Text

Initial Exam 2011-301 Post Exam Comments
	ML112280226
Person / Time
Site:	Vogtle
Issue date:	08/08/2011
From:	; NRC/RGN-II/DRS/OLB
To:	; Southern Nuclear Operating Co
References
	50-424/11-301, 50-425/11-301
	Download: ML112280226 (63)
	v • d • e

Southern Nuclear Operating Company Nuclear NMP-TR-21 5-F02 souTHERN. Management Exam Question Feedback Version 1.0 COMPANY form - - - Page 1 of 2 NOTE: The Comment box should be checked if the question is not worded clearly or contains errors and/or misleading information. The Challenge box should be checked if the question to be reviewed for credit on your exam. Include your name.

Exam

Title:

Vocitle 2011 NRC SRO Examination 4/1/11 Date Exam Administered Submitted By: Andrew Dyer 4/5/11 Date El Comment Challenge Question Identifier (Complete number example: Question #10 AFW-40201 D08004) LOCT Cycle 3, Question #2)

State the reason for comment or challenge on the question: Question #10 states that the main control room has been evacuated and all switches at PSDB have been taken to local and all switches at PSDA have not been taken to local. An automatic SI then occurs. This will cause Train A SI to automatically actuate. Per 18038-C step 30 RNO p. substep 2, we will start ECCS pumps as necessary to maintain PRZR pressure. Step 39 also has us start ECCS pumps on both trains to maintain PRZR level between 50%-70%. Appendix E, part B, number 7 of NUREG1O21 Supplement 1 states thatyou should assume actions would take place if they are a consequence of conditions stated in the question.

(State the question unambiguously, precisely, and as concisely as possible, but provide all necessary information. Often the individuals who develop a question assume that certain stipulations or conditions are inherent in the question when, in fact, they are not NUREG 1021 Appendix B, page 4 of 29). One must assume all procedural actions between SI actuation and SI termination criteria being met are completed as required. Both trains of ECCS would be running with shutdown panel switches in the LOCAL position and would be required to be shut down at their respective shutdown panels once SI termination criteria were met in 18038-C. The stem of the question does not contain a specific time frame. This would make choice D also a correct answer for question #10.

Operation Management supports this challenge for the reasons stated above.

Challenge Review:

Credit given to the submitter LI YES El NO Key changed El YES El NO [I N/A Submitted for exam bank update El YES El NO El N/A Exam Bank Review:

Comment/Challenge incorporated LI YES LI NO El N/A

Southern Nuclear Operating Company SOUTHERNmi Nuclear Management Reason for not incorporating:

j Exam Question Feedback NMP-TR-215-F02 Version 1.0 Page 2of 2 I

challenge Approved:

Training Supervisor Date N/A if challenge does not result in an exam key change

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved Page Number

- OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 21 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_27. Trip the following breakers:

BREAKER NO. LOCATION SIGNIFICATION EQUIPMENT ACTIONS 1AY2A-17 AB-118

Closes SG ARV 1-PV-3000 1AY2A-18 AB-118

Closes SG ARV 1-PV-3030

_28. Inside Shutdown Panel B, place 1-HS-3010A and 1-HS-3020A to the FIRE EMERGENCY position.

29. Align CCP suction to RWST:

At Shutdown Panel B

Open 1-LV-0112E

Close 1-LV-0112C

-OR-At Shutdown Panel A

Open 1-LV-0112D

Close 1-LV-0112B Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved Page Number OPERATION FROM REMOTE SHUTDOWN -

8/27/2010 PANELS 22 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTIONS

If there is a Control Room fire, Train B is preferred for Pressurizer pressure control.

PRZR Heaters will NOT turn off on low PRZR level after control has been transferred to the Shutdown Panels.

30. Control PRZR pressure between *30 IF PRZR pressure cannot be 2220 and 2260 psig: controlled between 2220 and 2260 psig and pressure is less

. Operate Backup Heaters on than 2220 psig AND lowering, Shutdown Panel A or Shutdown THEN:

Panel B.

a. Verify PRZR PORVs

Operate PRZR Sprays on 1-PV-0455A (Shutdown Shutdown Panel A. Panel A) and 1-PV-0456A (Shutdown Panel B) closed.

Step 30 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved PageNumber OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 23 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

b. UD PRZR PORV can NOT be closed, THEN close its Block Valve:

1-HV-8000A (Shutdown Panel A) 1-HV-8000B (Shutdown Panel B)

-OR-Trip the following:

Breaker 4 on 1ADI M (CB-B52) for 1 -PV-0455A

-OR-Breaker4onlBDlM (CB-B47) for 1 -PV-0456A

c. Verify PRZR Spray Valves on Shutdown Panel A closed.

_d. H PRZR Spray Valve can NOT be closed, THEN stop RCP4(SDPA).

_e. IF PRZR pressure continues lowering due to open Spray Valve, THEN stop RCP 1 (SDPA).

Step 30 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved PageNumber OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 24 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

f. Verify PRZR level greater than 19%,

THEN energize PRZR Heaters (SDP A and SDP B).

g. IF PRZR pressure is less than 1870 psig or continues to lower, THEN perform the following:

1) Close letdown isolation valves:

1-LV-459 (SDP A)

. 1-LV-460 (SDP A)

2) Start ECCS pumps as necessary:

CCP SIP RHR Pumps

3) Align CCP5 to RWST suction:

Open RWST TO CCPA&B SUCTION:

1-LV-0112D

1-LV-0112E

Close VCT OUTLET ISOLATION:

1-LV-0112B

1-LV-0112C Step 30 continued on next page Printed April 5,2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved PageNumber OPERATRDN FROM REMOTE SHUTDOWN 8/27/2010 PANELS 25 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

4) Close CHARGING TO RCS ISOLATION valves:

. 1-HV-8105

. 1-HV-8106

5) Open BIT DISCH ISOLATION valves:

1-HV-8801A

. 1-HV-8801B 30 continued on next page Printed April 5,2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved Page Number OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 26 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED IF PRZR pressure is greater than 2260 psig, THEN:

_a. De-energize PRZR Heaters on Shutdown Panel A and Shutdown Panel B.

_b. Control pressure using Normal PRZR Sprays (SDPA).

c. H Normal PRZR Spray NOT available, AND letdown is in service, THEN use Auxiliary Spray:

_1) Open 1-HV-8145 (SDPA).

2) Close Normal Charging Isolation valves:

. 1-HV-8146 (SDP A)

. 1-HV-8147 (SDP B)

3) Verify Normal PRZR Spray Valves closed:

1-PV-455B (SDP A)

. 1-PV-455C (SDP A)

d. IF Auxiliary Spray NOT available, THEN use a PRZR PORV:

1-PV-455A(SDPA) 1-PV-456A (SDP B)

Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley -- VOgtle Electric Generating Plant - 18038-1 32 DateApproved PageNumber OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 27 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

31. Verify at least one PRZR PORV Block Valve OPEN:

_1 -HV-8000A PRZR PORV 455A BLOCK VALVE (Shutdown Panel A)

_1-HV-8000B PRZR PORV456A BLOCK VALVE (Shutdown Panel B)

CAUTION The AFW pumps and throttle valves will NOT respond to automatic signals after control has been transferred. If an SG fed by the MDAFW pump is also being fed from the TDAFW pump, one of the MDAFW pumps throttle valves or its miniflow valve must remain fully open to maintain minimum miniflow requirements.

32. Control SG WR level(s) between _*32. H MDAFW pumps NOT 65% and 70% on all SGs: available, THEN initiate ATTACHMENT A.

a. On Shutdown Panel A:

_1) Start MDAFW Pump A.

2) Throttle 1-HV-5139 and 1 -HV-51 37.

_3) Operate miniflow 1-FV-5155 as follows:

OPEN Total Pump flow less than 175 gpm.

CLOSE-Total Pumpflow greater than 330 gpm.

Step 32 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved PageNumber OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 28 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

b. On Shutdown Panel B:

_1) Start MDAFW Pump B.

2) Throttle 1-HV-5134 and 1-HV-5132.

_3) Operate miniflow 1-FV-5154 as follows:

OPEN Total Pump flow less than 175 gpm.

CLOSE Total Pump flow greater than 330 gpm.

Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved PageNumber OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 29 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUT ION Closing BSIVs by opening 1AD12-03 and 1BD12-03 will isolate RMW to VCT blender.

33 CHECK RCS temperature - *33 IF temperature is less than STABLE AT OR TRENDING TO 557°F and lowering, 557°F. THEN:

a. Verify SGARVs are closed.

SGARVcanNOTbe closed, THEN control RCS temperature by initiating ATTACHMENT E.

