ML21208A422

CN-2021-06 Final Written Exam

ML21208A422
Person / Time
Site:	Cooper
Issue date:	06/25/2021
From:	Heather Gepford Operations Branch IV
To:	Nebraska Public Power District (NPPD)
References
Download: ML21208A422 (227)

Text

ES-401 Site-Specific RO Written Examination Form ES-401-7 Cover Sheet U.S. Nuclear Regulatory Commission Site-Specific RO Written Examination Applicant Information Name:

Date: Facility/Unit Cooper Nuclear Station Region: I II III IV Reactor Type: W CE BW GE Start Time: Finish Time:

Instructions Use the answer sheets provided to document your answers. Staple this cover sheet on top of the answer sheets. To pass the examination, you must achieve a final grade of at least 80 percent. Examination papers will be collected 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after the examination begins Applicant Certification All work done on this examination is my own. I have neither given nor received aid.

Applicants Signature Results Examination Value 75 Points Applicants Score________ Points Applicants Grade Percent 1

Examination Outline Cross-Reference Level RO 295001 (APE 1) Partial or Complete Loss of Forced Tier# 1 Core Flow Circulation / 1 & 4 Group# 1 AK3.04 - Knowledge of the reasons for the following K/A # 295001 AK3.04 responses as they apply to Partial or Complete Loss Rating 4.1 of Forced Core Flow Circulation: Reactor SCRAM. Revision 1 (CFR: 41.5 / 45.6)

Revision Statement: Rev 1 - Per CE comments, changed stem to Which one of the following actions is required first, and clarified explanation of correct answer to cover the second part (the reason).

Question 1 The plant is at 100% power.

Then, both RR Pumps A and B simultaneously trip.

Which one of the following actions is required first IAW Procedure 2.4RR [Reactor Recirculation Abnormal] AND why?

A. Insert a manual scram to avert thermal hydraulic instability.

B. Insert a manual scram to avert high reactor water level trips.

C. Insert Emergency Power Reduction Rods to lower rod line below 118.9%.

D. Insert Emergency Power Reduction Rods to exit the Stability Exclusion Region.

Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of why a scram is inserted IAW the AOP for trip of both RR pumps. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated AOP.

Thermal hydraulic instability can occur during conditions of high power and low recirculation flow. Regional high power oscillations could challenge fuel design limits.

While core-wide reactor instability is the predominate mode and regional mode oscillations are not expected to occur, the reactor is protected from regional mode oscillations through avoidance of the Stability Exclusion Region and administrative controls on reactor conditions which are primary factors affecting reactor stability.

One administrative control required by Procedure 2.4RR is a manual scram is 2

required with no RR loops in operation anytime power is >1% in order to avert the possibility of THI. Since power would be >1% following trip of both RR pumps from 100% power, a manual scram is required to ensure THI will not be experienced.

Distracters:

Answer B is plausible because trip of both RR pumps causes rapid core void production, which results in a significant rise in downcomer water level. If RR pump shaft seizure had occurred, RPV level could rapidly exceed the high water level trip setpoint, +53.5. Procedure 2.4RXLVL immediate action step 3.1.2 requires inserting a manual scram anytime level goes above +50 to provide margin to the high level trip setpoint. This answer is wrong because the pumps trip due to control circuit failure, not shaft seizure, so reactor water level would not rise to >+50 due to the coast down effects of the RR pumps and the response of the RVLCS.

Answer C is plausible because reduction in core flow from high power could result in rod line rising above 118%, as stated for executing a Rapid Power Reduction in Procedure 2.1.10 Caution before step 9.4. Procedure 2.1.10 P&L 2.6 states if rod line exceeds 118.9%, take action to reduce rod line to 118.9% or below and to reduce power using recirculation flow per Section 7 and/or control rods per Procedure 10.13.

This answer is incorrect because Immediate action required by 2.4RR step 3.1 supersedes Att. 3 actions.

Answer D is plausible because trip of both RR pumps would result in operation of the Stability Exclusion Region of the P/F Map, and Procedure 2.4RR Att. 3 step 1.3.2 states exit the region by inserting Emergency Power Reduction Rods. This answer is incorrect because Immediate action required by 2.4RR step 3.1 supersedes Att. 3 actions.

Technical

References:

Procedure 2.4RR, Reactor Recirculation Abnormal (Rev 47),

Procedure 2.1.10, Station Power Changes (Rev 120), Procedure 10.13, Control Rod Sequence and Movement Control (Rev 77), Procedure 2.4RXLVL, RPV Water Level Control Trouble (Rev 28)

References to be provided to applicants during exam: none Learning Objective: INT032-01-24 EO-G, Given plant condition(s), state from memory all immediate operator actions required to mitigate the event(s).

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 3 3

SRO Only Justification: N/A PSA Applicability N/A 4

Examination Outline Cross-Reference Level RO 295003 (APE 3) Partial or Complete Loss of AC Tier# 1 Power / 6 Group# 1 AA1.02 - Ability to operate and/or monitor the K/A # 295003 AA1.02 following as they apply to Partial or Complete Loss Rating 4.5 of AC Power: Emergency Generators. Revision 1 (CFR: 41.7 / 45.6)

Revision Statement: Rev 1 - Per CE comments, added due to loss of cooling water flow to part 2 stem and enhanced explanation why local EMERGENCY STOP button must be used to stop the respective DG.

Question 2 Given the following:

• Plant is in Mode 3

• Loss of all offsite power occurred 1 minute ago

• DG1 and DG2 are in operation IAW Procedure 5.3EMPWR [Emergency Power during Modes 1, 2, or 3] for these conditions, The maximum load at which a DG may be operated for an UNLIMITED time is (1) kW.

AND If a DG must be immediately tripped due to loss of cooling water flow, stop the DG by (2)

A. (1) 4000 (2) pressing the local EMERGENCY STOP button.

B. (1) 4000 (2) placing and holding DIESEL GEN 1(2) STOP/START switch at Panel C to STOP for 1 to 2 seconds.

C. (1) 4400 (2) pressing the local EMERGENCY STOP button.

D. (1) 4400 5

(2) placing and holding DIESEL GEN 1(2) STOP/START switch at Panel C to STOP for 1 to 2 seconds.

Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of a load limit associated with monitoring DG operation and knowledge of controls used to operate the DG IAW the AOP/EP. This question meets Tier 1 requirements because it tests knowledge of an administrative limitation specified in the associated AOP for DG operation during a loss of offsite power in Mode 3.

DG initiation signals are:

1) reactor water level low, -113

2) Drywell pressure high, 1.84 psig

3) 4160V Bus 1F (1G) undervoltage, 2300 V If all off-site power sources are lost simultaneously, the main generator will trip, causing loss of NSST. If there is no bus lockout, 1AS and 1BS will close on to the SSST when 1AN and 1BN trip open. 1AS and 1BS will close even if there is no voltage on the SSST secondary. 1AF, 1FA, 1BG, and 1GB will trip in < 1 second (with an inverse time constant, "0" volts will result in a very short delay before the breakers trip on first level protection). The DGs will receive an auto start signal at the same time as these breakers receive a trip signal. The voltage permissive for 1FS and 1GS will not be met, so these breakers will not close. When DGs reach rated voltage and speed, and at least 10 seconds after the first level voltage protection signal was sensed, DG output breakers will close and energize 4160 VAC Bus 1F/1G.

Procedure 5.3EMPWR states the primary function of Control Room Operators during loss of normal AC power transient is to monitor the automatic sequence of events to ensure the necessary emergency equipment returns to service. Operator must monitor emergency power source loading to ensure overload limits are avoided. step 1.1.2 lists the maximum continuous load limit for a DG as 4000 kW.

If Service Water flow is lost to a DG, the DG must be immediately tripped. Procedure 5.3EMPWR step 4.2.2.1 states IF initiation signal present, THEN locally at DG1(2)

Control Panel, press and release EMERGENCY STOP. This is because the DG START/STOP switches on Panel C will not stop the respective DGs if an initiation signal is present.

Distracters:

Answer B part 1 is correct. Part 2 is plausible because Procedure 5.3EMPWR step 4.2.2.2. states IF no initiation signal present, place and hold DIESEL GEN 1(2)

STOP/START switch to STOP for 1 to 2 seconds, THEN release. The examinee who fails to recognize an undervoltage DG initiation signal occurred or believes it would have cleared, since DG1 would have restored bus voltage above 2300 V, may choose 6

this answer. It is wrong because Procedure 5.3EMPWR states if an initiation signal is present, the local EMERGENCY STOP is to be pressed, since there is an undervoltage initiation sealed-in and the START/STOP switches on Panel C will not stop the respective DGs.

Answer C part 1 is plausible because 5.3EMPWR Att. 1 step 1.1.2 states a DG may be overloaded to 4400 kW and 763 amps for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. It is wrong because the stem asks for the maximum load at which a DG may be operated for an unlimited time, and 4400 kW is limited to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Part 2 is correct.

