ML20288A204

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CN-2020-09-Post Exam Comments
ML20288A204
Person / Time
Site: Cooper Entergy icon.png
Issue date: 10/12/2020
From: Greg Werner
Operations Branch IV
To:
Nebraska Public Power District (NPPD)
References
Download: ML20288A204 (52)
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N Nebraska Public Power District Always there when you need, us NLS2020062 October 12,2020 John Kirkland Chief Examiner, Region IV U.S. Nuclear Regulatory Commission 1600 East Lamar Boulevard Arlington, TX 7601 I-4511

Subject:

Initial Post-Examination Documentation Cooper Nuclear Station, Docket No. 50-298, DPR-46

Reference:

NUREG 1021, Operator Licensing Examination Standards for Power Reactors, Revision I I

Dear Sir:

On September 29,2020, Reactor Operator and Senior Reactor Operator written examinations were administered at Cooper Nuclear Station (CNS). On October 8,2020,the following post-examination documentation was transmitted electronically to your office as required by Section ES-501 C.1.b of the reference:

a the graded written examinations (i.e., each applicant's original answer and examination cover sheets) plus a clean copy of each applicant's answer sheet (ES-403, "Grading Initial Site-Specifi c Written Examinations");

a the master written examination(s) and answer key(s), annotated to indicate any changes made while administering and grading the examination(s) (ES-402, "Administering Initial Written Examinations," and ES-a03);

There were two changes required to the master examination during the administration of the examination; these changes were made after consultation with the chief examiner.

any questions asked by the applicants and the answers given to the applicants during the written examination (ES-402);

a all examination administration or post-examination review comments made by the facility licensee and the applicants after the written examination and/or operating tests (ES-a02);

There were three post-examination review comments made by the facility licensee after the written examination; refer to Bullet 7 below for additional information.

a the seating chart for the written examination (ES-402);

COOPER NUCTEARSTATION P.O. Box 98 / Brownville, NE 68321-0098 retephone:,*t,,fl,,i;t":!0,-::x:(402)B2s_s2tl

NLS2020062 Page2 of 2 t a completed Form ES-403-1, o'Written Examination Grading Quality Checklist" (ES-403 and Section D.1);

a the results of any performance analysis that was performed for the written examination, with recommended substantive changes (ES-a03);

There were substantive comments made by the facility licensee after the written examination. A perfornance analysis of the written examination was conducted; we request the chief examiner to consider three substantive changes to the written examination answer key.

a original Form ES-201-3, o'Examination Security Agreement," with a pre- and post-examination signature by every individual who had detailed knowledge of any part of the operating tests or written examination before they were administered.

The graded written examinations, questions asked and answers, and written examination performance analysis contain personally identifiable information. As such, we request the Nuclear Regulatory Commission (NRC) to withhold these documents from the public document room per 10 CFR 2.390.

We also request the NRC to withhold the master examination and answer key from the public document room for two years from the date of the exam.

This letter contains no new regulatory commitments. Should you have any questions or require additional information, please contact me at (402) 825-5416 or James Florence, Facility Representative, at (402) 825-57 00.

S Dewhirst Regulatory Affairs and Compliance Manager ljo cc: Training Manager Cooper Nuclear Station Facility Representative Cooper Nuclear Station Operations Training Superintendent Cooper Nuclear Station CNS Records

Post-Examination Review Comments Ref: NUREG 1021, Operator Licensing Examination Standards for Power Reactors, Revision 11, Section ES-501 C.1.b Cooper submits: (1) post-examination review comments made by the facility licensee after the written examination (ES-402); and, (2) the results of a performance analysis performed for the written examination with recommended substantive changes (ES-403).

There were three post-examination review comments made by the facility licensee after the written examination; a performance analysis of the written examination was conducted by the facility licensee. Cooper requests the chief examiner to consider three substantive changes to the written examination answer key.

Three substantive changes to the written examination answer key and a technical justification are provided in the following pages for written examination Questions #2, #61, and #51.

Examination Outline Cross-Reference Level RO 205000 (SF4 SCS) Shutdown Cooling Tier # 2 Group # 1 Ability to (a) predict the impacts of the K/A # A2.08 following on the SHUTDOWN COOLING Rating 3.3 SYSTEM (RHR SHUTDOWN COOLING MODE); and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations:

A2.08 Loss of heat exchanger cooling Question 2 Given the following:

  • The plant is in Mode 4

A. (1) When reactor coolant temperature approaches 212ºF, close the reactor head vent valves.

(2) Bypass RHR flow around RHR heat exchanger A until SW flow is restored.

B. (1) When reactor coolant temperature approaches 212ºF, close the reactor head vent valves.

(2) Immediately place alternative decay heat removal systems in service until SW flow is restored.

C. (1) There would be a loss of circulation throughout the reactor core and thermal stratification would take place.

(2) Bypass RHR flow around RHR heat exchanger A until SW flow is restored.

D. (1) There would be a loss of circulation throughout the reactor core and thermal stratification would take place.

(2) Immediately place alternative decay heat removal systems in service until SW flow is restored.

Answer: A Explanation:

A is correct because 1. At 212ºF the reactor would be in Mode 4 and the head vent valves would need to be closed; without the reactor open to atmospheric pressure, as the reactor coolant temperature increases, reactor pressure will increase and 2. Precaution and Limitation 2.14 and Procedure 2.4SDC, Attachment 1 direct operators - If RHR SW lost to in Page 2 of 10

service RHR HX, bypass RHR flow around HX until SW flow restored per Procedure 2.4SDC. This will prevent boiling water in tube side of HX which will cause a water hammer when SW flow is restored.

B is wrong because 1. The RHR pump is still operating. Per lesson plan COR002-23-02-S-OPS, the SDC mode could fail causing a loss of cooling to the reactor during refueling operations. Due to decay heat production, reactor water and metal temperatures would rise.

There would be a loss of circulation throughout the reactor core and thermal stratification would take place (if the RR pump was not operating). The upper portion of water in the reactor could heat up to the boiling point without the Control Room operator being aware of the situation. D is also wrong because part 2 is incorrect as Abnormal Procedure 2.4SDC, Shutdown Cooling Abnormal, Attachment 7 directs operators for contingencies to Consider placing alternate decay heat removal systems in service per Procedure 2.1.20.2. This is plausible because it is guidance contained in the Shutdown Cooling Abnormal procedure.

C is wrong because 1. The CRS had RR pump A started. Per lesson plan COR002-23-02-S-OPS The SDC mode could fail causing a loss of cooling to the reactor during refueling operations. Due to decay heat production, reactor water and metal temperatures would rise.

There would be a loss of circulation throughout the reactor core and thermal stratification would take place (if the RR pump was not operating). The upper portion of water in the reactor could heat up to the boiling point without the Control Room operator being aware of the situation. And is plausible because 2. Is correct.

D is wrong because part 2 is incorrect as Abnormal Procedure 2.4SDC, Shutdown Cooling Abnormal, Attachment 7 directs operators for contingencies to Consider placing alternate decay heat removal systems in service per Procedure 2.1.20.2. This is plausible because it is guidance contained in the Shutdown Cooling Abnormal procedure. C is also plausible because part 1 is correct.

Technical

References:

Document where the correct answer is found (Reference, Revision, Page number)

  • System Operating Procedure 2.2.69.2, RHR System Shutdown Operations, Rev 106, Precaution and Limitation 2.14, page 3
  • Abnormal Procedure 2.4SDC, Shutdown Cooling Abnormal, Rev 17, Attachment 1 and Attachment 7, pages 8 and 25

None.

Learning Objective:

COR002-23-02, Residual Heat Removal System, Revision 36, Enabling Objective 8.r Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question History: Last NRC Exam No Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis 3 10CFR Part 55 Content: 55.41.5 Page 3 of 10

Technical justification to change the written examination answer key - Question #2 Question #2 NOTE - Answer A was identified as the correct answer in the Answer Key.

NOTE - Answers A & B should be accepted as correct answers. Newly discovered technical information supports a change in the answer key.

Facility Comment:

Answer B(2) is correct for the following reasons:

Ref: Abnormal Procedure 2.4SDC Shutdown Cooling Abnormal

1. Abnormal Procedure 2.4SDC Subsequent Operator Action Step 4.9 states; IF a RHR heat exchanger or service water malfunction exists, THEN concurrently (emphasis added) perform Attachment 1.
2. Abnormal Procedure 2.4SDC Step 4.16 states; Place RHR Subsystem in SDC Mode per Procedure 2.2.69.2.
3. Abnormal Procedure 2.4SDC ATTACHMENT 1 Step 1.3 states; IF other subsystem of RHR is available, THEN place in SDC per Procedure 2.2.69.2.
4. Abnormal Procedure 2.4SDC ATTACHMENT 2 refers to GOP 2.1.20.2 Cycle Specific Fuel Transfer and Alternate Cooling Guideline; this procedure notes that an operable RHR SDC Subsystem can be credited as an alternative method of decay heat removal.

Answer A(2) remains correct for the reasons given in the original explanation and because bypassing the RHR A heat exchanger (Answer A) and placing an alternative method of decay heat removal in service (Answer B) are to be performed concurrently in accordance with 2.4SDC Step 4.9.

A marked-up copy of Abnormal Procedure 2.4SDC is attached for reference; key procedure steps are identified in yellow highlight.

Page 4 of 10

USE: CONTINUOUS CNS OPERATIONS MANUAL QUALITY: QAPD RELATED ABNORMAL PROCEDURE 2.4SDC EFFECTIVE: 2/13/19 APPROVAL: ITR-RDM SHUTDOWN COOLING ABNORMAL OWNER: OSG SUPV DEPARTMENT: OPS

1. ENTRY CONDITIONS 1.1 Reduction in RPV cooldown rate.

1.2 Rise in RPV pressure while in SDC.

1.3 Lowering RPV water level while in SDC.

1.4 Operating RHR pump trip while in SDC.

2. AUTOMATIC ACTIONS 2.1 If PCIS Group 2 or 72 psig high pressure isolation has occurred:

2.1.1 RHR-MO-17, SHUTDOWN COOLING RHR SUPPLY OUTBD VLV, closes.

2.1.2 RHR-MO-18, SHUTDOWN COOLING RHR SUPPLY INBD VLV, closes.

2.2 If PCIS Group 2 has occurred, RHR-MO-25A and/or RHR-MO-25B, INBD INJECTION VLV(s), close.

3. IMMEDIATE OPERATOR ACTION 3.1 None.
4. SUBSEQUENT OPERATOR ACTION 4.1 Record current time and date. Time/Date: /

4.2 Suspend all movement of irradiated fuel and suspend all movement of heavy loads over irradiated fuel until SDC is restored.

