administrative Limit for the maximum ~T between spray water temperature and PRZR liquid temperature is 300°F. (Reference 2.4.5 and 2.4.7) NOTE: Promptly reducing Pressurizer temperature (pressure) during Res cooldown evolutions will minimize the ~ T between the RCS hot leg and the Pressurizer. This will help prevent violations of the Pressurizer heatup and cooldown limits. (Reference 2.4.14) 5.37 Ensure the PRZR cooldown proceeds as follows: 5.37.1 Cooldown, at ~ 90°F/hr, by manually operating the spray valves, Pressurizer Master Pressure Controller, and PRZR Heaters. 5.37.2 Every 30 minutes, do the following:
- a. Plot the wide range Tc versus RCS pressure on Attachment 1, RCS/PRZR Cool-Down Curves.
DOMINION 1-0P-3.3 North Anna Power Station Revision 59 Page 21 of 47 NOTE: WHEN the Accumulator pressure is greater than the PORV lift setpoint, THEN SI Accumulators must be isolated with the power removed from the MOVs. This is performed for Tech Spec SR 3.4.12.3. NOTE: WHEN Solid State Protection Fuses are removed, THEN SI Accumulator MOV Breakers must be tagged OFF. 5.8 Do the following: 5.8.1 Verify all RCS loop Hot Leg temperatures (Th) are less than 350°F. 5.8.2 Place the following breakers in OFF:
- 1-EE-BKR-1Hl-2N-L3, A SI Accumulator Discharge Isol Valve CB 1-SI-MOV-1865A
- 1-EE-BKR-1Hl-2N-N3, B SI Accumulator Discharge Isolation Valve 1-SI-MOV-1865B
- 1-EE-BKR-1Jl-2N-K4, C SI Accumulator Discharge Isolation Valve 1-SI-MOV-1865C 5.8.3 Lock the following breakers in OFF:
- 1-EE-BKR-1Hl-2N-L3, A SI Accumulator Discharge Isol Valve CB 1-SI-MOV-1865A
- 1-EE-BKR-1Hl-2N-N3, B SI Accumulator Discharge Isolation Valve 1-SI-MOV-1865B
- 1-EE-BKR-1Jl-2N-K4, C SI Accumulator Discharge Isolation Valve 1-SI-MOV-1865C
DOMINION 1-0P-3.3 North Anna Power Station Revision 59 Page 22 of 47 5.8.4 Hang Danger Tags, assigned to the SRO, on the following breakers:
- 1-EE-BKR-1Hl-2N-L3, A SI Accumulator Discharge Isol Valve CB '
1-SI-MOV-1865A
- 1-EE-BKR-1Hl-2N-N3, B SI Accumulator Discharge Isolation Valve 1-SI-MOV-1865B
- 1-EE-BKR-1Jl-2N-K4, C SI Accumulator Discharge Isolation Valve 1-SI-MOV-1865C 5.9 Depressurize the SI Accumulators to less than 350 psig using 1-0P-7.3, Filling, Sluicing, Draining, Pressurizing, and Venting SI Accumulators, while continuing with this procedure. (Reference 2.4.1)
- 1-SI-TK-1A, Accumulator A
- 1-SI-TK-1B, Accumulator B
- l-SI-TK-1C, Accumulator C NOTE: Promptly reducing Pressurizer temperature (pressure) during RCS cooldown evolutions will minimize the i:lTbetween the RCS hot leg and the Pressurizer. This will help prevent violations of the Pressurizer heatup and cooldown limits. (Reference 2.4.18) 5.10 Continue the RCS cooldown and depressurization at ~75 °F/hr using Steam Dumps or Steam Generator PORV s.
5.11 Every 30 minutes, do the following: 5.11.1 Plot the wide range T c versus RCS pressure on Attachment 1, RCSIPRZR Cool Down Curves.
- NUCLEAR DESIGN INFORMATION PORTAL-LTOP System 3.4.12 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.12 Low Temperature Overpressure Protection (LTOP) System LCO 3.4.12 An LTOP System shall be OPERABLE with a maximum of one charging pump and one low head safety injection (LHSI) pump capable of injecting into the RCS and the accumulators isolated, with power removed from the isolation valve operators, and one of the following pressure relief capabilities:
- a. Two power operated relief valves (PORVs) with lift setting allowable values of:
- 1. S 540 psig when any RCS cold 1eg temperature S 280°F; and
- 2. S 375 psig when any RCS cold 1eg temperature S 180°F.
- b. The RCS depressurized and an RCS vent of ~ 2.07 square inches.
- - - - - - - - - - - - NOTES- - - - - - - - - - - - -
- 1. Two charging pumps may be made capable of injecting for s 1 hour for pump swapping operations.
- 2. Accumulator isolation with power removed from the isolation valve operators is only required when accumulator pressure is greater than the PORV lift setting.
APPLICABILITY: MODE 4 when any RCS cold leg temperature is S 280°F, MODE 5, MODE 6 when the reactor vessel head is on. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Two LHSI pumps capable A.l Initiate action to Immediately of injecting into the verify a maximum of RCS. one LHSI pump is capable of injecting into the RCS. North Anna Units 1 and 2 3.4.12-1 Amendments 242/223
- NUCLEAR DESIGN INFORMATION PORTAL-LTOP System 3.4.12 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. Two or more charging B.1 Initiate action to Immediately pumps capable of verify a maximum of injecting into the one charging pump is RCS. capable of injecting into the RCS.
C. --------NOTE--------- C.1 Isolate affected Immediately Only applicable when accumulator. accumulator pressure is greater than PORV AND lift setting.
--------------------- C.2 Remove power from 1 hour affected accumulator An accumulator not isolation valve isolated. operators.
OR Power available to one or more accumulator isolation valve operators. D. Required Action and 0.1 Increase RCS cold leg 12 hours associated Completion temperature to > 280°F. Time of Condition C not met. OR 0.2 Depressurize affected 12 hours accumulator to less than PORV lift setting. E. One required PORV E.1 Restore required PORV 7 days inoperable in MODE 4. to OPERABLE status. F. One required PORV F.1 Restore required PORV 24 hours inoperable in MODE 5 to OPERABLE status. or 6. North Anna Units 1 and 2 3.4.12-2 Amendments 242/223
- NUCLEAR DESIGN INFORMATION PORTAL-LTOP System 3.4.12 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G. Two required PORVs G.1 Depressurize RCS and 12 hours inoperable. establish RCS vent of
~ 2.07 square inches.
OR Required Action and associated Completion Time of Condition A, B, D, E, or F not met. OR LTOP System inoperable for any reason other than Condition A, B, C, D, E, or F. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.1 Verify a maximum of one LHSI pump is 12 hours capable of injecting into the RCS. SR 3.4.12.2 Verify a maximum of one charging pump is 12 hours capable of injecting into the RCS. SR 3.4.12.3 -------------------NOTE-------------------- Only required to be met if accumulator pressure is greater than PORV lift setting. Verify each accumulator is isolated and 12 hours power is removed from the accumulator isolation valve operator. North Anna Units 1 and 2 3.4.12-3 Amendments 231/212
- NUCLEAR DESIGN INFORMATION PORTAL-LTOP System 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.4 Verify required RCS vent ~ 2.07 square 12 hours for inches open. unlocked open vent valve(s) 31 days for other vent paths SR 3.4.12.5 Verify PORV block valve is open for each 72 hours required PORV and PORV keyswitch is in AUTO.
SR 3.4.12.6 Verify required PORV backup nitrogen supply 7 days pressure is within limit. SR 3.4.12.7 -------------------NOTE-------------------- Not required to be met until 12 hours after decreasing RCS cold leg temperature to
~ 280°F.
Perform a COT on each required PORV, 31 days excluding actuation. SR 3.4.12.8 Perform CHANNEL CALIBRATION for each 18 months required PORV actuation channel. North Anna Units 1 and 2 3.4.12-4 Amendments 242/223
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #15 (KIA 013 K4.15) This item has no discriminatory value. Discerning the status of the general warning lights in the SSPS logic cabinets is not part of the job requirements for licensed operators at North Anna. If the associated annunciator were received, Operations would dispatch Instrument Technicians to the SSPS logic cabinets to determine the cause. The KIA discusses the continuous testing feature ofESFAS. This feature only exists on PLC-based systems. North Anna's ESFAS/SSPS is not a PLC-based system. Finally, SRO item #81 gives away this item, which could explain why 7 of 8 ROs missed the item, but 4 of 5 SROs answered it correctly. This item should be deleted.
References:
1K-G1, SFGDS PROT SYS TRA TROUBLE 1K-G2, SFGDS PROT SYS TR B TROUBLE
VIRGINIA POWER 1-EI-CB-21K ANNUNCIATOR G1 1-AR-K-G1 NORTH ANNA POWER STATION REV. 0 APPROVAL: ON FILE Effective Date:07/24/97 SFGDS -PROT SYS TR A TROUBLE 1.0 Probable Cause 1.1 Loss of 48VDC power supply 1.2 Loss of 15VDC power supply 1.3 Printed circuit card not tight 1.4 Instrument Department performing test on SFGDS protection system Train A 2.0 Operator Action 2.1 Verify approved Instrument Department test in progress. 2.2 Ensure Train A is the only Train to be affected. 2.3 Notify Instrument Department of power supply or card malfunction. 3.0 References 3.1 Westinghouse technical manual, Solid State Protection System 3.2 11715-ESK-10K, 10AAX 4.0 Actuation NOTE: 4.1 Through 4.5 initiate general warning which triggers annunciator via K524-A 4.1 Failure of 48VDC or 15VDC power supplies 4.2 Printed circuit card not fully inserted 4.3 Input error inhibit switch in "INHIBIT POSITION" 4.4 "PERMISSIVES" switch or "MEMORIES" switch is not in the "OFF" position, or the "MODE SELECTOR" switch is not in the "OPERATE" position 4.5 "LOGIC A" switch is not in "OFF" position or "MULTIPLEXER TEST" switch in the "INHIBIT" position
VIRGINIA POWER 1-EI-CB-21K ANNUNCIATOR G2 1-AR-K-G2 NORTH ANNA POWER STATION REV. 0 APPROVAL: ON FILE Effective Date:07/24/97 SFGDS PROT SYS TR B TROUBLE 1.0 Probable Cause 1.1 Loss of 48VDC power supply 1.2 Loss 15VDC power supply 1.3 Printed circuit card not tight 1.4 Instrument Department performing test on SFGDS Protection System Train B 2.0 Operator Action 2.1 Verify approved Instrument Department test in progress. 2.2 Ensure Train B is the only train to be affected. 2.3 Notify Instrument Department of power supply or card malfunction. 3.0 References 3.1 Westinghouse technical manual, Solid State Protection System 3.2 11715-ESK-10K, 10AAX 4.0 Actuation NOTE: 4.1 through 4.5 initiate general warning which triggers annunciator via K524-B 4.1 Failure of 48VDC or 15VDC power supplies 4.2 Printed circuit card not fully inserted 4.3 Input error inhibit switch in "INHIBIT" position 4.4 "PERMISSIVES" switch or "MEMORIES" switch is not in the "OFF" position, or the "MODE SELECTOR" switch is not in the "OPERATE" position 4.5 "LOGIC A" switch is not in the "OFF" position, or "MULTIPLEXER TEST" switch in the "INHIBIT" position
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #20 (KIA 022 AK3.03) Test Key Answer: One of the distractors for this question states the following: Although I-OP-8.S P&L 4.7 states that placing excess letdown in service may result in a boration due to "potentially higher boron concentration in the excess letdown piping," it is possible that the excess letdown system was placed in service at the end of the previous cycle, then NOT drained during the outage. In this case, the system would contain water with virtually zero boron concentration. It is also possible that the excess letdown system was filled from a source with lower boron concentration than the expected reactor coolant system (RCS) boron concentration with the unit at 100% power following a refueling outage. In either case, the result would be a dilution of the RCS when excess letdown is placed in service. The operators are trained to closely monitor reactor power when placing systems in service that interface with the RCS due to the potential for either boration or, more importantly, dilution that could cause reactor power to exceed 100%. The consequences of a slight reduction in reactor power from 100% are far less severe than those of a slight increase in reactor power from an initial power of 100%. The item stem states "when placing excess letdown in service lAW I-OP-8.5," but it does not specifically solicit the operator's knowledge ofP&L 4.7. Either "A" or "D" should be accepted as correct answers. Both choices are considered acceptable and correct.
References:
I-OP-8.S
DOMINION 1-0P-8.5 North Anna Power Station Revision 18 Page 5 of 17 4.0 PRECAUTIONS AND LIMITATIONS 4.1 Comply with the following guidelines when marking steps N/A:
- IF the conditional requirements of a step do not require the action to be performed, THEN mark the step N/A.
- IF any other step is marked N/A, THEN have the SRO approve the N/A and justify the N/A on the Procedure Cover Sheet.
4.2 IF Component Cooling is lost, THEN immediately stop primary flow through the Excess Letdown Heat Exchanger. 4.3 WHEN excess letdown flow is aligned to the PDrr instead of to the VCT, THEN inventory will be lost from the RCS/CVCS. 4.4 The design flow from the Excess LTDN HX is 7500 lbmlhr, sized to compensate for RCP seal injection if normal letdown is lost. 4.5 Only one loop drain valve may be open in Modes 1-4, to prevent the possibility of bypassing SI flow to the two intact loops in a Design Basis Accident, due to loop cross-connect through the drain header. (Reference 2.4.1) 4.6 WHEN RCS pressure is greater than 300 psig, THEN Normal Letdown pressure should be at least 300 psig to prevent cavitation erosion of the letdown orifices. Operating with Letdown pressure less than 300 psig is acceptable for short durations. (References 2.3.19 and 2.3.20) 4.7 WHEN Excess Letdown is placed in service, THEN monitor RCS temperature and Reactor power closely due to the possible reactivity effects. A dilution may be required to maintain desired RCS temperature and Reactor power level. This is due to a potentially higher boron concentration in the Excess Letdown piping. The reactivity impact of placing the system in service is approximately -6 pcm at BOL and -15 pcm at EOL. (Reference 2.4.2)
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #23 (KIA 026 A4.01) Test Key Answer: "CDA is not required, however, Quench Spray is required; open Quench Spray Discharge Valves and then start Quench Spray Pump." One of the distractors for this question states the following: "CDA is not required, however, Quench Spray is required; start Quench Spray Pumps and then open Quench Spray discharge valves." l-E-O, "Reactor Trip or Safety Injection," provides two sequences for verifying or initiating Quench Spray (QS). One for Containment Depressurization Actuation (CDA) and another for the actuation of Quench Spray for radio-isotope control. Step 11 (Continuous Action Step) "Check If CDA is Required" provides the sequence of verifying QS Pumps running (RNO - manually start pumps) and then verifying QS Pump Discharge Valves open (RNO- manually open valves). This sequence (pump actuation, then valve actuation) is identical in Continuous Action Page (CAP) Item 6, "CDA Actuation Criteria." Step 12 (Continuous Action Step) "Check If Quench Spray is Required" provides the sequence of manually opening the QS Pump Discharge Valves and then manually starting the QS Pumps. The design configuration for the QS pump and discharge valves, during Mode 1-4 operation, is the QS pump in "Auto" with the QS Pump Suction MOV open and the QS Pump Dicharge MOV closed. Upon automatic CDA actuation (with no UV/DV condition on the associated Emergency Bus), the pump and the suction and discharge MOVs simultaneously receive actuation signals; thus the QS Pump breaker closes (immediately starting the pump) while the QS Pump Discharge Valve motor starts to move the valve to the fully open position (the QS Pump Suction MOV is already open). Should automatic actuation not occur when required, as discussed above, l-E-O Continuous Action Page Item 6 or Step 11 would manually start the pump(s) and then manually open the discharge valve, in that sequence (similar to the sequence for automatic actuation). In the question initial conditions, Containment pressure has not yet reached the CDA setpoint of 27.75 psia (EOP step uses the setpoint of28 psia), but has exceeded 20 psia. Normally, under these conditions, Step 12 would be used to establish Quench Spray, with the sequence of manually opening the pump discharge MOV(s) and then manually starting the pump(s). Technically, there is no functional difference between the two sequences of establishing Quench Spray. In both cases, the final configuration ofpump(s) running with discharge valve(s) open is achieved within a very short period of time with negligible short-term consequences in the event of actuation failure of any individual component on demand.
North Anna RO/SRO NRC ILO Exam Test Item Comments The WaG Background Document does not specify the sequence for the component actuations to establish Quench Spray in Step 11 ofE-O. Continuous Action Page (CAP) Item 6 was added to 1-E-O by Dominion to provide direction to perform the equivalent action steps of Step 11, if the condition was encountered prior to reaching Step 11 in the procedure, or after bypassing Step 11 in the procedural flow through earlier steps, if Containment pressure had not reached the Main Steam Isolation setpoint of 17.8 psia (EOP uses the setpoint of 18 psia). An equivalent CAP Item is not contained in the WaG Background Document; however the action steps mirror the sequence of Step 11. As noted above, the WaG Background Document does not specify the sequence for the component actuations to establish Quench Spray in Step 11. The North Anna EOP Step Differences Evaluation Document does not specify a basis for the manual actuation sequence establishing Quench Spray in the CAP Item, other than the description that it was intended to be the same as Step 11. Step 12 was a step added to 1-E-O by Dominion for radio-isotope control afforded by actuation of Quench Spray, including the injection of the Chemical Addition Tank (for the addition of NaOH). An equivalent step is not contained in the WaG Background Document. The North Anna EOP Step Differences Evaluation Document does not specify a basis for the manual actuation sequence establishing Quench Spray. Since there is no documented technical basis difference between the two approved manual actuation sequences, and there are no short-term adverse consequences associated with the execution of either sequence, then either sequence is an acceptable response to the conditions stated in the question stem. Verbatim knowledge of the sequence difference between 1-E-O, Step 11 and 12 requires memorization of action steps that are not considered Immediate Operator Action Steps. Cognitive knowledge of the actuations required for the establishment of Quench Spray, under the non-CDA conditions listed in the question stem, is demonstrated by the selection of either of the answer selections stated above. Both choices are considered acceptable and correct.
References:
1-E-O, "Reactor Trip or Safety Injection" 1-E-O WaG Background Document North Anna EOP Step Differences Evaluation Document 11715-ESK-6K, 6L, 6CP, 6CQ
NORTH ANNA POWER STATION EMERGENCY PROCEDURE NUMBER PROCEDURE TITLE REVISION 36 1*E*Q REACTOR TRIP OR SAFETY INJECTION PAGE (WITH SEVEN ATTACHMENTS) 1 of 24 PURPOSE This procedure provides actions to verify proper response of the automatic protection systems following manual or automatic actuation of a Reactor trip or Safety Injection, to assess plant conditions, and to identify the appropriate recovery procedure. ENTRY CONDITIONS
- 1) The following are symptoms that require a Reactor trip, if one has not occurred:
- A Reactor protection system setpoint has been exceeded
- A Turbine protection system setpoint with power greater than P-8 setpoint
- 2) The following are symptoms of a Reactor trip:
- Any Reactor trip first out Annunciator - LIT
- Reactor Trip and Bypass Breakers - OPEN
- Rod Bottom Lights - LIT
- Neutron flux - DECREASING
- 3) The following are symptoms that require a Reactor trip and Safety Injection, if one has not occurred:
- Low PRZR pressure
- High Containment pressure
- St~~mlin~,giffere~':i~1 Pf~iSLJ~~
- Hig~'stec.lt'l"lfl()w wltm; 10-tC[>>j"avEJ
- Hi~~>stel_fl~~;~~~~~ I01J,~~eam Pi~rsure
~~. ~h.~;t:~IIOwim;~ are~J~~!rto~~ of a R~~~tor trip
- Any SI first out Ar:lrlmnciator - LIT'
- Any Low-Head SI Pumps - RUNNING
- 5) Transition from another plant procedure.