Answer D part 1 is plausible and wrong for the reason given for distractor C. Part 2 is plausible and wrong for the reason given for distractor B.

Technical

References:

Procedure 5.3EMPWR, 5.3EMPWR, Emergency Power during Modes 1, 2, or 3 (Rev 71), Procedure 2.2.18.1, 4160V Auxiliary Power Distribution System (Rev 3), Procedure 2.2.20, Standby AC Power System (Diesel Generator) (Rev 111)

References to be provided to applicants during exam: none Learning Objective: INT032-01-31 EO-U, Given plant condition(s), state from memory all immediate operator actions required to mitigate the event(s); EO-T, Given plant condition(s), state from memory any automatic actions listed in the applicable Abnormal/Emergency Procedure(s) which will occur due to the event(s)

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(7),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - Emergency AC Power, DGs 7

Examination Outline Cross-Reference Level RO 295004 (APE 4) Partial or Total Loss of DC Power / Tier# 1 6 Group# 1 AA2.01 - Ability to determine and/or interpret the K/A # 295004 AA2.01 following as they apply to Partial or Complete Loss Rating 4.0 of DC Power: Partial or complete loss of DC power. Revision 1 (CFR: 41.10 / 43.5 / 45.13)

Revision Statement: Rev 1 - Per CE comments, revised distractors to make them more plausible and to make them more balanced. Also, enhanced explanation justifying this is RO-level due to testing AOP entry conditions, not SRO-level procedure selection.

Question 3 A LOCA has occurred.

The Control Room red AND green indicating lights for the following switches are extinguished:

• RHR Pump B

• Core Spray Pump A

• DIESEL GEN 1 BKR 1FE Which one of the following conditions would cause these indications AND which procedure is required to be entered?

A. Panel AA3 is de-energized, enter Procedure 5.3DC125 [Loss of 125 VDC].

B. Panel AA3 is de-energized, enter Procedure 5.3AC120 [Loss of 120 VAC].

C. Panel BB3 is de-energized, enter Procedure 5.3DC125 [Loss of 125 VDC].

D. Panel BB3 is de-energized, enter Procedure 5.3AC120 [Loss of 120 VAC].

Answer: A Explanation:

This question satisfies the K/A because it determination/interpretation of indications of a partial loss of DC power associated with AOP/EP mitigation strategy. This question meets Tier 1 requirements because it involves diagnosis that leads to selection of the appropriate AOP required to respond to the evolution.

8

The breakers associated with the listed components are all on 4160 VAC Bus 1F.

125 VDC Panel AA3 supplies the breaker control circuits for Bus 1F. The Control Room control switch indicating lights are powered from the breaker control circuits.

Loss of Panel AA3 requires entry into Procedure 5.3DC125.

This is RO level because it only tests knowledge of AOP entry conditions. This is not SRO level because it does not require procedure selection for a condition where more than one procedure is applicable. The entry condition to Procedure 5.3EMPWR is implied and requires first diagnosing that a loss of 125VDC Panel AA3 exists. If panel AA3 was de-energized, the examinee should deduce multiple control room annunciators would also be alarming, which is an entry condition for Procedure 5.3EMPWR.

Distracters:

Answer B is plausible to the examinee who does not know panel AA3 is a 125 VDC panel and believes it to be 120 VAC. This is plausible because 120 VAC panel CCP-1A powers indicating lights for some control room indication, such as SGT A inlet valves, and loss of critical 120 VDC requires entry into Procedure 5.3AC120.. This answer is wrong because Procedure 5.3DC125 is required to be entered for loss of panel AA3.

Answer C is plausible because 125 VDC Panel BB3 powers control switch indicating lights for components similar to those listed in the stem but with breakers related to 4160V Bus 1G. This answer is wrong because panel AA3 supplies the subject indicating lights Answer D is plausible and wrong for the reasons stated for distractors B and C.

Technical

References:

2.2A_125DC.DIV1 [125 VDC Power Checklist (DIV 1)](Rev 8), Procedure 2.2A_125DC.DIV2 [125 VDC Power Checklist (DIV 2)](Rev 8),

Procedure 2.2A_4160.DIV1 [4160 VAC Auxiliary Power Checklist (DIV 1)](Rev 2),

Procedure 5.3AC120 [Loss of 120 VAC] (Rev 42), Procedure 5.3DC125 [Loss of 125 VDC] (Rev 45)

References to be provided to applicants during exam: none Learning Objective: COR002-07-02 Obj. LO-06b, 08b Question Source: Bank #

(note changes; attach parent) Modified Bank # NRC 2017-3 Q#3 New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7),(10) 9

Level of Difficulty: 2 SRO Only Justification:

N/A PSA Applicability Top 10 Risk Significant System - Emergency DC Power Top 10 Risk Sensitive Components - 125 VDC Panel AA3 From NRC 2017-3 10

Examination Outline Cross-Reference Level RO 295005 (APE 5) Main Turbine Generator Trip / 3 Tier# 1 G2.4.2 - Knowledge of system setpoints, interlocks Group# 1 and automatic actions associated with emergency K/A # 295005 G2.4.2 and abnormal operating procedure entry conditions. Rating 4.0 (CFR: 41.7 / 45.7 / 45.8) Revision 2 Revision Statement: Rev 1 - Changed power level in stem to 20% and bolded based on validation.

Rev 2 - Per CE comment, unbolded 20% in stem, because it was cueing.

Question 4 The plant is at 20% power.

Main turbine lube oil pressure is 17 psig and lowering for unknown reasons.

(1) At what turbine lube oil pressure setpoint will an automatic turbine trip occur as turbine lube oil pressure continues to lower?

AND (2) Procedure(s) is(are) required to be entered when the turbine trips.

A. (1) 11 psig (2) 2.4TURB [Main Turbine Abnormal], ONLY B. (1) 11 psig (2) 2.4TURB [Main Turbine Abnormal] AND 2.1.5 [Reactor Scram]

C. (1) 6 psig (2) 2.4TURB [Main Turbine Abnormal], ONLY D. (1) 6 psig (2) 2.4TURB [Main Turbine Abnormal] AND 2.1.5 [Reactor Scram]

Answer: C Explanation:

This question satisfies the K/A because it tests knowledge of setpoints for interlocks, automatic actions, AOP entry conditions, and alarm response procedures associated with a main turbine trip. This question meets Tier 1 requirements because it involves diagnosis that leads to selection of the appropriate AOP required to respond to the evolution.

11

The setpoint for the main turbine trip on low lube oil pressure is 6 psig. Procedure 2.4TURB entry is required. With reactor power below the TSV/TCV Closure RPS trip bypass setpoint, 29.5% power, RPS will not trip due to a TSV/TCV closure (turbine trip) signal; therefore, Procedure 2.1.5 entry will not be required. Bypass valves, with a capacity of 25% rated steam flow, rapidly open to control reactor pressure upon the scram, so no other transient effects would result in a scram.

Distracters:

Answer A part 1 is plausible because the Emergency DC Oil Pump auto starts at 9-11 psig. This answer is wrong because the setpoint for the turbine trip is 6 psig per alarm card B-1/A-4 [TG Low Brg Oil Pressure Trip]. Part 2 is correct.

Answer B part 1 is plausible and wrong for the reason stated for distractor A. Part 2 is plausible because TSV/TCV closure (turbine trip) would cause a reactor scram at some reactor power levels, which would require entry into Procedure 2.1.5. This answer is wrong because the power level stated in the stem, 20%, is below the setpoint and the automatic scram for TSV/TCV closure is bypassed, and 20% power is within the capacity of bypass valves.

Answer D part 1 is correct. Part 2 is plausible and wrong for the reason stated for distractor B.

Technical

References:

Procedure 2.4TURB [Main Turbine Abnormal](Rev 36), alarm card B-1/A-4 [TG Low Brg Oil Pressure Trip](Rev 40), Lesson Plan COR001-14-01

[Ops Main Turbine] (Rev 33), Procedure 2.1.5 [Reactor Scram](Rev 77), Lesson Plan COR001-14-01 [Ops Main Turbine] (Rev 33), Alarm Card 9-5-2/C-4 [TSV & TCV Closure Trip Byp Chan A/B] (Rev 52), Alarm Card B-1/B-4 [TG Low Brg Oil Pressure Pre-Trip] (Rev 40)

References to be provided to applicants during exam: none Learning Objective: INT032-01-27 EO-M, Given plant condition(s), state from memory the appropriate Abnormal/Emergency Procedure(s) to be utilized to mitigate the event(s); EO-N, Given plant condition(s), state from memory any automatic actions listed in the applicable Abnormal/Emergency Procedure(s) which will occur due to the event(s)

COR001-14-01 Obj LO-21a, Given plant/system conditions, determine if: The Main Turbine should have tripped Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental 12

Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(4),(5),(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 13

Examination Outline Cross-Reference Level RO 295006 (APE 6) Scram / 1 Tier# 1 AK1.02 - Knowledge of the operational implications Group# 1 and/or cause and effect relationships of the following K/A # 295006 AK1.02 as they apply to SCRAM: Shutdown margin. Rating 3.6 (CFR: 41.8 to 41.10) Revision 2 Revision Statement: Rev 1 - Replaced question with one similar to that provided by CE recommendation.