PROCEDURE 2.4SDC REVISION 17 PAGE 1 OF 25

NOTE - If RHR-MO-25A or RHR-MO-25B are closed when RHR System temperature exceeds 200F, cooldown of RHR-MO-25A(B) could exceed 100F and then thermal binding could occur. This condition is most likely to occur following valve isolation while in shutdown cooling at elevated RPV Coolant temperatures. To avoid thermal binding, valve is cycled within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of closure and prior to exceeding a 100F RPV cooldown of valve.

4.3 IF RHR-MO-25A(B), INBD INJECTION VLV(s), is closed when RHR System temperature exceeds 200F, THEN ensure valve(s) are cycled as follows:

4.3.1 Within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of closure.

4.3.2 Prior to exceeding 100F RPV cooldown.3 4.4 Monitor following temperatures and pressures frequently until SDC is restored:

4.4.1 IF a RR pump is in service, THEN monitor RR-TI-151A(B), SUCT TEMP (PNL 9-4).

4.4.2 IF a RR pump is not in service, THEN monitor RPV metal temperatures on NBI-TR-89, REACTOR VESSEL METAL TEMPERATURE RECORDER (PNL 9-21), for indications of stratification and approach to boiling.

4.4.3 IF RWCU is in service, THEN monitor inlet temperature on RWCU-TI-137, TEMP IND, using Point 1 on TEMP POINT SELECTOR (PNL 9-4).

4.4.4 Monitor following reactor pressure PMIS Points for indication of pressurization:

4.4.4.1 B025.

4.4.4.2 N013.

4.4.4.3 N014.

4.5 IF SDC isolated due to PCIS Group 2 or 72 psig signal, THEN go to Step 4.10.

4.6 IF a RHR pump tripped and no SDC valves isolated, THEN perform Step 4.7 for Loop A or Step 4.8 for Loop B.

PROCEDURE 2.4SDC REVISION 17 PAGE 2 OF 25

4.7 IF RHR Pump A or C can be placed in service immediately, THEN perform following (PNL 9-3):

NOTE - Step 4.7.1 can be performed concurrent with Step 4.7.2.

4.7.1 Ensure RHR SW Subsystem A is in service per Procedure 2.2.70.

4.7.2 Ensure following valves aligned as specified:

4.7.2.1 RHR-MO-12A, HX-A OUTLET VLV, is closed.6 4.7.2.2 RHR-MO-65A, HX-A INLET VLV, is open.

4.7.2.3 RHR-MO-27A, OUTBD INJECTION VLV, is open.6 4.7.2.4 RHR-MO-25A, INBD INJECTION VLV, is open.

4.7.2.5 RHR-MO-18, SHUTDOWN COOLING RHR SUPPLY INBD VLV, is open.

4.7.2.6 RHR-MO-17, SHUTDOWN COOLING RHR SUPPLY OUTBD VLV, is open.

4.7.3 Close RHR-MO-66A, HX BYPASS VLV.6 CAUTION - Exceeding 3000 gpm RHR Subsystem A flow before 30 seconds has elapsed from time pump is started could cause water hammer.

NOTE - After 30 second hold at 2500 to 3000 gpm, raising flow to rated minimizes cooldown/heatup cycles on RHR/RR tee.

4.7.4 Perform following in rapid succession to prevent running pump at shutoff head:

4.7.4.1 Start RHR Pump A or C.

NOTE - RHR-FI-133A, RHR A FLOW, may also be utilized for RHR System A flow.

4.7.4.2 Throttle open RHR-MO-66A to obtain 2500 to 3000 gpm RHR Subsystem A flow at RHR-FR-143, RHR FLOW.6 4.7.5 AFTER RHR Subsystem A flow has been at 2500 to 3000 gpm for 30 seconds from time pump was started, THEN raise RHR Subsystem A flow to one of following using RHR-MO-66A:

4.7.5.1 7700 to 8400 gpm; or 4.7.5.2 7000 gpm if fuel or blade guides are removed from around dry tubes.

4.7.6 Throttle RHR-MO-27A until a slight reduction in RHR Subsystem A flow is observed.

PROCEDURE 2.4SDC REVISION 17 PAGE 3 OF 25

4.7.7 Open RHR-MO-66A.

4.7.8 Throttle RHR-MO-27A to obtain a RHR Subsystem A flow of one of following:

4.7.8.1 7700 to 8400 gpm; or 4.7.8.2 7000 gpm if fuel or blade guides are removed from around dry tubes.

4.7.9 IF reactor coolant temperature is 50F than bottom of previous temperature band, THEN commence monitoring plant heatup/cooldown rate per Procedure 6.RCS.601.

NOTE - During performance of following step, control initial RHR System flow through HX to minimize thermal shock.

4.7.10 Adjust RHR Subsystem A flow using following valves to ensure average heatup/cooldown rate 90F/hr average over any 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period:1 4.7.10.1 RHR-MO-27A.

4.7.10.2 RHR-MO-66A.

4.7.10.3 RHR-MO-12A.

4.8 IF RHR Pump B or D can be placed in service immediately, THEN perform following (PNL 9-3):

NOTE - Step 4.8.1 can be performed concurrent with Step 4.8.2.

4.8.1 Ensure RHR SW Subsystem B is in service per Procedure 2.2.70.

4.8.2 Ensure following valves aligned as specified:

4.8.2.1 RHR-MO-12B, HX-B OUTLET VLV, is closed.6 4.8.2.2 RHR-MO-65B, HX-B INLET VLV, is open.

4.8.2.3 RHR-MO-27B, OUTBD INJECTION VLV, is open.6 4.8.2.4 RHR-MO-25B, INBD INJECTION VLV, is open.

4.8.2.5 RHR-MO-18, SHUTDOWN COOLING RHR SUPPLY INBD VLV, is open.

4.8.2.6 RHR-MO-17, SHUTDOWN COOLING RHR SUPPLY OUTBD VLV, is open.

4.8.3 Close RHR-MO-66B, HX BYPASS VLV.6 PROCEDURE 2.4SDC REVISION 17 PAGE 4 OF 25

CAUTION - Exceeding 3000 gpm RHR Subsystem B flow before 30 seconds has elapsed from time pump is started could cause water hammer.

NOTE - After 30 second hold at 2500 to 3000 gpm, raising flow to rated minimizes cooldown/heatup cycles on RHR/RR tee.

4.8.4 Perform following in rapid succession to prevent running pump at shutoff head:

4.8.4.1 Start RHR Pump B or D.

NOTE - RHR-FI-133B, RHR B FLOW, may also be utilized for RHR System B flow.

4.8.4.2 Throttle open RHR-MO-66B to obtain 2500 to 3000 gpm RHR Subsystem B flow at RHR-FR-143, RHR FLOW.6 4.8.5 AFTER RHR Subsystem B flow has been at 2500 to 3000 gpm for 30 seconds from time pump was started, THEN raise RHR Subsystem B flow to one of following using RHR-MO-66B:

4.8.5.1 7700 to 8400 gpm; or 4.8.5.2 7000 gpm if fuel or blade guides are removed from around dry tubes.

4.8.6 Throttle RHR-MO-27B until a slight reduction in RHR Subsystem B flow is observed.

4.8.7 Open RHR-MO-66B.

4.8.8 Throttle RHR-MO-27B to obtain a RHR Subsystem B flow of one of following:

4.8.8.1 7700 to 8400 gpm; or 4.8.8.2 7000 gpm if fuel or blade guides are removed from around dry tubes.

4.8.9 IF reactor coolant temperature is 50F than bottom of previous temperature band, THEN commence monitoring plant heatup/cooldown rate per Procedure 6.RCS.601.

NOTE - During performance of following step, control initial RHR System flow through HX to minimize thermal shock.

4.8.10 Adjust RHR Subsystem B flow using following valves to ensure average heatup/cooldown rate 90F/hr average over any 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period:1 4.8.10.1 RHR-MO-27B.

4.8.10.2 RHR-MO-66B.

4.8.10.3 RHR-MO-12B.

PROCEDURE 2.4SDC REVISION 17 PAGE 5 OF 25

4.9 IF a RHR heat exchanger or service water malfunction exists, THEN concurrently perform Attachment 1 (Page 8).

4.10 IF RHR cannot be placed in SDC, THEN concurrently enter Attachment 2 (Page 9).

4.11 IF RHR Subsystem is required for LPCI injection, THEN perform applicable Attachment.

RHR Subsystem A Attachment 3 Page 12 RHR Subsystem B Attachment 4 Page 14 4.12 WHEN condition resolved and isolation signal is clear, THEN proceed in this section.

4.13 IF SDC lost due to PCIS Group 2, THEN perform following:

4.13.1 Ensure both LOOP A INITIATION LOGIC and LOOP B INITIATION LOGIC is reset by pressing both RESET buttons (PNL 9-3).

4.13.2 Press CONTAINMENT SPRAY INITIATION SIGNAL S33A(B) button.

4.13.3 Place GROUP ISOL RESET CHANNEL A and GROUP ISOL RESET CHANNEL B switches to GR 2, 3, 6, 7 RESET (PANEL 9-5).

4.13.3.1 Check Group 2, CHANNEL A Isolation lights turn on (PANEL 9-5).

4.13.3.2 Check Group 2, CHANNEL B Isolation lights turn on (PANEL 9-5).

4.13.4 Press SDC ISOL RESET VLV 25A(B) button (PNL 9-3).

4.14 IF SDC lost due to 72 psig signal, THEN place GROUP ISOL RESET CHANNEL A and GROUP ISOL RESET CHANNEL B switches to GR 2, 3, 6, 7 RESET (PANEL 9-5).