-OR-Close SGARV by opening its breaker:

Brkr 17 on 1AY2A for 1 -PV-3000 (AB-1 18)

Brkr 18 on 1 AY2A for 1 -PV-3030 (AB-1 18)

Brkr 10 on 1BYC1 for 1-PV-3010 (CB-B61)

Brkr 12 on 1BYC1 for 1-PV-3020 (CB-B61)

_b. IF cooldown continues, THEN throttle total AFW flow to a minimum of 570 gpm, OR less if at least one SG level is above 10% NR.

Step 33 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 30 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

c. IF cooldown continues, THEN close MSIVs, BSIVs and SGBD valves by opening the following breakers:

At 1AD12 (CB-B52)

Breaker 8 Breaker 3

At IADII (CB-B52)

Breaker 8

At1BD12(CB-B47)

Breaker 8 Breaker 3 IF temperature greater than 557°F and rising, AND IF a control room fire, THEN control RCS temperature by performing the following:

Initiate ATTACHMENT G.

-OR Use SGARVs 1-PV-3010 and 1-PV-3020 by initiating ATTACHMENT E.

Step 33 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved PageNumber OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 31 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED IF temperature greater than 557°F and rising, AND IF NOT a control room fire, THEN control RCS temperature by performing the following:

Use SG ARVs on Shutdown Panel A or Shutdown Panel B.

-OR-By initiating ATTACHMENT E.

NOTE If an SI actuation occurs, TSC consultation may be necessary after it is staffed.

34 Check if SI is actuated. *34 Go to Step 39.

Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved OPERA11ON FROM REMOTE SHUTDOWN 8/27/2010 PANELS 32 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

35. Check if ECCS flow should be 35. Do not reduce ECCS flow.

reduced:

Consult TSC when it is staffed.

RCS subcooling GREATER THAN 24°F (using Core Exit Go to Step 37.

Temperature and RCS WR

pressure)

. RCS pressure STABLE OR RISING

. PRZR level - GREATER THAN 9%

Secondary heat sink:

Total feed flow to SGs -

GREATER THAN 570 gpm.

-OR-WR level in at least one SG

- GREATER THAN 65%.

NOTE Train B is the preferred charging train for a Control Room fire when operating from Remote Shutdown Panels.

36. Reduce ECCS flow by stopping the following equipment:

All but 1 CCP

SI Pumps

RHR Pumps Printed April 5,2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant io-i DateApproved OPERATION FROM REMOTE SHUTDOWN PageNumber 8/27/2010 PANELS 33 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_37. IF preferred normal power is supplying Emergency 4160V Busses, THEN stop emergency Diesel Generators using local emergency stop pushbuttons.

_38. Check NCP stopped BREAKER

- 38. Perform the following:

1 NAO5-08 TRIPPED (AB-A52).

_a. Turn 1 NAO5-08 control power breaker off.

_b. Trip 1NAO5-08.

Printed April 5,2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18Q1 32 DateApproved OPERATION FROM REMOTE SHUTDOWN PageNumber 8/27/2010 PANELS 34 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTIONS

1-LV-01 12B, 01 12C, 01 12D, 01 12E will NOT reposition on VCT low-low level after they have been transferred to the Shutdown Panels.

PRZR Heaters will NOT cut off on low PRZR level after controls have been transferred to the Shutdown Panels.

When operating from the Shutdown Panels, Train B is the preferable charging train.

Closing BSIVs by opening 1AD12-03 and 1BD12-03 will isolate RMW to VCT blender.

39 Control PRZR level 50% to 70%:

a. Check charging pump suction a. Align charging pump suction aligned to VCT: to RWST:

. Letdown in service At Shutdown Panel B:

(1-FI-0132B on Shutdown PanelA). . Open 1-LV-0112E.

. 1-LV-0112B VCT OUTLET

Close 1-LV-0112C.

ISOLATION on Shutdown Panel A OPEN.

- -OR-

. 1-LV-01 12C VCT OUTLET At Shutdown Panel A:

ISOLATION on Shutdown Panel B OPEN.

. Open 1-LV-01 12D.

. 1-LV-0112D RWSTTO

Close 1-LV-0112B.

CCP-A&B SUCTION on Shutdown Panel A -

CLOSED.

1-LV-01 12E RWST TO CCP-A&B SUCTION on Shutdown Panel B -

CLOSED.

0 Step 39 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Staniey Vogtle Electric Generating Plant 32 DateApproved OPERATION FROM REMOTE SHUTDOWN PageNumber 8/27/2010 PANELS 35 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

b. Open CHARGING TO RCS ISOLATION valves:

1-HV-8105 (Shutdown Panel B)

. 1-HV-8106 (Shutdown Panel A)

c. IF SI actuated, THEN at discretion of Shift Supervisor, close BIT DISCH ISOLATION valves:

. 1-HV-8801A (Shutdown Panel A) 1-HV-8801B (Shutdown Panel B)

_d. Start CCP B on Shutdown Panel B or CCP A on Shutdown Panel A.

e. Start additional CCP if desired while waiting for local charging valve 1-FHC-0121 (AB-C113)to be manned

_f. Stop NCP by locally tripping breaker 1 NAO5-08 (AB-A52).

Step 39 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved PageNumber OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 36 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTES

At SS discretion, ATTACHMENT F may be used to establish Safety Grade Charging even if Instrument Air is available.

CCP motor starting limitations are two consecutive starts from ambient temperature, one start from operating temperature; subsequent start after 15 minutes running or 45 minutes standstill.

ATTACHMENT L should be used to locally operate 1-FHC-0 121.

g. Maintain PRZR level between g. Maintain PRZR level 50% and 70%: between 50% and 70%

using either of the following:

Throttle charging using 1-FHC-0121 (outside NCP With CCP B running:

Room in AB-Ci 13).

1) Verify mini-flow path:

. Control seal injection flow 8 to 13 gpm per RCP by

1-HV-8110 throttling 1-1208-U6-136 and CCP-A&B closing 1-1208-U6-134 (both COMMON in NCP valve gallery MINIFLOW open AB-Ci 12). (Shutdown Panel A).

-OR-

. 1-HV-8111B CCP-B MINIFLOW open

. IF instrument air is NOT (Shutdown Panel available, B).

THEN maintain PRZR level between 50% and 70% by using ATTACHMENT F.

Step 39 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-i DateApproved OPERATION FROM REMOTE SHUTDOWN PageNumber 8/27/2010 PANELS 37 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_2) Isolate letdown by closing LETDOWN ISOLATION VLV UPSTREAM 1-LV-460 AND LETDOWN ISOLATION VLV DOWNSTREAM 1-LV-459 (Shutdown Panel A).

_3) Close CHARGING TO RCS ISOLATION 1-HV-8106 (Shutdown Panel A).

_4) Open 1-HV-8801B BIT DISCH ISOLATION (Shutdown Panel B).

5) Control PRZR level by:

Closing and opening 1-HV-8801 B (Shutdown Panel B).

-OR-Stopping and starting CCP B.

Step 39 continued on next page Printed April 5,2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 PageNumber DateApproved OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 38 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

6) At Shift Supervisors discretion, establish control of seal injection flow by closing 1-1208-U6-153 to isolate 1-FV-0121 (reach rod handwheel in NCP valve gallery AB-C112), and throttle seal injection using 1-1208-U6-151, (reach rod handwheel in CCP B valve gallery AB-CI 19). Flows can be monitored locally on 1-FI-0143B and 1-FI-0142B (FHB-A10) or on Plant Computer.

-OR-With CCP A running:

1) Verify mini-flow path:

. 1-HV-8110 CCP-A&B COMMON MINIFLOW open (Shutdown Panel A).

. 1-HV-81 1 1A CCP-A MINIFLOW open (Shutdown Panel B).

Step 39 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved Page Number OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 39 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

_2) Isolate letdown by closing LETDOWN ISOLATION VLV UPSTREAM 1-LV-460 AND LETDOWN ISOLATION VLV DOWNSTREAM 1-LV-459 (Shutdown Panel A).

3) Close 1-HV-8105 CHARGING TO RCS ISOLATION (Shutdown Panel B).

4) Open 1-HV-8801A BIT DISCH ISOLATION (Shutdown Panel A).

5) Control PRZR level by:

Closing and opening 1-HV-8801A (Shutdown Panel A).

-OR Stopping and starting CCPA.

Step 39 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved Page Number OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 40 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

6) At Shift Supervisors discretion, establish control of seal injection flow by closing 1-1208-U6-153 to isolate 1-FV-0121 (reach rod handwheel in NCP valve gallery AB-C112) and throttle seal injection using 1-1208-U6-152 (reach rod handwheel in CCP A valve gallery AB-Ci 14). Flows can be monitored locally on 1-Fl-0144B and 1-Fl-0145B (AB-A09) or on Plant Computer.