CONTINUOUS USE
NUMBER PROCEDURE TITLE REVISION 36 1-E-O REACTOR TRIP OR SAFETY INJECTION PAGE 7 of 24 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
- 11. CHECK IF CDA IS REQUIRED:
0 a) Containment pressure - HAS EXCEEDED o a) GO TO Step 12. 28 PSIA 0 b) Manually actuate CDA 0 c) Verify CC Pumps - TRIPPED o c) Stop CC Pumps. 0 d) Stop all RCPs 0 e) Verify QS Pumps - RUNNING o e) Manually start QS Pumps. f) Verify QS Pump Discharge MOVs - OPEN o f) Manually open valves. 0
- 1-QS-MOV-101A 0
- 1-QS-MOV-101B o g) On the Unit 1 Ventilation Panel, verify o g) Place switch in CLOSE.
1-SW-TV-101A&B SERVICE WATER SUPPLY & RETURN TO RECIRC AIR FANS - SWITCH IN CLOSE POSITION o h) Initiate ATTACHMENT 2, VERIFICATION OF PHASE B ISOLATION o i) Initiate ATTACHMENT 3, PRIMARY PLANT VENTILATION ALIGNMENT o j) GO TO Step 13
NUMBER PROCEDURE TITLE REVISION 36 1-E-O REACTOR TRIP OR SAFETY INJECTION PAGE 8 of 24 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
- 12. CHECK IF QUENCH SPRAY IS REQUIRED:
a) Verify BOTH of the following: D a) GO TO Step 13. D
- Containment pressure - HAS EXCEEDED 20 psia D
- All SG pressures stable or under operator control b) Manually start Quench Spray:
- 1) Open the following valves: D 1) Locally open valve.
D
- 1-QS-MOV-101A D
- 1-QS-MOV-101B
- 2) Start the following pumps:
D
- 1-QS-P-1A D
- 1-QS-P-1 B
- 3) Open Chemical Addition Tank D 3) Locally open valves.
Outlet Valves: D
- 1-QS-MOV-102A D
- 1-QS-MOV-102B
CONTINUOUS ACTION PAGE FOR 1-E-0
- 1. ADVERSE CONTAINMENT CRITERIA
!E either of the following conditions exist, THEN use setpoints in brackets:
D
- 20 psia Containment pressure, OR D
- Containment radiation has reached or exceeded 1.0E5 R/hr (700/0 on High Range Recorder).
- 2. SI FLOW CRITERIA D !E SI is actuated AND High-Head Cold Leg SI flow is NOT indicated, THEN initiate ATTACHMENT 6, MANUAL VERIFICATION OF SI FLOWPATH.
- 3. RCP TRIP CRITERIA
!E both conditions listed below exist, THEN trip all RCPs:
D
- Charging Pumps - AT LEAST ONE RUNNING AND FLOWING TO RCS, AND D
- RCS subcooling based on Core Exit TCs - LESS THAN 25°F [85°F].
- 4. CHARGING PUMP RECIRC PATH CRITERIA D
- IF RCS pressure decreases to less than 1275 psig [1475 psig] AND RCPs tripped, THEN close Charging Pump Recirc Valves.
D
- IF RCS pressure increases to 2000 psig, THEN open Charging Pump Recirc Valves.
- 5. ECST LEVEL CRITERIA D WH,EN the ECST level decreases to 40%, THEN initiate 1-AP-22.5, LOSS OF EMERGENCY CONDENSATE STORAGE TANK 1-CN-TK-1.
- 6. CDA ACTUATION CRITERIA IF Containment pressure exceeds 28 psia, THEN do the following:
D a. Manually actuate CDA. D b. Ensure CC Pumps STOPPED. D c. Stop all RCPs. D d. Ensure as Pumps RUNNING. D e. Ensure as Pump Discharge MOVs OPEN. D f. Initiate ATTACHMENT 2, VERIFICATION OF PHASE B ISOLATION. D g. Initiate ATTACHMENT 3, PRIMARY PLANT VENTILATION ALIGNMENT.
- 7. CONTAINMENT RECIRC MODE CRITERIA D To prevent possible radioactive release from the RWST, VCT level should be maintained greater than 12%.
- 8. RCP CRITERIA D Seal injection flow should be maintained to all RCPs.
- 9. REACTIVITY CONTROL CRITERIA D An Operator should be sent to locally close and lock 1-CH-217, PG to Blender Isolation Valve.
- 3. RECOVERY/RESTORATION TECHNIQUE The objective of the recovery/restoration technique incorporated into guideline E-O is to verify proper response of the automatic protection systems followinQ manual or automatic actuation of a reactor trip or safety injection, to assess plant conditions and to identify the appropriate recovery guideline.
The following subsection provides a summary of the major categories of operator actions for guideline E-O, REACTOR TRIP OR SAFETY INJECTION. 3.1 High Level Action Summary A high level summary of the actions performed in E-O is given on the following page in the form of major action categories. These are discussed below in more detail. o Verify Automatic Actions as Initiated by the Protection and Safeguards Systems Upon a reactor trip or safety injection, the operator enters E-O. After verifying reactor trip, turbine trip and the availability of ac power, the operator checks if S1 has been actuated or is required. If SI was neither actuated nor required, then the operator transfers to the guideline ES-0.1, REACTOR TRIP RESPONSE. If SI was actuated or is required, the operator then proceeds to verify proper alignment and condition of the safeguards systems including containment spray system if containment pressure exceeds the spray actuation setpoint. Appropriate steps for verification of other essential equipment as required by the specific plant design should be included at this time. o Identify Appropriate Optimal Recovery Guideline The operator checks that the pressurizer PORVs and spray valves are closed and determines if the RCPs should be tripped. Following these actions is the first attempt at identification of an appropriate Optimal Recovery Guideline, including a check on SI termination criteria. E-O Background 4 HP-Rev. 2, 4/30/2005 HEOBG.doc
MAJOR ACTION CATEGORIES IN E-O o Verify Automatic Actions as Initiated by the Protection and Safeguards Systems o Identify Appropriate Optimal Recovery Guideline o Shut Down Unnecessary Equipment and Continue Trying to Identify Appropriate Optimal Recovery Guideline E-O Background 5 HP-Rev. 2, 4/30/2005 HEOBG.doc
o Shut Down Unnecessary Equipment and Continue Trying to Identify Appropriate Optimal Recovery Guideline If SI cannot be terminated and an appropriate Optimal Recovery Guideline cannot be identified in the previous steps, the operator would continue to evaluate plant conditions, fill his steam generators to normal range and secure low-head SI while continuing to try to identify an appropriate Optimal Recovery Guideline transition. The safety status of the plant would also be ensured by the monitoring of the Critical Safety Function Status Trees. 3.2 Key Utility Decision Points When Revision 1 of the ERGs was validated in 1983, the operators were completing E-O and transferring to the appropriate optimal recovery gUideline in approximately 5 minutes. Accident analyses that credited operator action did not assume any operator action prior to ten minutes. Because the progression through E-O was performed in a timely manner in 1983, there was no need to adjust E-O to shorten the time that operators spent in it. Over the years, changes in control room protocol and communications standards have impacted operator action times in the emergency operating procedures. Modifications can be made on a plant-specific basis to help the utilities expedite the performance of E-O in general and to specifically permit qUicker termination of high pressure injection flow for spurious SI events. The appendix to section 4.1 of the Step Description tables provides some generic suggestions and examples for expediting operator action in E-O. It is the responsibility of each utility to determine which if any enhancements discussed in the appendix should be implemented at their site. E-O Background 6 HP-Rev. 2, 4/30/2005 HEOBG.doc
STEP DESCRIPTION TABLE FOR E-O Step 1 - NOTE 2 NOTE: Foldout page should be open PURPOSE: To remind the operator that the foldout page for E-O should be open. BASIS: The foldout page provides a list of important items that should be continuously monitored. If any of the parameters exceed their limits, the appropriate operations should be initiated. Refer to the section FOLDOUT PAGE in this background document and the document FOLDOUT PAGE ITEMS in the Generic Issues section of the EXECUTIVE VOLUME for additional information on which foldout page items apply to this guideline and sample wording of those items. ACTIONS: N/A INSTRUMENTATION: N/A CONTROL/EQUIPMENT: N/A KNOWLEDGE: The operator should know what items comprise each foldout page. PLANT-SPECIFIC INFORMATION: N/A E-O Background 10 HP-Rev. 2, 4/30/2005 HEOBG.doc
STEP DESCRIPTION TABLE FOR E-O Step --lL STEP: Verify Containment Spray Not Required PURPOSE: To ensure automatic actuation of containment spray and Containment Isolation Phase B if containment pressure exceeded the Hi-3 setpoint BASIS: If containment pressure exceeds the high-3 setpoint, containment spray is automatically initiated to mitigate the containment pressure transient. Containment Isolation Phase B valves are closed to isolate additional potential release paths from containment. Since component cooling to the RCP seals and motors is isolated on a Phase B signal, the RCPs are tripped to preclude overheating of the seals and motors. The basis for the IIhas remained less than (T.02) psig conditions on ll containment pressure is that containment pressure may have exceeded the setpoint and then decreased due to spray actuation. In this case the operator should still verify system operation as per the Response Not Obtained (RNO) column. ACTIONS: o Determine if containment pressure has remained less than (T.02) psig o Determine if containment spray initiated o Determine if Containment Isolation Phase B valves closed o Manually initiate containment spray o Manually close Phase B valves o Stop all RCPs INSTRUMENTATION: o Containment pressure indication o Containment spray pumps status indications o Containment Isolation Phase B valves position indications o RCPs status indication E-O Background 27 HP-Rev. 2, 4/30/2005 HEOBG.doc
STEP DESCRIPTION TABLE FOR E-O Step ~ CONTROL/EQUIPMENT: Switches for: o Containment spray initiation o Phase B isolation valves o RCPs KNOWLEDGE: This step is a continuous action step while in this guideline. PLANT-SPECIFIC INFORMATION: (T.02) Containment pressure setpoint for spray actuation. E-O Background 28 HP-Rev. 2, 4/30/2005 HEOBG.doc
- 6. FOLDOUT PAGE This section provides the reasons for the inclusion of each item on the foldout page for the E-O guideline. Refer to the document FOLDOUT PAGE ITEMS in the Generic Issues section of the Executive Volume for discussion on the technical basis of each foldout page item.
RCP Trip Criteria The RCP trip criteria should be monitored continuously while in E-O guideline. While the operator is in this guideline, it is generally early in the transient with higher decay heat levels present. Refer to the document RCP TRIP/RESTART in the Generic Issues section of the Executive Volume. AFW Supply Switchover Criterion While performing the actions in the E-O gUideline, the limited supply of water in the CST may be exhausted. Therefore, the criterion to switch to alternate AFW water supplies should be continuously monitored. E-O Background 73 HP-Rev, 2, 4/30/2005 HEOBG,doc
NAPS EOP: TITLE: REVISION: E-O REACTOR TRIP OR SAFETY INJECTION 9-17-2007 EOP Step ERG Step Sequence No. Pu~ose Pu~ose No significant deviation. Entry Cond Entry Cond No significant deviation. CAP Foldout Added Adverse Containment Criteria, and Charging Pump Recife Path Criteria to the Continuous Action Page (CAP). Added additional criteria to the.CAP which corresponds to continuous action steps in the procedure. The purpose of the CAP is to provide. assistance .to the operator to monitor continuous action steps. For NAPS adding these additional criteria is consistent with the purpose of the CAP. The Charging Pump Recirc Criteria addresses the engineering issue related to IE Compliance Bulletin 86-03. The addition the Adverse Containment Criteria was responding to a Validation Comment. Added CDA Actuation Criteria to CAP. CDA actuation criteria is a continuous action step in the procedure. Since the containment pressure may slowly .increase to the CDA setpoint (for certain size primary or secondary breaks), the setpoint may not have been reached at the time the step is read. Also, the step may be bypassed if containment pressure is low enough in the preceding step. Therefore, the information was added to the CAP to ensure it is available to the operator at any time during the procedure. (Reference DW-91-026) Added SI Flow Criteria to CAP. Upon 81 actuation, if cold leg HH8I flow not *indicated the operator is directed to the Attachment. Added to CAP to address operator feedback. Added Containment Recirc Mode Criteria to CAP. Caution regarding veT level added to CAP. This caution informs the operator that the VCT level should be greater than the level at which the charging pump suction automatically swaps to the RWST,. prior to transferring to recirculation mode. If VeT level is above this setpoint, then when (if) the operator later (during transfer to cold leg recirculation) closes the charging pump suction from the RWST valves (MOV-OI15B and D) they will not reopen due to a low VCT level signal. See NSA memo N8A-91042 and EFI-91-083. Added Rep Criteria to CAP. lA W the writer' s guide, information provided to the operator needed to prevent equipment damage shall be in the form of a caution. Because seal injection flow should be maintained to prevent Rep seal degradation, the information in the generic NOTE is more appropriate as a CAUTION. This caution was moved to the CAP during the Rev. 1C revision. Page 1 of20
NAPS EOP: TITLE: REVISION: E-O REACTOR TRIP OR SAFETY INJECTION 9-17-2007 EOP Step ERG Step Sequence No. 11 14 (5) Changed wording 'of high level step to "Check If CDA Is Required" rather than "Verify Containment Spray Not Required." The high level step wording was changed to eliminate the negative logic in the ERG step and to be consistent with plant specific nomenclature. The proper terminology at NAPS for containment spray is CDA (Containment Depressurization Actuation). " Added substeps to manually actuate CDA, initiate Attachment 2, verify CCW pumps are off, and stop RCPs. These substeps include actions that are contingent upon the containment spray setpoint being reached. Manually actuating CDA implements the North Anna plant policy to manually back-up all automatic safety functions. These functions include:
- a. Reactor trip
- b. Safety injection
- c. Phase A isolation
- d. Containment Spray
- e. Turbine trip Attachment 2, which verifies the Phase B isolation, should be initiated in this step. Since containment pressure isolates component cooling, a substep verifies that the component cooling pumps are tripped.
The RCPs should be stopped to avoid damage because component cooling has been isolated. Moved detailed verification of containment isolation to Attachment 2. Since there are numerous valves and equipment status to verify for the Phase B signal automatic actions, these verifications are more appropriate in an attached checklist. Including this information in the main body of the procedure would unnecessarily clutter the procedure. Included check of QS pumps running. These pumps auto start on CDA. Therefore, they are checked with the other automatic actuations. This step is designated as a continuous action step by placing an asterisk before the step number. (DW-91-026) ./ The NAPS EOPs explicitly identify continuous action steps while the ERGs identify continuous action steps in the knowledge section of the background documents. . Substep added to bypass next step. If CDA has been actuated then the next step which initiates 'containment spray at a lower containment pressure (for dose reduction considerations) is already completed, so it is bypassed. Page 70f20
NAPS EOP: TITLE: REVISION: E-O REACTOR TRIP OR SAFETY INJECTION 9-17-2007 Eor Step ERG Step Sequence No. RNO substep added to verify that the Service Water supply and return to Recirc Air Fans' is closed. This substep incorporates guidance from NRC GL. 96-06,' Assurance of Equipment Operability and Containment Integrity During Design Basis Accident Conditions. This substep ensures that SW supply will not automatically realign to the Recirc Air fans on reset .of CDA. This will prevent possible waterhammer damage to the Chilled Water System in containment and a challenge to the containment integrity if the SW system was aligned to the Containment Recirc Air Fans prior to the DBA. (
References:
NRC GL 96-06, CTS Item 02-96-1754-009, EOP Basis Document Change Nos.*99-001 and 99-002.) Substep added to initiate Attachment 3, Primary Plant Ventilation Alignment. If CDA has been actuated the operators perform this attachment to ensure that safeguards ventilation flows through the Auxiliary Building Iodine Filters during a*DBA event. 12 Added step to initiate quench spray. For primary break LOCAs that do not cause containment pressure to exceed <M.27> it has been shown that no fuel damage is expected, so that containment iodine is a not a concern. For larger breaks, it is prudent to initiate containment spray for dose reduction and to ensure iodine retention in the containment sump. Reference CTS 02-94-1204 item 001, Operating Experience Review PT21 93 S1, Westinghouse NSAL-93-016, and NSA memo # 93~ 172. This step is designated as a continuous action step by placing an asterisk before the step number. (DW-93-025) The NAPS EOPs explicitly identify continuous action steps while the ERGs identify continuous action steps in the knowledge section of the background documents. 13,Att 6 15, 18 (5) Generic steps 15 and 18 were compiled into step 13 and Attachment 6.. The revised format provides efficiencies for performing the actions. Art 6 is used to manually align SI if SI flow cannot be verified. Verification of charging pump valve alignment and low-head SI alignment was moved to an attachment. The attachment, "Verification of Phase A Isolation" has steps at the beginning of the attachment that verify the alignment of the charging pump suction valves, normal charging isolation valves, and the low-head 81 pump discharge and cold leg injection valves. The attachment is initiated earlyin the procedure and cannot be bypassed, therefore the valve alignments are checked each time the unit enters the procedure. Page 8*of20
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North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #26 (KIA 027 G2.2.42) Test Key Answer: "Maintain closed and maintain power to 1-RC-MOV-1536." One of the distractors for this question states the following: "Maintain closed and remove power from 1-RC-MOV-1536." The Test Key Answer is based on TS 3.4.11, Condition B, Action B.1 "One or more PORVs inoperable for reason other than Condition A and being capable of being manually cycled" This would be the case if the PORV were "inoperable and capable of being manually cycled (e.g., excessive seat leakage)" as stated in the TS Bases B 3.4.11 B.1. The given conditions of the question do not give positive confirmation of the status of the PORV after the valve was taken to close. In the absence of positive indication of the PORV and given that the question further states "RCS pressure is recovering at a much slower rate than expected", it would be reasonable to assume that the valve could in fact be partially open. In this case the aforementioned distractor (Action C.1 and C.2 of Condition C, "One PORV inoperable and not cabable of being manually cycled") would be correct. The question does not provide enough information to positively eliminate the possibility of the PORV being partially open, as opposed to only having excessive leak-by. Both choices are considered acceptable and correct.
References:
TS 3.4.11 and Bases
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)
LCO 3.4.11 Each PORV and associated block valve shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS - - - - - - - - - - - - - - - - NOTE - - - - - - - - - - - - - - - - Separate Condition entry is allowed for each PORV and each block valve. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more PORVs A.1 Restore backup 14 days inoperable due to nitrogen supply to inoperable backup OPERABLE status. nitrogen supply and capable of being manually cycled. B. One or more PORVs B.1 Close and maintain 1 hour inoperable for reason power to associated other than Condition A block valve. and capable of being manually cycled. C. One PORV inoperable C.1 Close associated block 1 hour and not capable of valve. being manually cycled. AND C.2 Remove power from 1 hour associated block valve. AND C.3 Restore PORV to 72 hours OPERABLE status. North Anna Units 1 and 2 3.4.11-1 Amendments 231/212
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs 3.4.11 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. One block valve -------------NOTE------------
inoperable. Required Action D.1 and D.2 do not apply when block valve is inoperable solely as a result of complying with Required Action C.2. D.1 Place associated PORV 1 hour in manual control. AND D.2 Restore block valve to 72 hours OPERABLE status. E. Required Action and E.1 Be in MODE 3. 6 hours associated Completion Time of Condition A, AND B, C, or D not met. E.2 Be in MODE 4. 12 hours F. Two PORVs inoperable F.1 Be in MODE 3. 6 hours and not capable of being manually cycled. AND F.2 Be in MODE 4. 12 hours North Anna Units 1 and 2 3.4.11-2 Amendments 231/212
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs 3.4.11 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME G. Two block valves G.1 ---------NOTE---------
inoperable. Required Action G.1 does not apply when block valve is inoperable solely as a result of complying with Required Action C.2. Restore one block 2 hours valve to OPERABLE status. H. Required Action and H.1 Be in MODE 3. 6 hours associated Completion Time of Condition G AND not met. H.2 Be in MODE 4. 12 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1 Verify PORV backup nitrogen supply pressure 7 days is within limit. SR 3.4.11.2 -------------------NOTES-------------------
- 1. Not required to be performed with block valve closed in accordance with the Required Actions of this LCO.