4.14.1 Check Group 2, CHANNEL A Isolation lights turn on.

4.14.2 Check Group 2, CHANNEL B Isolation lights turn on.

4.15 Place switch for selected RHR pumps to TRIP and then release to ensure breaker anti-pumping is reset (PNL 9-3).

4.16 Place RHR Subsystem in SDC Mode per Procedure 2.2.69.2.

4.17 IF RHR Subsystem is to be returned to LPCI standby lineup, THEN ensure system lineup is correct per Procedure 2.2.69.

PROCEDURE 2.4SDC REVISION 17 PAGE 6 OF 25

4.18 Obtain following reviews:

  • Control Room Supervisor Signature/Date: /
  • Shift Manager Signature/Date: /
  • AOM-Shift Signature/Date: /

4.19 Forward completed procedure to OSG Supervisor.

5. ATTACHMENTS ATTACHMENT 1 HEAT EXCHANGER/SERVICE WATER MALFUNCTION ................ 8 ATTACHMENT 2 CONTINGENCY ACTIONS FOR COMPLETE LOSS OF SDC10 ............................................................................................ 9 ATTACHMENT 3 RHR SUBSYSTEM A RECOVERY FROM SDC TO LPCI MODE .. 12 ATTACHMENT 4 RHR SUBSYSTEM B RECOVERY FROM SDC TO LPCI MODE .. 14 ATTACHMENT 5 TIME TO CORE BOILING/TIME TO CORE UNCOVERY ............... 16 ATTACHMENT 6 INFORMATION SHEET .................................................................. 21 ATTACHMENT 7 PRE-STAGING AID FOR PROCEDUE 2.4SDC ............................. 25 PROCEDURE 2.4SDC REVISION 17 PAGE 7 OF 25

ATTACHMENT 1 HEAT EXCHANGER/SERVICE WATER MALFUNCTION 0.ATTACHMENT 1 HEAT EXCHANGER/SERVICE WATER MALFUNCTION

1. HEAT EXCHANGER/SERVICE WATER MALFUNCTION 1.1 IF RHR SW malfunction or loss has occurred, THEN perform following (PNL 9-3):

1.1.1 Bypass RHR HX until SW flow becomes available.9 1.1.1.1 Open RHR-MO-66A (RHR-MO-66B), HX BYPASS VLV.

1.1.1.2 Close RHR-MO-12A (RHR-MO-12B), HX OUTLET VLV.

1.1.1.3 Close RHR-MO-65A (RHR-MO-65B), HX INLET VLV.

1.2 IF RHR HX malfunction (tube failure or HX rupture) or loss has occurred, THEN perform following (PNL 9-3):

1.2.1 Open RHR-MO-66A (RHR-MO-66B), HX BYPASS VLV.

1.2.2 Close RHR-MO-12A (RHR-MO-12B), HX OUTLET VLV.

1.2.3 Close RHR-MO-65A (RHR-MO-65B), HX INLET VLV.

1.2.4 Notify Radiation Protection of possible release.

1.3 IF other subsystem of RHR is available, THEN place in SDC per Procedure 2.2.69.2.

1.4 IF RHR SDC cannot be restored, THEN go to Attachment 2 (Page 9).

PROCEDURE 2.4SDC REVISION 17 PAGE 8 OF 25

ATTACHMENT 2 CONTINGENCY ACTIONS FOR COMPLETE LOSS OF SDC10 0.ATTACHMENT 2 CONTINGENCY ACTIONS FOR COMPLETE LOSS OF SDC10

1. CONTINGENCY ACTIONS FOR COMPLETE LOSS OF SDC 1.1 Commence monitoring plant heatup rate per Procedure 6.RCS.601.8 NOTE - Preferred level indication is NBI-LI-86, SHUTDOWN LVL. RFC-LI-94A, RFC-LI-94B, or RFC-LI-94C, RX NR LEVEL, may indicate up to 9" higher than actual during cold conditions.

1.2 Control RPV level > 48" to aid in thermal convection flow.

1.3 IF blade guides in RPV or fuel bundle removed from around core instrumentation, THEN Step 1.4 is N/A.2 1.4 Place or maintain one available RR pump in service per Procedure 2.2.68.

1.5 Place RWCU System in service per alternate heat removal section of Procedure 2.2.66.8 1.6 Review Attachment 5 (Page 16) using time to core boiling/uncovery figure for existing reactor cavity water level.

1.7 Monitor following temperatures and pressures frequently and log in Control Room Log every 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />s:4 1.7.1 IF a RR pump is in service, THEN monitor RR-TI-151A(B), SUCT TEMP (PNL 9-4).

1.7.2 IF a RR pump is not in service, THEN monitor RPV metal temperatures on NBI-TR-89, REACTOR VESSEL METAL TEMPERATURE RECORDER (PNL 9-21), for approach to boiling.

1.7.3 IF RWCU is in service, THEN monitor inlet temperature on RWCU-TI-137, TEMP IND, using Point 1 on TEMP POINT SELECTOR (PNL 9-4).

1.7.4 Monitor following reactor pressure PMIS Points for indication of pressurization:

1.7.4.1 B025.

1.7.4.2 N013.

1.7.4.3 N014.

1.8 IF RPV head is off, THEN go to Step 1.12.

PROCEDURE 2.4SDC REVISION 17 PAGE 9 OF 25

ATTACHMENT 2 CONTINGENCY ACTIONS FOR COMPLETE LOSS OF SDC10 1.9 IF RPV head is tensioned and reactor coolant temperature trending above 200F, THEN ensure all Technical Specification SRs are met for Mode 3 before coolant temperature reaches 212F.8 1.9.1 Check status of primary containment using Primary Containment Status Board and Outage System Status Report (from O&M Department).7 1.9.2 WHEN personnel are available, THEN coordinate establishment of primary containment.7 1.9.3 Initiate actions to establish Secondary Containment OPERABILITY.

1.10 Close reactor head vents by performing following when average reactor coolant temperature reaches 212F or RPV pressure is rising:8 1.10.1 At Panel 9-4, perform following:

1.10.1.1 Close MS-738AV, RX HEAD VENT.

1.10.1.2 Place control switch for MS-739AV, RX HEAD VENT, to CLOSE.

1.10.1.3 Have Electrician verify MS-739AV closed using Procedure 2.2.56.

1.11 Utilize main condenser or any available steam load as a heat sink. Reference following procedures as applicable:

1.11.1 Procedure 2.2.1, Nuclear Pressure Relief System, if Reactor pressure rises above 50 psig.

1.11.2 Procedure 2.2.3, Circulating Water System.

1.11.3 Procedure 2.2.6, Condensate System.

1.11.4 Procedure 2.2.28, Feedwater System Startup and Shutdown.

1.11.5 Procedure 2.2.55, Main Condenser Gas Removal System.

1.11.6 Procedure 2.2.56, Main Steam System.

1.11.7 Procedure 2.2.75, Steam Sealing System.

1.11.8 Procedure 2.2.78, Turbine Cylinder Heating System.

1.11.9 Procedure 2.2.80, Turbine High Pressure Fluid System.

PROCEDURE 2.4SDC REVISION 17 PAGE 10 OF 25

ATTACHMENT 2 CONTINGENCY ACTIONS FOR COMPLETE LOSS OF SDC10 1.12 IF RPV head is off, THEN perform following:8 1.12.1 IF reactor cavity flooded and cross-tied with spent fuel storage pool, THEN ensure Fuel Pool Cooling System is in service with maximized cooling per Procedure 2.2.32.

1.12.1.1 Refer to Procedure 2.1.20.2 for specific configuration decisions regarding various decay heat removal methods.

1.12.2 Ensure actions to establish Secondary Containment have been completed. IF boiling is imminent, THEN perform following:

1.12.2.1 Evacuate personnel from Reactor Building.

1.12.2.2 Manually start SGT System to maintain Reactor Building P per Procedure 2.2.73.

1.12.2.3 Allow RPV/reactor cavity to boil off.

1.12.2.4 Provide makeup, as necessary, using Condensate System or ECCS.

Reference following procedures as applicable:

a. Procedure 2.1.4.
b. Procedure 2.1.20.3.

PROCEDURE 2.4SDC REVISION 17 PAGE 11 OF 25

ATTACHMENT 3 RHR SUBSYSTEM A RECOVERY FROM SDC TO LPCI MODE 0.ATTACHMENT 3 RHR SUBSYSTEM A RECOVERY FROM SDC TO LPCI MODE

1. RHR SUBSYSTEM A RECOVERY FROM SDC TO LPCI MODE 1.1 Ensure RHR-MO-25A, INBD INJECTION VLV, is closed (PNL 9-3).

1.2 Open CM-296, LOOP A INJ LINE PRESS MAINT SHUTOFF (R-881-NW Quad).

1.3 Open CM-297, LOOP A INJ LINE PRESS MAINT ROOT (R-881-NW Quad).

WARNING - If RPV 212F at time of isolation, steam may discharge from vents. Care should be taken to prevent steam burns and spread of contamination.

NOTE - Steps 1.4 through 1.9 may be performed concurrently.

1.4 IF RPV 212F at time of isolation, THEN vent RHR Subsystem A SDC suction piping as follows. IF RPV 212F at time of isolation and system is full, THEN go to Step 1.6.

1.4.1 Open RHR-97, RHR SHUTDOWN COOLING COND SUPP ROOT (R-881-NW Quad).

1.4.2 Open RHR-96, RHR SHUTDOWN COOLING CONDENSATE SUPPLY SHUTOFF (R-881-NW Quad).

1.4.3 At RHR-208, RHR SHUTDOWN COOLING SUPPLY LINE VENT (TORUS AREA SOUTH OF BENT 1, 890'), ensure installed drain hose is routed to a drain.

1.4.4 Throttle open RHR-208 and thoroughly vent SDC suction piping until evidence of no steam is present.

1.4.5 Close RHR-208.

1.4.6 Close RHR-96.

1.4.7 Close RHR-97.

1.5 IF time or conditions do not permit releasing Clearance Order on RHR-MO-16A, THEN with CRS permission, N/A Steps 1.6, 1.14, and 1.17.3, and perform Step 1.17.3.1.

NOTE - Step 1.6 can be performed in parallel with Steps 1.7 through 1.13 if LPCI injection is required and conditions and time permit.