Rev 2 - Reformatted part 2 stem into bulleted list based on validator comments Question 5 A scram occurs at 100% power, resulting in the following conditions:

• Reactor power is 0%

• Control rod 26-27 is stuck at position 48 (1) The crew enters Procedure 2.1.5 [Reactor Scram], and needs to determine the status of the remaining control rods for shutdown margin.

This is directed by Procedure 2.1.5 .

AND (2) Assuming:

• a xenon free core,

• moderator temperature is greater than the most reactive state,

• and all remaining rods are at position 00, What is the status of shutdown margin (SDM)?

A. (1) Attachment 1, Mitigating Task Scram Actions (2) SDM is met B. (1) Attachment 1, Mitigating Task Scram Actions (2) SDM is NOT met C. (1) Attachment 2, Reactor Power Control (2) SDM is met D. (1) Attachment 2, Reactor Power Control 14

(2) SDM is NOT met Answer: C Explanation:

This question satisfies the K/A because it tests knowledge of the effect of shutdown margin and its operational implications with respect to the related AOP during scram conditions.

This question meets Tier 1 requirements because it requires knowledge of the scram procedure that ensures shutdown margin by verification of control rod position.

Procedure 2.1.5, Attachment 2, Step 1.4 directs verifying all control rods fully inserted and is performed for all plant scrams.

ROs are responsible for knowing the TS definition of Shutdown Margin (i.e. above the line information for TS 3.1.1).

Shutdown margin is defined in TS as:

SDM shall be the amount of reactivity by which the reactor is subcritical or would be subcritical throughout the operating cycle assuming that:

a. The reactor is xenon free;

b. The moderator temperature is~ 68°F, corresponding to the most reactive state; and

c. All control rods are fully inserted except for the single control rod of highest reactivity worth, which is assumed to be fully withdrawn.

With control rods not capable of being fully inserted, the reactivity worth of these control rods must be accounted for in the determination of SDM.

Since only one control rod is withdrawn, shutdown margin is met.

Distracters:

Answer A part 1 is plausible because Procedure 2.1.5 Att. 1 contains important response actions for a scram and is performed for all plant scrams. This answer is wrong because Att. 1 does not require verifying control rod position. Part 2 is correct Answer B part 1 is plausible and wrong for the reason given for distractor A. Part 2 is plausible because one control rod is at position 48. The examinee who does not know the definition of shutdown margin may choose this answer. This answer is wrong because the definition of shutdown margin assumes the control rod of the highest worth is fully withdrawn for the degree of shutdown margin required by TS, so adequate shutdown margin still exists.

Answer D part 1 is correct. Part 2 is plausible and wrong for the reason given for distractor B.

15

Technical

References:

TS section 1.1, TS 3.1.1 [Shutdown Margin], Procedure 2.1.5

[Reactor Scram](Rev 77)

References to be provided to applicants during exam: none Learning Objective: INT007-05-01 EO-3d, From memory, define the following terms:

Shutdown Margin Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(1),(10)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 16

Examination Outline Cross-Reference Level RO 295016 (APE 16) Control Room Abandonment / 7 Tier# 1 AK2.06 - Knowledge of the relationship between Group# 1 Control Room Abandonment and the following K/A # 295016 AK2.06 systems or components: Rating 3.8 Safety/relief valves. Revision 1 (CFR: 41.7 / 45.8)

Revision Statement: Rev 1 - Per CE comments, added control room evacuated due to toxic fumes to stem Question 6 A scram occurred from 100% power.

Procedure 5.1ASD [Alternate Shutdown] has been entered due to toxic fumes.

The Alternate Shutdown Panel operator has just placed the Automatic Depressurization System valve isolation switch to ISOLATE for the first time IAW 5.1ASD.

(1) What SRV manual control switches are CURRENTLY functional?

AND (2) IAW Procedure 5.1ASD, which SRVs are used to control reactor pressure?

A. (1) Three SRVs at the Alternate Shutdown Panel, ONLY (2) 71A, 71B, 71C B. (1) Three SRVs at the Alternate Shutdown Panel, ONLY (2) 71E, 71F, 71G C. (1) Three SRVs at the Alternate Shutdown Panel AND five other SRVs at panel 9-3.

(2) 71A, 71B, 71C D. (1) Three SRVs at the Alternate Shutdown Panel AND five other SRVs at panel 9-3.

(2) 71E, 71F, 71G Answer: D Explanation:

17

This question satisfies the K/A because it tests knowledge of SRV interlocks associated with the Alternate Shutdown ADS isolation switch and knowledge of ininstructions contained in procedure 5.1ASD for pressure control. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated AOP.

Control switches for 3 SRVs, along with a common isolation switch, are located on the local ADS Panel. When the isolation switch is first taken to ISOLATE IAW 5.1ASD, all automatic control and manual control from panel 9-3 for SRVs 71E,F,G is removed and manual control for 71E,F,G from the ADS panel ability is enabled. Later in 5.1ASD to maintain Mode 4, installation of jumpers effectively converts the isolation switch into a manual open/close switch for 71E,F,G, simultaneously opening all three valves when taken to ISOLATE. (These different configurations makes this question higher order.) Therefore, when the ADS isolation switch is first placed to isolate, auto and control room manual control for SRVs 71E,F,G is defeated and manual control at the ASD Panel is enabled. Manual and auto control for the other 5 SRVs is unaffected, so their control room panel 9-3 control switches are still functional.

Distracters:

Answer A part 1 is plausible because for other systems, such as HPCI, isolation switches defeat all automatic signals and manual control from panel 9-3. It is wrong because with the isolation switch in ISOLATE, only manual control from panel 9-3 for SRV-71E,F,G is defeated. Manual control from control room panel 9-3 is still available for SRVs 71A,B,C,D,H. Part 2 is plausible because the 3 valves listed in the answer are are all ADS valves. An examinee may conclude since the panel and isolation switch are labeled ADS, they must only control ADS valves and not SRV 71F, which is a low-low set valve. This is wrong because the valves controlled from the ADS Panel are 71E,F,G.

Answer B part 1 is plausible and wrong for the same reasons as stated for distractor A. Part 2 is plausible because it is correct.

Answer C part 1 is plausible because it is correct. Part 2 is plausible and wrong for the same reasons as stated for distractor A.

Technical

References:

Procedure 5.1ASD [Alternate Shutdown](Rev 20), lesson plan COR002-34-02 [Ops Alternate Shutdown](Rev 24)

References to be provided to applicants during exam: none Learning Objective: COR002-34-02 LO-02a, 09 Question Source: Bank # NRC ILT 2018-9 Q#41 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental 18

Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(3),(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability:

Top 10 Risk Significant Systems - ADS/SRV 2018-9 NRC ILT Q#41 19

Examination Outline Cross-Reference Level RO 295018 (APE 18) Partial or Complete Loss of CCW / Tier# 1 8 Group# 1 AK3.01 - Knowledge of the reasons for the following K/A # 295018 AK3.01 responses or actions as they apply to Partial or Rating 3.4 Complete Loss of Component Cooling Water: Revision 0 Isolation of non-essential heat loads.

(CFR: 41.5 / 45.6)

Revision Statement:

Question 7 The plant is at 100% power with REC Pump B tagged out of service for preventive maintenance.

REC Pump C trips.

15 seconds later, conditions are:

• REC discharge header pressure 60 psig, stable

• REC temperature 90°F, stable Which one of the following describes an operator action required IAW Procedure 5.2REC

[Loss of REC] immediate operator actions AND the reason for this action?

A. Close REC-AO-710, RWCU Non-Regen Hx Inlet, to reduce the heat load on REC in order to lower REC temperature B. Close REC-AO-710, RWCU Non-Regen Hx Inlet, to raise discharge header pressure above the low pressure isolation setpoint.

C. Close REC MO-1329, Augmented Radwaste Supply, to reduce the heat load on REC in order to lower REC temperature.

D. Close REC MO-1329, Augmented Radwaste Supply, because it will not automatically close on low REC discharge header pressure.

Answer: B Explanation:

20

This question satisfies the K/A because it tests knowledge of what non-critical load is isolated IAW the AOP/EP and why during a partial loss of CCW (REC). This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated AOP.