- 2. Only required to be performed in MODES 1 and 2.
Perform a complete cycle of each block 92 days valve. North Anna Units 1 and 2 3.4.11-3 Amendments 231/212
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs 3.4.11 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.3 --------------------NOTE-------------------
Only required to be performed in MODES 1 and 2. Perform a complete cycle of each PORV. 18 months SR 3.4.11.4 Perform a complete cycle of each solenoid 18 months control valve and check valve on the accumulators in PORV control systems. North Anna Units 1 and 2 3.4.11-4 Amendments 231/212
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs B 3.4.11 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) BASES BACKGROUND The pressurizer is equipped with two types of devices for pressure relief: pressurizer safety valves and PORVs. The PORVs are air or nitrogen operated valves that are controlled to open at a set pressure when the pressurizer pressure increases and close when the pressurizer pressure decreases. The PORVs may also be manually operated from the control room. Block valves, which are normally open, are located between the pressurizer and the PORVs. The block valves are used to isolate the PORVs in case of excessive leakage or a stuck open PORV. Block valve closure is accomplished manually using controls in the control room. A stuck open PORV is, in effect, a small break loss of coolant accident (LOCA). As such, block valve closure terminates the RCS depressurization and coolant inventory loss. The PORVs and their associated block valves may be used by unit operators to depressurize the RCS to recover from certain transients if normal pressurizer spray is not available. Additionally, the series arrangement of the PORVs and their block valves permit performance of surveillances on the valves during power operation. The PORVs may also be used for feed and bleed core cooling in the case of multiple equipment failure events that are not within the design basis, such as a total loss of feedwater. The PORVs, their block valves, and their controls are powered from the emergency buses that normally receive power from offsite power sources, but are also capable of being powered from emergency power sources in the event of a loss of offsite power. The PORVs are air operated valves and normally are provided motive force by the Instrument Air System. A backup, nitrogen supply for the PORVs is also available. Two PORVs and their associated block valves are powered from two separate safety trains (Ref. 1). The unit has two PORVs, each having a relief capacity of 210,000 lb/hr at 2335 psig. The functional design of the PORVs is based on maintaining pressure below the Pressurizer (continued) North Anna Units 1 and 2 B 3.4.11-1 Revision 0
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs B 3.4.11 BASES BACKGROUND Pressure-High reactor trip setpoint following a step (continued) reduction of 50% of full load with steam dump. In addition, the PORVs minimize challenges to the pressurizer safety valves and also may be used for low temperature overpressure protection (LTOP). See LCO 3.4.12, IILow Temperature Overpressure Protection (LTOP) System. 1I APPLICABLE Unit operators employ the PORVs to depressurize the RCS in SAFETY ANALYSES response to certain unit transients if normal pressurizer spray is not available. For the Steam Generator Tube Rupture (SGTR) event, the safety analysis assumes that manual operator actions are required to mitigate the event. A loss of offsite power is assumed to accompany the event, and thus, normal pressurizer spray is unavailable to reduce RCS pressure. The PORVs are assumed to be used for RCS depressurization, which is one of the steps performed to equalize the primary and secondary pressures in order to terminate the primary to secondary break flow and the radioactive releases from the affected steam generator.
The PORVs are also modeled in safety analyses for events that result in increasing RCS pressure for which departure from nucleate boiling ratio (DNBR) criteria are critical (Ref. 2). By assuming PORV actuation, the primary pressure remains below the high pressurizer pressure trip setpoint; thus, the DNBR calculation is more conservative. As such, this actuation is not required to mitigate these events, and PORV automatic operation is, therefore, not an assumed safety function. Pressurizer PORVs satisfy Criterion 3 of 10 CFR 50.36 (c) (2) (i i ) . LCO The LCO requires the PORVs and their associated block valves to be OPERABLE for manual operation to mitigate the effects associated with an SGTR. By maintaining two PORVs and their associated block valves OPERABLE, the single failure criterion is satisfied. An OPERABLE block valve may be either open and energized with the capability to be closed, or closed and energized with the capability to be opened, since the required safety function is accomplished by manual operation. Although typically open to allow PORV operation, the block valves may be OPERABLE when closed to isolate the flow path of an inoperable PORV (continued) North Anna Units 1 and 2 B 3.4.11-2 Revision 0
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs B 3.4.11 BASES LCO that is capable of being manually cycled (e.g., as in the (continued) case of excessive PORV leakage). Similarly, isolation of an OPERABLE PORV does not render that PORV or block valve inoperable provided the relief function remains available with manual action.
An OPERABLE PORV is required to be capable of manually opening and closing, and not experiencing excessive seat leakage. Excessive seat leakage, although not associated with a specific acceptance criteria, exists when conditions dictate closure of the block valve to limit leakage to within LCO 3.4.13, IIRCS Operational Leakage. 1I Satisfying the LCO helps minimize challenges to fission product barriers. APPLICABILITY In MODES 1, 2, and 3, the PORVs and their associated block valves are required to be OPERABLE to limit the potential for a small break LOCA through the flow path and for manual operation to mitigate the effects associated with an SGTR. The PORVs are also required to be OPERABLE in MODES 1, 2, and 3 for manual actuation to mitigate an SGTR event. Imbalances in the energy output of the core and heat removal by the secondary system can cause the ReS pressure to increase to the PORV opening setpoint. The most rapid increases will occur at the higher operating power and pressure conditions of MODES 1 and 2. Pressure increases are less prominent in MODE 3 because the core input energy is reduced, but the RCS pressure is high. Therefore, the LCO is applicable in MODES 1, 2, and 3. The LCO is not applicable in MODES 4, 5, and 6 with the reactor vessel head in place when both pressure and core energy are decreased and the pressure surges become much less significant. LCO 3.4.12 addresses the PORV requirements in these MODES. ACTIONS Note 1 has been added to clarify that all pressurizer PORVs are treated as separate entities, each with separate Completion Times (i.e., the Completion Time is on a component basis). North Anna Units 1 and 2 B 3.4.11-3 Revision 0
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs B 3.4.11 BASES ACTIONS A.1 (continued)
The PORVs are provided normal motive force by the Instrument Air system and have a backup nitrogen supply. If the backup nitrogen supply is inoperable, the PORVs are still capable of being manually cycled provided the Instrument Air system is available. The Instrument Air system is highly reliable and the likelihood of its being unavailable during a demand for PORV actuation is low enough to justify a 14 day Completion Time for return of the backup nitrogen supply to OPERABLE status. B.1 PORVs may be inoperable and capable of being manually cycled (e.g., excessive seat leakage). In this Condition, either the PORVs must be restored or the flow path isolated within 1 hour. The associated block valve is required to be closed, but power must be maintained to the associated block valve, since removal of power would render the block valve inoperable. This permits operation of the unit until the next refueling outage (MODE 6) so that maintenance can be performed on the PORVs to eliminate the problem condition. Quick access to the PORV for pressure control can be made when power remains on the closed block valve. The Completion Time of 1 hour is based on unit operating experience that has shown that minor problems can be corrected or closure accomplished in this time period. C.1, C.2, and C.3 If one PORV is inoperable and not capable of being manually cycled, it must be either restored, or isolated by closing the associated block valve and removing the power to the associated block valve. The Completion Time of 1 hour is reasonable, based on challenges to the PORVs during this time period, and provides the operator adequate time to correct the situation. If the inoperable valve cannot be restored to being capable of being manually cycled (permitting entry into Condition B), or OPERABLE status, it must be isolated within the specified time. Because there is one PORV that remains OPERABLE, an additional 72 hours is provided to restore the inoperable PORV to OPERABLE status. If the PORV cannot be restored within this additional time, the unit must be brought to a MODE in which the LCO does not apply, as required by Condition E. North Anna Units 1 and 2 B 3.4.11-4 Revision a
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs B 3.4.11 BASES ACTIONS D.1 and D.2 (continued)
If one block valve is inoperable, then it is necessary to either restore the block valve to OPERABLE status within the Completion Time of 1 hour or place the associated PORV in manual control. The prime importance for the capability to close the block valve is to isolate a stuck open PORV. Therefore, if the block valve cannot be restored to OPERABLE status within 1 hour, the Required Action is to place the PORV in manual control to preclude its automatic opening for an overpressure event and to avoid the potential for a stuck open PORV at a time that the block valve is inoperable. The Completion Time of 1 hour is reasonable, based on the small potential for challenges to the system during this time period, and provides the operator time to correct the situation. Because at least one PORV remains OPERABLE, the operator is permitted a Completion Time of 72 hours to restore the inoperable block valve to OPERABLE status. The time allowed to restore the block valve is based upon the Completion Time for restoring an inoperable PORV in Condition C, since the PORVs may not be capable of mitigating an event if the inoperable block valve is not full open. If the block valve is restored within the Completion Time of 72 hours, the PORV may be restored to automatic operation. If it cannot be restored within this additional time, the unit must be brought to a MODE in which the LCO does not apply, as required by Condition E. The Required Actions D.1 and D.2 are modified by a Note stating that the Required Actions do not apply if the sole reason for the block valve being declared inoperable is as a result of power being removed to comply with another Required Action. In this event, the Required Actions for inoperable PORV(s) (which require the block valve power to be removed once it is closed) are adequate to address the condition. While it may be desirable to also place the PORV(s) in manual control, this may not be possible for all causes of Condition C entry with PORV(s) inoperable and not capable of being manually cycled (e.g., as a result of failed control power fuse(s) or control switch malfunction(s).) E.1 and E.2 If the Required Action of Condition A, B, C, or D is not met, then the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours and to MODE 4 within (continued) North Anna Units 1 and 2 B 3.4.11-5 Revision 0
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs B 3.4.11 BASES ACTIONS E.1 and E.2 (continued) 12 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 4, automatic PORV OPERABILITY is required. See LCO 3.4.12.
F.1 and F.2 If more than one PORV is inoperable and not capable of being manually cycled, then the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours and to MODE 4 within 12 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 4, automatic PORV OPERABILITY is required. See LCO 3.4.12. G.1 If two block valves are inoperable, it is necessary to restore at least one block valve within 2 hours. The Completion Time is reasonable, based on the small potential for challenges to the system during this time and provide the operator time to correct the situation. The Required Action G.1 is modified by a Note stating that the Required Action does not apply if the sole reason for the block valve being declared inoperable is as a result of power being removed to comply with another Required Action. In this event, the Required Action for inoperable PORV (which requires the block valve power to be removed once it is closed) is adequate to address the condition. While it may be desirable to also place the PORV in manual control, this may not be possible for all causes of Condition C entry with PORV inoperable and not capable of being manually cycled (e.g., as a result of failed control power fusees) or control switch malfunction(s)). H.1 and H.2 If the Required Actions of Condition G are not met, then the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at (continued) North Anna Units 1 and 2 B 3.4.11-6 Revision 0
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs B 3.4.11 BASES ACTIONS H.l and H.2 (continued) least MODE 3 within 6 hours and to MODE 4 within 12 hours.
The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 4, automatic PORV OPERABILITY is required. See LCO 3.4.12. SURVEILLANCE SR 3.4.11.1 REQUIREMENTS SR 3.4.11.1 requires verification that the pressure in the PORV backup nitrogen system is sufficient to provide motive force for the PORVs to cope with a steam generator tube rupture coincident with loss of the containment Instrument Air system. The Frequency of 7 days is based on operating experience. SR 3.4.11.2 Block valve cycling verifies that the valve(s) can be opened and closed if needed. The basis for the Frequency of 92 days is the ASME Code (Ref. 3). This SR is modified by two Notes. Note 1 modifies this SR by stating that it is not required to be performed with the block valve closed, in accordance with the Required Actions of this LCO. Opening the block valve in this condition increases the risk of an unisolable leak from the RCS since the PORV is already inoperable. Note 2 modifies this SR to allow entry into and operation in MODE 3 prior to performing the SR. This allows the test to be performed in MODE 3 under operating temperature and pressure conditions, prior to entering MODE 1 or 2. SR 3.4.11.3 SR 3.4.11.3 requires a complete cycle of each PORV. Operating a PORV through one complete cycle ensures that the PORV can be manually actuated for mitigation of an SGTR. This testing is performed in MODES 3 or 4 to prevent possible RCS pressure transients with the reactor critical. The Frequency of 18 months is based on a typical refueling cycle and industry accepted practice. (continued) North Anna Units 1 and 2 B 3.4.11-7 Revision a
- NUCLEAR DESIGN INFORMATION PORTAL-Pressurizer PORVs B 3.4.11 BASES SURVEILLANCE SR 3.4.11.3 (continued)
REQUIREMENTS The Note modifies this SR to allow entry into and operation in MODE 3 prior to performing the SR. This allows the test to be performed in MODE 3 under operating temperature and pressure conditions, prior to entering MODE 1 or 2. SR 3.4.11.4 Operating the solenoid control valves and check valves on the accumulators ensures the PORV control system actuates properly when called upon. The Frequency of 18 months is based on a typical refueling cycle and the Frequency of the other Surveillances used to demonstrate PORV OPERABILITY. REFERENCES 1. Regulatory Guide 1.32, February 1977.
- 2. UFSAR, Section 15.4.
- 3. ASME Code for Operation and Maintenance of Nuclear Power Plants.
North Anna Units 1 and 2 B 3.4.11-8 Revision 0
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #28 (KIA 029 EK1.05) Test Key Answer: "Manual Turbine Trip" One of the distractors for this question states the following: "Automatic Control Rod Insertion" The Test Key Answer is based on analyzing the reactivity effects solely from the Transient Accident Analysis perspective and is correct in that regard. The question was intended to test the aforementioned knowledge which is why there is no mention of procedure FR-S.1 being in effect in the stem of the question. However the stem of the question begins with the words "During an ATWS", hence it must be acknowledged that the nature of this wording, along with the fact that all of the distractors are contained in the first 5 Steps of FR-S.l, makes it implicit that procedure FR-S.l is in effect. Thus 5 of the 13 candidates rationally concluded that they were expected to respond to the question in accordance with FR-S.1, although it was not specifically stated in the stem. All of the candidates who missed the question selected the distractor "Automatic Control Rod Insertion". Rev.2 of the ERGs provides for control rod insertion manually or automatically. As stated in the Background Document for Step 1 Knowledge and further emphasized in the Frequent Questions Section of the Background document leaving rods in auto for events involving a temperature rise will result ill rods stepping in auto faster than if manually inserted, thus adding negative reactivity at a faster rate. NAPS implements the strategy of leaving rods in auto and places them in manual only if they are stepping at a rate of 48 steps per minute or less (48 steps per minute is rod speed in manual). The Background Document for the step to initiate Emergency Boration states "After control rod trip and rod insertion functions, boration is the next most direct manner of adding negative reactivity to the core." The Background Document for the step that trips the Turbine states "The turbine is tripped to prevent an uncontrolled cooldown of the RCS due to steam flow that the turbine would require. For an ATWS event where a loss of normal feedwater has occurred, analyses have shown that a turbine trip is necessary (within 30 seconds) to maintain SG inventory." Students who answered the question with the mindset that they selecting a response based on procedure FR-S.1 and the associated Background Document, chose "Automatic Control Rod Insertion", which is correct.
North Anna RO/SRO NRC ILO Exam Test Item Comments Utilizing automatic rod insertion vice manually inserting control rods was a resent change to the ERGs and heavily emphasized during training, this further contributed to the mindset that the question was soliciting knowledge of procedure FR-S.l and the associated Background Document. Based on the aforementioned discussion it is concluded that both choices are considered acceptable and correct.
References:
I-FR-S.l & ERG Background document for FR-S.l
NORTH ANNA POWER STATION FUNCTION RESTORATION PROCEDURE NUMBER PROCEDURE TITLE REVISION 14 1-FR-S.1 RESPONSE TO NUCLEAR POWER GENERATION/ATWS (WITH FOUR ATTACHMENTS) PAGE 1 of 12 PURPOSE To provide instructions for adding negative reactivity to a core that is observed to be critical when expected to be shutdown. ENTRY CONDITIONS This procedure is entered from:
- 1-E-O, REACTOR TRIP OR SAFETY INJECTION, or
- Red or Orange terminus of the SUBCRITICALITY CSF STATUS TREE.
CONTINUOUS USE
NUMBER PROCEDURE TITLE REVISION 14 1-FR-S.1 RESPONSE TO NUCLEAR POWER GENERATION/ATWS PAGE 2 of 12 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: RCPs should not be tripped with Reactor power greater than 5%. 1 ]_ VERIFY REACTOR TRIP: o Verify or place control rods in AUTO. o a) Manually Trip Reactor b) Check the following: o
- Reactor Trip and Bypass Breakers -
OPEN o
- Rod Bottom Lights - LIT o
- Neutron flux - DECREASING 2 ]_ VERIFY TURBINE TRIP:
o a) Manually Trip Turbine o b) Verify all Turbine Stop Valves - CLOSED o b) Put both EHC Pumps in PTL. o IF Turbine is still NOT tripped, THEN manually run back Turbine. o IF Turbine cannot be run back, THEN close MSTVs and Bypass Valves. o c) Reset Reheaters o d) Verify Generator Output Breaker - OPEN o d) IF Generator Output Breaker does NOT open after 30 seconds, THEN manually open G-12 AND Exciter Field Breaker.
NUMBER PROCEDU RE TITLE REVISION 14 1-FR-S.1 RESPONSE TO NUCLEAR POWER GENERATION/ATWS PAGE 3 of 12 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 3 ]_ VERIFY CONTROL RODS - INSERTING o Manually insert control rods. IN AUTO AT GREATER THAN 48 STEPSI MINUTE
- 4. CHECK ALL AFW PUMPS - RUNNING o Manually start pumps.
G- INITIATE EMERGENCY BORATION OF RCS: o a) Verify at least one Charging Pump - o a) Start Charging Pumps as necessary. RUNNING b) Emergency borate: o 1) Put Boric Acid Transfer Pump in FAST o 2) Open 1-CH-MOV-1350, Emergency Borate Valve (STEP 5 CONTINUED ON NEXT PAGE)
NUMBER PROCEDURE TITLE REVISION 14 1-FR-S.1 RESPONSE TO NUCLEAR POWER GENERATION/ATWS PAGE 4 of 12 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
- 5. INITIATE EMERGENCY BORATION OF RCS: (Continued) c) Verify adequate negative reactivity c) Inject the BIT:
insertion:
- 1) Open Charging Pump Suction From D
- Emergency boration - FLOW RWST Isolation Valves:
INDICATED AND o
- 1-CH-MOV-1115B D
- 1-CH-MOV-1115D o
- Control Rods - MOVING IN OR FULLY INSERTED
- 2) Close Charging Pump Suction From AND VCT Isolation Valves:
D
- Neutron flux - DECREASING o
- 1-CH-MOV-1115C D
- 1-CH-MOV-1115E
- 3) Close BIT Recirc Valves:
D
- 1-SI-TV-1884A D
- 1-SI-TV-1884B o
- 1-SI-TV-1884C (STEP 5 CONTINUED ON NEXT PAGE)
NUMBER PROCEDURE TITLE REVISION 14 1-FR-S.1 RESPONSE TO NUCLEAR POWER GENERATION/ATWS PAGE 5 of 12 ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED
- 5. INITIATE EMERGENCY BORATION OF RCS: (Continued)
- 4) Open BIT Outlet Valves:
0
- 1-SI-MOV-1867C 0
- 1-SI-MOV-1867D
- 5) Open BIT Inlet Valves:
0
- 1-SI-MOV-1867A 0
- 1-SI-MOV-1867B
- 6) Close Letdown Valves:
0
- 1-CH-HCV-1200A 0
- 1-CH-HCV-1200B 0
- 1-CH-HCV-1200C 0
- 1-CH-LCV-1460A 0
- 1-CH-LCV-1460B
- 7) Close Normal Charging Line Isolation Valves:
0
- 1-CH-MOV-1289A 0
- 1-CH-MOV-1289B 0 d) Check PRZR pressure - LESS THAN 0 d) Verify PRZR PORVs and Block Valves 2335 PSIG are open.