1.6 Release SDC Clearance Order for Loop A and ensure RHR-MO-16A, LOOP A MIN FLOW BYP VLV, remains closed (PNL 9-3).

1.7 Ensure RHR-MO-27A, OUTBD INJECTION VLV, is open (PNL 9-3).

PROCEDURE 2.4SDC REVISION 17 PAGE 12 OF 25

ATTACHMENT 3 RHR SUBSYSTEM A RECOVERY FROM SDC TO LPCI MODE 1.8 Ensure RHR-MO-66A, HX BYPASS VLV, is open (PNL 9-3).

1.9 Ensure RHR-MO-12A, HX-A OUTLET VLV, is open (PNL 9-3).

1.10 Close RHR-MO-15A, PUMP A SDC SUCT VLV (PNL 9-3).

1.11 Close RHR-MO-15C, PUMP C SDC SUCT VLV (PNL 9-3).

1.12 Open RHR-MO-13A, PUMP A TORUS SUCT VLV (PNL 9-3).

1.13 Open RHR-MO-13C, PUMP C TORUS SUCT VLV (PNL 9-3).

1.14 Open RHR-MO-16A, LOOP A MIN FLOW BYP VLV (PNL 9-3).

1.15 Place switch for selected RHR pumps to TRIP and then release to ensure breaker anti-pumping is reset (PNL 9-3).

1.16 Reset PCIS Group 2 isolation signal to inboard injection valve by pressing SDC ISOL RESET VLV 25A button.

1.17 IF LPCI injection is required, THEN perform following (PNL 9-3):

1.17.1 Start available RHR pumps to restore RPV level.

1.17.2 Open RHR-MO-25A, INBD INJECTION VLV.

1.17.3 Throttle RHR-MO-27A to control injection rate.

1.17.3.1 IF RHR-MO-16A, LOOP A MIN FLOW BYP VLV, is not available to operate, THEN throttle RHR-MO-27A to control injection rate but maintain 2200 gpm unless securing RHR pump.

1.17.4 IF RHR-MO-25B, INBD INJECTION VLV, cycling open and closed, THEN press SDC ISOL RESET VLV 25B button.

1.17.5 Continue LPCI injection operation per Procedure 2.2.69.1.

PROCEDURE 2.4SDC REVISION 17 PAGE 13 OF 25

ATTACHMENT 4 RHR SUBSYSTEM B RECOVERY FROM SDC TO LPCI MODE 0.ATTACHMENT 4 RHR SUBSYSTEM B RECOVERY FROM SDC TO LPCI MODE

1. RHR SUBSYSTEM B RECOVERY FROM SDC TO LPCI MODE 1.1 Ensure RHR-MO-25B, INBD INJECTION VLV, is closed (PNL 9-3).

1.2 Open CM-38, PCV-266 BYPASS (R-958-SW).

WARNING - If RPV 212F at time of isolation, steam may discharge from vents. Care should be taken to prevent steam burns and spread of contamination.

NOTE - Steps 1.3 through 1.8 may be performed concurrently.

1.3 IF RPV 212F at time of isolation, THEN vent RHR Subsystem B SDC suction piping as follows. IF RPV 212F at time of isolation and system is full, THEN go to Step 1.5.

1.3.1 Open RHR-97, RHR SHUTDOWN COOLING COND SUPP ROOT (R-881-NW Quad).

1.3.2 Open RHR-96, RHR SHUTDOWN COOLING CONDENSATE SUPPLY SHUTOFF (R-881-NW Quad).

1.3.3 At RHR-208, RHR SHUTDOWN COOLING SUPPLY LINE VENT (TORUS AREA SOUTH OF BENT 1, 890'), ensure installed drain hose is routed to a drain.

1.3.4 Throttle open RHR-208 and thoroughly vent SDC suction piping until evidence of no steam is present.

1.3.5 Close RHR-208.

1.3.6 Close RHR-96.

1.3.7 Close RHR-97.

1.4 IF time or conditions do not permit releasing Clearance Order on RHR-MO-16A, THEN with CRS permission, N/A Steps 1.5 and 1.13, and perform Step 1.16.3.1.

NOTE - Step 1.5 can be performed concurrently with Steps 1.6 through 1.12 if LPCI injection is required and conditions and time permit.

1.5 Release SDC Clearance Order for Loop B and ensure RHR-MO-16B, LOOP B MIN FLOW BYP VLV, remains closed (PNL 9-3).

1.6 Ensure RHR-MO-27B, OUTBD INJECTION VLV, is open (PNL 9-3).

1.7 Ensure RHR-MO-66B, HX BYPASS VLV, is open (PNL 9-3).

1.8 Ensure RHR-MO-12B, HX-A OUTLET VLV, is open (PNL 9-3).

PROCEDURE 2.4SDC REVISION 17 PAGE 14 OF 25

ATTACHMENT 4 RHR SUBSYSTEM B RECOVERY FROM SDC TO LPCI MODE 1.9 Close RHR-MO-15B, PUMP B SDC SUCT VLV (PNL 9-3).

1.10 Close RHR-MO-15D, PUMP D SDC SUCT VLV (PNL 9-3).

1.11 Open RHR-MO-13B, PUMP B TORUS SUCT VLV (PNL 9-3).

1.12 Open RHR-MO-13D, PUMP D TORUS SUCT VLV (PNL 9-3).

1.13 Open RHR-MO-16B, LOOP B MIN FLOW BYP VLV.

1.14 Place switch for selected RHR pumps to TRIP and then release to ensure breaker anti-pumping is reset (PNL 9-3).

1.15 Reset PCIS Group 2 isolation signal to inboard injection valve by pressing SDC ISOL RESET VLV 25B button.

1.16 IF LPCI injection is required, THEN perform following (PNL 9-3):

1.16.1 Start available RHR pumps to restore RPV level.

1.16.2 Open RHR-MO-25B, INBD INJECTION VLV.

1.16.3 Throttle RHR-MO-27B to control injection rate.

1.16.3.1 IF RHR-MO-16B, LOOP B MIN FLOW BYP VLV, is not available to operate, THEN throttle RHR-MO-27B to control injection rate but maintain 2200 gpm unless securing RHR pump.

1.16.4 IF RHR-MO-25A, INBD INJECTION VLV, cycling open and closed, THEN press SDC ISOL RESET VLV 25A button.

1.16.5 Continue LPCI injection operation per Procedure 2.2.69.1.

PROCEDURE 2.4SDC REVISION 17 PAGE 15 OF 25

ATTACHMENT 5 TIME TO CORE BOILING/TIME TO CORE UNCOVERY 0.ATTACHMENT 5 TIME TO CORE BOILING/TIME TO CORE UNCOVERY Figure 1 - TIME TO BOILING - WATER LEVEL AT HIGH LEVEL TRIP PROCEDURE 2.4SDC REVISION 17 PAGE 16 OF 25

ATTACHMENT 5 TIME TO CORE BOILING/TIME TO CORE UNCOVERY Figure 2 - TIME TO BOILING - WATER LEVEL AT FLANGE PROCEDURE 2.4SDC REVISION 17 PAGE 17 OF 25

ATTACHMENT 5 TIME TO CORE BOILING/TIME TO CORE UNCOVERY Figure 3 - TIME TO BOILING - WATER TO LEVEL FLOODED TO 1001' PROCEDURE 2.4SDC REVISION 17 PAGE 18 OF 25

ATTACHMENT 5 TIME TO CORE BOILING/TIME TO CORE UNCOVERY Figure 4 - TIME TO CORE UNCOVERY PROCEDURE 2.4SDC REVISION 17 PAGE 19 OF 25

ATTACHMENT 5 TIME TO CORE BOILING/TIME TO CORE UNCOVERY Figure 5 - TIME TO CORE UNCOVERY PROCEDURE 2.4SDC REVISION 17 PAGE 20 OF 25

ATTACHMENT 6 INFORMATION SHEET 0.ATTACHMENT 6 INFORMATION SHEET

1. DISCUSSION 1.1 The purpose of this procedure is to address a loss of Shutdown Cooling (SDC).

Guidance is provided to immediately restore SDC to service if conditions allow. If SDC cannot be restored, contingency actions are provided to address decay heat removal and establishment of containment. Guidance is also provided to align RHR System that was lost to LPCI mode, if needed.

1.2 Complete loss of SDC Mode of RHR System is possible but unlikely due to built-in redundancy of two RHR and service water loops. A loss could occur due to a PCIS Group 2 isolation signal, a 72 psig high pressure isolation signal when SDC Mode supply valves are open, or from equipment failure.

1.3 Steam void formation and subsequent collapse in idle RHR loop suction piping has the potential to actuate the 72 psig high pressure isolation. Conditions that contribute to void formation on initial cooldown include a high RHR SDC flow rate and partial vacuum on reactor vessel due to mechanical vacuum pump operation. Reactor vessel level lowering ~ 7" is an indication of void collapse.5 1.4 Primary concern with loss of SDC Mode is potential for reactor coolant temperature to exceed 212F when primary containment is not established, as would probably be the case during an outage. Reactor coolant temperatures will stratify with low or no forced convection flow which may mislead Operator into assuming bulk water temperature is below 212F.

1.5 RHR System piping is not analyzed for water hammer loads. Operation of RHR System in SDC Mode with vessel temperature above 212F could result in a water hammer event occurring in RHR suction piping upon re-alignment to LPCI Mode. If SDC should isolate and subsystem is to be placed in a LPCI lineup, the loop needs to be thoroughly vented prior to and after re-alignment to LPCI.

1.6 In the event valves RHR-MO-25A or RHR-MO-25B are closed when RHR System temperature exceeds 200F, cooldown of RHR-MO-25A(B) could exceed 100F and then thermal binding could occur. This condition is most likely to occur following valve isolation while in shutdown cooling at elevated RPV temperatures. To avoid thermal binding, valve is cycled within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of closure and prior to exceeding a 100F RPV cooldown of the valve.

1.7 If a PCIS Group 2 isolation signal is received with SDC in service, both RHR-MO-25A and RHR-MO-25B receive close signals. If a LPCI initiation signal is received while the PCIS Group 2 isolation signal is present, neither RHR loop will inject until SDC ISOL RESET VLV 25A(B) is pressed. If only one button is pushed, the opposite loop's RHR-MO-25A(B) will cycle open and closed continuously possibly damaging valve motor. Under these conditions, both logics will need to be reset.