Step 39 continued on next page Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 -

DateApproved Page Number OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 41 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTE Power may need to be restored by closing breakers 1AD12-03 (CB-B52) and 1BDI2-03 (CB-B47) to establish safety grade letdown.

h. H PRZR level can NOT be maintained less than 88%,

THEN open the following until PRZR level lowers to less than 70%:

Train B head vent:

. 1-HV-8095B RX HEAD VENT TO LETDOWN ISOLATION VLV

. 1-HV-8096B RX HEAD VENT TO LETDOWN ISOLATION VLV

1-HV-0442B REACTOR HEAD VENT TO PRT

Train A head vent:

. 1-HV-8095A RX HEAD VENT TO LETDOWN ISOLATION VLV

1-HV-8096A RX HEAD VENT TO LETDOWN ISOLATION VLV

1-HV-0442A REACTOR HEAD VENT TO PRT Printed April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 DateApproved Page Number OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS 42 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED NOTES

RCP 4 (preferentially) or RCP I should be run to provide normal PRZR spray.

Spray valves should be closed if the associated RCP 4 or RCP 1 is not running to prevent spray flow leak through non-isolated spray path.

40. Check at least one RCP - RUNNING. 40. IF offsite power is available and at least one ACCW Pump is in service, THEN:

a. Start the RCP Lift Oil Pump.

b. Verify at Shutdown Panel A PRZR Spray Valves closed:

1-PV-0455B

. 1-PV-0455C Step 40 continued on next page Printed April 5, 2011 at 12:45

Southern Nuclear Operating Company Nuclear I NMP-TR-215-F02 SOUTHERNA Management Exam Question Feedback Version 1.0 - -

CØMPANV orm - Page 1 of 2 NOTE: The Comment box should be checked if the question is not worded clearly or contains errors and/or misleading information. The Challenge box should be checked if the question to be reviewed for credit on your exam. Include your name.

Exam

Title:

Vogtle 2011 NRC RO/SRO Examination 4/1/11 Date Exam Administered Submitted By: A. Curtis Jenkins 4/5/1 1 Date LI Comment Challenge Question Identifier (Complete number example: #52 (RO Exam)

AFW-40201 D08004) LOCT Cycle 3, Question #2)

State the reason for comment or challenge on the question: The question has no correct answer because for the scenario presented there is no need to maintain condenser vacuum. Procedure 18038 requires the crew to maintain one condensate pump running. Procedure 18038 also requires opening the breakers for MSIVs and BSIVs (step 25); thus, isolating main steam. Therefore, unless auxiliary steam is aligned to the other unit (aux steam is normally out-of-service), there is no need to maintain condensate flow for vacuum maintenance. The scenario presented requires both units to implement pçocedure 18038; thus, no auxiliary steam for air ejectors on either unit. Based on the procedure flow path, there is no acceptable answer, it is therefore submitted that this question be removed from the exam.

Operation Management supports this challenge for the reasons stated above.

Challenge Review:

Credit given to the submitter LI YES LI NO Key changed LI YES LI NO LI N/A Submitted for exam bank update LI YES LI NO LI N/A Exam Bank Review:

Comment/Challenge incorporated LI YES LI NO LI N/A Reason for not incorporating:

Southern Nuclear Operating Company I Nuclear NMP-TR-215-F02 I Management Exam Question Feedback Version 1.0 SOUTHERNA

- COMPANY Form Page2of2 I

challenge Approved:

Training Supervisor Date N/A if challenge does not result in an exam key change

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 Page Number DateApproved OPERATION FROM REMOTE SHUTDOWN 8/27/2010 PANELS l9of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTIONS

Closing BSIVs by opening 1AD12-03 and 1BDI2-03 will isolate RMW to VCT blender.

The SG ARVs, MSIVs and BSIVs will fail closed when breakers are opened in the following step. This will require secondary pressure control with ARV5 using ATTACHMENT E or ATTACHMENT G, or Main Steam Code Safeties.

_25. Trip the following breakers:

BREAKER NO. LOCATION SIGNIFICATION EQUIPMENT ACTIONS 1BDI2-08 CB-B47

Closes MSIVs

Closes MFIV5

Closes BFIVs 1BD12-03 CB-B47

Closes BSIVs

Closes 1-HV-7760B (RMW to VCT blender)

Closes Head Vent to PRT 1-HV-0442B

Closes Accumulator Vent 1-HV-0943B

Closes Safety Grade Charging 1-HV-0190B 1ADI2-08 CB-B52

Closes MSIVs

Closes MFIVs

Closes BFIV5 1AD12-03 CB-B52

Closes BSIVs

Closes 1-HV-7760A (RMW to VCT blender)

Closes Head Vent to PRT 1-HV-0442A

Closes Accumulator Vent 1-HV-0943A

Closes Safety Grade Charging 1-HV-0190A IAD11-08 CB-B52

Closes SGBD

Isolates Fire Protection to CNMT PTinted April 5, 2011 at 12:45

Approved By Procedure Number Rev J. B. Stanley Vogtle Electric Generating Plant 18038-1 32 PNu?bi DateApproved OPERATION FROM REMOTE SHUTDO\NN 8/27/2010 PANELS 20 of 123 ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

26. Transfer switches at SWGR as follows:

_a. IABO4 (CB B76) Place Transfer switch HS-IABO4O1B to LOCAL.

_b. Place HS-1ABO4O1A to CLOSE.

c. 1ABO5 (CB B76) Place Transfer switch HS-1ABO5OB to LOCAL.

_d. Place HS-.IABO5O1At0 CLOSE

_e. 1 BBO6 (CB B61) Place Transfer switch HS-1BBO6OIB to LOCAL.

_f. Place HS-1BBO6O1A to CLOSE

g. 1 BBO7 (CB B61) Place Transfer switch HS-1BBO7O1B to LOCAL.

_h. Place HS-1BBO7O1Ato CLOSE I. IAB15 (AB D105) Place Transfer switch HS-1AB15O1B to LOCAL.

j. Place HS-1AB15O1Ato CLOSE

_k. 1BBI6 (AB207) Place Transfer switch HS-1BB16OIB to LOCAL.

_l. Place HS-1BB16O1At0 CLOSE Printed AprD 5, 2011 at 12:45

Southern Nuclear Operating Company Nuclear NMP-TR-21 5-F02 Management Exam Question Feedback Version 1.0 SQUTHRL4.

COMPAV Form - --

Page 1 ot2 NOTE: The Comment box should be checked if the question is not worded clearly or contains errors and/or misleading information. The Challenge box should be checked if the question to be reviewed for credit on your exam. Include your name.

Exam

Title:

Vogtle 2011 NRC RO/SRO Examination 4/1/11 Date Exam Administered Submitted By: Mackie Sinkler 4/5/11 Date fl Comment Challenge Question Identifier (Complete number example: #66 (RO Exam)

AFW-40201 D08004) LOCT Cycle 3, Question #2)

State the reason for comment or challenge on the question: This question is at the wrong license level for the ROs and is not linked to iob requirements for both ROs and SROs. (NUREG 1021 Supplement 1, ES-403, D.1 .b.) Question is technically correct for reasons stated in the Answer/Distracter Analysis. However, knowledge of OMOC qualification criteria is not required by either ROs or SROs and ROs are not required to know what events require notification of the OMOC.

NMP-OS-007-001 Section 6.2, Operations Manager On-Call (attached) discusses the qualifications and the notification requirements. The SRO portion that is not a iob assignment or a function of an SRO is to be knowledgeable on the qualifications of the OMOC. The SROs on shift do not check the qualifications of the OMOC. The premise that the SRO knowledge of the OMOC qualification and knowledge is NOT important to protect the health and safety of the public is in error. The OMOC position is not listed in the station Technical Specifications Administration sections or the UFSAR Section 13, Conduct of Operations Qualification. ANSI 18.1-1 971 (station committed to this ANSI Standard) does not list this position or qualification in this document. Therefore, based on the aforementioned, this question is recommended to be deleted from the RO and SRO exam. The qualifications is NOT a SM (SRO) responsibility for the OMOC notification per step 6.2.2.2. OMOC notification is NOT an OATC or UO responsibility per section 5.9 and 5.10 of NMP-06-007.

The Utility supports this challenge for the reasons stated above.

Operation Management supports this challenge for the reasons stated above.

Challenge Review:

Credit given to the submitter YES LI NO Key changed YES LI NO LI N/A Submitted for exam bank update YES LI NO LI N/A Exam Bank Review:

Comment/Challenge incorporated LI YES LI NO LI N/A Reason for not incorporating:

Southern Nuclear Operating Company f Nuclear NMP-TR-21 5-F02 I SOUTHERN.