0 IF NOT, THEN open PRZR PORVs and Block Valves as necessary until PRZR pressure is less than 2335 psig.
STEP DESCRIPTION TABLE FOR FR-S.1 Step 1__ STEP: Verify Reactor Trip PURPOSE: To ensure that the reactor has tripped BASIS: Reactor trip must be verified to ensure that the only heat being added to the RCS is from decay heat and reactor coolant pump heat. The safeguards systems that protect the plant during accidents are designed assuming that only decay heat and pump heat are being added to the RCS. If the reactor cannot be tripped, then the control rods should be manually inserted into the core in order to decrease reactor power. ACTIONS: o Determine if the reactor has tripped o Determine if the reactor will not trip o Trip the reactor o Manually insert control rods INSTRUMENTATION: o Control rod position indications o Reactor trip and bypass breaker position indications o Neutron flux indication CONTROL/EQUIPMENT: o Switches to manually trip the reactor o Switch to select rod control mode o Switch to manually insert control rods KNOWLEDGE: If RCS temperature has increased above the current reference temperature, then the rods should automatically be driven in by the Rod Control System. This action satisfies the intent of the contingency requirement. PLANT-SPECIFIC INFORMATION: N/A FR-S.l Background 76 HP-Rev. 2, 4/30/2005 HFRSIBG.doc
STEP DESCRIPTION TABLE FOR FR-S.l Step -f-STEP: Verify Turbine Trip PURPOSE: To ensure that the turbine is tripped BASIS: The turbine is tripped to prevent an uncontrolled cooldown of the RCS due to steam flow that the turbine would require. For an ATWS event where a loss of normal feedwater has occurred, analyses have shown that a turbine trip is necessary (within 30 seconds) to maintain SG inventory. If the turbine will not trip, a turbine runback (manual decrease in load) at maximum rate will also reduce steam flow in a delayed manner. If the turbine stop valves cannot be closed by either trip or runback, the MSIVs should be closed. ACTIONS: o Determine if all turbine stop valves are closed o Determine if turbine will not trip o Determine if turbine cannot be run back o Trip the turbine o Manually run back turbine o Close main steamline isolation and bypass valves INSTRUMENTATION: o Turbine stop valve position indication o MSIVs and bypass valves position indication CONTROL/EQUIPMENT: o Switches for turbine trip (e.g. manual trip buttons, overspeed test switch, EH control oil pump switches) o Controls to manually run back turbine o Switches to close MSIVs and bypass valves FR-S.l Background 77 HP-Rev. 2, 4/30/2005 HFRSIBG.doc
STEP DESCRIPTION TABLE FOR FR-S.l Step _2_ KNOWLEDGE: A turbine trip is required for an ATWS event where a loss of main feedwater has occurred. For other ATWS events, with the exception of when a turbine trip is the initiating event, manual tripping of the turbine may yield a somewhat higher system pressure, depending on the initiating event and time in core life, than what would otherwise be expected. However, this action has been determined to be necessary due to the analytical results presented and discussed in subsections 2.4, ATWS Analysis and Results, and 2.5, Discussion of Analytical Results. Since there are many initiating ATWS events and some that require immediate mitigating actions, diagnosis of the initiating event would not be feasible and separate guidance for different ATWS events would complicate training and could delay timely performance of necessary operator actions. PLANT-SPECIFIC INFORMATION: N/A FR-S.l Background 78 HP-Rev. 2, 4/30/2005 HFRSIBG.doc
STEP DESCRIPTION TABLE FOR FR-S.l Step 3__ STEP: Check AFW Pumps Running PURPOSE: To ensure AFW pumps are running BASIS: The MD AFW pumps start automatically on an SI signal and SG low level to provide feed to the SGs for decay heat removal. If SG levels drop below the appropriate setpoint, the turbine-driven AFW pump will also automatically start to supplement the MD pumps. The ATWS analyses have shown that actuation of AFW within 60 seconds after the failure to scram provides acceptable results. ACTIONS: o Determine if MD AFW pumps are running o Determine if the turbine-driven AFW pump is running if necessary o Start MD AFW pumps o Open steam supply valves to turbine-driven AFW pump INSTRUMENTATION: o MD AFW pumps status indication o Turbine-driven AFW pump status indication o Turbine-driven AFW pump steam supply valve position indication CONTROL/EQUIPMENT: Switches for: o MD AFW pumps o Turbine-driven AFW pump steam supply valves KNOWLEDGE: N/A PLANT-SPECIFIC INFORMATION: N/A FR-S.l Background 79 HP-Rev. 2, 4/30/2005 HFRSIBG.doc
STEP DESCRIPTION TABLE FOR FR-S.l Step 4__ STEP: Initiate Emergency Boration of RCS PURPOSE: To add negative reactivity to bring the reactor core subcritical BASIS: After control rod trip and rod insertion functions, boration is the next most direct manner of adding negative reactivity to the core. The intended boration path here is the most direct one available, not requiring SI initiation, but using normal charging pump(s). Pump miniflow lines are assumed to be open to protect the pumps in the event of high RCS pressure. Several plant specific means are usually available for rapid boration and should be specified here in order of preference. Methods of rapid boration include emergency boration, injecting the BIT, and safety injection actuation. It should be noted that SI actuation will trip the main feedwater pumps. If this is undesirable, the operator can manually align the system for safety injection. However, the RWST valves to the suction of the SI pumps should be opened first before opening up the BIT valves. If a safety injection is already in progress but is having no effect on nuclear flux, then the BIT and RWST are not performing their intended function, perhaps due to blockage or leakage. In this case some other alignment using the BATs and/or non-safeguards charging pump(s) is required. The check on RCS pressure is intended to alert the operator to a condition which would reduce charging or SI pump injection into the RCS and, therefore, boration. The PRZR PORV pressure setpoint is chosen as that pressure at which flow into the RCS is insufficient. The contingent action is a rapid depressurization to a pressure which would allow increased injection flow. When primary pressure drops 200 psi below the PORV pressure setpoint, the PORVs should be closed. The operator must verify successful closure of the PORVs, closing the isolation valves, if necessary. FR-S.l Background 80 HP-Rev. 2, 4/30/2005 HFRSIBG.doc
STEP DESCRIPTION TABLE FOR FR-S.l Step _4_ ACTIONS: o Determine if PRZR pressure is less than (A.02) psig o Determine if PRZR PORVs and block valves are open o Start charging/SI pumps o Start PD pump o Align boration path o Align charging flow path o Open PRZR PORVs and block valves as necessary until PRZR pressure is less than (A.OB) psig INSTRUMENTATION: o Charging/SI pump(s) status indication o PD pump status indication o Position indication for charging path valves, boration path valves o PRZR pressure indication o PRZR PORV and block valve position indications CONTROL/EQUIPMENT: o Charging/SI pump(s) switches o PD pump switch o Switches for charging path valves/boration path valves o PRZR PORVs and block valves switches KNOWLEDGE: N/A PLANT-SPECIFIC INFORMATION: o (A.02) PRZR PORV pressure setpoint. o (A.OB) 200 psi less than PRZR PORV pressure setpoint. o Preferred alignments for emergency boration based on plant equipment and operating practices. FR-S.1 Background 81 HP-Rev. 2, 4/30/2005 HFRSIBG.doc
- 5. FREQUENT QUESTIONS The following are questions which have been frequently asked about FR-S.1, RESPONSE TO NUCLEAR POWER GENERATION/ATWS:
Q. If the ATWS event results in rising RCS temperatures, why are the control rods inserted manually? Auto rod control would be faster. A. For those events which involve rising temperatures, it is true that leaving the rod control system in AUTOMATIC will cause rods to drive in at 72 steps per minute (assuming the turbine is tripped and reference temperature is no-load) compared to the 48 steps per minute speed in MANUAL. In this combination of circumstances, the AUTOMATIC function satisfies the intent of this step. However, for other ATWS events, rod insertion in MANUAL will be required. Q. What is the expected ERG usage if SI is actuated to implement the IIEmergency Boration?1I A. Assuming that the reactor is promptly shut down due to the boration, the operator is returned to the guideline and step in effect. For an ATWS, this is E-O, REACTOR TRIP OR SAFETY INJECTION, Step 1, where the operator must recognize that the equivalent ofa trip has been implemented, and the reactor is shut down. He would then proceed in E-O, terminate the SI as spurious using ES-1.1, and then transition to some normal plant procedure. If entry to FR-S.1 is due to a return-to-power following reactor trip without SI actuation, then the transition would be back to ES-O.1, REACTOR TRIP RESPONSE, at the appropriate step. However, a CAUTION at the front of ES-0.1 states IIlf SI actuation occurs during this guideline, E-O, REACTOR TRIP OR SAFETY INJECTION, should be performed ll So the operator would go to E-O, and terminate the SI as spurious, just as above. If entry to FR-S.1 is based on Status Tree diagnosis during a normal plant shutdown/cooldown, the SI actuation implies entry to E-O once FR-S.1 is completed. FR-S.1 Background 109 HP-Rev. 2, 4/30/2005 HFRS1BG.doc
Q. Why is the turbine tripped for all ATWS events regardless of whether this action may degrade Res conditions for particular ATWS events? A. Analyses have shown that a turbine trip is required for an ATWS event where a loss of main feedwater has occurred. For other ATWS events, with the exception of when a turbine trip is the initiating event, manual tripping of the turbine may yield a somewhat higher system pressure, depending on the initiating event and time in core life, than what would otherwise be expected. However, since there are many initiating ATWS events and some that require immediate mitigating actions, diagnosis of the initiating event would not be feasible and separate guidance for different ATWS events would complicate training and could delay timely performance of necessary operator actions. Therefore, guideline FR-S.l contains immediate actions for tripping the reactor and tripping the turbine. FR-S.1 Background 110 HP-Rev. 2, 4/30/2005 HFRS1BG.doc
- 6. REFERENCES
- 1) Westinghouse Electric Corporation, Westinghouse Anticipated Transients Without Trip Analysis, WCAP-8330, August 1974.
- 2) Letter from T. M. Anderson to S. H. Hanauer, Anticipated Transients Without SCRAM for Westinghouse Plants, NS-TMA-2182, December 30, 1979.
- 3) Memorandum from W. J. Dircks to NRC Commissioners, Amendments to 10CFR50 Related to Anticipated Transients Without Scram (ATWS) Events, SECY-83-293, July 19, 1983.
- 4) T.W.T. Burnett, J. C. McIntyre, J. C. Baker, LOFTRAN Code Description, WCAP-7907 (NES Class 3), October 1972.
-OR-L. A. Campbell, LOFTRAN Code Description, WCAP-7878 Rev. 3 (Proprietary Class 2), January 1977.
FR-S.1 Background 111 HP-Rev. 2, 4/30/2005 HFRS1BG.doc
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #43 (KIA 061 G2.4.3) Test Key Answer: "SAFEIRESET green light on drawers LIT; UNIT I CONT HI RANGE RADIATION TROUBLE annunciator received on Unit 2." One of the distractors for this question states the following: .~'SAFEIRESET green light on drawers NOT LIT; UNIT 1 CONT HI RANGE RADIATION TROUBLE annunciator received on Unit 2.'~ The difference between the test key answer and the distractor listed above is the status of the SAFEIRESET green light on the monitor drawer during the conditions listed in the question stem (actual high radiation condition). During such conditions, the annunciator status and the status of the amber and red lights would be the determining factors of the condition of the monitor. In this case, an illuminated SAFEIRESET green light would only provide indication of power to the monitor drawer, redundant to the illuminated amber and red lights. The status of the SAFEIRESET green light is irrelevant during the plant conditions given in the question stem. It requires knowledge of a specific aspect of the light indication that is inconsequential during the proposed conditions. Knowledge at the level of detail required by the question is above that which is required for proper identification and response of the monitor to a high radiation condition. Since the knowledge of this specific aspect of the SAFEIRESET green light is above that required for validation and response to the high radiation conditions stated in the question stem, both choices are considered acceptable and correct.
References:
2A-B3, UNIT 1 CONT HI RANGE RADIATION TROUBLE
VIRGINIA POWER 2-EI-CB-21A ANNUNCIATOR B3 2-AR-A-B3 NORTH ANNA POWER STATION REV. 2 APPROVAL: ON FILE Effective Date:l0/22/01 UNIT 1 CONT HI RANGE RADIATION TROUBLE 1.0 Probable Cause 1.1 Containment radiation level 21.63 x 1000 R/hr (Alert) 1.2 Containment radiation level 21.4 x 10000 R/hr (High) 1.3 Instrument failure 1.4 Green "Reset" light bulb burned out 2.0 Operator Action 2.1 Determine cause of alarm from control room indication. 2.2 IF due to fail~re of either l-RMS-RM-165 or l-RMS-RM-166, THEN refer to O-LOG-6A for alternate preplanned actions AND enter into Action Statement Status Log. 2.3 IF due to high radiation level, THEN notify Shift Supervisor. 2.4 Replace light bulb with correct bulb. Bulb is "keyed" to be inserted correctly in only one direction. 3.0 References 3.1 DC 80-S35C 3.2 Instrument cal. procedure 3.3 Unit One Tech. Spec. 3.3.3.1 (ITS 3.3.1) 3.4 O-LOG-6A r Backboards Log 4.0 Actuation 4.1 l-RMS-RM-165 (0) 4.2 l-RMS-RM-166 (P)
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #50 (KIA 071 A2.02) O-OP-23.2 P&L 4.13 states that "It is preferred to operate 1-GW-FCV-101 in AUTO control to maintain flow < 3 scfm. IF Manual control is required, THEN it is to only be done with SRO permission." This test item asks for the preferred method for controlling flow rate lAW the procedure. However, the procedure steps that initiate the release are as follows:
- a. NotifyH.P. Dept tID-at \VGD'T' Release is starting.
- b. Ensure I-GVl-FC\l-lOl controller, CHARFILTmFM DECAY TKS CONT:~detmmd is O~~:.
- c. Push l'v10DULAT'E 'button. for I-G\\r-FC\l-lOl, WGDT TO:PROCES,S
\lENT~
NO"TE: It is, preferred to operate I-GVi'-FC'l-lOl in. AUTO control to maintain flow .r:;: 3 SCFM~ IF Matiua] control is required, THEN it is to only be done with SRO: permission, (Reference l.4.3)
- d. Adj111St I-GVl-FC'\l-l 0;1 Controller to obtaindesired flow, BlJT NOT to exceed. maximum flowon HP Release form,
- e. Place I-GW-FC\l"-l{}l in AUTO, and verify proper operation, (Refel"euce :2.",4~3)
Step 5.4.11.b is accomplished by placing the controller in MANUAL and reducing the demand to 0%. Depressing MODULATE in step 5.4.11.c enables the FCV to be opened. Step 5.4.11.d is accomplished by increasing controller demand with the controller in MANUAL. This is done very slowly while monitoring the process vent radiation monitor to prevent an auto-isolation of the release. When the maximum flow rate is achieved (based on maintaining an acceptable margin to the process vent RIM high radiation alarm), only then is the 1-GW-FCV-101 controller placed in AUTO. The answer key is incorrect, and there is no correct answer. This item should be deleted.
References:
O-OP-23.2
DOMINION O-OP-23.2 North Anna Power Station Revision 17 Page 8 of 64 4.12 Any significant increase in oxygen concentration of the inservice WGDT shall be investigated and actions taken to correct deficiencies. 4.13 It is preferred to operate 1-GW-FCY-101 in AUTO control to maintain flow
< 3 SCFM. IF Manual control is required, THEN it is to only be done with SRO permission. (Reference 2.4.3) 4.14 IF purging or venting of a unit's reactor vessel head pressurizer or PRT is in progress, THEN consideration should be given to delaying the release of 'A' or 'B' WGDT. Performing these evolutions simultaneously in the past has caused the auto functions associated with 1-GW-RI-178, Process Vents Rad Mon, to actuate on numerous occasions. (Reference 2.4.4) 4.15 Performance of Section 5.21 will deadhead each GW compressor against its associated discharge diaphragm valve.
4.16 During performance of Section 5.21, constant communication between the Fuel Building and MCR should be established. 4.17 In the event of a diaphragm rupture of 1-GW-69 or 1-GW-72, the WGDT(s) can be isolated from input by closing 1-GW-73 and 1-GW-74.
DOMINION O-OP-23.2 North Anna Power Station Revision 17 Page 19 of 64 5.4 Placing I-GW-TK-IB Waste Gas Decay Tank on Bleed 5.4.1 Verify Initial Conditions are satisfied. 5.4.2 Review Precautions and Limitations. CAUTION IF purging or venting of a unit's reactor vessel head, pressurizer, or PRT is in progress, THEN consideration should be given to delaying the release of 'A' or 'B' WGDT. Performing these evolutions simultaneously in the past has caused the auto functions associated with 1-GW-RI-178, Process Vents Rad Mon, to actuate on numerous occasions. NOTE: A numbered radioactive waste discharge record must be initiated by Health Physics Department or Operations Department before any waste is discharged. ALL numbered forms must be accounted for, even those that may have to be voided. NOTE: Tank should be held as long as possible to allow for radioactive decay. 5.4.3 Initiate a HP form "Waste Gas Decay Tank Release Record" and forward to Health Physics. 5.4.4 Verify the Process Vent System is in operation. 5.4.5 Verify that Process Vent MGP Radiation Monitors operable:
- a. 1-GW-RI-178-1, Process Vent RM Noble Gas Normal:
- operate light - LIT
- test light - NOT LIT
- alert, high and HIH lights - NOT LIT
- Display operable
DOMINION 0-OP-23.2 North Anna Power Station Revision 17 Page 20 of 64
- b. I-GW-RI-178-2, Process Vent RM Noble Gas Accident:
- operate light - LIT
- test light - LIT
- alert and high lights - NOT LIT
- Display operable
- c. Unit 2 Annunciator Panel B-C5, PROCESS VENT VNT STACK A&B RAD MONITORS FAILURE - NOT LIT 5.4.6 Verify I-GW-FCV-IOl, CHAR FILT IN PM DECAY TKS CONT, is closed.
5.4.7 Check closed I-GW-TK-IA outlet valves:
- I-GW-15, lA Waste Gas Decay Tk To Pres Vent/Surge Drum Isol
- I-GW-16, lA Waste Gas Decay Tank To Process Vent Isol Vv NOTE: The recirculation concentrated high activity gases which could be released through leaks in the recirculating path must be minimized.