PROCEDURE 2.4SDC REVISION 17 PAGE 21 OF 25

ATTACHMENT 6 INFORMATION SHEET 1.8 Time to Boiling/Time to Core Uncovery curves provide a guideline to Operators and is not intended to provide exact time limitations. Extrapolation of curves are allowed because it is an estimate.

1.9 PROBABLE CAUSES 1.9.1 RHR pump trip.

1.9.2 PCIS Group 2 isolation.

1.9.3 72 psig isolation.

1.10 PROBABLE ANNUNCIATORS 1.10.1 Annunciator 9-3-1/A-6, RHR A/B DISCH OR SDC SUCT HDR HI PRESS.

1.10.2 Annunciator 9-3-1/B-4, RHR PUMP A TRIP.

1.10.3 Annunciator 9-3-1/B-5, RHR PUMP C TRIP.

1.10.4 Annunciator 9-3-3/B-2, RHR PUMP B TRIP.

1.10.5 Annunciator 9-3-3/B-3, RHR PUMP D TRIP.

2. REFERENCES 2.1 TECHNICAL SPECIFICATIONS 2.1.1 Technical Specifications LCO 3.3.6.1, Primary Containment Isolation Instrumentation.

2.1.2 Technical Specifications LCO 3.4.7, Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown.

2.1.3 Technical Specifications LCO 3.4.8, Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown.

2.1.4 Technical Specifications LCO 3.4.9, RCS Pressure and Temperature (P/T)

Limits.

2.1.5 Technical Specifications LCO 3.6.1.1, Primary Containment.

2.1.6 Technical Specifications LCO 3.6.4.1, Secondary Containment.

2.1.7 Technical Specifications LCO 3.7.1, Residual Heat Removal Service Water Booster (RHRSWB) System.

2.1.8 Technical Specifications LCO 3.9.7, Residual Heat Removal (RHR) - High Water Level.

PROCEDURE 2.4SDC REVISION 17 PAGE 22 OF 25

ATTACHMENT 6 INFORMATION SHEET 2.1.9 Technical Specifications LCO 3.9.8, Residual Heat Removal (RHR) - Low Water Level.

2.2 PROCEDURES 2.2.1 General Operating Procedure 2.1.4, Normal Shutdown.

2.2.2 General Operating Procedure 2.1.20.2, Cycle Specific Fuel Transfer and Alternate Cooling Guideline.

2.2.3 General Operating Procedure 2.1.20.3, RPV Refueling Preparation (Wet Lift of Dryer and Separator).

2.2.4 System Operating Procedure 2.2.1, Nuclear Pressure Relief System.

2.2.5 System Operating Procedure 2.2.3, Circulating Water System.

2.2.6 System Operating Procedure 2.2.6, Condensate System.

2.2.7 System Operating Procedure 2.2.28, Feedwater System Startup and Shutdown.

2.2.8 System Operating Procedure 2.2.32, Fuel Pool Cooling and Demineralizer System.

2.2.9 System Operating Procedure 2.2.55, Main Condenser Gas Removal System.

2.2.10 System Operating Procedure 2.2.56, Main Steam System.

2.2.11 System Operating Procedure 2.2.66, Reactor Water Cleanup.

2.2.12 System Operating Procedure 2.2.68, Reactor Recirculation System.

2.2.13 System Operating Procedure 2.2.69, Residual Heat Removal System.

2.2.14 System Operating Procedure 2.2.69.1, RHR LPCI Mode.

2.2.15 System Operating Procedure 2.2.69.2, RHR System Shutdown Operations.

2.2.16 System Operating Procedure 2.2.70, RHR Service Water Booster Pump System.

2.2.17 System Operating Procedure 2.2.73, Standby Gas Treatment System.

2.2.18 System Operating Procedure 2.2.75, Steam Sealing System.

2.2.19 System Operating Procedure 2.2.78, Turbine Cylinder Heating System.

2.2.20 System Operating Procedure 2.2.80, Turbine High Pressure Fluid System.

PROCEDURE 2.4SDC REVISION 17 PAGE 23 OF 25

ATTACHMENT 6 INFORMATION SHEET 2.2.21 Surveillance Procedure 6.RCS.601, Technical Specification Monitoring of RCS Heatup/Cooldown Rate.

2.3 MISCELLANEOUS 2.3.1 1 Condition Report 94-0533, Exceeding Tech Spec Heatup/Cooldown Limits.

Affects Steps 4.7.10 and 4.8.10.

2.3.2 2 GE SIL 406, Revision 1, In-Core Instrumentation Protection. Affects Attachment 2, Step 1.3.

2.3.3 3 GL 95-07, Request for Additional Information (RAI), response dated June 14, 1999, NLS990058-02. Affects Step 4.3.2.

2.3.4 4 INPO SEN 118, Recurring Events. Affects Attachment 2, Step 1.7.

2.3.5 5 LER 94-005, Steam Void Collapse in SDC. Affects Attachment 6, Step 1.3.

2.3.6 6 NCR 94-046, LLRT Failure on RHR-MOV-MO27A. Affects Steps 4.7.2.1, 4.7.2.3, 4.7.3, 4.7.4.2, 4.8.2.1, 4.8.2.3, 4.8.3, and 4.8.4.2.

2.3.7 7 NUMARC 91-06, Guidelines for Industry Actions to Assess Shutdown Management. Affects Attachment 2, Steps 1.9.1 and 1.9.2.

2.3.8 8 SER 7-87, Pressurization of Vessel During Cold Shutdown. Affects Attachment 2, Steps 1.1, 1.5, 1.9, 1.10, and 1.12.

2.3.9 9 SER 11-87, Waterhammer in the Component Cooling System. Affects Attachment 1, Step 1.1.1.

2.3.10 10 SOER 09-1, Recommendation 11. Affects Attachment 2.

2.3.11 CAQ 96-0748, Potential for Water Hammer in RHR.

2.3.12 NEDC 92-108, Time to Core Boiling/Time to Core Uncovery.

PROCEDURE 2.4SDC REVISION 17 PAGE 24 OF 25

ATTACHMENT 7 PRE-STAGING AID FOR PROCEDUE 2.4SDC 0.ATTACHMENT 7 PRE-STAGING AID FOR PROCEDUE 2.4SDC Failure Scram Actions Action Points Contingencies Tech Specs Loss of SDC in

  • None
  • Determine heatup rate as soon as
  • Brief SDC restoration - Don't rush to place SDC back
  • LCO 3.4.7 Mode 4 practical. in service - ensure CAUTION prior to Steps 4.7.4 and
  • Reactor coolant temperature - report 4.8.4 are discussed - ensure cause is known and
  • Mode 3 temperature every 10F rise. corrected to prevent repeat isolations.
  • Request support from WCC for Procedure 6.RCS.601.

proximity to boiling.

  • Stop all activities that can affect restoration of primary

Mode change to Mode 3.

  • Determine status of Attachment 2 systems - Assign
  • Reactor coolant temperature 300F - individuals early to place necessary systems in proximity to 75 psig isolation. service.
  • Notify OCC as soon as it is apparent
  • IF entry into Mode 3 is likely, THEN assign individual that SDC will not readily be restored. early to develop Mode 3 strategy to prevent exceeding SDC high pressure isolation setpoint.
  • Consider restricting activities in Reactor Building.

Loss of SDC in

  • None
  • Determine heatup rate as soon as
  • Brief SDC restoration - Don't rush to place SDC back
  • LCO 3.9.7 Mode 5 practical. in service - ensure cause is known and corrected to
  • Reactor coolant temperature 200F - systems in service per Procedure 2.1.20.2.

proximity to boiling.

  • Consider placing RR pump in service or establishing

Boiling.

  • Request support from WCC for Procedure 6.RCS.601.
  • Notify OCC as soon as it is apparent
  • Review Attachment 2, Step 1.12 - Assign individuals early to monitor for boiling and establish level makeup systems.
  • Consider restricting activities in Reactor Building.
  • Monitor Reactor Building atmosphere activity.
  • Consider having Safety re-evaluate area stay times.
  • Review and implement outage SDC contingency plans.

PROCEDURE 2.4SDC REVISION 17 PAGE 25 OF 25

Examination Outline Cross-Reference Level RO 295008 (APE 8) High Reactor Water Level Tier # 1 Group # 2 Knowledge of the reasons for the following K/A # AK3.02 responses as they apply to HIGH REACTOR Rating 3.6 WATER LEVEL:

AK3.02 Reactor SCRAM Question 61 The plant is at 100% power.

The following indications are present;

  • All narrow range RPV level instruments are oscillating between 47 and 51
  • Annunciator 9-5-2/F-1, Reactor Water Level High is in alarm What actions will the control room perform?

A. Enter Procedure 2.4RXLVL, place Master level controller in MAN B. Enter Procedure 2.4RXLVL, place level control switch to 1 ELEMENT CONT C. Enter Procedure 2.1.5, SCRAM the reactor, and maintain RPV level with RFPs D. Enter Procedure 2.1.5, SCRAM the reactor, and ensure main turbine, RFPTs, HPCI, and RCIC are tripped Answer: D Explanation:

Procedure 2.3_9-5, Panel 9-5 Annunciator response directs the operators to SCRAM the reactor if RPV level is above 50.

Procedure 2.4RXLVL, attachment 4 states, 1.3.2 The language used in the associated procedure steps (i.e., "cannot be maintained") means that if RPV level ever goes below 12" during the event, the reactor shall be manually scrammed or if RPV level ever goes above 50" during the event, the reactor shall be manually scrammed and any operating turbines stopped. The language does not provide any tolerance or allowance for exceeding these values A is incorrect. Plausible because procedure 2.4RXLVL directs the operators to place the Master level controller in MAN if level control is still erratic after placing control switch to 1 element control.

B is incorrect. Plausible because this would be the correct action for oscillating RPV levels as long as the level does not exceed 50 C is incorrect. Plausible because normally once would control RPV level with the RFPs.

D is correct.