If REC discharge header pressure falls to 61 psig, after a 40 second time delay, the following valves automatically close, isolating the non-critical loads, in order to maintain REC available to the critical loads:

• REC-MO-712, HX A OUTLET

• REC-MO-700, NON-CRITICAL HEADER SUPPLY

• REC-MO-702, DRYWELL SUPPLY ISOLATION (if control switch in AUTO)

• REC-MO-1329, AUGMENTED RADWASTE SUPPLY

• REC-MO-713, HX B OUTLET At 100% power, normally three REC pumps are operating and the remaining pump is idle. If REC discharge header pressure falls to 62 psig, immediate operator actions of 5.2REC require first starting the idle REC pump to attempt to restore header pressure.

If that action has not raised pressure above 62 psig, the next strategy employed is to isolate the most sacrificial non-critical loads, RWCU and Augmented Radwaste, by closing REC-AO-710 and REC-MO-1329 in an attempt to avert a full non-critical header isolation, which would result in loss of cooling to RRMGs and DW FCUs and greatly complicate plant operations. Since REC Pump B is tagged out of service, no other pumps are available to raise REC pressure, so manually isolating REC-AO-710 and REC-MO-1329 is required.

Distracters:

Answer A is plausible because 5.2REC requires manually closing REC-AO-710. It is wrong because the reason for this action is not to reduce REC temperature, but to raise REC pressure. REC temperature given in stem, 90°F, is the maximum REC temperature allowed, 98°F. REC pressure given in the stem, 60 psig, is below the normal control band, 65-85 psig, and below the low pressure isolation setpoint.

Answer C is plausible because 5.2REC requires manually closing REC-MO-1329. It is wrong because the reason for this action is not to reduce REC temperature, but to raise REC pressure. REC temperature given in stem, 90°F, is within the normal range of REC temperature, 65-95°F. REC pressure given in the stem, 60 psig, is below the normal control band, 65-85 psig.

Answer D is plausible because 5.2REC requires manually closing REC-MO-1329. It is wrong because REC-MO-1329 does automatically close on low REC discharge header pressure, 61 psig, after a 40 second time delay, and the reason for manual closure is to attempt to raise REC header pressure before a low pressure isolation occurs.

Technical

References:

Procedure 5.2REC [Loss of REC](Rev 20), Procedure 2.2.65

[Reactor Equipment Cooling Water System](Rev 67) 21

References to be provided to applicants during exam: none Learning Objective: INT032-01-26 EO-N, Given plant condition(s), state from memory all immediate operator actions required to mitigate the event(s).

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(4),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 22

Examination Outline Cross-Reference Level RO 295019 (APE 19) Partial or Complete Loss of Tier# 1 Instrument Air / 8 Group# 1 AA1.03 - Ability to operate and/or monitor the K/A # 295019 AA1.03 following as they apply to Partial or Complete Loss Rating 3.5 of Instrument Air: Air compressors. Revision 1 (CFR: 41.7 / 45.6)

Revision Statement: Rev 1 - Per validator comments, added a leak occurs on the instrument air header to the stem to add credibility for IA pressure not recovering. Removed SAC B annunciators from stem, since they were not needed and only cluttered the stem, then enlarged gauge image.

Question 8 The plant is at 100% power with Station Air Compressors (SAC) aligned as follows:

• SAC 1A 1st Backup (stopped)

• SAC 1B Lead (running)

• SAC 1C 2nd Backup (stopped)

Then, a leak occurs on the instrument air header, and SAC 1B trips.

Instrument Air Pressure on IA-PI-606 lowers to the value indicated below AND stabilizes:

(1) Which SAC(s) is/are running?

AND (2) Which Procedure(s) is/are required to be entered for this condition?

A. (1) 1A, only (2) Associated alarm cards, ONLY 23

B. (1) 1A, only (2) Associated alarm cards AND 5.2AIR [Loss of Instrument Air]

C. (1) 1A and 1C (2) Associated alarm cards, ONLY D. (1) 1A and 1C (2) Associated alarm cards AND 5.2AIR [Loss of Instrument Air]

Answer: B Explanation:

This question satisfies the K/A because it tests knowledge for monitoring air compressors IAW the AOP/EP during a partial loss of IA. This question meets Tier 1 requirements because it involves diagnosis that leads to selection of the appropriate AOP required to respond to the evolution.

The lead SAC, 1B, is set to load between 100 to 110 psig. The 1st Backup SAC, 1A, is set to auto start at 93 psig and load between 93 to 105 psig. The 2nd Backup SAC, 1C, is set to auto start at 90 psig and load between 90 to 100 psig. Since IA pressure only 92 psig, only SAC 1A and 1B have a demand to be running loaded, since 92 psig is above the auto start and loading range of the 2nd backup compressor, SAC C.

Since SAC 1B is tripped, which does not automatically reset, only SAC 1A is running.

An entry condition for Procedure 5.2AIR per Step 1.1 is INSTRUMENT AIR PRESSURE below green band and does not recover back into green band. The lower limit of the green band for IA pressure is 95 psig, and the stem depicts IA pressure is 92 psig and stable. Since IA pressure has stabilized below the green band on IA-PI-606, Procedure 5.2AIR entry is required. Procedure 5.2AIR provides the mitigating action instructions to recover the tripped air compressor.

Distracters:

Answer A part 1 is correct. Part 2 is plausible because for other systems, operation below the indicator green band for header pressure does not require entry into the associated AOP. For example, the green band lower limit for REC header pressure is 65 psig; however, Procedure 5.2REC [Loss of REC] is not required to be entered unless pressure cannot be restored above 62 psig. It is also plausible because indicated IA pressure, 92 psig, is above the orange arrow at 77 psig on IA-PI-606. An examinee may believe the orange arrow is the limit for AOP entry. This answer is wrong because Procedure 5.2AIR is required to be entered if IA pressure cannot be restored to the green band (95 psig).

Answer C part 1 is plausible because SAC 1C would receive an automatic start when IA discharge header pressure falls below the setpoint for the 2nd Backup SAC. It is wrong because IA pressure never lowered to the setpoint for the 2nd Backup SAC, 90 psig. Part 2 is plausible and wrong for the same reason given for distractor A.

24

Answer D part 1 is plausible and wrong for the same reason given for distractor C.

Part 2 is correct.

Technical

References:

Procedure 5.2AIR [Loss of Instrument Air](Rev 24),

Procedure 2.2.59 [Plant Air System](Rev 77), Procedure 5.2REC [Loss of REC] (Rev 20)

References to be provided to applicants during exam: none Learning Objective: INT032-01-36 EO-M, Given plant condition(s), determine from memory any automatic actions listed in the applicable Abnormal/Emergency Procedure(s) which will occur due to the event(s).

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(4),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 25

Examination Outline Cross-Reference Level RO 295021 (APE 21) Loss of Shutdown Cooling / 4 Tier# 1 AA2.07 - Ability to determine and/or interpret the Group# 1 following as they apply to Loss of Shutdown K/A # 295021 AA2.07 Cooling: Reactor recirculation flow. Rating 3.8 (CFR: 41.10 / 43.5 / 45.13) Revision 1 Revision Statement: Rev 1 - removed momentarily and and then return to normal from fifth sentence per validator comments Question 9 The plant is in Mode 4 with the following conditions:

• RHR Pump B is operating in Shutdown Cooling mode

• Reactor Recirc Pump A flow is 10,800 gpm

• RWCU is secured Maintenance activities cause narrow range level instruments, ONLY, to drop downscale.

Which of the following indications is required to be used to monitor RPV temperature under these conditions?

A. RR-TI-151A, SUCT TEMP (Panel 9-4)

B. RHR-TR-131, Point 2, RHR HX B INLET (Panel 9-21)

C. RWCU-TI-137, TEMP IND, Point 1, PMP DISCH WITH SUBCOOL (Panel 9-4)

D. NBI-TR-89, REACTOR VESSEL METAL TEMPERATURE RECORDER, Point 11, VESSEL BOTTOM HEAD (Panel 9-21)

Answer: A Explanation:

This question satisfies the K/A because it requires interpreting/determining RR flow in order to select the appropriate temperature instrumentation to monitor IAW the AOP during a loss of SDC. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated AOP.

26

Group 2 (RHR) isolation occurs at +3 narrow range reactor water level. This results in trip of RHR Pump B and entry into Procedure 2.4SDC. RR Pump A flow given as an initial condition in the stem is indicative of RR Pump A running at minimum speed.

RR pump trip logic on low reactor water level comes from wide range reactor level instruments, so RR Pump A remains operating. Step 4.4.1 of Procedure 2.4SDC states IF a RR pump is in service, THEN monitor RR-TI-151A(B), SUCT TEMP, since that provides the most representative indication of coolant temperature when the respective RR pump is operating, providing adequate coolant circulation.

Distracters:

Answer B is plausible because RHR heat exchanger inlet temperature is used to monitor RCS temperature when the associated RHR SDC is in service. The examinee who believes Group 2 isolation on low reactor water level is based on wide range level instrumentation may choose this answer because they believe RHR Pump B is still operating. It is wrong because Group 2 isolation on low reactor water level is sensed by narrow range instruments, which would have tripped when <+3 inches was sensed by narrow range level instruments.