5.4.8 Check closed I-GW-30, IB Waste Gas Decay Tank Recirc To Surge Drum Iso1. NOTE: SRO authorizes clearance of tagout issued in Section 5.6 of this procedure. 5.4.9 Open I-GW-TK-IB outlet valves to Process Vent System:
- a. I-GW-28, IB Waste Gas Decay Tk To Pres Vent/Surge Drum Isol
- b. I-GW-29, IB Waste Gas Decay Tk To Process Vent Isol Valve
DOMINION O-OP-23.2 North Anna Power Station Revision 17 Page 21 of 64 NOTE: Gaseous waste activity shall be continuously monitored and recorded while releasing WGDT. 5.4.10 Do the following:
- a. Record the Waste Gas Decay Tank Release Permit Number: _
- b. Ensure the following recorders are in operation and mark the recorders with date, time, tank I-GW-TK-IB, and the Waste Gas Decay Tank Release Permit Number:
- I-GW-FR-I0l, Char Fltr Inlet Flow PM Decay Tks Recorder
- I-MM-SR-I02, Wind Speed Recorder
- I-MM-ZR-I02, Wind Direction Recorder
- c. Do the following for l-RM-RR-178, Process Vent RM Activity and Release Rate Recorder:
- 1. Ensure l-RM-RR-178, Radiation Recorder is in operation.
- 2. Open Soft Key access door (left pull slot).
- 3. Press the "FUNC" key to display blue functions on the screen.
- 4. Press the key under the "MESSAGE" blue function displayed on the screen.
DOMINION O-OP-23.2 North Anna Power Station Revision 17 Page 22 of 64 NOTE: Using the DISPLAYIENTER button and Arrow Keys to display trends on the recorder will display the message on recorder screen, when MESSAGE is entered.
- 5. Press the key one time under the "MESSAGE 3" blue function sv displayed on the screen to mark the recorder with "1-GW-TK-IB START", date and time.
- d. Make a narrative log entry addressing start of I-GW-TK-IB release with the Waste Gas Decay Tank Release Permit Number.
5.4.11 Release WGDT as follows:
- a. Notify H.P. Dept. that WGDT'Release is starting.
- b. Ensure I-GW-FCV-I0l controller, CHAR FILT IN FM DECAY TKS CONT, demand is 0%.
- c. Push MODULATE button for I-GW-FCV-I0l, WGDT TO PROCESS VENT.
NOTE: It is preferred to operate I-GW-FCV-I0l in AUTO control to maintain flow < 3 SCFM. IF Manual control is required, THEN it is to only be done with SRO permission. (Reference 2.4.3)
- d. Adjust I-GW-FCV-I0l Controller to obtain desired flow, BUT NOT to exceed maximum flow on HP Release form.
- e. Place I-GW-FCV-I0l in AUTO, and verify proper operation.
(Reference 2.4.3) 5.4.12 WHEN pressure in the tank reaches approximately 10 psig as indicated on I-GW-PI-I09C or when directed by the SRO, THEN do the following:
- a. Close I-GW-29, IB Waste Gas Decay Tk To Process Vent Isol Valve.
DOMINION O-OP-23.2 North Anna Power Station Revision 17 Page 23 of 64
- b. Close 1-GW-28, 1B Waste Gas Decay Tk To Pres Vent/Surge Drum Iso!.
- c. WHEN 1-GW-PI-103 indicates zero, THEN place the controller for 1-GW-FCV-101, CHAR FILT IN PM DECAY TKS CONT, to Manual and reduce demand to 0%.
- d. Depress the CLOSE pushbutton for 1-GW-FCV-101, WGDT TO PROCESS VENT.
- e. Verify 1-GW-FCV-101 is closed.
5.4.13 Do the following:
- a. Mark completion date, time and tank 1-GW-TK-1B, on the recorders that were marked at the start of the release:
- 1-GW-FR-101, Char Fltr Inlet Flow PM Decay Tks Recorder
- 1-MM-SR-102, Wind Speed Recorder
- 1-MM-ZR-102, Wind Direction Recorder
- b. Do the following for 1-RM-RR-178, Process Vent RM Activity and Release Rate Recorder:
- 1. Open Soft Key access door (left pull slot).
- 2. Press the "FUNC" key to display blue functions on the screen.
- 3. Press the key under the "MESSAGE" blue function displayed on the screen.
DOMINION O-OP-23.2 North Anna Power Station Revision 17 Page 24 of 64 NOTE: Using the DISPLAYIENTER button and Arrow Keys to display trends on the recorder will display the message on recorder screen, when MESSAGE is entered.
- 4. Press the key one time under the "MESSAGE 4" blue function sv displayed on the screen to mark the recorder with "1-GW-TK-1B STOP", date and time.
- c. Mark a narrative log entry addressing stop of 1-GW-TK-1B release.
5.4.14 Complete the discharge release record form. Date: _
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #53 (KIA 076 A1.02) The question stem explains that the crew verified a BC pump running, so steps 1 and 2 of 1-AP-19, Loss of Bearing Cooling Water, are complete. Step 3 is to verify BC system is operating in tower-to-tower. This is the normal system alignment, so the test item does not specify system alignment. (Lake-to-lake alignment is rarely used.) The applicant is assumed to answer step 3 as YES and continue. Step 4.a verifies BC system intact (YES) and step 4.b verifies BC tower level normal (YES). Step 4.c verifies BC tower fans running. If the applicant answers NO based on the initial conditions (one fan is in standby-not running) he/she would be incorrect, because the RNO directs using Attachment 2, Actions for loss of cooling fans. The intent of the attachment is to start fans that were previously running, as evidenced by step 1, Monitor the following temperatures while attempting to restart the Bearing Cooling Fans. Nowhere in the attachment does the operator receive direction to "shift fans to high speed." Step 4.c also gives the option of swapping BC system from tower-to-tower alignment to lake-to-lake alignment. This would be uncalled for since nothing in the question indicates that the standby fan is not available for operation, or that any of the fans are not available for operation in FAST speed. That said, the initial conditions state that annunciator 1A-F4, BASIN TEMP HVLOW, is LIT. This is an entry condition for 1-AP-19, but it also is the only procedural guidance referenced that directs starting additional fans or placing fans in FAST speed as required (AR step 2.7). These actions were selected as the correct response. However, during exam review with the NRC, the stem was revised to include the words "in accordance with 1-AP-19." Since 1-AP-19 does not directly require the operator to shift fans to FAST speed, the applicants could select the correct answer based on the fact that the annunciator response is an entry condition to the AP and would normally be performed in parallel with the AP by the backboards operator. (The BC fan controls are located on the backboard panels.) The initial conditions also state that annunciator 1T-C1, HYDROGEN TEMP OR CORE MONITOR, is LIT. This is also an entry condition for 1-AP-19, and it is the only procedural guidance referenced that directs reducing unit load to clear the alarm. Since 1-AP-19 does not directly require the operator to reduce unit load, the applicants could select "Verify Generator Hydrogen temperature is above the alarm setpoint and initiate a plant load reduction until the alarm is clear" based on the fact that the annunciator response is an entry condition to the AP and would normally be performed in parallel with the AP. Finally, annunciator 1T-C1, HYDROGEN TEMP OR CORE MONITOR, is the only procedural guidance referenced that directs controlling BC flow to hydrogen coolers (AR step 2.2.b). Since 1-AP-19 does not directly require the operator to control BC flow to the hydrogen coolers, the applicants could select "Bypass 1-BC-TCV-104, Generator Hydrogen Cooler TCV, to lower hydrogen temperature," based on the fact that the annunciator response is an entry condition to the AP and would normally be performed in parallel with the AP.
North Anna RO/SRO NRC ILO Exam Test Item Comments Since the ARs would normally be performed in parallel with the AP, and three of the choices could actually be performed simultaneously (depending on shift resources), some of the applicants were confused by the stem asking the initial action required. The question potentially has three correct answers, which would require that it be deleted.
References:
l-AP-19, Loss of Bearing Cooling Water lA-F4, BASIN TEMP HI/LOW IT-Cl, HYDROGEN TEMP OR CORE MONITOR
VIRGINIA POWER NORTH ANNA POWER STATION ABNORMAL PROCEDURE NUMBER PROCEDURE TITLE REVISION l-AP-19 LOSS OF BEARING COOLING WATER 16 PAGE (WITH TWO ATTACHMENTS) 1 of 7 PURPOSE To provide instructions to follow in the event that Bearing Cooling Water Flow is lost OR all Bearing Cooling Tower fans have tripped. ENTRY CONDITIONS This procedure is entered when any of the following conditions exist:
- Bearing Cooling Pump motor amps are low or erratic, or
- Increasing temperatures on components cooled by Bearing Cooling, or
- Computer alarms on components cooled by Bearing Cooling, or
- Annunciator Panel "A" F-3, BASIN LEVEL HI/LO, is LIT or
- Annunciator Panel "A" F-4, BASIN TEMP HI/LO, is LIT or
- Annunciator Panel "A" H-S, MORE THAN ONE BC PP RUNNING, is LIT or
- Annunciator Panel "F" F-4, BC WTR PP lA-lB AUTO TRIP SYS MISALIGNED, is LIT or
- Annunciator Panel "F" E-4, BC WTR DISCHG HDR LO PRESS, is LIT or
- Annunciator Panel "F" D-4, BC WTR SUCT HDR LO PRESS, is LIT or
- Annunciator Panel "T" C-l, HYDROGEN TEMPERATURE HIGH OR CORE MONITOR, is LIT.
RECOMMENDED APPROVAL: DATE EFFECTIVE RECOMMENDED APPROVAL - ON FILE DATE APPROVAL: DATE APPROVAL - ON FILE
NUMBER PROCEDURE TITLE REVISION 16 1-AP-19 LOSS OF BEARING COOLING WATER PAGE 2 of 7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED [ 1] __ CHECK STATUS OF BEARING COOLING Start standby Bearing Cooling Pump. SYSTEM a) One Bearing Cooling Pump - OPERATING b) Bearing Cooling Pump Amps - NORMAL
- 2. VERIFY AT LEAST ONE BEARING IF Bearing Cooling cannot be COOLING PUMP SUPPLYING SYSTEM restored, THEN GO TO 1-E-O, REACTOR TRIP OR SAFETY INJECTION, a) Pump - OPERATING while continuing with this procedure.
b) Amps - NORMAL GO TO Step 9.
- 3. VERIFY BEARING COOLING SYSTEM GO TO Step 5.
OPERATING TOWER-TO-TOWER
- 4. VERIFY TOWER-TO TOWER BEARING COOLING SYSTEM OPERATION - NORMAL a) Bearing Cooling System - INTACT a) Initiate O-AP-39.1, TURBINE BUILDING FLOODING, while continuing with this procedure.
b) Bearing Cooling Tower Level - b) Restore tower level using NORMAL 1-0P-50.2, OPERATION OF THE BEARING COOLING WATER SYSTEM. c) Bearing Cooling Tower Fans - c) Restore Bearing Cooling Tower RUNNING Fans using Attachment 2, ACTIONS FOR LOSS OF COOLING FANS OR initiate 1-0P-50.2, OPERATION OF THE BEARING COOLING WATER SYSTEM, section for Shifting from Tower-to-Tower to Lake-to-Lake. d) GO TO STEP 6
NUMBER PROCEDURE TITLE REVISION 16 1-AP-19 LOSS OF BEARING COOLING WATER PAGE 3 of 7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
- 5. VERIFY LAKE-TO-LAKE BEARING COOLING SYSTEM OPERATION - NORMAL a) Bearing Cooling System - INTACT a) Initiate 0-AP-39.1, TURBINE BUILDING FLOODING, while continuing with this procedure.
b) NPSH available: b) Initiate 1-AP-13, LOSS OF ONE OR MORE CIRCULATING WATER
- 1-WT-P-25, Auxiliary Flash PUMPS, while continuing with Evaporator Pump - RUNNING this procedure.
- Circ Water Intake Tunnel Full
- LIGHT LIT
- At least one Circulating Water Pump - RUNNING
- 6. MONITOR MAIN GENERATOR WHEN the AR instructs tripping the TEMPERATURES - NORMAL Unit, THEN GO TO 1-E-0, REACTOR TRIP OR SAFETY INJECTION, while
- Annunciator Panel "T" C-1, continuing with this procedure.
HYDROGEN TEMPERATURE HIGH OR CORE MONITOR - NOT LIT GO TO Step 9.
- Annunciator Panel "K" B-7, GEN LEADS COOLING TRBL - NOT LIT
- Local temperatures at generator leads bus ducting - LESS THAN 120 C 0
NUMBER PROCEDURE TITLE REVISION 16 1-AP-19 LOSS OF BEARING COOLING WATER PAGE 4 of 7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
- 7. SEND AN OPERATOR TO VERIFY THE GO TO 1-E-0, REACTOR TRIP OR FOLLOWING EQUIPMENT - NORMAL: SAFETY INJECTION, while continuing with this procedure.
- Main Feed Pumps
- Condensate Pumps GO TO Step 9.
- Station Vacuum Priming Pumps
- EHC Pumps
- High Pressure Heater Drain Pumps
- Low Pressure Heater Drain Pumps
- 8. RETURN TO PROCEDURE AND STEP IN EFFECT
- 9. START ALL AUXILIARY FEEDWATER Initiate 1-AP-22 series for PUMPS: malfunction of Auxiliary Feedwater while continuing with this
- 1-FW-P-3A procedure.
- 1-FW-P-3B
- 1-FW-P-2
- 10. FEED SGs TO MAINTAIN NARROW RANGE LEVELS - BETWEEN 23% AND 50%
NUMBER PROCEDURE TITLE REVISION 16 1-AP-19 LOSS OF BEARING COOLING WATER PAGE 5 of 7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: The Standby pumps should be placed in Pull-to-Lock or Off, as applicable, before stopping running pumps to prevent unnecessary auto starts.
- 11. DO THE FOLLOWING:
a) Secure components cooled by Unit 1 Bearing Cooling:
- 1) All Main Feedwater Pumps
- 2) All High Pressure Drain Pumps
- 3) Both Low Pressure Drain Pumps
- 4) All Condensate Pumps
- 5) All Station Vacuum Priming Pumps
- 6) Both EHC Pumps
- 7) Notify Chemistry Department to secure the On-Line Chemistry System b) Close both Steam Supply to Condenser Air Ejector valves:
- 1-AS-FCV-100A
- 1-AS-FCV-100B c) Secure Main Air Ejectors using 1-0P-36.2, MAIN CONDENSER AIR EJECTORS, while continuing with Step 12
NUMBER PROCEDURE TITLE REVISION 16 1-AP-19 LOSS OF BEARING COOLING WATER PAGE 6 of 7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
- 12. VERIFY TURBINE SPEED - LESS THAN Monitor turbine speed.
1000 RPM WHEN Turbine speed is less than 1000 rpm, THEN perform Step 13. Continue with Step 14.
- 13. OPEN VACUUM BREAKER 1-AS-MOV-100
- 14. __ CLOSE 1-GN-455, NITROGEN INJECTION TO LP TURBINE EXHAUST ISOL VV (LOCATED UNIT 1 TURBINE DOGHOUSE, SOUTHWEST CORNER)
- 15. VERIFY CONDENSER PRESSURE - Monitor condenser pressure.
ATMOSPHERIC WHEN Condenser pressure is atmospheric, THEN perform Step 16. Continue with Step 17.
- 16. SECURE GLAND SEAL STEAM SYSTEM USING 1-0P-39.1, GLAND SEAL STEAM SYSTEM
- 17. __ PURGE MAIN GENERATOR WITH C02 USING 1-0P-43.1, OPERATION OF THE GENERATOR GAS SYSTEM
- 18. SECURE HYDROGEN SEAL OIL SYSTEM USING 1-0P-42.1, HYDROGEN SEAL OIL SYSTEM.
- 19. __ SUBMIT WORK REQUESTS TO REPAIR MALFUNCTION OF THE BEARING COOLING SYSTEM
NUMBER PROCEDURE TITLE REVISION 16 1-AP-19 LOSS OF BEARING COOLING WATER PAGE 7 of 7 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED
- 20. RETURN TO PROCEDURE AND STEP IN EFFECT
- END -
NUMBER ATTACHMENT TITLE REVISION l-AP-19 16 REFERENCES ATTACHMENT PAGE 1 1 of 1
- 11715-FM-80, BEARING COOLING
- 11715-LSK-12-4A, BEARING COOLING PUMPS
- DCP 88-03-1, TURBINE TRIP - REACTOR TRIP, Setpoint change to P-8.
- DCP 95-172, Nitrogen Injection into Unit 1 LP Turbine Exhaust
- l-AP-22 SERIES, LOSS OF AUXILIARY FEEDWATER
- 0-AP-39.1, TURBINE BUILDING FLOODING
- l-E-O, REACTOR TRIP OR SAFETY INJECTION
- 1-0P-36.2, MAIN CONDENSER AIR EJECTORS
- 1-0P-39.1, GLAND SEAL STEAM SYSTEM
- 1-0P-42.1, HYDROGEN SEAL OIL SYSTEM
- 1-0P-43.1, OPERATION OF THE GENERATOR GAS SYSTEMS
- 1-0P-SO.2, OPERATION OF THE BEARING COOLING WATER SYSTEM
- UFSAR 10.4.7, BEARING COOLING WATER SYSTEM
- I-MOP-50.91, I-BC-CT-l, BEARING COOLING WATER COOLING TOWER
- 2-MOP-50.91, 2-BC-CT-l, BEARING COOLING WATER COOLING TOWER
- 00-SE-TM-06, SAFETY EVALUATION FOR TEMPORARY MODIFICATIONS
#1668 AND 1131
- PLANT ISSUE N-2000-2003, LOSS OF BEARING COOLING FANS
- VPAP-1403, Temporary Modifications
- 11715 / 12050-ESK-6FB-2, -3, and -4
- DCP 01-007, Phase 2 PCS Installation and P-250 Removal - Unit 1
- DCP 04-009, Bearing Cooling Tower Replacement
NUMBER ATTACHMENT TITLE REVISION 1-AP-19 ACTIONS FOR LOSS OF COOLING FANS 16 ATTACHMENT PAGE 2 1 of 3 NOTE:
- Temperatures can be viewed using groups 1AP19-1 and 1AP19-2.
- Setpoints are provided below to remind the operator that action is required by the applicable Annunciator Response procedure.
1 Monitor the following Temperatures while attempting to restart the Bearing Cooling Fans: a) Hydrogen Temp High (1-AR-T-C1)
- Alarm 114 F 0
- Load reduction or continuous monitoring >114 F 0
- Unit Trip >118 F 0
b) Generator Leads Cooling Enclosure Temp (1-AR-K-B7)
- Alarm c) Generator Leads Cooling Return Air Temp (1-AR-K-B7)
- Alarm 170 F 0
d) Generator Leads Cooling Iso-phase Temp (1-AR-K-B7)
- Load Reduction
- Unit Trip 2 Attempt to start fans.
3 1£ fans will NOT start, THEN have Electricians troubleshoot the start circuitry.
NUMBER ATTACHMENT TITLE REVISION 1-AP-19 ACTIONS FOR LOSS OF COOLING FANS 16 ATTACHMENT PAGE 2 2 of 3 4 Do the following to allow starting the fans: a) Inform Predictive Analysis to monitor the fan vibrations at least twice per shift while jumpers are installed and document on a 1-LOG-14. b) Have Electricians, using Simultaneous Verification, install the following jumpers in cabinet 1-EP-CB-120 (located in TB 1 basement on West wall) to allow starting 1-BC-F-1A and 1-BC-F-1B:
- At circuit 1BCPA04 on terminal board TC, jumper from TC-12 to TC-19.