Technical

References:

Page 5 of 10

Procedure 2.4RXLVL, RPV Water Level Control Trouble, Revision 28, page 1 and Procedure 2.3_9-5-2, Panel 9 Annunciator 9-5-2, Revision 49, page 63 Procedure 2.1.5 Reactor Scram, Revision 77, Attachment 3 References to be provided to applicants during exam:

None.

Learning Objective:

INTO032-01-04, Administrative Procedures General Operating Procedures, Revision 10, Enabling objective D.9 Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question History: Last NRC Exam No Question Cognitive Level: Memory/Fundamental 3 Comprehensive/Analysis 10CFR Part 55 Content: 55.41.5 Page 6 of 10

Technical justification to change the written examination answer key - Question #61 Question #61 NOTE - Answer D was identified as the correct answer in the Answer Key.

NOTE - Answers A & D should be accepted as correct answers. The question is presented such that the candidate must interpret the information provided in the stem.

NOTE - During validation it was noted that the verb oscillating could be indicative of instrument noise, or a failed instrument. An oscillation between 47 and 51 could be interpreted by an operator at the median value, or 49. The question is worded such that the candidate must interpret how the verb oscillating is intended.

Answer A is correct for the following reasons:

1. The entry condition to Abnormal Procedure 2.4RXVL Erratic or unexplained RPV level changes that requires an immediate operator action to scram applies if the operator determines that RPV level cannot be maintained below +50 on the narrow range instruments. The stem of the question states that all narrow range RPV level instruments are oscillating between 47" and 51"; the immediate operator action to scram applies if the operator interprets his indications to be accurate and that RPV level cannot be maintained below +50 on the narrow range instruments.
2. The first applicable step in Abnormal Procedure 2.4RXVL, Step 4.3, states that; IF level control is still erratic, THEN place following in MAN, MDEM, or MDVP, as necessary, and stabilize RPV level: MASTER LEVEL controller.
3. Taking the action to place the MASTER LEVEL controller in MAN, MDEM, or MDVP to stabilize RPV level would validate if level instruments were accurate; executing the scram action is applicable if RPV level could not be maintained below +50 on the narrow range instruments.

Subsequent to taking manual control to stabilize RPV water level to verify that the instruments are accurate, the operator would demonstrate use of multiple and diverse indications and subsequently scram if RPV level could not be maintained below +50 on the narrow range instruments.

4. Information given in the stem related to reactor water level is interpretive. No periodicity for the level oscillations is given. One could assume level indication is affected by induced, high frequency noise and that actual RPV narrow range level is below 50, the median value, based on the impossibility of actual narrow range level to cycle that quickly.

Answer D remains correct based on the original explanation and because NR reactor water level can be interpreted as 50 if one assumes an oscillation periodicity consistent with possible actual level changes from the information given in the stem.

A marked-up copy of Abnormal Procedure 2.4RXVL RPV Water Level Control Trouble is attached for reference; key procedure steps are identified in yellow highlight.

Page 7 of 10

USE: CONTINUOUS CNS OPERATIONS MANUAL QUALITY: QAPD RELATED ABNORMAL PROCEDURE 2.4RXLVL EFFECTIVE: 8/21/19 APPROVAL: ITR-RDM RPV WATER LEVEL CONTROL TROUBLE OWNER: AOM-SUPPORT DEPARTMENT: OPS

1. ENTRY CONDITIONS 1.1 Erratic or unexplained RPV level changes.

1.2 RPV level fails to follow power changes.

2. AUTOMATIC ACTIONS 2.1 See Attachment 1 (Page 4).
3. IMMEDIATE OPERATOR ACTION 3.1 IF either of following occur at any time, THEN SCRAM and concurrently enter Procedure 2.1.5:

3.1.1 RPV level cannot be maintained above +12" on narrow range instruments.

3.1.2 RPV level cannot be maintained below +50" on narrow range instruments.

4. SUBSEQUENT OPERATOR ACTION 4.1 Record current time and date. Time/Date: /

CAUTION - Manual setpoint tracks Auto setpoint on all RFPT/RVLC controllers so rapid response to control level may be necessary.

4.2 IF a steam flow or feed flow instrument is oscillating, THEN place LEVEL CONTROL SELECT switch to 1 ELEMENT CONT.

4.3 IF level control is still erratic, THEN place following in MAN, MDEM, or MDVP, as necessary, and stabilize RPV level:

4.3.1 MASTER LEVEL controller.

4.3.2 RFPT-1A/RFPT-1B controller.

4.3.3 STARTUP MASTER LEVEL controller.

4.3.4 FCV-11AA/FCV-11BB controller.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 1 OF 13

4.4 IF reactor water level is slowly lowering due to loss of RVLC/RFPT CORE switches (RFPs transferring to MDEM with no control available from HMIs), THEN lower power per Procedure 2.1.10 to control reactor water level in green band.

4.4.1 RVLC/RFPT CORE switch status may be monitored from any HMI by going to NETWORK screen.

4.5 IF 'A' and 'C' level instruments are trending opposite of 'B' and 'D' level instruments, THEN verify higher level instruments are trending with NBI-LI-92, STEAM NOZZLE LEVEL (PNL 9-3).

4.5.1 IF higher level instruments are not trending with NBI-LI-92, THEN bypass higher level instruments on RVLC MAINT. screen.

4.6 Check Control Room annunciators and indicators for evidence of system leakage.

NOTE - If operating from EOPs, level band for HPCI and RCIC operations are controlled in EOPs and operating band may exceed 50".

4.7 IF RPV level cannot be maintained below +50" on narrow range, THEN ensure following not operating:

4.7.1 Main Turbine.

4.7.2 Both RFPs.

4.7.3 HPCI.

4.7.4 RCIC.

4.8 If RPV level cannot be maintained below +110" on NBI-LI-92, STEAM NOZZLE LVL, close:

4.8.1 Inboard MSIVs.

4.8.2 MS-MO-74, INBD ISOL VLV.

4.8.3 HPCI-MO-15, STM SUPP INBD ISOL VLV.

4.8.4 RCIC-MO-15, INBD STM SUPP ISOL VLV.

4.9 If an operating RFP is malfunctioning and causing unsafe conditions:

4.9.1 When both RFPs operating:

4.9.1.1 Trip affected RFP.

4.9.2 WHEN single RFP operating or both RFPs affected, THEN perform following:

4.9.2.1 SCRAM and concurrently enter Procedure 2.1.5.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 2 OF 13

4.9.2.2 Transfer level control to HPCI/RCIC per Procedure 2.2.33.1 or 2.2.67.1.

4.9.2.3 Trip affected RFP(s).

4.10 IF either or both RFPTs are in MDEM/MDVP, THEN control level using UP/DOWN arrows.

4.11 Concurrently perform applicable attachment(s):

LEVEL/STEAM/FEED FLOW INSTRUMENT Attachment 2 Page 5 FAILURE REFERENCE LEG 3A/3B FAILURE Attachment 3 Page 7 4.12 WHEN malfunction cause has been corrected, THEN perform following:

4.12.1 Return available RPV level/RFPT controllers to AUTO per Procedure 2.2.28.1.

4.12.2 IF in 1 ELEMENT CONTROL, THEN return to AUTO (3 element) control per Procedure 4.4.1.

4.12.3 Ensure on any RFPT/RVLC HMI that on ACT. ALARM screens for RFPT-1A, RFPT-1B, or RVLCS that all alarms have been addressed.

4.13 Obtain following reviews:

  • Control Room Supervisor Signature/Date: /
  • Shift Manager Signature/Date: /
  • AOM-Shift Signature/Date: /

4.14 Forward completed procedure to AOM-Support.

5. ATTACHMENTS ATTACHMENT 1 AUTOMATIC ACTIONS .................................................................... 4 ATTACHMENT 2 LEVEL/STEAM/FEED FLOW INSTRUMENT FAILURE ................... 5 ATTACHMENT 3 REFERENCE LEG 3A/3B FAILURE ................................................. 7 ATTACHMENT 4 INFORMATION SHEET .................................................................... 9 ATTACHMENT 5 PRE-STAGING AID FOR PROCEDURE 2.4RXLVL ....................... 13 PROCEDURE 2.4RXLVL REVISION 28 PAGE 3 OF 13

ATTACHMENT 1 AUTOMATIC ACTIONS 0.ATTACHMENT 1 AUTOMATIC ACTIONS REACTOR LEVEL AUTO ACTION RFP Trip 52.5" (Tech Spec 54") RCIC Shutdown and HPCI Trip Main Turbine Trip 42.5" High Level Alarm Low Level Alarm 27.5" RR pump runback if either RFP feed flow is 1 Mlbm/hr or a RFP is tripped and total steam flow > 9 Mlbm/hr Reactor Scram 7.81" (Tech Spec 3") Group 2 Isolation ADS Logic Confirmatory ARI Initiation

-33.43" (Tech Spec -42") Group 3 and 6 Isolations HPCI and RCIC Initiation

-33.43" after 9 second time delay ATWS RPT (Tech Spec -42")

Group 1 and Group 7 Isolations ADS Timers Start

-104.39" (Tech Spec -113")

CS, RHR, and Diesel Generator Initiation Drywell FCUs Trip

-185.59" Fuel Zone Containment Spray Permissive (2/3 core height interlock)

(Tech Spec -193.19")

PROCEDURE 2.4RXLVL REVISION 28 PAGE 4 OF 13

ATTACHMENT 2 LEVEL/STEAM/FEED FLOW INSTRUMENT FAILURE 0.ATTACHMENT 2 LEVEL/STEAM/FEED FLOW INSTRUMENT FAILURE

1. IF a feed flow or steam flow instrument failed, THEN verify RVLC is controlling level.

1.1 AFTER level has stabilized, THEN perform one of following:

1.1.1 If affected instrument parameter displays a quality of red INV, affected instrument has been automatically bypassed. No further action required.

1.1.2 IF affected instrument parameter displays a quality of green, THEN perform following:

1.1.2.1 Ensure LEVEL CONTROL SELECT switch is in 1 ELEMENT CONT.

CAUTION - Bypass multiple instruments may cause negative effects such as 20% runback due to bypassing both FW flow elements; evaluate carefully prior to bypassing.