- COMPAtY Management Form I -

Exam Question Feedback Version 1.0 Page 2 of 2

challenge Approved:

Training Supervisor Date N/A if challenge does not result in an exam key change

[ Southern Nuclear Operating Company I Nuclear . NMP-OS-007-001 Conduct of Operations Version 8.0 SCUTHERNSa Management COMPM4Y Stancasds anc Expeqtations -

Page 5 49 n ruct oil for the stored energy within the reactor core. Faced with unexpected or uncertain conditions, operators place the plant in a known, safe condition and do not hesitate to reduce power or shut down the reactor.

6.1 .2 Expectations 6.1.2.1 Safety First Safe operation takes precedence over all other considerations. Operators do not hesitate to reduce power or shut down the reactor if nuclear safety is challenged.

Operators recognize degraded conditions that could challenge plant safety or reliability.

Licensed operators comply with Technical Specifications.

Because the need for a time-critical response is infrequent, operators avoid hasty decisions. When faced with time-critical decisions, operators:

Utilize alternate indications to validate information

Assume the available indications are valid until proven otherwise

Develop contingency actions, if time allows

Use all available resources, including people offsite, if necessary

Do not proceed in the face of uncertainty

Do not allow production or cost to override safety

Do not challenge the safe operating envelope 6.1.2.2 Conservative Approach

Information is gathered and analyzed from relevant sources in order to clearly define and provide options for resolution of operational concerns. Short and long-term risks, consequences, and the aggregate impact associated with decision options are critically and objectively considered.

When addressing operational concerns, operators implement plans that include contingencies and compensatory measures to maintain or enhance safety. Decision-makers and their roles and responsibilities are clearly identified. Command and control responsibilities are carried out in accordance with approved procedures. The bases for decisions are communicated throughout the organization. The effectiveness of significant operational decision-making is periodically evaluated.

Human pertormance tools, including team involvement, are used whenever practicable to avoid inappropriate actions when reaching operating decisions.

6.2 Operations Manager On-Call 6.2.1 Standard The on-duty Shift Manager consults with the management team in order to improve the quality of operational decisions. To this end, the on-duty Shift Manager notifies the Operations Manager on Call (OMOC) promptly of significant plant events.

Southern Nuclear Operating Company I

j, SWTHERNA Nuclear Management mston* I Conduct of Operations Standards an Expectations j NMP-OS-007-001 Version 8.0

-Page6o+49 6.2.2 Expectations 6.2.2.1 OMOC Responsibilities (may be coincident with EP on call functions)

An individual, assigned by the Operations Manager, is on-call to assist the duty Shift Manager in the resolution of problems.

The individual assigned as OMOC for the site is on-call and capable of arriving at the plant promptly if needed. Individuals fulfilling the OMOC function are knowledgeable at the SRO level.

6.2.2.2 OMOC Notification The OMOC serves as a resource for the Shift Manager to use to discuss operational decisions and insights from an Operations Department leadership point of view. The off shift operations leadership may have insights that are not known to the Shift Manager regarding overall plant conditions. The duty Shift Manager should contact the OMOC regarding conditions or events that are deemed to be of interest to management. If in doubt, the duty Shift Manager is encouraged to notify the OMOC.

In addition to notifications required specifically by procedure, the duty Shift Manager notifies OMOC without delay if any of the following occur:

Unplanned Reactor Protection System or Engineered Safeguard Function actuation

Personnel injury involving Operations personnel

Unplanned entry into a Technical Specification LCO Action Statement of less than 7 days

Valid entry into an abnormal or emergency procedure

Unplanned plant transient or load reduction

Out-of-specification chemistry that could result in significant short term damage (action level 2 or greater)

Significant radiological event

Unplanned condition that results in a heightened risk (orange or red)

Any reportable event (e.g., 10 CFR 50.72 or 50.73, environmental event)

Missed technical specification surveillance or test

Valid entry into the site Emergency Plan

Reactivity incident or event

Consequential component mispositioning

Significant human performance error involving Operations personnel 6.3 Performance Monitoring 6.3.1 Standard Operations personnel reinforce desired behaviors to optimize individual and team performance.

Southern Nuclear Operating Company Nuclear NMP-TR-21 5-F02

£OUTMRN Managçrnent Exam Question Feedback Version 1:0 COMPANY Form Pacieiof2 NOTE: The Comment box should be checked if the question is not worded clearly or contains errors and/or misleading information. The Challenge box should be checked if the question to be reviewed for credit on your exam. Include your Exam

Title:

Voqtle 201 1 NRC SRO Examination 4/1/11 Date Exam Administered Submitted By: A. Curtis Jenkins 4/5/11 Date D Comment Challenge Question Identifier (Complete number example: #78 (SRO Exam)

AFW-40201 D08004) LOCT Cycle 3, Question #2)

State the reason for comment or challenge on the question: Contrary to the Answer/Distracter Analysis, the correct answer is C. This is based on T.S. B 3.4.11, Pressurizer Power Operated Relief Valves (PORV5), which states, An OPERABLE PORV is required to be capable of manually opening and closinq, and not experiencing excessive seat leakage. Excessive seat leakage, although not associated with a specific criteria, exists when conditions dictate closure of the block valve to ilmit leakage.

Therefore, based on the Technical Specifications Bases, C is the only correct answer.

Operation Manaciement suoDorts this challenae for the reasons stated above.

Challenge Review:

Credit given to the submitter D YESLI NO Key changed LI YES NO LI N/A Submitted for exam bank update LI YES NO LI N/A Exam Bank Review:

Comment/Challenge incorporated YES LI NOD N/A Reason for not incorporating:

challenge Approved:

Training Supervisor Date

Southern Nuclear Operating Company Nuclear NMP-TR-21 5-F02 Management Exam Question Feedback Version tO sovTKInMS. -

COMPANY Form - - - Page 2 of 2 N/A if challenge does not result in an exam key change

Pressurizer PORVs

-3.411 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 Separate Condition entry is allowed for each PORV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more PORVs A.1 Close and maintain power 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable and capable to associated block valve.

of being manually cycled.

B. One PORV inoperable B.1 Close associated block 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and not capable of being valve.

manually cycled.

AND B.2 Remove power from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated block valve.

AND B.3 Restore PORV to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

(continued)

Vogtle Units 1 and 2 3.4.11-1 Amendment No. 137 (Unit 1)

Amendment No. 116 (Unit 2)

Pressurizer PORVs 341I ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One block valve C.1 Place associated PORV 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable, in manual control.

AND C.2 Restore block valve to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status.

D. Required Action and D.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A, B, AND or C not met.

D.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months E. Two PORVs inoperable E.1 Close associated block 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and not capable of being valves.

manually cycled.

AND E.2 Remove power from 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated block valves.

AND E.3 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months AND E.4 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months F. More than one block F.1 Place associated PORVs 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months valve inoperable, in manual control.

AND (continued)

Vogtle Units I and 2 3.4.11-2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Pressurizer PORVs 34A-1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. (continued) F.2 Restore one block valve 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to OPERABLE status.

AND F.3 Restore remaining 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months block valve to OPERABLE status.

G. Required Action and G.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition F not AND met.

G.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1 NOTE Not required to be performed with block valve closed in accordance with the Required Action of Conditions A, B, or E.

Perform a complete cycle of each block valve. 92 days SR 3.4.11.2 Perform a complete cycle of each PORV. 18 months Vogtle Units I and 2 3.4.1 1-3 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Pressurizer PORVs

- g34-i1 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 safety-related DC solenoid operated valves that are controlled to open at a specific 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 plant 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 block 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 power supplies to the PORVs, their block valves, and their controls are Class 1 E. Two PORVs and their associated block valves are powered from two separate safety trains (Ref. 1).

The plant has two PORVs, each having a relief capacity of 210,000 lb/hr at 2385 psig. The functional design of the PORVs is based on maintaining pressure below the Pressurizer PressureHigh reactor trip setpoint up to and including the design step-load decreases with steam dump.

In addition, the PORVs minimize challenges to the pressurizer (continued)

Vogtle Units I and 2 B 3.4.11-1 Revision No. 0

Pressurizer PORVs Ba4.1i BASES BACKGROUND safety valves and also may be used for cold overpressure (continued) protection. See LCO 3.4.12, Cold Overpressure Protection System (COPS).

APPLICABLE Plant operators may employ the PORVs to depressurize the RCS SAFETY ANALYSES in response to certain plant 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 or auxiliary pressurizer spray may 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.

n addition, in the event of an inadvertent safety injection actuation at power, the potential for pressurizer filling and subsequent water relief via the pressurizer safeties (PSV5) is evaluated (FSAR section 15.5.1).