- At circuit 1BCPB04 on terminal board TO, jumper from TO-12 to TO-19.
c) Start the desired Unit 1 BC Tower fans. d) Have Electricians, using Simultaneous Verification, install the following jumpers in cabinet 2-EP-CB-120 (located in TB 2 basement on East wall) to allow starting 2-BC-F-1A and 2-BC-F-1B:
- At circuit 2BCPA04 on terminal board TC, install a jumper from TC-12 to TC-19.
- At circuit 2BCPB04 on terminal board TO, install a jumper from TO-12 to TO-19.
e) Start the desired Unit 2 BC Tower fans. f) Notify the Shift Supervisor that the jumpers have been installed. g) 1£ jumpers will be installed for greater than one shift, THEN have the Shift supervisor do the following:
- Enter the jumpers in the Temporary Modification Log
- Place completed Attachment 3 of VPAP-1403, Temporary Modifications, in the Temporary Modification Log.
NUMBER ATTACHMENT TITLE REVISION 1-AP-19 ACTIONS FOR LOSS OF COOLING FANS 16 ATTACHMENT PAGE 2 3 of 3 5 1£ jumpers were installed in Step 5 of this Attachment and the problem has been found and corrected and jumper removal is desired, THEN remove the jumpers as follows: a) Have Electricians, using Simultaneous Verification, remove the following jumpers for 1-BC-F-1A and 1-BC-F-1B in cabinet 1-EP-CB-120 (located in TB 1 basement on West wall):
- At circuit 1BCPA04 on terminal board TC, remove the jumper from TC-12 to TC-19.
- At circuit 1BCPB04 on terminal board TO, remove the jumper from TO-12 to TO-19.
b) Verify that Unit 1 BC Tower fans are still running. c) Have Electricians, using Simultaneous Verification, remove the following jumpers in cabinet 2-EP-CB-120 (located in TB 2 basement on East wall) for 2-BC-F-1A and 2-BC-F-1B:
- At circuit 2BCPA04 on terminal board TC, remove the jumper from TC-12 to TC-19.
- At circuit 2BCPB04 on terminal board TO, remove the jumper from TO-12 to TO-19 d) Verify that Unit 2 BC Tower fans are still running.
e) Notify the Shift Supervisor that the jumpers have been removed. f) 1£ jumpers were installed for greater than one shift, THEN do the following:
- Remove the jumpers from the Temporary Modification Log
- Remove Attachment 3 of VPAP-1403, Temporary Modifications, from the Temporary Modification Log.
g) Suspend monitoring the fan vibrations.
-END-
VIRGINIA POWER 1-EI-CB-10T ANNUNCIATOR C1 1-AR-T-C1 NORTH ANNA POWER STATION REV. 4 APPROVAL: ON FILE Effective Date:12/07/00 HYDROGEN TEMPERATURE HIGH 114°F (Reset at 111°F) OR CORE MONITOR ~ .5 current NOTE: Core Monitor alarm is normal when Turbine is < 1800 RPM. 1.0 Probable Cause HYDROGEN HIGH TEMP 1.1 Loss of bearing cooling water supply. 1.2 Generator overload. 1.3 Low H2 purity. 1.4 Failure of 1-BC-TCV-104 (H2 coolers temp control valve). CORE MONITOR 1.5 Insulation deterioration in the generator. 1.6 Ground on the generator. 1.7 Core monitor instrumentation problem. 1.8 Main Generator Core Monitor check in progress 2.0 Operator Action ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 2.1 Check Hydrogen Cold Gas Temp - Go To Step 2.6 GREATER THAN 114°F a) Cold Gas Computer Points:
*T2811A
*T2812A b) Local Cold Gas TI 1-GM-TS-111 (located at 1-BC-TIC-104 Controller for BC to Gen H2 Coolers) c) IF 1-GM-TS-111 has lost power, THEN check 1-EP-CB-97 Breaker No.1.
2.2 Check BC flow to Hydrogen Coolers: a) BC Pump - RUNNING a) GO TO 1-AP-19, Loss of Bearing Cooling. 1-BC-TCV-104, Hydrogen b) Control Hydrogen Cooler TCV - CONTROLLING Temperature with
1-BC-158, TCV Bypass.
-------------------_.~
2.3 Check Hydrogen Cold Gas Temp - Do one of the following: DECREASING a) Reduce load as required using 1-0P-2.2, Unit Shutdown Mode 1 to 2, until temperature is less than 114°F. b) Allow Hydrogen Cold Gas Temperature to exceed the alarm setpoint but not exceed 118°F for a maximum of 48 hours with the following restrictions:
- 1) All Generator operating parameters such as temperature and vibration shall be continuously monitored and limits not exceeded.
- 2) Notify the following individuals:
a) System Engineer b) Westinghouse Site representative c) OPS Manager On-Call 2.4 Verify alarm is clear GO TO Step 2.6. 2.5 RETURN TO procedure in effect 2.6 Locally check Core Monitor - Submit WR on annunciator alarm IN ALARM and RETURN TO procedure in effect. 2.7 Check Core Monitor - energized IF Core Monitor should be energized, THEN ensure power available. 2.8 Check flow - 1.0 to 2.0 psid Adjust flow. IF unable to adjust, THEN notify Electric Shop. 2.9 Check Core Monitor Indicator Go To Step 2.12 Greater than .5 2.10 Check SAFE light - LIT Depress Reset and check the following:
- Safe light - LIT
- Alarm light - NOT LIT
IF any of the above NOT true, THEN Submit WR and notify electricians. 2.11 RETURN TO procedure in effect 2.12 Depress FILTER button AND check Submit WR on Core Monitor. Indicator - INCREASES TO
.7 to.9 2.13 After 15 to 20 seconds, release Do the following:
button AND check Indicator - DECREASES TO LESS THAN .5 a) Depress RESET button. b) Check SAFE light - LIT. c) RETURN TO procedure in effect. 2.14 Notify electrician to determine further action and to prepare a Generator gas sample for analysis by Westinghouse NOTE: Westinghouse recommends that an internal inspection of the Generator be made, even if the alarm clears while removing the Generator from service. 2.15 Check Reactor Power - GREATER GO TO 1-AP-2.1, Turbine Trip THAN 30% Without Reactor Trip Required. 2.16 GO TO 1-E-0, Reactor Trip or Safety Injection 3.0 References 3.1 Unit 1 Loop Book, pg GM-011 3.2 W Instuction Book 20804 (Generator Tech Manual) 3.3 11715-FM-80A, Bearing Cooling 3.4 W Generator Maintenance Memos #78-1 and 78-007 3.5 DCP 96-0219, Replace H2 Cold Gas Temperature Switch 3.6 Engineering Transmittal SE-97-124, Rev. 0, NAPS Generator Core Monitor Update to Operating Procedures 3.7 DCP 99-129, Main Generator Core Monitor Replacement 4.0 Actuation 4.1 1-GM-TS-111 4.2 1-GM-TI-101
-END-
VIRGINIA POWER 1-EI-CB-21A ANNUNCIATOR F4 1-AR-A-F4 NORTH ANNA POWER STATION REV. 2 APPROVAL: ON FILE Effective Date:04/04/02 BASIN TEMP HI/LO Hi Temp >95°F Lo Temp <70°F 1.0 Probable Cause 1.1 Ambient Temp. Hi or Lo 1.2 Improper number of cooling tower fans running 2.0 Operator Action ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 2.1 VERIFY TEMPERATURE LOW P ~TO Step 2?!:J 2.2 PLACE RUNNING FANS TO SLOW SPEED OR OFF, AS REQUIRED 2.3 VERIFY TEMPERATURE GO TO Step 2.5. INCREASING 2.4 MONITOR TEMPERATURE AND ADJUST FANS AS REQUIRED 2.5 LOCALLY VERIFY NO Commence de-icing operations ICE ACCUMULATION in accordance with 0-OP-50.2 2.6 CHECK BC TEMPERATURE - Return to Step 2.1. NORMAL, THEN RETURN TO PROCEDURE IN EFFECT START ADDITIONAL FANS OR PLACE FANS IN FAST SPEED AS REQUIRED 2.8 VERIFY TEMPERATURE Determine if BC system should DECREASING be placed on lake-to-lake operation as per 1-0P-50.2. 3.0 References 3.1 System Description 12-4 3.2 11715-ESK-10A 3.3 11715-ESK-6CF-2 4.0 Actuation 4.1 Hi Temp sensed by 1-BC-TSH-120 4.2 Lo Temp as sensed by 1-BC-TSL-120
QUESTIONS REPORT for NORTH ANNA 2008 NRC RO EXAM - FINAL
- 53. 076 Al.02 053INEW//HIGHER//ROINORTH ANNA/6/2008/
Given the following:
- Unit 1 is at 100% power.
- Three BC fans are running in SLOW speed and the fourth is in standby.
- Computer alarms are received on several components cooled by the Bearing Cooling System.
- Subsequently, the following alarms are received 90 seconds apart:
1A-F4, BASIN TEMP HI/LOW 1T-C1, HYDROGEN TEMP OR CORE MONITOR
- The crew enters 1-AP-19, Loss of Bearing Cooling Water, and verifies a Bearing Cooling Pump is running.
Which ONE of the following describes the initial action required in accordance with 1-AP-19? A. Place Bearing Cooling in Lake - to - Lake Mode and verify the operation of the Circ Water System to ensure cooling requirements are met. B~ Start available Bearing Cooling Tower Fans or shift fans to high speed; verify Bearing Cooling temperatures are decreasing. C. Verify Generator Hydrogen temperature is above the alarm setpoint and initiate a plant load reduction until the alarm is clear. D. Bypass 1-BC-TCV-104, Generator Hydrogen Cooler TCV, to lower hydrogen temperature. A Incorrect. Lake to Lake mode may be initiated after evaluation and after attempting to start all fans; therefore, plausible because it may be performed. B Correct. AR for basin temperture HI is confirmed by annunciator for Hydrogen temperature so the initial response would be to maximize system cooling and assess if additional cooling is adequate to control system supply temperature. C Incorrect. Verify temperature but for the Generator Hydrogen cooler, would attempt to bypass the TCV before anything else. Generator Hydrogen Cooler is a priority component in this situation. D Incorrect. Would bypass the TCV if the BC fans did not solve the problem, but would reduce load instead of trip the reactor if temperature exceeded the limit. Thursday, June 26, 2008 6:32:39 AM 106
QUESTIONS REPORT for NORTH ANNA 2008 NRC RO EXAM - FINAL Ability to predict and/or monitor changes in parameters (to prevent exceeding design limits) associated with operating the SWS controls including: Reactor and turbine building closed cooling water temperatures. Question Number: Tier: 2 Group: 1 Importance Rating: 2.6 Technical
Reference:
1T-C1, 1A-F4, 1-AP-19 Proposed references to be provided to applicants during examination: None Learning Objective: U11413 Question History: 10 CFR Part 55 Content: 41.10 Comments: KA Match: Facility has a secondary system called Bearing Cooling that serves the same function as the Service Water system at other facilities. KA is met because the item requires operating the system controls to prevent exceeding temperature limits Thursday, June 26,2008 6:32:39 AM 107
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #92 (KIA 062 AA2.05) Test Key Answer: "Throttle Service Water to CC Heat Exchangers within 1 hour; Ensures design flows to the RS Heat Exchangers are achieved following a LOCA with NO additional failures." One of the distractors for this question states the following: "Restore the Service Water Loop to operable status within 72 hours; Ensures design flows to the RS Heat Exchangers are achieved following a LOCA with ONE additional failure." The test key answer is correct if the assumption from the initial conditions listed in the question stem was that the Service Water (SW) System was not already in the "throttled" condition. In such a case, LCO 3.7.8 Action Condition B, Required Action B.1 would require throttling SW System flow to the CC Heat Exchangers within 1 hour. In accordance with the associated T.S. Bases (B 3.7.8), this would ensure that design flows to the RS Heat Exchangers are achieved if no additional failures occur following an accident (LOCA). Although not mentioned in the test key answer, there is a second part of Action Condition B; that is Required Action B.2, which requires one SW Pump to be restored to operable status within 72 hours. In accordance with the associated T.S. Bases, restoring one SW pump to operable status (which would restore the associated SW Loop to operable status), together with the throttling ensures that design flows to the RS Heat Exchangers are achieved following an accident (LOCA), and that a single failure disabling a SW Pump would not result in loss of the SW System function. The distractor listed above is correct if the assumption from the initial conditions was that the Service Water System was already in the "throttled" condition, either due to the normal operational status of the system or as a result of the initial condition that 2-SW-P-1B was already out of service. Under normal conditions, the SW System is operated with SW flow properly throttled through the CC Heat Exchangers (i.e., the system is normally operated in the "throttled condition"). The characteristics of the system allow for normal operation of the system in this configuration, deviating from this condition only when necessary for testing or increased cooling requirements for the supported systems (e.g., extreme hot weather; high heat load on the Component Cooling System, such as might be encountered during shutdown while on RHR with a high decay heat load, or high spent fuel pool heat load following core offload; etc...). In the event of removing a SW Pump from service for planned or emergent maintenance, the associated SW Pump Maintenance Operating Procedure (MOP), used to remove the pump from service, requires the establishment or verification of proper SW System throttling. The initial conditions in the question stem do not clearly indicate whether the SW System is properly "throttled" or not. With the initial condition description that "2-SW-P-1B is OOS" (out of service), it would be reasonable to assume that the pump was removed from service using 2-
North Anna RO/SRO NRC ILO Exam Test Item Comments MOP-49.02 (whether due to a planned or emergent condition). Since the MOP directs the establishment or verification of proper SW System throttling, and the "throttled" condition is the . normal operational practice and expectation for the system, it would be reasonable to conclude that the system was already in the properly "throttled" condition after 2-SW-P-lB was removed from service, prior to the trip of l-SW-P-lB. Given the reasonable conclusion that the SW System was already in the properly "throttled" state, with 2-SW-P-lB out of service, the LCO 3.7.8 Action Condition, Required Action A.l, to "throttle" the system within 72 hours would have already been satisfied. Following the trip of l-SW-P-lB and start of2-SW-P-lA, the status of the SW System would be normal operation of the two SW Loops with one SW Pump running on each SW Loop. However, the operability condition of the system would be degraded due to the inoperability of both SW Loops as a result of the two SW Pumps being inoperable simultaneously. SW Loop operability is dependent on several criteria, one being the operability status of the SW Pumps aligned to the Loop(s). The LCO 3.7.8 Bases describes the pump criteria for SW Loop operability as follows: A SW loop is considered OPERABLE during Modes 1,2,3, and 4 when:
- a. Either a.l Two SW pumps are OPERABLE in an OPERABLE flow path; or a.2 One SW pump is OPERABLE in an OPERABLE flow path provided two SW pumps are OPERABLE in the other loop and SW flow to the CC heat exchangers is throttled Neither of these criteria is satisfied for the SW Loops, with the two stated SW Pumps inoperable simultaneously. Thus in this condition, both SW Loops are inoperable. The proper LCO 3.7.8 Action Condition for this situation would be Action Condition B. Required Action B.l would require throttling of SW flow to the CC Heat Exchangers within 1 hour. This requirement would have already been met, as previously discussed above. Required Action B.2 would require that one SW Pump be restored to operable status within 72 hours. Restoring one SW Pump to operable status would restore its associated SW Loop to operable status. By the provision in the LCO 3.7.8 Bases (a.2 criterion stated above) with the associated SW Loop restored to operable status (two operable SW Pumps on that Loop), the other SW Loop would then be considered operable, even with the remaining pump inoperable, due to the "throttled" condition of the system. Thus, in accordance with the associated T.S. Bases, restoring the SW Loop to operable status (by restoring one SW Pump) together with the throttling ensures that design flows to the RS Heat Exchangers are achieved following an accident (LOCA), and that a single failure disabling a SW Pump would not result in loss of the SW System function.
The correct answer to the question is based on the whether the SW System is in the properly "throttled" condition prior to the trip of l-SW-P-lB. As stated above, the question stem does not provide a direct statement to this status, thus, requiring an assumption to be made to properly
North Anna RO/SRO NRC ILO Exam Test Item Comments evaluate the answer selections. If the assumption is made that the SW System is not already throttled, then the test key answer is correct. If the assumption is made that the SW System is already throttled prior to the trip of l-SW-P-IB, then the distractor listed above is correct. Given the initial conditions stated in the question stem, both choices are considered acceptable and correct.
References:
North Anna T.S. Leo 3.7.8 and Bases 1/2-MOP-49.01 and 49.02
- NUCLEAR DESIGN INFORMATION PORTAL-SW System 3.7.8 3.7 PLANT SYSTEMS 3.7.8 Service Water (SW) System LCO 3.7.8 Two SW System loops shall be OPERABLE.
APPLICABILITY: MODES 1, 2, 3, and 4. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SW pump A.1 Throttle SW System flow 72 hours inoperable. to Component Cooling (CC) heat exchangers. B. Two SW pumps B.1 Throttle SW System flow 1 hour inoperable. to CC heat exchangers. AND B.2 Restore one SW pump to 72 hours OPERABLE status. North Anna Units 1 and 2 3.7.8-1 Amendments 231/212
- NUCLEAR DESIGN INFORMATION PORTAL-SW System 3.7.8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. One SW System loop C.1 Restore SW System loop -----NOTE------
inoperable for reasons to OPERABLE status. 72 hour other than Completion Time Condition A. only required if criteria allowing 7 day Completion Time are not met. 72 hours AND
-----NOTE------
Only applicable if:
- 1. SW loop inoperability is part of SW System upgrades, and
- 2. Three SW pumps are OPERABLE from initial Condition entry (one SW pump allowed to not have automatic start capability),
and
- 3. Two auxiliary SW pumps are OPERABLE from initial Condition entry.
7 days North Anna Units 1 and 2 3.7.8-2 Amendments 231/212
- NUCLEAR DESIGN INFORMATION PORTAL-SW System 3.7.8 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Actions and 0.1 Be in MODE 3. 6 hours associated Completion Times of Conditions A, AND B or C not met.
D.2 Be in MODE 5. 36 hours E. Two SW System loops E.1 Be in MODE 4. 12 hours inoperable for reasons other than only two SW AND pumps being OPERABLE. E.2 Initiate actions to be 13 hours in MODE 5. SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.8.1 -------------------NOTE-------------------- Isolation of SW flow to individual components does not render the SW System inoperable. Verify each SW System manual, power 31 days operated, and automatic valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position. SR 3.7.8.2 Verify each SW System automatic valve in 18 months the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal. SR 3.7.8.3 Verify each SW pump starts automatically on 18 months an actual or simulated actuation signal. North Anna Units 1 and 2 3.7.8-3 Amendments 231/212
- NUCLEAR DESIGN INFORMATION PORTAL-SW System B 3.7.8 B 3.7 PLANT SYSTEMS B 3.7.8 Service Water (SW) System BASES BACKGROUND The SW System provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or transient. During normal operation, and a normal shutdown, the SW System also provides this function for various safety related and nonsafety related components. The safety related function is covered by this LCO.