Answer C is plausible because Procedure 2.4SDC Step 4.4.3 lists RWCU-TI-137, TEMP IND, Point 1, PMP DISCH WITH SUBCOOL as an indication by which RPV temperature should be monitored. The examinee who does not know the bottom head drain piping arrangement and that RWCU is required to be in service for this indication to be valid may select this answer. This answer is wrong because Procedure 2.4SDC Step 4.4.3 requires monitoring this point only if RWCU is in service, but RWCU is listed as not in service in the stem.

Answer D is plausible because it represents an indication required to be used to monitor RPV temperature per Procedure 2.4SDC Step 4.4.2. It is also plausible because RR pumps trip on low reactor water level sensed by wide range instrumentation. The examinee who confuses narrow range level instrumentation with wide range and believes RR Pump A has tripped may select this answer. This answer is wrong because Procedure 2.4SDC Step 4.4.2 states to use NBI-TR-89 only if a RR pump is not in service, but RR Pump A is in service. The RR pump trip on low reactor water level is based on Wide Range level at a setpoint of -42, which has not been exceeded.

Technical

References:

Procedure 2.4SDC [Shutdown Cooling Abnormal] (Rev 18),

Dwg CNS-NBI-10, Procedure 2.1.22 [Recovering from a Group Isolation] (Rev 63),

Procedure 2.2.69.2 [RHR System Shutdown Operations] (Rev 109)

References to be provided to applicants during exam: none Learning Objective: INT032-01-26 EO-Q, Given plant condition(s) and the applicable Abnormal/Emergency Procedure, discuss the correct subsequent actions required to mitigate the event(s) 27

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(2),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 28

Examination Outline Cross-Reference Level RO 295023 (APE 23) Refueling Accidents / 8 Tier# 1 G2.4.20 - Knowledge of the operational implications Group# 1 of emergency and abnormal operating procedures K/A # 295023 G2.4.20 warnings, cautions, and notes. Rating 3.8 (CFR: 41.10 / 43.5 / 45.13) Revision Revision Statement:

Question 10 A refueling accident results in total loss of Spent Fuel Pool (SFP) cooling flow.

EOP-5A has been entered due to high SFP temperature.

EOP Caution #13 applies for elevated SFP temperature prior to boiling.

(1) IAW EOP Caution #13, what is the FIRST effect of loss of cooling on SFP level?

AND (2) What indication(s) is/are available to the operator to determine a value for SFP level?

A. (1) Level lowers due to evaporation (2) Local observation at SFP, ONLY B. (1) Level lowers due to evaporation (2) Panel 9-21 recorder AND local observation at SFP C. (1) Level overflows due to thermal expansion (2) Local observation at SFP, ONLY D. (1) Level overflows due to thermal expansion (2) Panel 9-21 recorder AND local observation at SFP Answer: D Explanation:

This question satisfies the K/A because it tests knowledge of operational implications of an EOP Caution and an EP note related to a refueling accident.

29

This question meets Tier 1 requirements because it tests knowledge of information contained in the associated EOP and EP.

Caution #13 states:

Prolonged loss of SFP cooling will accelerate evaporation and thermal expansion of water in the SFP resulting in condensation on colder building walls, overflow of the SFP, flooding in the Reactor Building, and personnel habitability and access restrictions.

The basis for Caution #13 is:

During a prolonged loss of spent fuel pool cooling, spent fuel pool temperature will increase, resulting in higher evaporation rates and thermal expansion of water in the spent fuel pool. The accelerated evaporation will elevate secondary containment humidity, leading to significant condensation on cooler surfaces, which will then drain to lower building elevations. While the increased evaporation will tend to reduce pool inventory, the thermal expansion effect predominates, resulting in a net rise in spent fuel pool level (at least until spent fuel pool temperature approaches the boiling point). Water may overflow spent fuel pool surge tanks, drain into pool ventilation ducts, or spill into the reactor cavity and dryer/separator pit. The combination of thermal expansion overflow and condensation runoff may lead to flooding in various areas of the reactor building.

SFP level can be obtained locally from SFP level indicator FP-LI-2, and it can be obtained from RHR-TR-131 RHR Temperature Recorder on Panel 9-21 in the control room. Addition of a channel for SFP level is a plant change for FLEX strategy. The channel receives input from the new SFP Monitoring System.

Distracters:

Answer A part 1 is plausible because evaporation occurs as SFP temperature rises.

This answer is wrong because the stem asks for the first effect on SFP level related to Caution #13. The bases for Caution #13 states thermal expansion effect on SFP level predominates over evaporation, resulting in level rising to the point of pool overflow.

Part 2 is plausible because SFP level indication is an indication which has been added to recorder RHR-TR-131 [RHR Heat Exchanger Temperature Recorder] on Panel 9-21 during FLEX modifications. An examinee may not remember SFP level has been added as Channel 11 on this RHR temperature recorder, and since there is not a separate SFP level recorder or indicator in the control room, the examinee may select this answer. This answer is wrong because remote indication of SFP level is located in the control room on RHR-TR-131 on Panel 9-21.

Answer B part 1 is plausible and wrong for the same reason stated for distractor A.

Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the same reason stated for distractor A 30

Technical

References:

EOP-5A [Secondary Containment Control] (Rev 19), PSTG AMP00 App. B (Rev 10), Procedure 5.1RAD [Building Radiation Trouble] (Rev 19)

References to be provided to applicants during exam: none Learning Objective: INT008-06-17 EO-8, Explain why actions to control spent fuel pool temperature and level may need to be taken relatively early in an event; EO-10, Explain why the preferred spent fuel pool level control band may need to be replaced with the alternate level control band.

Question Source: Bank #

(note changes; attach parent) Modified Bank # 2017-3 NRC ILT Q#10 New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(4),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 31

From 2017-3 NRC ILT Q#10 32

Examination Outline Cross-Reference Level RO 295024 High Drywell Pressure / 5 Tier# 1 EK1.01 - Knowledge of the operational implications Group# 1 and/or cause and effect relationships of the following K/A # 295024 EK1.01 as they apply to High Drywell Pressure: Drywell Rating 4.3 integrity. Revision 0 (CFR: 41.8 to 41.10)

Revision Statement:

Question 11 Reference Provided The following conditions exist during a LOCA.

• Torus pressure is 29 psig, stable.

• Torus water level is 13 feet, slowly rising.

• Reactor pressure is 600 psig.

(1) What is the adverse consequence of these conditions?

AND (2) Which of the following actions is/are required IAW EOP-3A?

A. (1) Steam formation in the suppression chamber air space (2) Operate PC sprays, ONLY B. (1) Steam formation in the suppression chamber air space (2) Emergency Depressurize AND operate PC sprays C. (1) Structural design pressure limit for the drywell has been exceeded (2) Operate PC sprays, ONLY D. (1) Structural design pressure limit for the drywell has been exceeded (2) Emergency Depressurize AND operate PC sprays Answer: B Explanation:

This question satisfies the K/A because it tests knowledge of the effect of high DW pressure on drywell integrity and the associated operational implications with respect 33

to the applicable EOP. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated EOP.

The Pressure Suppression Pressure (PSP) limit is a function of Torus pressure and Torus water level and pertains to preserving drywell integrity. Conditions in the stem reflect operation in the unsafe zone of the (PSP) Curve. At CNS, the PSP limit is the highest suppression chamber pressure which can occur without steam in the suppression chamber airspace.

EOP-3A Steps PC/P-4 and 5 require operation of Torus and Drywell sprays when Torus pressure is above 10 psig. Step PC/P-6 requires emergency depressurization when Torus pressure cannot be maintained below the PSP limit. For the case presented, the PSP limit is ~26 psig, so PSP has been exceeded. Therefore, both PC sprays and emergency depressurization are required.

Distracters:

Answer A part 1 is correct. Part 2 is plausible because some EOP actions are only required if a parameter cannot be restored and maintained to within limits (e.g. EOP-3A Step SP/L-6 for high PC water level), and operation of PC sprays would be expected to lower Torus pressure to be the PSP limit. An examinee who believes it is acceptable for PC sprays be given the opportunity to lower PC pressure to within limits to avert emergency depressurization, or an examinee who errantly plots operation within the safe zone of the PSP curve may choose this answer. This answer is wrong because operation is in the unsafe zone of the PSP curve, and EOP-3A Step PC/P-6 requires emergency depressurization in addition to operation of PC sprays.

Answer C part 1 is plausible because the PC pressure limit, PCPL-A, is a function of water level and pressure. PCPL-A is the lesser of: a) the pressure capability of the primary containment, b) the maximum primary containment pressure at which vent valves sized to reject all decay heat from the containment can be opened and closed, and c) the maximum primary containment pressure at which SRVs can be opened and will remain open. PCPL-A the maximum design pressure limit for the drywell.