Operator action to make one PORV available is credited in the analysis to mitigate this event. If the PORV is available for automatic actuation, the event consequences would be mitigated directly by preventing water relief through the PSVs. However, automatic actuation is not required to mitigate this event. The analysis includes an acceptable delay for the operator to open a block valve and to manually control the PORV if necessary.

The PORVs also provide the safety-related means for reactor coolant system depressurization to achieve safety-grade cold shutdown and to mitigate the effects of a loss of heat sink or an SGTR. They are modeled in safety analyses for events that result in increasing RCS pressure for which departure from nucleate boiling ratio (DNBR) criteria, pressurizer filling, or reactor coolant saturation 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, automatic actuation is not required to mitigate these events, and PORV automatic operation is, therefore, not an assumed safety function. Events that assume this condition include a turbine trip, loss of normal feedwater, and feedwater line break (Ref. 2).

Pressurizer PORVs satisfy Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

(continued)

Vogtle Units 1 and 2 B 3.4.11-2 Rev. 3-10/01

Pressurizer PORVs B34.it.

BASES 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, or loss of heat sink, and to achieve safety grade cold shutdown. The PORVs are considered OPERABLE in either the manual or automatic mode. The PORVs (PV-455A and PV-456A) are powered from 125 V MCCs 1/2AD1M and 1/2BDIM, respectively. If either or both of these MCCs become inoperable, the affected PORV(s) are to be considered inoperable.

By maintaining two PORVs and their associated block valves OPERABLE, the single failure criterion is satisfied.

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 criteria, exists when conditions dictate closure of the block valve to limit leakage.

An OPERABLE block valve may be either open and energized, 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 that is capable of being manually cycled (e.g., as in the 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. Satisfying the LCO helps minimize challenges to fission product barriers.

APPLICABILITY The PORVs are required to be OPERABLE in MODES 1, 2, and 3 for manual actuation to mitigate a steam generator tube rupture event, an inadvertent safety injection, and to achieve safety grade cold shutdown. In addition, the block valves are required to be OPERABLE to limit the potential for a small break LOCA through the flow path. The most likely cause for a PORV small break LOCA is a result of a pressure increase transient that causes the PORV to open. Imbalances in the energy output of the core and heat removal by the secondary system can cause the RCS 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 (continued)

Vogtle Units I and 2 B 3.4.11-3 Rev. 1-2/00

Pressurizer PORVs B3.4.11-BASES APPLICABILITY requirements in MODES 4, 5, and 6 with the reactor vessel head in place.

(continued)

ACTIONS A Note 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).

A.1 PORVs may be inoperable and capable of being manually cycled (e.g.,

excessive seat leakage, instrumentation problems, or other causes that do not create a possibility for a small break LOCA). In this condition, either the PORVs must be restored or the flow path isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . 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. The PORVs may be considered OPERABLE in either the manual or automatic mode. This permits operation of the plant 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 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is based on plant operating experience that has shown that minor problems can be corrected or closure accomplished in this time period.

B.1, B.2, and B.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 Times of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months are reasonable, based on challenges to the PORVs during this time period, and provide the operator adequate time to correct the situation. If the inoperable valve cannot be restored to OPERABLE status, it must be isolated within the specified time. Because there is at least one PORV that remains OPERABLE, an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is provided to restore the inoperable PORV to (continued)

Vogtle Units 1 and 2 B 3.4.11-4 Rev. 26/05

Pressurizer PORVs B3.4.l1 BASES ACTIONS B.1, B.2, and B.3 (continued)

OPERABLE status. If the PORV cannot be restored within this additional time, the plant must be brought to a MODE in which the LCO does not apply, as required by Condition D.

C.1 and C.2 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 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , 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 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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. The time allowed to restore the block valve is based upon the Completion Time for restoring an inoperable PORV in Condition B since the PORV may not be capable of mitigating an event if the inoperable block valve is not fully open. If the block valve is restored within the Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the PORV may be restored to automatic operation. If it cannot be restored within this additional time, the plant must be brought to a MODE in which the LCO does not apply, as required by Condition D.

0.1 and D.2 If the Required Action of Condition A, B, or C is not met, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODES 4, 5, and 6, maintaining PORV OPERABILITY may be required. See LCO 3.4.12.

(continued)

Vogtle Units 1 and 2 B 3.4.11-5 Rev. 1-2/00

Pressurizer PORVs 3,411 BASES ACTIONS E.1, E.2, E.3, and E.4 (continued)

If more than one PORV is inoperable and not capable of being manually cycled, it is necessary to either restore at least one valve within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or isolate the flow path by closing and removing the power to the associated block valves. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable, based on the small potential for challenges to the system during this time and provides the operator time to correct the situation. If one PORV is restored and one PORV remains inoperable, then the plant will be in Condition B with the time clock started at the original declaration of having two PORVs inoperable. If no PORVs are restored within the Completion Time, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODES 4, 5, and 6, maintaining PORV OPERABILITY may be required. See LCO 3.4.12.

F.1, F.2, and F.3 If more than one block valve is inoperable, it is necessary to either restore the block valves within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , or place the associated PORVs in manual control and restore at least one block valve within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and restore the remaining block valve within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The Completion Times are reasonable, based on the small potential for challenges to the system during this time and provide the operator time to correct the situation.

G.1 and G.2 If the Required Actions of Condition F are not met, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant (continued)

Vogtle Units 1 and 2 B 3.4.11-6 Revision No. 0

Pressurizer PORVs B3.414 BASES ACTIONS G.1 and G.2 (continued) conditions from full power conditions in an orderly manner and without challenging plant systems. In MODES 4, 5, and 6, maintaining PORV OPERABILITY may be required. See LCO 3.4.12.

SURVEILLANCE SR 3.4.11.1 REQU I REMENTS Block valve cycling verifies that the valve(s) can be closed if needed.

The basis for the Frequency of 92 days is the ASME Code,Section XI (Ref. 2). The Note 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 Conditions A, B, or E.

SR 3.4.11.2 SR 3.4.11.2 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. The Frequency of 18 months is based on a typical refueling cycle and industry accepted practice.

REFERENCES 1. Regulatory Guide 1.32, February 1977.

2. AS ME, Boiler and Pressure Vessel Code,Section XI.

Vogtle Units 1 and 2 B 3.4.11-7 Revision No. 0

Southern Nuclear Operating Company Nuclear NMP-TR-21 5-F02 Management .xam Question Feedback Version 1-.O COMPANY Form Page 1 of 2 NOTE: The Comment box should be checked if the question is not worded clearly or contains errors andlor misleading information. The Challenge box should be checked if the question to be reviewed for credit on your exam. Include your name.

Exam

Title:

Vogtle 2011 NRC SRO Examination 4/1/11 Date Exam Administered Submitted By: Carla Smith 4/5/11 Date Comment Challenge Question Identifier (Complete number example: #90 (SRO Exam)

AFW-40201 D08004) LOCT Cycle 3, Question #2)

State the reason for comment or challenge on the question: This question stem states, The Main Control Board indicators for various Steam Generator (SG) pressure channels display a RED Bezel on the bottom of the indicator. The SG pressures are also displayed on the Remote Shutdown Panels. Which ONE of the following is correct concerning both (1) the Control Room indicators and (2) the Remote Shutdown Panel indicators for SG Pressure?

Based on instructor interviews with the candidates, the question stem was confusing in that it biased the students to assume that the question was asking what was the difference between the RED Bezels in the control room versus the B Remote Shutdown panel, in that case A would be the correct answer. Five out of six SROs picked A. (See VEPG-FSAR-1 8.1 .2.11 and FSAR-7 Alternate Shutdown Indication System page 7.4-14)

This question confusion may be contributed to psychometric deficiencies, namely this question is a list of true false statements (refer to NUREG-1 021 Supplement 1, Appendix B for basic psychometric principles of exam writing. The stem of the question should have directly asked the question if the SG Pressure is fire qualified.

This question therefore has an unclear stem that confused the applicants and did not ask the question in a more direct manner. Interviewing a sample of the candidates, one indicated that a group of SROs studying for the exam discussed the RED Bezels. The question was asked of the candidates, which instruments went through Eagle 21 (fire qualified instruments), the sampling could answer the question.

(Refer to NUREG-1021 Supplement 1, ES-403, D.b., unclear and confusing stems.). Based on aforementioned, tis question is recommended to be deleted from the SRO exam.

The utility suonorts this cMllenoed based on the reasons above

Challenge Review:

Credit given to the submitter YES El NO Key changed YES El NO N/A Submitted for exam bank update YES El NO N/A Exam Bank Review:

Comment/Challenge incorporated YES El NO El N/A Reason for not incorporating:

challenge Approved:

Training Supervisor Date N/A if challenge does not result in an exam key change

VEGP-FSAR-1 8 18.1.2.11 Labeling (Grouping. Marking)

This is defined as alphanumeric, color, and other visual methods used for controls and displays to improve the performance of control room personnel.