1.1.2.2 Bypass selected instrument per Procedure 4.4.1.

1.1.2.3 IF conditions permit, THEN restore to AUTO (3 element) level control per Procedure 4.4.1.

2. If A and B narrow range level indications are different:

2.1 Compare narrow ranges to NBI-LI-92, STEAM NOZZLE LEVEL, to determine actual level.1 2.1.1 IF NBI-LI-92, STEAM NOZZLE LEVEL, does not approximately match either A or B narrow range, THEN compare A and B wide range level indicators:

2.1.1.1 IF A and B wide range level indicators are different, THEN concurrently enter Attachment 3 (Page 7).

2.1.1.2 IF A and B wide range level indicators approximately match, THEN use wide range indicators.

3. IF feed flow, steam flow, or RPV level instrument affected, THEN perform following:

3.1 Notify FRED and System Engineer.

3.2 Insert GARDEL substitute value, as necessary, for affected instrument per Procedure 2.6.3GARDEL.

3.3 Bypass affected instrument in RVLC per Procedure 4.4.1.

4. IF a loss of all reactor level instruments, THEN take action per Attachment 3.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 5 OF 13

ATTACHMENT 2 LEVEL/STEAM/FEED FLOW INSTRUMENT FAILURE

5. IF only two of the level instruments are good and they are deviating by more than 8",

THEN compare HMI readings to RFC-LI-94A and RFC-LI-94B.

5.1 IF erroneous reading can be determined, THEN bypass affected reading on RVLC MAINT. screen.

6. IF only two of the level instruments are good and they are deviating by more than 8",

THEN compare HMI readings to NBI-LI-92/NBI-LI-86.

6.1 IF erroneous reading can be determined, THEN bypass affected reading on RVLC MAINT. screen.

7. Following PMIS points may be used to determine historical trends, as needed:
  • B021, RX WTR LVL A NBI-LT-52A.
  • N011, RX WTR LVL B NBI-LT-52B.
  • N012, RX WTR LVL C NBI-LT-52C.
  • N333, RX WTR LVL A (WR) NBI-LT-59A.
  • N334, RX WTR LVL B (WR) NBI-LT-59B.
  • N337, RX WTR LVL C (WR) NBI-LT-59C.
  • N009, RX WTR LVL A (FZ) NBI-LI-91A.
  • N010, RX WTR LVL B (FZ) NBI-LI-91B.
  • N332, RX WTR LVL C (FZ) NBI-LI-91C.
  • N355, RX WTR LVL STM NOZZLE NBI-LT-92.
  • N335, RX WTR LVL SHUTDOWN NBI-LT-61.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 6 OF 13

ATTACHMENT 3 REFERENCE LEG 3A/3B FAILURE

  • ATTACHMENT 3 REFERENCE LEG 3A/3B FAILURE NOTE - Below guidance will aid in determining which level indicator(s) is reading accurately.
1. WHEN any wide range level indication at -30", THEN check status of following annunciators:

1.1 9-5-2/D-7, ATWS RPT CHAN A/B LEVEL TRIP.

1.2 9-3-2/A-5, RX LOW WATER LEVEL -42".

1.3 If both annunciators clear, actual level > -33".

1.4 IF both annunciators alarming, THEN check following alarm points in alarm:

1.4.1 (3074) ATWS RPT CHAN A LEVEL TRIP.

1.4.2 (3075) ATWS RPT CHAN B LEVEL TRIP.

1.4.3 (1700) RX LOW WATER LEVEL -42" ALARM (NBI-LIS-72A).

1.4.4 (1701) RX LOW WATER LEVEL -42" ALARM (NBI-LIS-72B).

1.4.5 (1702) RX LOW WATER LEVEL -42" ALARM (NBI-LIS-72C).

1.4.6 (1703) RX LOW WATER LEVEL -42" ALARM (NBI-LIS-72D).

1.4.7 If all alarm points in alarm, actual level < -33".

2. WHEN any wide range level indication at -100", THEN check status of following annunciators:

NOTE - RX low water level alarms on Panel 9-5 and associated annunciator points alarm when the respective RPS Bus is lost.

2.1 9-5-1/B-1, RX LOW LEVEL CHANNEL A -113".

2.2 9-5-1/B-2, RX LOW LEVEL CHANNEL B -113".

2.3 9-3-2/B-5, RX LOW WATER LEVEL -113".

2.4 If all three annunciators clear, actual level > -104".

2.5 IF all annunciators alarming, THEN check following alarm points in alarm:

2.5.1 (2102) RX LOW LEVEL -113" CHANNEL A2 TRIP.

2.5.2 (2103) RX LOW LEVEL -113" CHANNEL A1 TRIP.

2.5.3 (2114) RX LOW LEVEL -113" CHANNEL B2 TRIP.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 7 OF 13

ATTACHMENT 3 REFERENCE LEG 3A/3B FAILURE 2.5.4 (2115) RX LOW LEVEL -113" CHANNEL B1 TRIP.

2.5.5 (1704) RX LOW WATER LEVEL -113" ALARM (NBI-LIS-72A).

2.5.6 (1705) RX LOW WATER LEVEL -113" ALARM (NBI-LIS-72B).

2.5.7 (1706) RX LOW WATER LEVEL -113" ALARM (NBI-LIS-72C).

2.5.8 (1707) RX LOW WATER LEVEL -113" ALARM (NBI-LIS-72D).

2.5.9 If all alarm points in alarm, actual level < -104".

PROCEDURE 2.4RXLVL REVISION 28 PAGE 8 OF 13

ATTACHMENT 4 INFORMATION SHEET 0.ATTACHMENT 4 INFORMATION SHEET

1. DISCUSSION 1.1 This procedure provides guidance for abnormal reactor water level conditions that can be attributed to reactor level control malfunctions or failures. Although this procedure does not provide specific instructions for abnormal reactor level conditions associated with system leakage/LOCAs, it would still be entered and those actions not specific to control malfunctions would still be appropriate (e.g., scram if level cannot be maintained above 12"). Abnormal reactor water level conditions associated with system leakage would be accompanied by additional indications (e.g., changes in drywell atmosphere). These additional indications would dictate entering the appropriate procedure for system leakage/LOCA (e.g., EOPs, Procedure 5.1BREAK, or Procedure 2.4PC).

1.2 There are several important factors to keep in mind during performance of this procedure:

1.2.1 Ensure all annunciators and abnormal indications are considered before acting.

If attention is focused solely on RPV level and RFP control response, the real condition or event may be overlooked (e.g., RPV level may be lowering due to system leakage and the RFPs may be responding correctly).

1.2.2 Determine, as quickly as possible, whether the controls or the indicators are in error. Comparison of multiple instruments is important to ensure correct action.

1.2.3 When controllers are transferred to MDVP/MDEM or MAN, the OUTPUT signal will stop changing and hold at the current value. At this point, manual adjustment may be required in order to control RPV level and/or RFPT speed.

The controllers track manual and auto, therefore, if transferred to manual in a transient, adjustments will most likely be necessary.

1.2.4 More than one Attachment may be applicable to a given malfunction.

1.3 This procedure requires the reactor to be manually scrammed if RPV narrow range level cannot be maintained above 12" or below 50". This procedure also requires the main turbine, RFPTs, HPCI, and RCIC to be stopped if RPV narrow range cannot be maintained below 50".

1.3.1 These levels were selected based on actual trip setpoints, setpoint tolerances, experience gained from auto scrams/trips due to RPV level, and to allow a reasonable level range for recovery.

1.3.2 The language used in the associated procedure steps (i.e., "cannot be maintained") means that if RPV level ever goes below 12" during the event, the reactor shall be manually scrammed or if RPV level ever goes above 50" during the event, the reactor shall be manually scrammed and any operating turbines stopped. The language does not provide any tolerance or allowance for exceeding these values.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 9 OF 13

ATTACHMENT 4 INFORMATION SHEET 1.3.3 A NOTE explains that if operating from EOPs, level band for HPCI and RCIC operations are controlled in EOPs and operating band may exceed 50". This is because EOPs are a higher tier document.

1.4 There are various steps in this procedure that require a reactor scram, which are immediately followed by steps that require level control to be established with HPCI/RCIC and RFP(s) to be tripped. The intent of these steps is to hasten the HPCI/RCIC level control actions and RFP trips, and to alleviate some of the decision making that would be necessary during the concurrent performance of Procedure 2.1.5 (e.g., what level control method to use).

1.5 There are various steps in this procedure that are applicable when both RFPs are operating and only one RFP is affected by the malfunction. Due to RVLC/RFPT modification, tripping the affected RFP is the only Operator action necessary. The RVLC System will runback recirc, as necessary, to maintain reactor level but minimizes unnecessary runback.

1.6 All Control Room A side level instruments share a common reference leg. This is also true of the B side level instruments. A reference line break or leak on the controlling instrument could cause all the level instruments connected to that line to indicate a higher level than actual reactor water level. This will cause the Feedwater Level Control System to reduce the speed of the feed pumps and actual level will drop. The level instruments connected to affected reference leg will indicate a rising level while the instruments connected to the unaffected line will indicate the actual lowering level.

Operator can then compare A side and B side level indications to steam nozzle indication on Panel 9-3. Steam nozzle indication has an independent reference leg from the A and B side level instruments and will trend actual level. Operator can then determine which level instruments are reading correctly by determining which instruments are trending with the steam nozzle indicator.1 1.6.1 If steam nozzle indicator is downscale, other Annunciators, ECCS, and PCIS initiation signals exist that can be used to determine which level indication is accurate or at least trending correctly. These indications are fed from 2A/2B reference legs. Attachment 3 has been written to address alternate indications and to aid the Operator in determining which level instruments are reading correctly.

1.6.2 As a thumb rule, in determining which level instrument is indicating actual level, compare RFP speed to the narrow ranges. If RFP speed is raising, the instrument indicating actual level should be rising. If RFP speed is lowering, the instrument indicating actual level should be lowering. This is a diagnostic aid only and shall not be used in lieu of comparing narrow ranges to the steam nozzle indication.

1.7 A complete loss of the speed probes for the given RFP will cause the controller for that RFP to shift to MDVP.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 10 OF 13

ATTACHMENT 4 INFORMATION SHEET 1.8 When EOP flowcharts are entered, Operator is directed to evaluate whether or not RPV water level can be determined.