This answer is wrong because the PCPL-A limit is 62.7 psig for the conditions presented in the stem. Therefore, the drywell structural design pressure limit has not been exceeded. Part 2 is plausible and wrong for the reason given for distractor A.

Answer D Part 1 is plausible and wrong for the reason given for distractor C. Part 2is correct.

Technical

References:

EOP/SAG Graphs (Rev 17), EOP-3A [Primary Containment Control] (Rev 18), PSTG AMP00 App. B (Rev 10)

References to be provided to applicants during exam: EOP Graph 10 [Pressure Suppression Pressure]

34

Learning Objective: INT008-06-13 EO-4c, State the basis for primary containment control actions as they apply to the following: Graphs referenced on Flowchart 3A Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(9),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 35

Examination Outline Cross-Reference Level RO 295025 (EPE 2) High Reactor Pressure / 3 Tier# 1 EK2.12 - Knowledge of the relationship between Group# 1 High Reactor Pressure and the following systems or K/A # 295025 EK2.12 components: Main and reheat steam system. Rating 3.1 (CFR: 41.7 / 45.8) Revision 0 Revision Statement:

Question 12 When executing EOP-1A, the operator is directed to open SRVs to reduce RPV pressure to 940 psig if SRVs, not including Low-Low Set, are cycling.

What is basis for the specific value of 940 psig when reducing pressure?

A. low enough to allow resetting the scram B. high enough to fully open bypass valves C. high enough to provide a sufficient margin above the shutoff head of CS and RHR pumps D. low enough to prevent the actuation of SRVs on mechanical setpoints and prevents arming of LLS Answer: B Explanation:

This question satisfies the K/A because it tests knowledge of the EOP actions related to the main steam system required for a high reactor pressure condition. It satisfies Tier 1 requirements because it tests knowledge of information contained in the sites EOPs and associated bases documents.

RPV pressure reduction with SRVs is continued until RPV pressure reaches the pressure at which steam flow through the main turbine BPVs is at 100% of BPV capacity (937 psig as listed in PSTGs). EOP-1A lists the target as 940 psig, since that is a rounded value more readable on an analog gauge. If the MSIVs are open, reducing RPV pressure to below this value results in partial closure of the BPVs and a corresponding rise in the amount of steam discharged to the suppression pool through the SRVs. If the MSIVs are not open, reducing RPV pressure to the lowest pressure 36

at which all BPVs would be fully open, if controlling pressure, provides an adequate operating margin below the setpoint pressure of the lowest lifting SRV.

Distracters:

Answer A is plausible because scram setpoint is 1050 psig and resetting the scram is desirable for level control and RPV bottom head cooldown concerns. This answer is wrong because the setpoint is based on BPV position, not RPS initiation setpoint.

Answer C is plausible because inadvertent injection from high volume systems is undesirable. This answer is wrong because this pressure is significantly higher than shutoff head of these pumps and other steps prevent inadvertent injection.

Answer D is plausible because rejecting heat to the condenser is preferable to rejecting heat to the containment. This answer is wrong because although this is low enough to prevent actuation of LLS, it is based on BPV positioning not actuation of SRVs on mechanical setpoint.

Technical

References:

EOP-1A [RPV CONTROL] (Rev 22), PSTG AMP00 App. B (Rev 10)

References to be provided to applicants during exam: none Learning Objective: INT0080605001070A State the basis for pressure control actions in Flowchart 1A as they apply to the following: Specific Setpoints Question Source: Bank # 17991 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(7),(10)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability:

N/A 37

Examination Outline Cross-Reference Level RO 295026 (EPE 3) Suppression Pool High Water Tier# 1 Temperature / 5 Group# 1 EK3.04 - Knowledge of the reasons for the following K/A # 295026 EK3.04 responses as they apply to Suppression Pool High Rating 3.6 Water Temperature: SLCS injection. Revision 2 (CFR: 41.5 / 45.6)

Revision Statement: Rev 1 - Per CE comments changed question to only ask reason for SLC injection before exceeding BIIT limit. Replaced part 1 and plotting BIIT graph and removed BIIT graph as a provided reference. Former part 2 is now part 1. Added new part 2.

Rev 2 - Per CE comments, replaced part 2 distractor and moved Suppression Pool temperature from the stem to the answer to prevent cueing.

Question 13 An ATWS is in progress at 20% power.

The reason EOP-6A requires SLC to be initiated before entering the unsafe zone of the Boron Injection Initiation Temperature (BIIT) graph is to permit injection of (1) Shutdown Boron Weight of boron before (2) .

A. (1) Hot (2) Drywell pressure exceeds the Primary Containment Pressure Limit B. (1) Hot (2) Suppression Pool temperature exceeds the Heat Capacity Temperature Limit C. (1) Cold (2) Drywell pressure exceeds the Primary Containment Pressure Limit D. (1) Cold (2) Suppression Pool temperature exceeds the Heat Capacity Temperature Limit Answer: B Explanation:

This question satisfies the K/A because it requires knowledge of why SLC injection is required IAW the EOP based on high SP water temperature. This question meets 38

Tier 1 requirements because it tests knowledge of instructions contained in the associated EOP and its bases.

The Boron Injection Initiation Temperature (BIIT) specifies the suppression pool temperature before which boron injection must be started. It is the greater of:

• The highest suppression pool temperature at which initiation of boron injection will permit injection of the Hot Shutdown Boron Weight of boron before suppression pool temperature exceeds the Heat Capacity Temperature Limit.

• The suppression pool temperature at which a reactor scram is required by plant Technical Specifications.

The BIIT is a function of reactor power. If boron injection is initiated before suppression pool temperature reaches the BIIT, emergency RPV depressurization may be precluded at lower reactor power levels.

BIIT is the highest suppression pool temperature at which initiation of boron injection will permit injection of the Hot Shutdown Boron Weight of boron before suppression pool temperature exceeds the Heat Capacity Temperature Limit.

Distracters:

Answer A part 1 is correct. Part 2 is plausible because Drywell pressure will rise as suppression pool temperature and Torus pressure rises. This answer is wrong because injection of SLC before BIIT ensures HSBW is injected before HCTL is exceeded, which would occur well before PCPL was challenged.

Answer C part 1 is plausible because BIIT is based on avoiding HCTL due to injecting sufficient boron. It is wrong because BIIT is based on Hot shutdown boron weight, not Cold shutdown boron weight. Part 2 is plausible and wrong for the reason given for distractor A.

Answer D part 1 is plausible and wrong for the reason given for distractor C. Part 2 is correct.

Technical

References:

EOP-6A [RPV Pressure and Reactor Power (Failure-to-Scram)] (Rev 19), AMP-TBD00 (PSTG) Technical Basis App. B (rev 10), EOP/SAG Graph 8 [Boron Injection Initiation Temperature (BIIT)], TS 3.6.2.1 [Suppression Pool Average Temperature]

References to be provided to applicants during exam: none Learning Objective: INT008-06-06 EO-7, Explain the basis for injecting boron before the Boron Injection Initiation Temperature is exceeded and when large periodic neutron flux oscillations in excess of 25% occur.

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X 39

Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(1),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability:

N/A 40

Examination Outline Cross-Reference Level RO 295028 (EPE 5) High Drywell Temperature (Mark I Tier# 1 and Mark II only) / 5 Group# 1 EA1.05 - Ability to operate and/or monitor the K/A # 295028 EA1.05 following as they apply to High Drywell Rating 3.8 Temperature: Safety relief valves. Revision 0 (CFR: 41.7 / 45.6)

Revision Statement:

Question 14 IAW EOP-3A for rising drywell temperature (1) What action is ONLY required WHEN drywell temperature can NOT be restored and maintained below 340°F?

AND (2) What does 340°F drywell temperature equate to?

A. (1) Initiate Drywell Sprays (2) ADS qualification limit B. (1) Initiate Drywell Sprays (2) RHR qualification limit C. (1) Emergency depressurize (2) ADS qualification limit D. (1) Emergency depressurize (2) RHR qualification limit Answer: C Explanation:

This question satisfies the K/A because it tests knowledge associated with operating SRVs IAW the EOP due to high DW temperature. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated EOP.

PSTGs state the basis for EOP-3A step DW/T-5 is that 340°F is the environmental qualification temperature for ADS; therefore, emergency depressurization using ADS valves is required while ADS valves are still functional.

41

Distracters:

Answer A part 1 is plausible because EOP-3A step DW/T-4 requires operation of DW Spray BEFORE DW temperature reaches 280°F. It is wrong because DW spray is required BEFORE 280°F, not 340°F. Emergency depressurization is ONLY required WHEN DW temperature cannot be restored and maintained below 340°F. Part 2 is correct.

Answer B part 1 is plausible and wrong for the reason stated for distractor A. Part 2 is plausible because both RHR and ADS are ECCS systems that have components located inside PC. It is wrong because 340°F is the ADS qualification temperature limit.