A color coding scheme for the switchplates on the QMCB, QEAB, QHVC, QPCP, PSDA, and PSDB is implemented in a plant procedure.

Additionally:

A. Controls located on the bench board section of the QMCB are grouped by subsystems divided by the demarcation lines (paragraph 18.1.1.2.A) and enveloped, where room permits, with hierarchical labels for subsystems at the top center of the envelopes to improve recognition of functional grouping.

B. Labels are located to minimize interference with operator view and to avoid interference with other control functions.

C. Labels are designed for legibility and visibility based on the contrast between the lettering and its background.

D. Labels are designed to have white letters on black tags. Black on white is sometimes used to highlight a display.

E. Labels are designed with 3/16-in, capital letters. Annunciator window engravings are designed with 1/4-in, or 3/16-in, letters. The 1/4-in, letters are used to improve readability when message length permits.

F. Controls and displays are labeled with service description and tag number engravings. In addition, the control switch modules shall contain engravings for switching development functions, equipment-actuated functions, and train, if applicable.

G. Labels are placed above the instruments and on the escutcheon plates for control switches to allow adequate viewing from a distance of about 3 ft.

H. Labels for similar devices throughout a board are designed to be uniform in style, size, lettering, and use of abbreviations, with the exception of integral panels supplied by the vendor and inserted into the boards or panels as a unit.

I. Labels are designed and mounted so that they cannot easily be damaged or removed.

J. Labels and tag numbers are designed for accessibility and visibility during maintenance.

K. Labels are concise with minimum repetitive information and are directly usable with minimum decoding and interpretation of the service descriptions and abbreviations. A hierarchical label is used to highlight functional grouping.

L. Labels are not designed to describe engineering characteristics, name of manufacturer, trademarks, or nonfunction-related nomenclatures of the equipment.

M. Shades of colors used for mimics on the QEABs are designed to have maximum contrast between the mimic bus and the boards.

N. Safety-related post-accident monitoring instrumentation is identified by a dark red line on the black bezel base of each instrument.

18.1-12 REV 14 10/07

Southern Nuclear Operating Company Nuclear NMP-TR-21 5-F02 5OUTHFRN. Mana9ement Exam Question Feedback Version 1.0 COMPANY Form Page 1 of 2 NOTE: The Comment box should be checked if the question is not worded clearly or contains errors and/or misleading information. The Challenge box should be checked if the question to be reviewed for credit on your exam. Include your name.

Exam

Title:

Voqtle 2011 NRC SRO Examination 4/1111 Date Exam Administered Submitted By: Mackie Sinkler 4/6/11 Date El Comment Challenge Question Identifier (Complete number example: #97 (SRO Exam)

AFW-40201 D08004) LOCT Cycle 3, Question #2)

State the reason for comment or challenge on the question: This question also has C as a correct answer based on the following discussion. The question states, The Unit 2 CSTs are (inoperable / operable (question answer / distractor) and the basis for the Tech Spec minimum level requirements are for (holding the unit in MODE 3 for 7/ 4 (question answer / distractor)hours followed by a 5 hour5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months cooldown to RHR entry conditions. Based on T.S. 3.7.6 and the associated Bases T.S. B 3.7.6 (attached), Unit Two is Inoperable (CST #2 is 11% level). Bases 3.7.6, Actions B.1 and B.2 states, If the AFW pumps cannot be aligned to an OPERABLE CST within the required Completion Time, the unit must be placed in a MODE in which the LCD does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Answer C is also correct based on 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months in MODE 3 with 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months for MODE 4, RHR entry, as the Bases states, MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Therefore C would be a correct answer. Option C for this question is also a correct subset of the bounding time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Based on outage performance in 1 Ri 6, from the time the unit was offline until RHR was 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months (per the detailed outage schedule). This supports the five hours given in the question stem. Therefore there are two correct answers for this question.

Operation Management supports this challenge for the reasons stated above.

Challenge Review:

Credit given to the submitter El YES El NO Key changed El YES El NO El N/A Submitted for exam bank update El YES El NO El N/A Exam Bank Review:

Comment/Challenge incorporated El YES El NO El N/A Reason for not incorporating:

S.outhern Nuclear Operating Company Nuclear NMP-TR-21 5-F02 SOUTHERNA Management Exam Question Feedback Version 1.0 For Pe2OfZ

challenge Approved:

Training Supervisor Date N/A if challenge does not result in an exam key change

VEGP-FSAR-9

3. Ultimate heat sink maximum temperature case (one-train operation post LOCA until basin depletion) Units 1 and 2;

4. Ultimate heat sink design, MSLB accident case (two-train operation post MSLB accident inside containment for 1 day followed by one-train operation for 29 days) Unit 1 [HISTORICAL];

5. Ultimate heat sink performance, post MSLB accident (during one-train operation post-MSLB accident inside containment) Unit I [HISTORICAL].

Based on this data, the governing case for the maximum inventory loss is two-train operation post-LOCA for I day followed by one-train operation for the remainder of the accident duration.

The governing case for the maximum basin temperature and NSCW outlet temperature from the fan coolers is one-train continuous operation post-LOCA. On this basis, only these two cases were evaluated for Unit 2 to account for the difference in the heat removal requirement.

For the Unit 1 3626 MWt plant uprate, cases 1 and 3 were reanalyzed to determine the impact to the plant.

Unit 1 system performance data, including containment conditions, total heat loads, evaporation rates, and basin water depth and temperature for cases 2, 4, and 5 are presented in tables 9.2.5-4, 9.2.5-6, and 9.2.5-7 for historical purposes. These values do not represent the Unit I power uprate or SFP reracking.

Unit 1 system performance data for cases I and 3 are presented in tables 9.2.5-3 and 9.2.5-5.

Table 9.2.5-10 provides shutdown heat loads with loss of offsite power for two-train and one-train operation. The two-train analyses (tables 9.2.5-3, 9.2.5-4, and 9.2.5-6) used meteorological conditions (paragraph 9.2.5.2.5.B) which maximize total water usage (drift and evaporation) over the postulated 30-day period. Since blowdown is terminated during accident conditions, blowdown need not be considered in basin sizing. The one-train analyses, for which system temperatures are a maximum, used meteorological conditions (paragraph 9.2.5.2.5.A) which maximize the cold water outlet temperature from the cooling tower.

For the 1-day, two-train analyses (tables 9.2.5-3 and 9.2.5-6), water from the basin of the inactive train is transferred to the basin of the active train until the inactive train basin is depleted. For the one-train analyses (tables 9.2.5-5 and 9.2.5-7), no interbasin water transfer is assumed.

During and following a tornado, offsite power is presumed lost, with a subsequent reactor trip.

Immediately following the reactor trip, the auxiliary feedwater system (subsection 10.4.9) is used to maintain the plant at hot standby, using the inventory of the safety-grade condensate storage tanks (CSTs) to effect reactor heat removal. Each CST has sufficient auxiliary feedwater supply to hold the plant at hot standby for 4 h followed by a 5-h cooldown to the temperature (350°F) at which the residual heat removal (RHR) Wm may be piad to service. If both CSThi available, the allowable time at hot standby is increased to 31 h before cooldown must be initiated. Once the RHR system is placed in service, the RHR heat load is rejected to the component cooling water (COW) system which in turn rejects the heat load to the ultimate heat sink (the cooling tower) via the nuclear service cooling water (NSCW) system.

During hot standby assuming the most limiting single active failure (loss of one complete NSCW train) plus loss of one fan in the operable tower as a result of a missile strike, the remaining three fans in the operating train will maintain the temperature in the tower basin below 90°F.

Thus the ability to maintain hot standby under such conditions is provided. During the subsequent cooldown using the RHR and COW systems, three fans in one NSOW tower are adequate to bring the plant to a cold shutdown condition. However, because the tower is only 75% effective, cold shutdown will not be achieved in 32 h (36-4) stated in paragraph 9.2.2.1.1.F.

9.2-21 REV 17 3/11

CST 3.7.6 THIS PAGE APPLICABLE TO UNIT I ONLY 3.7 PLANT SYSTEMS 3.7.6 Condensate Storage Tank (CST)

LCO 3.7.6 One CST shall be OPERABLE with a safety-related volume 340,000 gallons.