1.8.1 An off-scale indication does not itself mean that RPV water level cannot be determined provided the instrument is believed to be functioning properly and the off-scale indication is consistent with plant conditions. For example, if all available RPV water level instruments are observed to trend downward following indication of a large primary system break with limited makeup capability, an eventual downscale indication would be consistent with plant conditions and could be considered valid, subject to the instrumentation limits addressed in EOP Caution #1.

1.8.2 Whether RPV water level can be determined within the context of EOP strategies depends upon whether identified action levels and decisions can be evaluated, not whether the precise value of RPV water level is known. If fuel zone RPV water level instruments are indicating downscale and the downscale indications are believed to be valid, RPV water level relative to the top of the fuel and the minimum steam cooling RPV water level can be determined even though level is below the indicating range.

1.8.3 Similarly, if RPV water level indications are driven off-scale high and upscale indications are believed to be valid, level can be determined to be above the top of the fuel. Whether an off-scale indication can be considered valid, however, and the length of time an off-scale indication can be relied upon, requires a judgment based on the nature of the event, plant conditions, and the instrument characteristics.

1.9 PROBABLE CAUSES 1.9.1 Loss of all level instruments.

1.9.2 A complete loss of the speed probes for the given RFP will cause the controller for that RFP to shift to MDVP.

1.9.3 A feed flow instrument going to 0" but not giving a failed signal.

1.10 PROBABLE ANNUNCIATORS 1.10.1 9-5-2/D-1, REACTOR LOW LEVEL TRIP.

1.10.2 9-5-2/F-1, REACTOR HIGH WATER LEVEL.

1.10.3 9-5-2/G-1, REACTOR LOW WATER LEVEL.

1.10.4 9-5-2/F-4, RVLC SYSTEM LOGIC INITIATED.

1.10.5 9-5-2/G-4, RVLC SYSTEM TROUBLE.

1.10.6 A-1/E-6, RFP TURBINE A CONTROL TROUBLE.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 11 OF 13

ATTACHMENT 4 INFORMATION SHEET 1.10.7 A-1/F-5, RFP TURBINE A SUPERVISORY TROUBLE.

1.10.8 A-1/F-6, RFP TURBINE A DIAGNOSTIC XFER TO MAN.

1.10.9 A-2/E-3, RFP TURBINE B CONTROL TROUBLE.

1.10.10 A-2/F-2, RFP TURBINE B SUPERVISORY TROUBLE.

1.10.11 A-2/F-3, RFP TURBINE B DIAGNOSTIC XFER TO MAN.

1.11 PROBABLE INDICATIONS 1.11.1 Failure of RFP to respond to changes in RPV level or steam flow.

2. REFERENCES 2.1 PROCEDURES 2.1.1 General Operating Procedure 2.1.5, Reactor Scram.

2.1.2 General Operating Procedure 2.1.10, Station Power Changes.

2.1.3 System Operating Procedure 2.2.28.1, Feedwater System Operation.

2.1.4 System Operating Procedure 2.2.33.1, High Pressure Coolant Injection System Operations.

2.1.5 System Operating Procedure 2.2.67.1, Reactor Core Isolation Cooling System Operations.

2.1.6 Abnormal Procedure 2.4PC, Primary Containment Control.

2.1.7 Computer System Operating Procedure 2.6.3GARDEL, GARDEL Computer Systems Operation and Outage Recovery.

2.1.8 Instrument Operating Procedure 4.4.1, Reactor Vessel Level Control System.

2.1.9 Emergency Procedure 5.1BREAK, Pipe Break Outside Secondary Containment.

2.2 MISCELLANEOUS 2.2.1 LER 95-012, RPS Trip Signal and PCIS Group Isolations During Shutdown for Refueling Outage.

2.2.2 NEDC 92-050N, Reactor Vessel Shroud Level Below Low Level Trip Setpoint Calculation.

2.2.3 1 NRC Generic Letter 89-11, Boiling Water Reactor Water Level Redundancy. Affects Attachment 2, Step 2.1, and Attachment 4, Step 1.6.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 12 OF 13

ATTACHMENT 5 PRE-STAGING AID FOR PROCEDURE 2.4RXLVL 0.ATTACHMENT 5 PRE-STAGING AID FOR PROCEDURE 2.4RXLVL FAILURE SCRAM ACTIONS ACTION POINTS CONTINGENCIES TECH SPECS RPV Water

  • Level cannot be
  • Report level in 5" increments until scram.
  • Assign Procedure 2.1.5 responsibilities.
  • Report when level has stabilized.
  • Pre-stage Operator at HPCI/RCIC to Trouble
  • Level cannot be

maintained < 50". and RCIC tripped, if level band not widened via

  • Stabilize level with HPCI/RCIC following

malfunctioning and

  • 110" rising - requires steam lines isolated -
  • Consider lowering reactor pressure to causing unsafe Step 4.8. 500 lb to allow use of CBP if S/U valves are conditions.
  • 12" lowering - Scram Action. available.
  • 3.5" lowering - EOP entry.
  • IF level is rising following scram, THEN
  • Report all controllers taken to manual. prepare for MSIV closure.
  • Transition pressure control to SRVs.
  • Assign Operator to restore steam systems as soon as level can be maintained below 90".
  • IF scram is not required, THEN assign Operator with no concurrent duties to manually control level until level control is restored to automatic.

PROCEDURE 2.4RXLVL REVISION 28 PAGE 13 OF 13

Examination Outline Cross-Reference Level RO 295005 (APE 5) Main Turbine Generator Trip Tier # 1 Group # 1 Ability to determine and/or interpret the K/A # AA2.04 following as they apply to MAIN TURBINE Rating 3.7 GENERATOR TRIP:

AA2.04 Reactor pressure Question 51 The plant is operating at near rated power when the following occurred:

  • Main Generator MVARs begin to steadily increase
  • Doniphan contacts you to inform you the grid is becoming unstable
  • PCB 3310 trips open followed by PCB 3312
  • RV-71F is inoperable and cannot be opened After the scram is complete reactor pressure will be automatically controlled between .

A. 876 and 1040 psig B. 835 and 1010 psig C. 926 and 1025 psig D. 1004 and 1034 psig Answer: B Explanation:

This is a load reject situation. RPV pressure would rapidly rise before it tripped on RPV high pressure. On a trip like this low-low set (LLS) should activate since an SRV should open and RPS high pressure signal is received. Didnt move psig and and psig. to the stem because I think the question is easier to read this way. Tried to encapsulate the chart below for describing the range of LLS.

A is wrong because of Rev 3 statement.

B is correct because of Rev 3 statement.

C is wrong because of Rev 3 statement.

D is wrong because of Rev 3 statement.

Technical

References:

Procedure 2.2.77.1, Digital Electro-Hydraulic (DEH) Control System, Revision 42, p. 49 References to be provided to applicants during exam:

None.

Learning Objective:

COR002-16-02, Nuclear Pressure Relief, Revision 21, Enabling objectives 1.c and 3.j.

Page 8 of 10

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question History: Last NRC Exam No Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis 4 10CFR Part 55 Content: 55.41.10 Page 9 of 10

Technical justification to change the written examination answer key - Question #51 Question 51 NOTE - Answer B was identified as the correct answer in the Answer Key.

Recommend that the question be deleted because there is no correct answer for the following reasons:

1. The stem states that the grid is becoming unstable and the main generator output breakers have opened. This information does not state that a loss of offsite power has occurred.
2. Offsite power remains available after a generator trip; a Group 1 isolation will not occur since a transfer to the Startup Transformer maintains power to the Group 1 isolation logic.
3. After the initial pressure transient, the Main Turbine Bypass Valves will subsequently maintain RPV pressure at the pressure setpoint.

If the stem would have stated a loss of offsite power had occurred, or that a Group 1 isolation had occurred, then Answer B would be the only correct answer.

Page 10 of 10

FORM 9 - EXAM ITEM ANALYSIS Exam ID# _CNS 2020-9 ILT NRC Examination_

Date Evaluation Instrument Administered: __09/29/20__

Number of Trainees Evaluated: ______9_______

Section A - Any question receiving greater than 50% failure rate N/A List each question receiving greater than 50% failure rate.

Question Question Review Failure Corrective Action Number Conclusion*

Rate (%)

2 89 F Question has two correct answers; requested a change to the answer key via the post-exam documentation submittal.

20 56 G Determined to be a weakness in applicant knowledge. This GAP was resolved during post examination review. No other actions taken.

27 56 G Determined to be a weakness in applicant knowledge. This GAP was resolved during post examination review. No other actions taken.

29 67 G Determined to be a weakness in applicant knowledge. This GAP was resolved during post examination review. No other actions taken.

34 67 G Determined to be a weakness in applicant knowledge. This GAP was resolved during post examination review. No other actions taken.

40 56 G Determined to be a weakness in applicant knowledge. This GAP was resolved during post examination review. No other actions taken.

61 56 F Question has two correct answers; requested a change to the answer key via the post-exam documentation submittal.

72 56 G Determined to be a weakness in applicant knowledge. This GAP was resolved during post examination review. No other actions taken.

89 63 G Determined to be a weakness in applicant knowledge. This GAP was resolved during post examination review. No other actions taken.

91 63 G Determined to be a weakness in applicant knowledge. This GAP was resolved during post examination review. No other actions taken.

  • Review Conclusion A. Insufficient training for the learning objective tested B. Learning objectives not adequately covered in the lesson plan C. Poorly worded or invalid learning objective D. Poorly worded or invalid test item or answer E. Incorrect answer in the exam key F. More than one correct answer G. Question acceptable H. Other (state reason in table or on additional sheet)

Form Rev #: _01_

Approved by (IT or Trng Mgmt initials): _RSH Date: _11/12/2019

FORM 9 - EXAM ITEM ANALYSIS Section B - Greater than 25% overall exam failure N/A Conclusion Summary Corrective Action Review performed by: __Clyde Edgington__________________ Date: _10/06/20__

Approved by: _________James B. Florence________________ Date: _10/07/20 _

Training Supervision Form Rev #: _01_

Approved by (IT or Trng Mgmt initials): _RSH Date: _11/12/2019

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