Answer D part 1 is correct. Part 2 is plausible and wrong for the reason stated for distractor B.

Technical

References:

EOP-3A [Primary Containment Control](Rev 18), lesson plan INT008-06-13 [OPS EOP Flowchart 3A - Primary Containment Control](Rev 18),

PSTG (AMP-TBD00 Technical Basis)(Rev 10)

References to be provided to applicants during exam: none Learning Objective: INT008-06-13 EO-12, Given plant conditions and EOP flowchart 3A, PRIMARY CONTAINMENT CONTROL, state the reasons for the actions contained in the steps; EO-4b, State the basis for primary containment control actions as they apply to the following: Specific setpoints Question Source: Bank # 2018-9 NRC ILT Q#14 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(7),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - ADS 42

Examination Outline Cross-Reference Level RO 295030 (EPE 7) Low Suppression Pool Water Level Tier# 1

/5 Group# 1 EA2.05 - Ability to determine and/or interpret the K/A # 295030 EA2.05 following as they apply to Low Suppression Pool Rating 4.1 Water Level: ECCS/RCIC pump flow. Revision 0 (CFR: 41.10 / 43.5 / 45.13)

Revision Statement:

Question 15 Reference Provided The plant has experienced an earthquake resulting in the following conditions:

• RHR Pump C is in Suppression Pool Cooling at 8200 gpm

• CS Pump A is operating on minimum flow

• RCIC is injecting 400 gpm IAW EOP Caution 3, which system(s) exceed(s) the respective vortex limit when suppression pool level is 5.75 feet?

A. RHR, only B. CS and RHR, only C. RHR and RCIC, only D. CS, RHR, and RCIC Answer: C Explanation:

This question satisfies the K/A because it requires interpreting low pressure ECCS and RCIC pump flows IAW the EOP during a condition when SP level is low. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated EOP and its bases.

Caution 3 reminds the operator of potential equipment damage when operating above NPSH & Vortex limits. The vortex limits are defined to be the lowest suppression pool water level above which air entrainment is not expected to occur in pumps taking 43

suction on the pool. These levels are functions of pump flow. Exceeding the limits can lead to air entrainment at the pump suction strainers. RCICs vortex limit is reached when SP level falls below 6 feet. RHRs vortex limit at 8200 gpm is ~7 feet. Minimum flow for CS is <2120 gpm, and the corresponding vortex limit is 4.5 feet SP level.

Therefore, both RHR and RCIC have exceeded their vortex limits for their stated flows at 5.75 feet SP level.

Distracters:

Answer A is plausible because RHR has exceeded its vortex limit and the RCIC limit is not depicted as a curve, as are the limits for HPCI, CS, and RHR, but only by a notation in the top left of the Vortex Limits graph. An examinee who overlooks the notation for RCIC may choose this answer. This answer is wrong because RCICs vortex limit of 6 feet has been exceeded with SP level 5.75 feet.

Answer B is plausible because RHR has exceeded its vortex limit, and a numerical value for CS flow is not provided. The examinee who does not know the value for CS minimum flow may choose this answer. It is wrong because CS minimum flow is

<2120 gpm, which correlates to a vortex limit of 4.5 feet, which has not been exceeded. Also, the RCIC vortex limit, 6 feet, has been exceeded.

Answer D is plausible because RHR and RCIC have exceeded their vortex limits, and a numerical value for CS flow is not provided. The examinee who does not know the value for CS minimum flow may choose this answer. It is wrong because CS minimum flow is <2120 gpm, which correlates to a vortex limit of 4.5 feet, which has not been exceeded.

Technical

References:

EOP 3A [Primary Containment Control] (Rev. 18), Emergency Operating Procedure 5.8 [EOP and SAG Graphs], (Rev. 17), PSTG (AMP-TBD00 Technical Basis)(Rev 10), Lesson Plan COR002-06-02 [Ops Core Spray System] (Rev 30)

References to be provided to applicants during exam: EOP Vortex Limits (Graphs 4A,B 6A,B)

Learning Objective:

INT00806180010300 Given plant conditions and the EOP and SAG Graphs Flowchart, determine if operation is within the allowed region of a graph.

Question Source: Bank #

(note changes; attach parent) Modified Bank # 2020-9 NRC ILT Q#43 New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(10) 44

Level of Difficulty: 4 SRO Only Justification: N/A PSA Applicability:

Top 10 Risk Significant Systems - RHR, RCIC 2020-9 NRC ILT Q#43:

45

Examination Outline Cross-Reference Level RO 295031 (EPE 8) Reactor Low Water Level / 2 Tier# 1 G2.4.18 - Knowledge of the specific bases for Group# 1 emergency and abnormal operating procedures. K/A # 295031 G2.4.18 (CFR: 41.10 / 43.1 / 45.13) Rating 3.3 Revision 2 Revision Statement: Rev 1 - Per CE comment, changed answer A to NOT assured because RPV level and injection flow rates are too low, because original answer did not include a bases, as requested in the stem.

Rev 2 - Per CE comment, replaced distractor C for balance.

Question 16 LOCA conditions exist:

• Reactor pressure is 50 psig, steady

• Reactor water level is -200 inches Corrected Fuel Zone, steady

• RHR Pump A injection is 6000 gpm

• CS pump A injection is 4800 gpm

• The ONLY injection sources are RHR A and CS A What is the status of adequate core cooling IAW EOP-1A and its bases?

Adequate core cooling is .

A. NOT assured because of RPV level and injection rates B. assured by spray cooling C. NOT assured because of RPV level and spray flow injection rate D. assured by steam cooling Answer: B Explanation:

46

This question satisfies the K/A because it requires knowledge of the specific bases for EOP-1A thresholds for low reactor water level related to adequate core cooling. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated EOP and its bases.

Adequate Core Cooling is defined by the CNS Emergency Operating Procedures and the associated bases documents. Adequate core cooling within the EPGs, heat removal from the reactor sufficient to prevent rupturing the fuel clad. Three viable mechanisms for establishing adequate core cooling have been evaluated: core submergence, steam cooling, and spray cooling.

Spray cooling is accomplished by establishing flow through at least one CS subsystem at 4750 gpm while also maintaining RPV water level at or above -209",

the elevation of the jet pump suction. This method is only available in EOP-1A, in which the reactor is shutdown under all conditions without boron. Design core spray flowrate is listed in PSTGs as 4721 gpm. A conservative value of 4750 gpm is used in EOPs because it is more readable on the panel flow meter.

Distracters:

Answer A is plausible because RPV level is below TAF (-158 inches), so adequate core cooling by submergence does not exist. Submergence (RPV water level at or above the top of the active fuel) is the preferred method of adequate core cooling and always assures that maximum fuel cladding temperature does not exceed 1500ºF, which is the threshold temperature for fuel cladding perforations. The examinee who recognizes RPV level is below TAF and does not know the definition of spray cooling might select this answer. It is wrong because level is above -209 inches, and injection flow from one CS pump is above 4750 gpm.

Answer C is plausible because RPV level is very low, below the minimum for adequate core cooling by submergence (TAF, -158) and below the minimum for steam cooling with injection (MSCRWL, -183). The examinee who does not know the definition of spray cooling might select this answer. It is wrong because level is above

-209 inches, and injection flow from one CS pump is above 4750 gpm.

Answer D is plausible because level is below -183 inches. Steam cooling with injection, in which the core is partially uncovered but the required steam pressure needed to assure cooling of the uncovered portions of the fuel is maintained with positive injection, also always assures that maximum fuel cladding temperature does not exceed 1500°F (for as long as the required conditions are maintained). It is applicable with level -158 inches to -183 inches. Steam cooling without injection, in which no injection means is available and cooling of the uncovered portions of the fuel is a function of RPV level and pressure, assures that maximum fuel cladding temperature does not exceed 1800°F, which is the threshold for the zirconium-water reaction. While these transient conditions are maintained, minimal fuel cladding damage is assured. It is applicable with level -183 inches to -195 inches. The examinee who does not know the definition of steam cooling might select this answer.

47

It is wrong because level is below -195 inches, where only spray cooling can cool the core.

Technical

References:

EOP-1A [RPV Control] (Rev 22), PSTG AMP00 App. B (Rev 10)

References to be provided to examinees during exam: none Learning Objective: INT008-06-09 EO-1, Describe the three mechanisms specified in the EOPs to assure adequate core cooling including the RPV water level band required and which is the preferred method Question Source: Bank # LOR Biennial Bank Q#8-1 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10),(8),(2)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability:

N/A 48

Examination Outline Cross-Reference Level RO 295037 (EPE 14) Scram Condition Present and Tier# 1 Reactor Power Above APRM Downscale or Group# 1 Unknown / 1 K/A # 295037 EK1.04 EK1.04 - Knowledge of the operational implications Rating 3.7 and/or cause and effect relationships of the following Revision 2 as they apply to SCRAM Condition Present and Reactor Power Above APRM Downscale or Unknown: Hot shutdown boron weight.