The SW System is common to Units 1 and 2 and is designed for the simultaneous operation of various subsystems and components of both units. The source of cooling water for the SW System is the Service Water Reservoir. The SW System consists of two loops and components can be aligned to operate on either loop. There are four main SW pumps taking suction on the Service Water Reservoir, supplying various components through the supply headers, and then returning to the Service Water Reservoir through the return headers. Eight spray arrays are available to provide cooling to the service water, as well as two winter bypass lines. The isolation valves on the spray array lines automatically open, and the isolation valves on the winter bypass lines automatically shut, following receipt of a Safety Injection signal. The main SW pumps are powered from the four emergency buses (two from each unit). There are also two auxiliary SW pumps which take suction on North Anna Reservoir and discharge to the supply header. When the auxiliary SW pumps are in service, the return header may be redirected to waste heat treatment facility if desired. However, the auxiliary SW pumps are strictly a backup to the normal arrangement and are not credited in the analysis for a DBA. During a design basis loss of coolant accident (LOCA) concurrent with a loss of offsite power to both units, one SW loop will provide sufficient cooling to supply post-LOCA loads on one unit and shutdown and cooldown loads on the other unit. During a DBA, the two SW loops are cross-connected at the recirculation spray (RS) heat exchanger supply and return headers of the accident unit. On a Safety Injection (SI) signal on either unit, all four main SW pumps start and the system is aligned for Service Water Reservoir spray operation. On a containment high-high (continued) North Anna Units 1 and 2 B 3.7.8-1 Revision 0
- NUCLEAR DESIGN INFORMATION PORTAL-SW System B 3.7.8 BASES BACKGROUND pressure signal the accident unit1s Component Cooling (CC)
(continued) heat exchangers are isolated from the SW System and its RS heat exchangers are placed into service. All safety-related systems or components requiring cooling during an accident are cooled by the SW System, including the RS heat exchangers, main control room air conditioning condensers, and charging pump lubricating oil and gearbox coolers. The SW System also provides cooling to the instrument air compressors, which are not safety-related, and the non-accident unit1s CC heat exchangers, and serves as a backup water supply to the Auxiliary Feedwater System, the spent fuel pool coolers, and the containment recirculation air cooling coils. The SW System has sufficient redundancy to withstand a single failure, including the failure of an emergency diesel generator on the affected unit. Additional information about the design and operation of the SW System, along with a list of the components served, is presented in the UFSAR, Section 9.2.1 (Ref. 1). The principal safety related function of the SW System is the removal of decay heat from the reactor following a DBA via the RS System. APPLICABLE The design basis of the SW System is for one SW loop, in SAFETY ANALYSES conjunction with the RS System, to remove core decay heat following a design basis LOCA as discussed in the UFSAR, Section 6.2.2 (Ref. 2). This prevents the containment sump fluid from increasing in temperature, once the cooler RWST water has reached equilibrium with the fluid in containment, during the recirculation phase following a LOCA and provides for a gradual reduction in the temperature of this fluid which is supplied to the Reactor Coolant System by the ECCS pumps. The SW System also prevents the buildup of containment pressure from exceeding the containment design pressure by removing heat through the RS System heat exchangers. The SW System is designed to perform its function with a single failure of any active component, assuming the loss of offsite power. The SW System, in conjunction with the CC System, also cools the unit from residual heat removal (RHR), as discussed in the UFSAR, Section 5.5.4, (Ref. 3) entry conditions to MODE 5 during normal and post accident operations. The time required for this evolution is a function of the number of CC and RHR System trains that are operating. (continued) North Anna Units 1 and 2 B 3.7.8-2 Revision 0
- NUCLEAR DESIGN INFORMATION PORTAL-SW System B 3.7.8 BASES APPLICABLE The SW System satisfies Criterion 3 of 10 CFR SAFETY ANALYSES 50.36(c) (2) (i t ) ,
(continued) LCO Two SW loops are required to be OPERABLE to provide the required redundancy to ensure that the system functions to remove post accident heat loads, assuming that the worst case single active failure occurs coincident with the loss of offsite power. A SW loop is considered OPERABLE during MODES 1, 2, 3, and 4 when:
- a. Either a.1 Two SW pumps are OPERABLE in an OPERABLE flow path; or a.2 One SW pump is OPERABLE in an OPERABLE flow path provided two SW pumps are OPERABLE in the other loop and SW flow to the CC heat exchangers is throttled; and
- b. Either b.1 Three spray arrays are OPERABLE in an OPERABLE flow path; or b.2 Two spray arrays are OPERABLE in an OPERABLE flow path, provided two spray arrays are OPERABLE in the other loop; and the spray valves for the required OPERABLE spray arrays in both loops are secured in the accident position and power removed from the valve operators; and
- c. The associated piping, valves, and instrumentation and controls required to perform the safety related function are OPERABLE.
A required valve directing flow to a spray array, bypass line, or other component is considered OPERABLE if it is capable of automatically moving to its safety position or if it is administratively placed in its safety position. North Anna Units 1 and 2 B 3.7.8-3 Revision 14
- NUCLEAR DESIGN INFORMATION PORTAL-SW System B 3.7.8 BASES APPLICABILITY In MODES 1, 2, 3, and 4, the SW System is a normally operating system that is required to support the OPERABILITY of the equipment serviced by the SW System and required to be OPERABLE in these MODES.
In MODES 5 and 6, the OPERABILITY requirements of the SW System are determined by the systems it supports. ACTIONS A.1 If one SW System loop is inoperable due to an inoperable SW pump, the flow resistance of the system must be adjusted within 72 hours by throttling component cooling water heat exchanger flows to ensure that design flows to the RS System heat exchangers are achieved following an accident. The required resistance is obtained by throttling SW flow through the CC heat exchangers. In this configuration, a single failure disabling a SW pump would not result in loss of the SW System function. B.1 and B.2 If one or more SW System loops are inoperable due to only two SW pumps being OPERABLE, the flow resistance of the system must be adjusted within one hour to ensure that design flows to the RS System heat exchangers are achieved if no additional failures occur following an accident. The required resistance is obtained by throttling SW flow through the CC heat exchangers. Two SW pumps aligned to one loop or one SW pump ali gned to each l oop i s capab 1e of performing the safety function if CC heat exchanger flow is properly throttled. However, overall reliability is reduced because a single failure disabling a SW pump could result in loss of the SW System function. The one hour time reflects the need to minimize the time that two pumps are inoperable and CC heat exchanger flow is not properly throttled, but is a reasonable time based on the low probability of a DBA occurring during this time period. Restoring one SW pump to OPERABLE status within 72 hours together with the throttling ensures that design flows to the RS System heat exchangers are achieved following an accident. The required resistance is obtained by throttling SW flow through the CC heat exchangers. In this configuration, a single failure disabling a SW pump would not result in loss of the SW System function. North Anna Units 1 and 2 B 3.7.8-4 Revision 14
- NUCLEAR DESIGN INFORMATION PORTAL-SW System B 3.7.8 BASES ACTIONS C.1 (continued)
If one SW loop is inoperable for reasons other than Condition A, action must be taken to restore the loop to OPERABLE status. In this Condition, the remaining OPERABLE SW loop is adequate to perform 'the heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE SW loop could result in loss of SW System function. The inoperable SW loop is required to be restored to OPERABLE status within 72 hours unless the criteria for a 7 day Completion Time are met, as stated in the 72 hour Completion Time Note. The 7 day Completion Time applies if the three criteria in the 7 day Completion Time Note are met. The first criterion in the 7 day Completion Time Note states that the 7 day Completion Time is only applicable if the inoperability of one SW loop is part of SW System upgrades. Service Water System upgrades include modification and maintenance activities associated with the installation of new discharge headers and spray arrays, mechanical and chemical cleaning of SW System piping and valves, pipe repair and replacement, valve repair and replacement, installation of corrosion mitigation measures and inspection of and repairs to buried piping interior coatings and pump or valve house components. The second criterion in the 7 day Completion Time Note states that the 7 day Completion Time is only applicable if three SW pumps are OPERABLE from initial Condition entry, including one SW pump being allowed to not have automatic start capability. The third criterion in the 7 day Completion Time Note states that the 7 day Completion Time is only applicable if two auxiliary SW pumps are OPERABLE from initial Condition entry. The 72 hour and 7 day Completion Times are both based on the redundant capabilities afforded by the OPERABLE loop, and the low probability of a DBA occurring during this time period. The 7 day Completion Time also credits the redundant capabilities afforded by three OPERABLE SW pumps (one without automatic start capability) and two OPERABLE auxiliary SW pumps. Changing the designation of the three OPERABLE SW pumps during the 7 day Completion Time is allowed. North Anna Units 1 and 2 B 3.7.8-5 Revision 14
- NUCLEAR DESIGN INFORMATION PORTAL-SW System B 3.7.8 BASES ACTIONS D.1 and D.2 (continued)
If the SW pumps or loop cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours and in MODE 5 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. E.1 and E.2 If two SW loops are inoperable for reasons other than only two SW pumps being OPERABLE, the SW System cannot perform the safety function. With two SW loops inoperable, the CC System and, consequently, the Residual Heat Removal (RHR) System have no heat sink and are inoperable. Twelve hours is allowed to enter MODE 4, in which the Steam Generators can be used for decay heat removal to maintain reactor temperature. Twelve hours is reasonable, based on operating experience, to reach MODE 4 from full power conditions in an orderly manner and without challenging unit systems. The unit may then remain in MODE 4 until a method to further cool the units becomes available, but actions to determine a method and cool the unit to a condition outside of the Applicability must be initiated within one hour and continued in a reasonable manner and without delay until the unit is brought to MODE 5. SURVEILLANCE SR 3.7.8.1 REQUIREMENTS This SR is modified by a Note indicating that the isolation of the SW System components or systems may render those components inoperable, but does not affect the OPERABILITY of the SW System. Verifying the correct alignment for manual, power operated, and automatic valves in the SW System flow path provides assurance that the proper flow paths exist for SW System operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since they are verified to be in the correct position prior to being locked, sealed, or secured. This SR does not require any testing or (continued) North Anna Units 1 and 2 B 3.7.8-6 Revision 14
- NUCLEAR DESIGN INFORMATION PORTAL-SW System B 3.7.8 BASES SURVEILLANCE SR 3.7.8.1 (continued)
REQUIREMENTS valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions. SR 3.7.8.2 This SR verifies proper automatic operation of the SW System valves on an actual or simulated actuation signal. The SW System is a normally operating system that cannot be fully actuated as part of normal testing. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint. SR 3.7.8.3 This SR verifies proper automatic operation of the SW pumps on an actual or simulated actuation signal. The SW System is a normally operating system that cannot be fully actuated as part of normal testing during normal operation. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint. REFERENCES 1. UFSAR, Section 9.2.1.
- 2. UFSAR, Section 6.2.2.
- 3. UFSAR, Section 5.5.4.
North Anna Units 1 and 2 B 3.7.8-7 Revision 14
PROCEDURE NO: o . . InlO -" 2-MOP-49.02 REVISION NO: NORTH ANNA POWER STATION 16 PROCEDURE TYPE: UNIT NO: MAINTENANCE OPERATING PROCEDURE 2 PROCEDURE TITLE: 2-SW-P-1B AND SERVICE WATER BAY REVISION
SUMMARY
- Administrative:
- Added initial lines to Section 3.0 and 4.0 for place keeping.
- Incorporated OP 08-0121, 2-SW-P-lNlB and SW Bay as follows:
- Added (FU-D) to Step 5.l.6.d. and Step 5.2.7.c.
, PROBLEMS ENCOUNTERED: D NO DYES Note: If YES, note problems in remarks. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ (Use back for additional remarks.) SRO: DATE: CONTINUOUS USE
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 2 of 15 1.0 PURPOSE 1.1 To provide instructions for removing 2-SW-P-IB and Service Water Bay from service. (Reference 2.4.4) 1.2 To provide instructions for returning 2-SW-P-IB and Service Water Bay to service. (Reference 2.4.4) The following synopsis is designed as an aid to understanding the procedure, and is not intended to alter or take the place of the actual purpose, instructions, or text of the procedure itself. This MOP is designed to prepare 2-SW-P-IB and its associated Service Water Bay for subsystem maintenance or for subsystem inspection by diver. The procedure is laid out to be used for complete bay isolation or for simple SW pump isolation. If the Service Water Bay is required to be removed from service, then the electrical supplies for 2-SW-P-IB, B Service Water Pump, 2-SW-S-IB, IB Traveling Water Screen, 2-SW-S-3, Service Water Screen Wash Strainer, 2-SW-P-2, Service Water Screen Wash Pump, and the Discharge Valves for 2-SW-P-IB are tagged out. If the intake bay is not required to be removed from service, then the electrical supply to 2-SW-P-IB and the Discharge Valves are tagged out.
2.0 REFERENCES
2.1 Source Documents 2.1.1 UFSAR Section 9.2.1, Service Water System 2.2 Technical Specifications 2.2.1 Tech Spec 3.7.8 2.2.2 Tech Spec TRM 3.7.11 2.3 Technical References 2.3.1 11715-FM-78A, Service Water System, Sheet 3
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 3 of 15 2.3.2 11715-FM-008A, Arrangement Service Water Pump House 2.3.3 11715-FM-008B, Arrangement Service Water Pump House 2.3.4 Station Lubrication Manual 2.3.5 Engineering Analysis for 2-PT-75.6, dated 11-13-90 2.3.6 0-OP-49.1, Service Water System Normal Operation (References 2.4.3 and 2.4.5) 2.3.7 2-PT-75.2B, 2-SW-P-1B, Service Water Pump, Test 2.3.8 0-OP-26.9, 4160-Volt Breaker Operation 2.3.9 0-OP-49.6, Service Water System Throttling Alignment 2.3.10 12050-FE-8BN, Wiring Diagram 4160V Emer Bus 2J Serv Wtr Pp 2-SW-P-1B, Bkr 25J5 2.4 Commitment Documents 2.4.1 CTS Assignment 02-90-0210, Commitment 001, LER N1/2 90-007-00, Service Water Pumphouse missile shield blocks not in place 2.4.2 CTS Assignment 02-91-1808-003, Tech Spec Amendments 152/136 2.4.3 CTS Assignment 02-90-1750-037, Generic Letter 89-13: SW System Problems affecting SR Equipment 2.4.4 OP-231, create MOPs for Service Water Bays similar to Circ Water Bay MOPs 2.4.5 Generic Letter 89-19, Service Water Problems Affecting Safety-Related Systems 2.4.6 Standing Order No. 177, Rev. 1, Service Water System Control, deleted by inclusion in procedures
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 4 of 15 2.4.7 CTS Assignment 02-94-0500, Commitment 002, Independent Verification of control switch position 2.4.8 Memo from B. K. Day to R. A. Bergquist, dated June 5, 1995; Service Water System Throttling Controls for (old) Tech Spec 3.7.4.1 2.4.9 Standing Order No. 221, Rev. 5, Component Cooling Heat Exchanger Operating Pressure Init Verif 3.0 INITIAL CONDITIONS Review the equipment status to verify station configuration supports the performance of this procedure. 4.0 PRECAUTIONS AND LIMITATIONS 4.1 Comply with the following guidelines when marking steps N/A:
- IF the conditional requirements of a step do not require the action to be performed, THEN mark the step N/A.
- IF any other step is marked N/A, THEN have the SRO (or designee) approve the N/A and justify the N/A on the Procedure Cover Sheet.
4.2 The following Service Water Controls shall apply at all times. (References 2.4.6 and 2.4.9) 4.2.1 To ensure the SW System can supply adequate flow to equipment in the event of a CDA, maintain at least three (3) Service Water Pumps Operable (does not include 1/2-SW-P-4). IF this condition cannot be met, THEN enter the action of Tech Spec 3.7.8 or TRM 3.7.11 as applicable. 4.2.2 With all four SW pumps operable and all four EDGs operable, maintain SW pump discharge pressure greater than 30 psig.
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 5 of 15 4.2.3 With three SW pumps operable or one of four EDGs out of service for any reason (including operation allowed by Tech Specs in Mode 5 and 6), enter the action of Tech Spec 3.7.8 or TRM 3.7.11 as applicable until Step 4.2.4 actions are accomplished. The action statement clock begins when the fourth pump becomes inoperable or the EDG enters its associated action statement. 4.2.4 The following is the required starting condition for any SW System valve lineup (for example, if it is necessary to run 2 SW pumps on a header, then the system should be aligned as follows before starting the second pump):
- a. Establishing the following conditions ensures proper SW flows with only three operable SW pumps.
- c.
- Ensure only one SW pump is in service on each header.
- Open all SW Spray valves.
- Close the SW Bypass valves.
- Throttle the CCHX outlet valves so that each SW pump discharge pressure is greater than 54 psig using O-OP-49.6, Service Water System Throttling Alignment. (References 2.4.8 and 2.4.9)
- Place administrative controls on the throttled position of the CCHX outlet valves.
- b. To avoid entry into a Tech Spec Action Statement, the conditions of Step 4.2.4.a MUST be established before a SW Pump OR an EDG is removed from service.
- c. IF a SW pump failure occurs, THEN enter the Action Statement of Tech Spec 3.7.8 or TRM 3.7.11 as applicable until the conditions specified in Step 4.2.4.a are established.
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 6 of 15 4.3 The following Tech Specs apply:
- Tech Spec 3.7.8
- TRM 3.7.11
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 7 of 15 5.0 INSTRUCTIONS 5.1 Removing 2-SW-P-IB And Service Water Intake Bay From Service 5.1.1 Verify Initial Conditions are satisfied. 5.1.2 Review Precautions and Limitations. 5.1.3 IF 2-SW-P-IB is in service, THEN do the following:
- a. Start an operable Service Water Pump using O-OP-49.1, Service Water System Normal Operation. (References 2.4.3 and 2.4.9)
- b. Stop 2-SW-P-IB using O-OP-49.1, Service Water System Normal Operation. (Reference 2.4.3) 5.1.4 IF Unit 1 OR Unit 2 is in Mode 1,2,3, or 4, THEN do the following:
(References 2.3.5 and 2.4.6)
- a. Verify the following equipment is operable:
- I-SW-P-IA, A SERVICE WATER PUMP
- I-SW -P-IB, B SERVICE WATER PUMP
- 2-SW-P-IA, A SERVICE WATER PUMP
- l-EE-EG-IH, IH EMERGENCY DIESEL GENERATOR
- l-EE-EG-IJ, IJ EMERGENCY DIESEL GENERATOR
- 2-EE-EG-2H, 2H EMERGENCY DIESEL GENERATOR
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 8 of 15 NOTE: An additional SW Pump may be started or the Bypass and Spray MOVs may be changed to meet seasonal conditions after throttling has been completed provided that the positions of the CC Heat Exchanger Service Water Outlet Valves are not changed.
- b. IF all of the equipment in Step 5.I.4.a is operable, THEN throttle the Service Water outlet of the CCHX so that each Service Water Pump discharge pressure is > 54 psig using O-OP-49.6, Service Water System Throttling Alignment. (References 2.4.8 and 2.4.9)
- c. IF any of the equipment in Step 5.I.4.a is NOT operable, THEN do the following:
- 1. Throttle the Service Water outlet of the CCHX so that each Service Water Pump discharge pressure is > 54 psig using O-OP-49.6, Service Water System Throttling Alignment.
(References 2.4.8 and 2.4.9)
- 2. Notify the SRO to enter the 72 hour Action Statement of Tech SRO Spec 3.7.8.
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 9 of 15 5.1.5 IF Unit 1 AND Unit 2 are in Mode 5 or 6, THEN do the following: (References 2.3.5 and 2.4.6)
- a. Verify at least TWO of the following equipment combinations are operable. Mark the remaining combinations N/A:
- l-SW-P-lA, A Service Water Pump AND l-EE-EG-lH, lH Emergency Diesel Generator
- l-SW-P-lB, B Service Water Pump AND l-EE-EG-lJ, lJ Emergency Diesel Generator
- 2-SW-P-lA, A Service Water Pump AND 2-EE-EG-2H, 2H Emergency Diesel Generator
- l-SW-P-4, Auxiliary Service Water Pump, 2-SW-P-4, Auxiliary Service Water Pump, l-EE-EG-lH, lH Emergency Diesel Generator, AND 2-EE-EG-2H, 2H Emergency Diesel Generator NOTE: An additional SW Pump may be started or the Bypass and Spray MOVs may be changed to meet seasonal conditions after throttling has been completed, provided that the positions of the CC Heat Exchanger Service Water Outlet Valves are not changed.