APPLICABILITY: MODES 1, 2, and 3, ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. CST volume not within A.1 Align Auxiliary Feedwater 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months limit, pumps to OPERABLE CST.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 4 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.6.1 Verify the CST volume is within limit. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Vogtle Units I and 2 3.7.6-1 Amendment No. 105 (Unit 1)

CST 3.7.6 THIS PAGE APPLICABLE TO UNIT 2 ONLY 3.7 PLANT SYSTEMS 3.7.6 Condensate Storage Tank (CST)

LCO 3.7.6 Two CSTs shall be OPERABLE with:

a. A combined safety-related volume of 378,000 gallons; and

b. The CST aligned to supply the auxiliary feedwater pumps shall have a safety-related volume 340,000 gallons.

APPLICABILITY: MODES 1, 2, and 3, ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. CST volume(s) not A.1 Restore volume(s) to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months within limit(s), within limit(s).

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND B.2 Be in MODE 4 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.6.1 Verify CST volumes within limits. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Vogtle Units 1 and 2 3.7.6-1 Amendment No. 120 (Unit 2)

CST B 37.6 B3.7 PLANTSYSTEMS B 3.7.6 Condensate Storage Tank (CST)

BASES BACKGROUND The two CSTs (V4001 and V4002) provide redundant safety grade sources of water to the steam generators for removing decay and sensible heat from the Reactor Coolant System (RCS). The CSTs provide a passive flow of water, by gravity, to the Auxiliary Feedwater (AFW) System (LCO 3.7.5). The steam produced is released to the atmosphere by the main steam safety valves or the atmospheric dump valves.

When the main steam isolation valves are open, the preferred means of heat removal is to discharge steam to the condenser by the nonsafety grade path of the steam dump valves. The condensed steam is returned to the CST. This has the advantage of conserving condensate while minimizing releases to the environment.

Because the CST is a principal component in removing residual heat from the RCS, it is designed to withstand earthquakes and other natural phenomena, including missiles that might be generated by natural phenomena. The CST is designed to Seismic Category I to ensure availability of the feedwater supply.

A description of the CST is found in the FSAR, Subsection 9.2.6 (Ref. 1).

APPLICABLE The CST provides cooling water to remove decay heat and to SAFETY ANALYSES cool down the unit following all events in the accident analysis as discussed in the FSAR, Chapters 6 and 15 (Refs. 2 and 3, respectively). For anticipated operational occurrences and accidents that do not affect the OPERABILITY of the steam generators, the analysis assumption is generally 60 minutes at MODE 3, steaming through the MSSVs, followed by a cooldown to residual heat removal (RHR) entry conditions.

The limiting event for the condensate volume is the large feedwater line break coincident with a loss of offsite (continued)

Vogtle Units 1 and 2 B 3.7.6-1 Revision No. 0

CST 3.7.

BASES APPLICABLE power. Single failures that also affect this event include SAFETY ANALYSES the following:

(continued)

a. Failure of the diesel generator powering the motor driven AFW pump to the unaffected steam generator (requiring additional steam to drive the remaining AFW pump turbine);

and

b. Failure of the steam driven AFW pump (requiring a longer time for cooldown using only one motor driven AFW pump).

These are not usually the limiting failures in terms of consequences for these events.

A nonlimiting event considered in CST inventory determinations is a break in either the main feedwater or AFW line near where the two join. This break has the potential for dumping condensate until terminated by operator action, since the Auxiliary Feedwater Actuation System would not detect a difference in pressure between the steam generators for this break location. This loss of condensate inventory is partially compensated for by the retention of steam generator inventory.

The CST satisfies Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

LCO To satisfy accident analysis assumptions, the CST must contain sufficient cooling water to remove decay heat for 60 minutes following a reactor trip from 102% RTP, and then to cool down the RCS to RHR entry conditions, assuming a coincident loss of offsite power and the most adverse single failure. In doing this, it must retain sufficient water to ensure adequate net positive suction head for the AFW pumps during cooldown, as well as account for any losses from the steam driven AFW pump turbine, or before isolating AFW to a broken line.

The CST level required is equivalent to a usable volume of 340,000 gallons (66% instrument span) which is based on holding the unit in MODE 3 for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , followed by a 5 hour5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months cooldown to RHR entry conditions at 50°F/hour with one Reactor Coolant Pump in operation. This basis is (continued)

Vogtle Units I and 2 B 3.7.6-2 Rev. 1-10/01

CST

- B3.7.6 THIS PAGE APPLICABLE TO UNIT I ONLY BASES LCO established in Reference 4 and exceeds the volume required (continued) by the accident analysis.

The OPERABILITY of the CST is determined by maintaining the tank level at or above the minimum required level. Either CST V4001 or CST V4002 may be used to satisfy the LCO requirement.

APPLICABILITY In MODES 1, 2, and 3, the CST is required to be OPERABLE.

Due to the reduced heat removal requirements and short period of time in MODE 4 and the availability of RHR in MODE 4, the LCO does not require a CST to be OPERABLE in this MODE.

In MODE 5 or 6, the CST is not required because the AFW System is not required.

(continued)

Vogtle Units 1 and 2 B 3.7.6-3 Rev. 1-3/99

CST B3.T THIS PAGE APPLICABLE TO UNIT 2 ONLY BASES LCO established in Reference 4 and exceeds the volume required (continued) by the accident analysis.

The OPERABILITY of the CST is determined by maintaining the tank level at or above the minimum required level. Either CST V4001 or CST V4002 may be used to satisfy the LCO requirement.

For Unit 2 only, two CSTs are required to be OPERABLE with a combined safety-related volume of 378,000 gallons, and the CST aligned to supply the auxiliary feedwater pumps shall have a safety-related volume 340,000 gallons. The basis for requiring an additional 38,000 gallons of safety-related usable CST inventory is to support the elimination of the bypass line and associated valve bonnet depressurization line for the 2HV-8701 B RHR suction isolation valve.

2HV-8701B valve bonnet and the space between the 2HV-8701B and 2HV-8701A RHR suction isolation valves have depressurized sufficiently to allow the suction isolation valves to be opened.

APPLICABILITY In MODES 1, 2, and 3, the CST is required to be OPERABLE.

Due to the reduced heat removal requirements and short period of time in MODE 4 and the availability of RHR in MODE 4, the LCO does not require a CST to be OPERABLE in this MODE.

In MODE 5 or 6, the CST is not required because the AFW System is not required.

(continued)

Vogtle Units 1 and 2 B 3.7.6-3 Rev. 0-3/06

CST THIS PAGE APPLICABLE TO UNIT I ONLY BASES (continued)

ACTIONS A.1 and A.2 If the required CST volume is not within limit, the Completion Time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provides sufficient time for the three AFW pumps to be aligned to the OPERABLE CST. This Completion Time is acceptable based on: 1) Operating experience to perform the required valve operations; 2) The ACTIONS being entered as soon as the CST level decreased below the limit, which would most probably leave sufficient capacity in the inoperable CST to support AFW pump operation for at least the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time; and 3) The low probability of an event occurring during this interval that would require the CST to be fully OPERABLE.

B.1 and B.2 If the AFW pumps cannot be aligned to an OPERABLE CST within the required 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . 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.

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS CSTV4001 (LI-5101 and LI-5111A)

CSTV4002 (LI-5104 and LI-5116A)

This SR verifies that the CST contains the required volume of cooling water. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is based on operating experience and the need for operator awareness of unit evolutions that may affect the CST inventory between checks.

Also, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications in the control room, including alarms, to alert the operator to abnormal deviations in the CST level.

(continued)

Vogtle Units 1 and 2 B 3.7.6-4 Revision No. 0

CST THIS PAGE APPLICABLE TO UNIT 2 ONLY BASES (continued)

ACTIONS A.1 and A.2 If one or both of the CST volumes are not within limits, the volume(s) must be restored to within limits within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . This Completion Time is acceptable based on : 1) The ACTIONS being entered as soon as the CST level(s) decreased below limit(s), which would provide reasonable assurance of at least sufficient capacity to support AFW operation for at least the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time; and 2) The low probability of an event occurring during this interval that would require the CSTs to be fully OPERABLE.

B.1 and B.2 If the AFW pumps cannot be aligned to an OPERABLE CST within the required 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . 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.

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS CSTV4001 (LI-5101 and LI-5111A)

CST V4002 (LI-5104 and LI-5116A)

This SR verifies that the CSTs contain the required volumes of cooling water. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is based on operating experience and the need for operator awareness of unit evolutions that may affect the CST inventory between checks.

Also, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications in the control room, including alarms, to alert the operator to abnormal deviations in the CST level.

(continued)

Vogtle Units I and 2 B 3.7.6-4 Rev. 0-3/06

CST 3J.

BASES (continued)

REFERENCES 1. FSAR, Subsection 9.2.6.