- b. IF at least TWO of the equipment combinations in Step 5.l.5.a are operable, THEN throttle the Service Water outlet of the CCHX so that each Service Water Pump discharge pressure is > 54 psig using O-OP-49.6, Service Water System Throttling Alignment.
(References 2.4.8 and 2.4.9)
- c. IF at least TWO of the equipment combinations in Step 5.l.5.a are NOT operable, THEN do the following:
- 1. Throttle the Service Water outlet of the CCHX so that each Service Water Pump discharge pressure is > 54 psig using O-OP-49.6, Service Water System Throttling Alignment.
(References 2.4.8 and 2.4.9)
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 10 of 15
- 2. Notify the SRO to enter the 12 hour Action Statement of Tech SRO Spec TRM 3.7.11.
5.1.6 Isolate 2-SW-P-IB as follows:
- a. Place the control switches for 2-SW-P-IB, B SERVICE WATER PUMP, located on the J Train Safeguards Panel in PULL-TO-LOCK:
- b. Rack 2-EE-BKR-25J5, B Service Water Pump Circuit Breaker 2-SW-P-IB, to DISC using 0-OP-26.9, 4160 Volt Breaker Operation, and hang a Danger Tag on the breaker.
NOTE: To remove all control power to breaker 2-EE-BKR-25J5, a total of 8 fuses must be removed.
- c. IF the control power fuses for 2-EE-BKR-25J5, B Service Water Pump Circuit Breaker 2-SW-P-IB, will be removed, THEN remove the control power fuses from Cubicle 25J5 as follows:
- 1. Remove the two 30A FU Breaker Close fuses from Device AX.
- 2. Remove the two 35A FU Breaker Trip fuses from Device AY.
- 3. Have an Electrician remove the two 30A FU Breaker Close fuses ELEC SV from Device AXA.
- 4. Have an Electrician remove the two 35A FU Breaker Trip fuses from ELEC SV Device AYA.
- 5. Danger Tag the fuses.
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 11 of 15
- d. IF electrical maintenance will be done on 2-SW-P-1B, THEN remove the motor heater fuses for 2-SW-P-1B from 1-EP-CB-84H (FU-D), located in the Service Water Pumphouse, and hang a Danger Tag on the fuses.
- e. Close and hang Danger Tags on the following valves:
- 2-SW-11, 1B SW PP Dish To Supply Header No 2 Isol Valve
- 2-SW-13, 1B SW PP Dish To Supply Header No 1 Isol Valve 5.1.7 IF the Service Water Intake Bay is being isolated, THEN do the following:
(Reference 2.4.4)
- a. Isolate the Traveling Water Screen for 2-SW-P-1B as follows:
- 1. Place the local Traveling Water Screen Drive 2-SW-S-1B HAND /
OFF / AUTO switch, in OFF, located on stanchion between the Traveling Water Screen and 2-SW-P-1B.
- 2. Place 2-EE-BKR-2Jl-3 AI, 1B Service Water Traveling Water Screen Circuit Breaker 2-SW-S-1B, in OFF and hang a Danger Tag on the breaker.
- 3. Close 2-SW-232, Service Water Air Sply To 2-SW-LT-200B Isol Valve, and hang a Danger Tag on the valve.
- 4. Close 2-SW-34, Scm Wash To 1B Traveling Water Screen Isol Valve, and hang a Danger Tag on the valve.
- b. Isolate 2-SW-P-2, Service Water Screen Wash Pump, as follows:
- 1. Have Unit 2 OATC place the remote HAND / OFF / AUTO switch for 2-SW-P-2, Service Water Screen Wash Pump, in OFF.
- 2. Place 2-EE-BKR-2Hl-3 B2, Service Water Screen Wash Pump Circuit Breaker 2-SW-P-2, in OFF and hang a Danger Tag on the breaker.
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 12 of 15
- 3. Close 2-SW-32, Service Water Screen Wash Strainer Outlet Isolation Vv, and hang a Danger Tag on the valve.
- c. Isolate 2-SW-S-3, Service Water Screen Wash Strainer, as follows:
- 1. At 2-EP-CB-27C, place the local CONT. / INTER. / OFF switch for 2-SW-S-3, Service Water Screen Wash Strainer, in OFF.
- 2. Place 2-EE-BKR-2HI-3 A2L, Service Water Screen Wash Strainer Circuit Breaker 2-SW-S-3, in OFF and hang a Danger Tag on the breaker.
- d. IF required for Bay maintenance, THEN have the Maintenance Department install the stop logs.
Date: _
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 13 of 15 5.2 Returning 2-SW-P-IB And Service Water Intake Bay to Service 5.2.1 Verify Initial Conditions are satisfied. 5.2.2 Review Precautions and Limitations. 5.2.3 Have the SRO verify all maintenance activities on Service Water Intake Bay SRO for 2-SW-P-IB are.complete. 5.2.4 Ensure Stop Log for Service Water Intake Bay is removed. 5.2.5 Verify that all Service Water Pumphouse roof missile shield blocks are installed. (Reference 2.4.1) 5.2.6 IF the SW Bay was isolated, THEN do the following:
- a. Restore 2-SW-S-IB, IB Service Water Traveling Water Screen, as follows:
- 1. Remove the Danger Tag and open 2-SW-232, Service Water Air Sply To 2-SW-LT-200B Isol Valve.
- 2. Remove the Danger Tag and open 2-SW-34, Scm Wash To IB Traveling Water Screen Isol Valve.
- 3. Remove the Danger Tag and place 2-EE-BKR-2JI-3 AI, IB Service Water Traveling Water Screen Circuit Breaker 2-SW-S-IB, in ON.
- 4. Ensure the Traveling Water Screen Drive 2-SW-S-IB HAND /OFF /
AUTO switch, located on stanchion between the Traveling Water Screen and 2-SW-P-IB, is in AUTO.
- b. Restore 2-SW-P-2, Service Water Screen Wash Pump, as follows:
- 1. Remove the Danger Tag and open 2-SW-32, Service Water Screen Wash Strainer Outlet Isolation Vv.
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 14 of 15
- 2. Remove the Danger Tag and place 2-EE-BKR-2HI 3 B2, Service Water Screen Wash Pump Circuit Breaker 2-SW-P-2, in ON.
- 3. Have Unit 2 OATC place the remote HAND / OFF / AUTO switch for 2-SW-P-2, Service Water Screen Wash Pump, in OFF.
- c. Restore 2-SW-S-3, Service Water Screen Wash Pump, as follows:
- 1. Remove the Danger Tag and place 2-EE-BKR-2HI-3 A2L, Service Water Screen Wash Strainer Circuit Breaker 2-SW-S-3, in ON.
- 2. At 2-EP-CB-27C, place the local CONTi / INTER. / OFF switch for 2-SW-S-3, Service Water Screen Wash Strainer, in INTER.
- 3. Place the Traveling Water Screen Drive 2-SW-S-IB HAND / OFF /
AUTO switch, located on stanchion between the Traveling Water Screen and 2-SW-P-IB, in AUTO. 5.2.7 Restore 2-SW-P-IB as follows:
- a. Remove the Danger Tag from 2-SW-II, IB SW PP Dish To Supply Header No 2 Isol Valve.
- b. Remove the Danger Tag and open 2-SW-I3, IB SW PP Dish To Supply Header No 1 Isol Valve.
- c. IF electrical maintenance was done on 2-SW-P-IB, THEN remove the Danger Tag and install the motor heater fuses on I-EP-CB-84H (PU-D),
located in the Service Water Pumphouse.
- d. IF the control power fuses for 2-EE-BKR-25J5, B Service Water Pump Circuit Breaker 2-SW-P-IB, were removed, THEN install the control power fuses in Cubicle 25J5 as follows:
- 1. Remove Danger Tags from fuses.
sv
- 2. Install the two 30A FU Breaker Close fuses in Device AX.
sv
DOMINION 2-MOP-49.02 North Anna Power Station Revision 16 Page 15 of 15
- 3. Install the two 35A FU Breaker Trip fuses in Device AY.
sv
- 4. Have an Electrician install the two 30A FU Breaker Close fuses in ELEC sv Device AXA.
- 5. Have an Electrician install the two 35A FU Breaker Trip fuses in ELEC sv Device AYA.
- e. Do the following at 2-EE-BKR-25J5, B Service Water Pump Circuit Breaker 2-SW-P-IB:
- 1. Remove the Danger Tag and rack 2-EE-BKR-25J5, B Service Water Pump Circuit Breaker 2-SW-P-IB, to CONN using 0-OP-26.9, 4160 Volt Breaker Operation.
- 2. Place control switch 2-SW-P-IB, B SERVICE WATER PUMP, located on the J Train Safeguards Panel, in AUTO-AFTER-STOP.
(Reference 2.4.7) 5.2.8 IF required, THEN test 2-SW-P-IB in accordance with required PMT to verify operability. Date: _
North Anna RO/SRO NRC ILO Exam Test Item Comments RO test item #96 (G2.2.11) Test Key Answer: "VPAP-1403, Temporary Modifications; FSRC (formerly known as SNSOC)." One of the distractors for this question states the following: "VPAP-1403, Temporary Modifications; Shift Manager." The Test Key Answer is based on the fact that using a jumper to remedy the given situation is controlled under a temporary modification package. All temporary modification packages require final approval of FSRC in accordance with VPAP-1403. Following approval of the temporary modification package, the Shift Manager has final approval of the actual installation of the jumper. The stem does not specify whether we are asking for the final approval of the temporary modification package or final approval for the actual installation of the jumper. Based on the lack of specificity in the stem, both choices are considered acceptable and correct.
References:
VPAP-1403, Substep 5.6.3 VPAP-1403, Substep 6.8.l.a and Temporary Modification form Part D.
DOMINION VPAP-1403 REVISION 11 PAGE 10 OF 29 5.5.2 Reviewing active Temporary Modifications every 30 days. 5.6 Shift Supervisor The Shift Supervisor is responsible for: 5.6.1 Reviewing proposed Temporary Modifications to ensure they will not result in a violation of Technical Specifications (TS), create a hazard to Station safety or personnel, or conflict with existing Station conditions. 5.6.2 Maintaining a Temporary Modification Log and File, and routing Temporary Modification forms for applicable reviews and approval, as specified in this procedure. 5.6.3 Approving Temporary Modification installation and removal. 5.6.4 Ensuring Operations Department personnel are adequately informed of Temporary Modifications and Station status. 5.6.5 Reviewing drawings and procedures affected by Temporary Modifications. 5.6.6 Ensuring any other required notifications are made. 5.6.7 Authorizing restoration of systems to normal configuration. 5.6.8 Verifying that Temporary Modification-required testing is satisfactorily completed prior to declaring equipment inservice. 5.6.9 Reviewing active Temporary Modifications prior to Mode changes. 5.7 Shift Technical Advisor (STA) The STA is responsible for: 5.7.1 Preparing or reviewing (when prepared by another individual) Safety and Regulatory Reviews for Temporary Modifications. 5.7.2 Reviewing Temporary Modifications for concurrence. [Commitment 3.2.12]
DOMINION VPAP-1403 REVISION 11 PAGE 18 OF 29 6.8 Installation of Temporary Modifications 6.8.1 The Temporary Modification Installer shall:
- a. Obtain the Shift Supervisor's approval for installation in Part D of the Temporary Modification Form.
- b. If the Temporary Modification is performed in conjunction with a Tag-Out, then ensure that the Temporary Modification number is entered on the Tag-Out and the Tagging Record number is entered on the Temporary Modification Form.
- c. Install the approved modification in accordance with the Temporary Modification package, including approved procedures, as applicable.
- d. Attach the Special Order Tag to the Temporary Modification, as required, and write the time and date the Temporary Modification is installed on the tag.
- e. Complete the appropriate portions of Part D of the original Temporary Modification Form.
- f. Notify the assigned individual to perform an Independent Verification of the Temporary Modification, as required.
6.8.2 The assigned individual shall perform an Independent Verification of the Temporary Modification, as required, in accordance with approved procedures and VPAP-1405, Independent, Simultaneous, and Documented Peer Check Verification, and complete the necessary portions of Part D of the Temporary Modification Form. 6.8.3 The Temporary Modification Installer shall notify the Shift Supervisor that the Temporary Modification is installed and that the required post installation testing can be performed. 6.8.4 The Shift Supervisor shall:
- a. Direct personnel to perform any required post installation testing to assure that the modified equipment and system will perform its intended function with the modification in place.
- b. Complete Part D of the Temporary Modification Form.
- c. Review the Temporary Modification package to ensure it is complete and properly filled out.
VPAP-1403 REVISION 11 PAGE 24 OF 29 Temporary Modification Dominion Page 1 of 4 VPAp*1403* Attachment 1 Sequence Number
- 1. Affected Systems
- 2. Reason (e.g., awaiting parts, testing, calibration, repairs, temporary power supply)
- 3. Description (e.g., specific details on the aspects of the modification; attach copies of the Work Order, affected marked-up drawings, procedures, and instrument index as applicable) and location (e.g., racks, cubicles, building, area, elevation, and rooms to identify in detail the location of the modification.) Attach sketches as necessary.
- 4. List any Documents, Including Drawings and Procedures (attach copy of PARs), that are Affected and require revision.
- 5. Required System Testing Following TM Installation
- 6. Required System Testing Following TM Removal
- 7. Action Plan for Removal- Close-out Document (REA/DCP, Work Order, PARs)
- 8. Requested By (Name-Please Print) Requested By (Signature) Date
- 9. Responsible Manager (Name-Please Print) Responsible Manager (Signature) Date Key: SNSOC-Station Nuclear Safety Operating Committee:TM-Ternporary Modification; DCP-Design Change Form No. 720598(Apr 2005)
Package; REA-Request for Engineering Assistance; PAR-Procedure Action Request
VPAP-1403 REVISION 11 PAGE 25 OF 29 Temporary Modification Page 2 of 4 VPAP-1403 - Attachment 1 such as pressure, temperature, fluid chemistry, voltage, current material compatibility, or [ ] Yes [ ]No thermal, and dynamic loading? [Commitment 3.2.5]
- 2. Could the TM increase the loading of a safety-related electrical system and is a load calculation [ ] Yes [ ] No needed? [Commitment 3.2.8]
- 3. Could this TM affect the opposite Unit? [Commitment 3.2.7] [ ] Yes [ ]No
- 4. Could this TM affect electrical system functions, breaker coordination, or protective devices? [Commitment 3.2.4] [ ] Yes [ ] No
- 5. Explain "Yes" answers from above.
Attach a copy of the Safety Review/Regulatory Screen (VPAP-3001, Safety and Regulatory Reviews). Independent / Design Authority Review (Signature) Date STA Concurrence (Signature) Date Part C
- Operations Review (To be completed by the Shift Supervisor.)
- 1. Are controlled Station drawings affected by the TM and has it been attached? [ ]Yes [ ] No [ ] N/A
- 2. Necessary Station personnel are informed of the TM? [ ]Yes [ ] No [ ] N/A
- 3. Temporary procedure changes and Temporary procedures are implemented to support the TM? [ ]Yes [ ] No [ ] N/A
- 4. Evaluated need for check valves and/or other anti-siphon protection, if TM utilizes piping or hoses? [ ] Yes [ ] No [ ] N/A
- 5. Limiting conditions and special requirements identified in the TM Safety Review verified
[ ]Yes [ ] No [ ] N/A implemented or in effect (See Part 8, 5)?
- 6. TM verified not to violate Technical Specifications, not to create a hazard to Station safety or personnel, or conflict with existing Station conditions? [ ]Yes [ ] No [ ] N/A
- 7. Special Order Tags (Blue), Form No. 720613 (Large Tag), Form No. 722628 (Small Tag) generated in
[ ]Yes [ ] No [ ] N/A accordance with OPAP-0011 and any special instructions included on the tags?
- 8. TM Log updated? [ ]Yes [ ] No [ ] N/A
- 9. The affected Unit shall not exceed the operating mode of:
- 10. The opposite Unit shall not exceed the operating mode of:
Shift Supervisor (Signature) Date Manager Nuclear Operations or Operations Manager on Call (Signature) Date Key: STA-Shift Technical Advisor; TM-Temporary Modification Fonn No. 720598 (Apr 2005)
VPAP-1403 REVISION 11 PAGE 26 OF 29 Temporary Modification Page 30f4 VPAP-1403 - Attachment 1 Shift Supervisor Approval (Signature) Installation Instructions To Be Used
- 1. Completed By (Name-Please Print) Completed By (Signature) Date
- 2. Independently Verified By (Name-Please Print) Independently Verified By (Signature) Date Notify the Shift Supervisor that the TM is installed and that the required post installation testing can be performed.
Instructions Used For Post Installation Testing Testing Performed By (Name - Please Print) Testing Performed By (Signature) Date 1 . Post installation testing completed satisfactorily? [ ] Yes [ ] No
- 2. Required administrative controls established? [ ] Yes [ ] No Shift Supervisor (Name-Please Print) Shift Supervisor (Signature) Date Instructions Used For TM Removal
- 1. Completed By (Name-Please Print) Completed By (Signature) Date
- 2. Independently Verified By (Name-Please Print) Independently Verified By (Signature) Date Notify the Shift Supervisor that the TM has been removed and that the required restoration testing can be performed.
Instructions Used For TM Removal Restoration Testing Testing Performed By (Name) Testing Performed By (Signature) Date Key: TM-Temporary Modification Form No. 720598(Apr 2005)
VPAP-1403 REVISION 11 PAGE 27 OF 29 Temporary Modification Page 4 of 4 VPAP-1403 - Attachment 1 Year Sequence Number [ ] Unit 1 [ ] Unit 2
. .. I.
- Note: If the TM is used to move radioactive fluids or gases, the Manager Radiological Protection or Radiological Protection alternate must be a member of SNSOC.
SNSOC Authorized Duration SNSOC Chairman Approval (Signature)
- 1. Post restoration testing completed satisfactorily? [ ] Yes [ ] No
- 2. Documentation satisfactorily completed? ] Yes [ ] No
- 3. Temporary drawings removed from Control Room? [ ] Yes [ ] No
- 4. Procedures changed to eliminate TM? (Review Section A, Nos. 4 & 7) [ ] Yes [ ]No
- 5. Necessary Station personnel notified? [ ] Yes [ ] No
- 6. TM Log updated? [ ] Yes [ ] No Shift Supervisor (Signature) Date Key: TM-Temporary Modification; SNSOC-Station Nuclear Safety and Operating Committee Form No. 720598(Apr 2005)
Memorandum May 30,2003 To: All Nuclear Personnel From: D. A. Christian NBU USE OF SHIFT SUPERVISOR AND ASSISTANT SHIFT SUPERVISOR TITLES Job titles for Shift Supervisor/Nuclear Shift Supervisor and Assistant Shift Supervisor/Nuclear Assistant Shift Supervisor at the North Anna and Surry Power Stations are being changed to Shift Manager and Unit Supervisor respectively. The change is being made as a result of a recommendation by INPO and to make titles consistent across the Nuclear Business Unit. Although the change will be effective June 1, 2003, dual titles will need to be maintained until regulatory relevant documents can be revised. The old titles will be maintained for verbatim compliance until the old titles are removed from Station/ISFSI Technical Specifications, Quality Assurance Topical Report, Emergency Plan, Safety Analysis Report, and Station/Corporate procedures, programs and standards. These documents should have the new title incorporated when the need arises for a document revision. Therefore, until these documents are revised and the transition is complete, the dual titles as noted above shall be maintained.
/Signature on file/
D. A. Christian cc: Mr. J. K. Orris Note to Supervisors: Please print and post this for employees without electronic mail,}}