2. FSAR, Chapter 6.

3. FSAR, Chapter 15.

4. Branch Technical Position RSB 5-1, Rev. 2, July 1981, Design Requirements of the Residual Heat Removal System.

Vogtle Units 1 and 2 B 3.7.6-5 Revision No. 0

- VEGP-FSAR-9 9.2.6 CONDENSATE STORAGE FACILITY The condensate storage facility consists of two condensate storage tanks (CSTs), a vacuum degasifier, degasifier feed and transfer pumps, degasifier vacuum pumps, and associated valves, piping, and instrumentation. The condensate storage facility provides the following:

Degasified and demineralized makeup and surge capacity to compensate for changes in the turbine plant water inventory.

Reserve supply for emergency shutdown decay heat removal in the event of failure of the normal feedwater system.

Secondary system fill water for plant startups.

9.2.6.1 Design Bases Protection of the condensate storage from wind and tornado effects is discussed in section 3.3.

Flood protection is discussed in section 3.4. Missile protection is discussed in section 3.5.

Protection against the dynamic effects associated with postulated rupture in piping is addressed in section 3.6. Environmental design is discussed in section 3.11.

9.2.6.1.1 Safety Design Bases A. The condensate storage facility provides water to the suctions of the auxiliary feedwater pumps during emergency conditions, including loss of offsite power, with a coincident single failure.

B. Each CST capacity is based on satisfying the safety-grade cold shutdown capability which is sufficient to allow plant operation in the hot standby mode for 4 h, followed by a 5-h orderly plant cooldown, at an average rate of 50°F/h but not to exceed a rate of 100°F/h, to a temperature of 350°F when the residual heat removal (RHR) system may be placed in operation.

C. The CSTs are designed to remain functional during and after a safe shutdown earthquake (SSE). Provision is made so that failure of any non-Seismic Category I lines attached to the CSTs cannot cause a loss of the reserve capacity required for safe plant shutdown.

D. The piping layout from the CSTs to the auxiliary feedwater pumps ensures adequate net positive suction head (NPSH) at the maximum CST water temperature.

9.2.6.1.2 Power Generation Design Bases A. The CSTs provide:

1. Sufficient water storage for simultaneous filling of all three condenser shells upon completion of condenser field erection for the purpose of hydrostatic testing of the condenser.

9.2-26 REV 17 3/11

VEGP-FSAR-9

2. Sufficient water volume for filling of the condensate feedwater system condenser hotwells and steam generators to their normal water levels just prior to initial plant operation.

3. Sufficient water capacity to simultaneously fill all three condensers for leak testing of condensers during scheduled shutdown periods.

B. The CSTs serve as a reservoir to supply or receive condensate as required by the condenser hotwell level control system.

C. The condensate storage facility permits periodic testing of the auxiliary feedwater pumps and valves.

9.2.6.1.3 Codes and Standards Codes and standards applicable to the condensate storage facility are listed in table 3.2.2-1.

The storage tanks and safety-related piping are designed and constructed as Seismic Category 1. The vacuum degasifier and appurtenances are designed and constructed as Seismic Category 2.

9.2.6.2 System Description 9.2.6.2.1 General System Description The condensate storage facility is shown in drawing IX4DBI61-1. The layout of the condensate storage facility is shown in section 1 .2. The system consists of two CSTs, a vacuum degasifier, degasifier feed pump, degasifier transfer pump, a degasifier feed/transfer pump, two degasifier vacuum pumps, and associated piping and instrumentation. There is one condensate storage facility for each plant unit.

9.2.6.2.2 Component Description A. Condensate Storage Tanks Each CST has a capacity of 480,000 gal. The tanks are vertical right cylindrical tanks, constructed of reinforced concrete with stainless steel liners. The tanks are provided with vent and overflow standpipes. The tanks are provided with level and temperature instrumentation. Each pair of tanks is surrounded by a dike with a capacity to retain leakage or overflow equal to 5% of one tank volume.

B. Vacuum Degasifier Subsystem This subsystem consists of the vacuum degasifier designed to withstand pressure range from 30 in. mercury vacuum to 125 psig. The capacity rate of the degasifier is 350 gal/mm. Two vacuum pumps are provided to maintain the required vacuum in the degasifier. Three fluid pumps are provided:

1. One to feed condensate to the degasifier.

2. One to transfer condensate from the degasifier back to the CSTs.

9.2-27 REV 17 3/11

VEGP-FSAR-9

3. One that can be used as either a feed or a transfer pump. Each of these three pumps is rated at 350 gal/mm at 32 psig.

To control corrosion within the system, the CSTs are provided with floating diaphragms which minimize the absorption of oxygen by the condensate. The degasifier system further reduces the concentration of dissolved oxygen.

9.2.6.3 System Operation 9.2.6.3.1 Normal Operation The condensate level in each storage tank is automatically maintained by a level control valve in the line from the demineralized water system. The valve opens when the volume of liquid in the tank drops to 457,000 gal and closes when the volume increases to 503,000 gal, thus maintaining the volume at 480,000 gal plus or minus 23,000 gal.

If changes in the condensate system inventory cannot be accommodated by the condenser hotwell, the hotwell level control automatically obtains makeup from, or diverts excess to, the condensate storage facility.

Operation of the degasifier subsystem is intermittent as required to maintain the dissolved oxygen in the condensate at less than 0.1 ppm.

The condensate storage facility normally contains no radioactivity. However, in the event of a primary-to-secondary leak resulting from a steam generator tube leak, it is possible for the CSTs to become contaminated. A further discussion of the radiological aspects of primary-to-secondary leakage is included in chapter II.

9.2.6.3.2 Emergency Operation The condensate storage facility is normally aligned such that CST No. 1 provides water to all three auxiliary feedwater pumps. A separate line connects the tank to each pump. In each line are two locked open valves; thus, no automatic or manual action is required to supply water to the suction of the auxiliary feedwater pumps.

As the level in CST No. I decreases to the minimum allowable level, the operator manually realigns the system so that CST No. 2 serves all three pumps. A separate line connects each pump to CST No. 2. Each line contains a locked open valve and a normally shut, remote-manual valve. The remote-manual valves have two points of control:

The main control room.

The appropriate shutdown panel (train A or B) or the auxiliary feedwater turbine driven pump local control panel.

9.2.6.4 Safety Evaluation A. Two CSTs are provided for each plant unit. The systems active components are designed to satisfy the single failure criteria. A failure modes and effects analysis 9.2-28 REV 17 3/11

VEGP-FSAR-9 (FMEA) is included in the FMEA provided for the auxiliary feedwater system in subsection 10.4.9.

B. The total design capacity of each storage tank is 480,000 gal. A total of 340,000 gal is required to operate the plant in hot standby mode for 4 h, followed by a 5-h cooldown to 350°F, the temperature at which the RHR system may be used to remove the remaining residual heat as required for plants with safety-grade cold shutdown capability. (See paragraph 10.4.9.2.2.5.)

C. The CSTs and associated safety-related piping and valves are designed and constructed as Seismic Category 1, ensuring that they will remain functional through the SSE.

The components and supporting structures of any system or equipment which are not Seismic Category I are evaluated to ensure that their failure does not cause a loss of function of safety-related portions of the condensate storage facility.

All nozzles used in normal power generation and nozzles to and from the vacuum degasifier are located on the storage tank at an elevation such that a reserve volume of 340,000 gal is always maintained below the level of these nozzles. This ensures an adequate reserve for emergency safety use.

D. For a maximum CST water temperature of 120°F, the NPSH margin at the motor-and turbine-driven auxiliary feedwater pumps suctions is greater than 11 ft.

9.2.6.5 Tests and Inspections Hydrostatic testing will be done prior to initial startup. Analytical qualifications are performed as required by seismic category and quality classification of each item.

Proper system performance and integrity during normal plant operation will be verified by system operation and visual inspections.

Correct positioning of valves is ensured by written procedure, as applicable.

Inservice testing of pumps and valves is in accordance with American Society of Mechanical EngineersSection XI as discussed in subsection 3.9.6.

Samples are taken to ensure oxygen levels are maintained within acceptable limits.

9.2.6.6 Instrumentation Applications A level detection system is installed on the CST. Level signals are transmitted to the automatic tank level control devices. Level indication is provided in the control room and on the shutdown panels. A level recorder is located on the main control panel in the control room. Low- and high-level alarms are provided in the control room. A low-level alarm is provided on the turbine driven auxiliary feedwater panel.

A temperature sensor is provided for each CST with the temperature data transmitted to the plant computer. The plant computer provides an alarm function on low water temperature by a flashing readout on the CRT display screen.

9.2-29 REV 17 3/11

ML112280226

Contents

Text

Title:

Title:

Title:

Title:

Title:

Title:

Navigation menu

ML112280226

Text

Title:

Title:

Title:

Title:

Title:

Title:

Navigation menu

Search