(CFR: 41.8 to 41.10)

Revision Statement: Rev 1 - Per CE comments, removed reverse logic by moving part 2 to part 1 and moving the required action relative to hot shutdown boron weight to part 2 by asking what action is required when hot shutdown boron weight has been injected.

Rev 2 - Per CE comments, added You are in EOP-6A and at step FS/Q-13 Boron Injection required to stem to better meet Tier 1 requirements and removed HSBW from stem to prevent cueing. For this revised arrangement, Added The next action with respect to SLC required by EOPs is: to stem to make distractor D wrong. Also, added current SLC tank level to prevent assumption SLC level is already below HSBW.

Question 17 An ATWS is in progress with the following conditions:

• Reactor power is 5%

• 30 control rods are stuck out due to fuel channel bow

• Reactor water level has been intentionally lowered to -80 inches to suppress neutronic oscillations

• You are in EOP-6A and at step FS/Q-13 Boron Injection required.

o SLC Pumps A and B are injecting o Initial SLC Tank level was 80%

o Current SLC Tank level is 78%, lowering slowly The next action with respect to SLC required by EOPs is:

When SLC Tank level reaches (1) , the crew is required to begin (2) .

A. (1) 54%

(2) raising RPV water level to the normal band IAW EOP-7A B. (1) 54%

(2) depressurizing the RPV to begin cooldown IAW EOP-6A 49

C. (1) 20%

(2) raising RPV water level to the normal band IAW EOP-7A D. (1) 20%

(2) depressurizing the RPV to begin cooldown IAW EOP-6A Answer: A Explanation:

This question satisfies the K/A because it requires knowledge of the value in SLC Tank percent volume of HSD Boron Weight and the its operational implications with respect to actions in EOP-6A and EOP-7A. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated EOP.

The Hot Shutdown Boron Weight (HSBW) is the least weight of soluble boron which, if injected into the RPV and mixed uniformly, will maintain the reactor shutdown under hot standby conditions. The HSBW is utilized to assure the reactor will be shutdown irrespective of control rod position when RPV water level is raised to uniformly mix the injected boron. EOP-7A Step FS/L-5, second override, and Step FS/L-24 direct raising RPV water level to the normal band when HSBW has been injected. EOP-6A lists the HSBW as 26% volume of the SLC Tank. Therefore, HSBW has been injected when SLC Tank level lowers to 56%, and the crew may begin raising RPV water level IAW EOP-7A Step FS/L-24. (80%-26%=54%)

EOP-6A Step FS/P-6 directs depressurizing to place SDC in service after Cold Shutdown Boron weight has been injected. The Cold Shutdown Boron Weight (CSBW) is that amount of soluble boron which, if injected into the RPV and mixed uniformly, will maintain the reactor shutdown under all conditions. EOP-6A lists CSBW as 60% volume of the SLC Tank. The CSBW is utilized to assure the reactor will remain shut down irrespective of control rod position or RPV water temperature.

CSBW assumes the increased volume required by operation of RHR SDC. However, HSBW does not assume the increased volume required by operation of RHR SDC.

Distracters:

Answer B part 1 is correct. Part 2 is plausible because it reflects the action required for CSBW having been injected. This answer is wrong because the stem asks what is required as soon as HSBW has been injected, and EOP-7A Step FS/L-5, second override, and Step FS/L-24 direct raising RPV water level to the normal band when HSBW has been injected, which occurs before CSBW has been injected.

Depressurization is not allowed until CSBW, 60%, has been injected.

Answer C part 1 is plausible because it reflects CSBW, 60%, injected. (80% - 60% =

20%). This answer is wrong because the stem requires the SLC Tank level for HSBW injected, which is 54% (80%-26%=54%). Part 2 is correct.

50

Answer D part 1 is plausible and wrong for the reason given for distractor C. Part 2 is plausible and wrong for the reason given for distractor B.

Technical

References:

EOP-6A [RPV Pressure and Reactor Power (Failure-to-Scram)] (Rev 19), EOP-7A [RPV Level (Failure-to-Scram)] (Rev 21), PSTG AMP00 App. B (Rev 10)

References to be provided to applicants during exam: none Learning Objective: INT008-06-10 EO-6, State the SLC tank level at which RPV level may be slowly raised to above the scram setpoint.

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 51

Examination Outline Cross-Reference Level RO 295038 (EPE 15) High Offsite Radioactivity Release Tier# 1 Rate / 9 Group# 1 EK2.09 - Knowledge of the relationship between K/A # 295038 EK2.09 High Offsite Radioactivity Release Rate and the Rating 3.0 following systems or components: Post-accident Revision 2 sample system.

(CFR: 41.7 / 45.8)

Revision Statement: Rev 1 - Per CE comments, changed part 1 distractor to -100 inches wide range to be more credible for fuel failure than -50 inches. Changed due to LOCA conditions in stem to due to conditions to eliminate potential challenge that LOCA conditions would not cause fuel failure if level is maintained at or above -100 inches.

Rev 2 - Per CE comments, referenced EOP-1A in stem to better meet Tier 1 requirements. Also, broke 2nd sentence of stem into two separate statements to avoid compound sentence and to clarify Procedure 2.1.22 is being used as directed by EOP-1A.

Question 18 EOP-1A and EOP-5A have been entered due to conditions that have resulted in high offsite release rates.

The CRS has directed you to align valves for Chemistry to obtain a reactor coolant PASS sample.

When verifying isolations IAW EOP-1A per Procedure 2.1.22 [Recovering from a Group Isolation], you discover the following valves have automatically isolated:

• RR-AO-740, OUTBD ISOL VLV

• RR-AO-741, INBD ISOL VLV (1) Which one of the following conditions caused the above valves to automatically close?

AND (2) While performing EOP-1A, how is that isolation signal bypassed in order to open the subject valves?

A. (1) Reactor water level lowered to -100 inches wide range (2) by installing EOP PTMs B. (1) Reactor water level lowered to -100 inches wide range (2) using bypass switches on Panel 9-4 C. (1) Main Steam Line radiation rose to four times normal full power background 52

(2) by installing EOP PTMs D. (1) Main Steam Line radiation rose to four times normal full power background (2) using bypass switches on Panel 9-4 Answer: D Explanation:

This question satisfies the K/A because it tests knowledge of Group 7 isolation signal related to high offsite radioactivity release and procedural requirements for bypassing the isolation signal for obtaining PASS samples of RCS. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated procedures. EOP-1A essentially directs performance of Procedure 2.2.68.1, because EOP-1A directs performance of Procedure 2.1.22, and Procedure 2.1.22 directs performance of Procedure 2.2.68.1.

PCIS Group 7 is comprised of valves RR-AO-740 and 741. Isolation signals for these valves are Low Reactor Water Level, -113 inches, and MSL High Radiation, 3X normal full power background (NFPB). Since MSL radiation has reached 4X NFPB, and reactor water level has only reached -50 inches, MSL high radiation was the cause of the isolation.

EOP-1A step RC/L-1 requires verifying isolations IAW Procedure 2.1.22. Procedure 2.1.22 step 10.6 requires using guidance in Procedure 2.2.68.1 if Group 7 is isolated and PASS sampling of the RCS is required. Procedure 2.2.68.1 directs first by passing the isolation for each RCS sample valve using its respective keylock bypass switch, located on Panel 9-4, and then opening the valve using its Panel 9-4 control switch.

Distracters:

Answer A part 1 is plausible because the subject valves isolate on a low reactor water level signal, and other PCIS valve groups (i.e Groups 2 and 3) isolate at -42 inches.

This answer is wrong because the subject valves, Group 7, do not isolate until Low-Low Level 1, -113 inches wide range. Part 2 is plausible because many other isolation interlocks are bypassed IAW plant procedures by installing Plant Temporary Modifications (PTMs) which usually involve lifting leads or installing jumpers (e.g. EOP PTMs 53-56 involve installation of jumpers to bypass the low reactor water level and high DW pressure isolation signals for Group 6 Reactor Building ventilation valves).

This answer is wrong because Group 7 isolation signals are bypassed using keylock bypass switches on Panel 9-4.

Answer B part 1 is plausible and wrong for the reason given for distractor A. Part 2 is correct.

53

Answer C part 1 is correct. Part 2 is plausible and wrong for the reason given for distractor A.

Technical

References:

Procedure 2.1.22 [Recovering from a Group Isolation] (Rev 63), Procedure 2.2.68.1 [Reactor Recirculation System Operations] (Rev 91),

Procedure 8.4.1.1 [Post-Accident Sampling System] (Rev 17), Procedure 8.PASS.1

[PASS Reactor Coolant Sampling] (Rev 5), Procedure 5.8.20 [EOP Plant Temporary Modifications] (Rev 21)

References to be provided to applicants during exam: none Learning Objective: INT032-01-04 EO-G1, Given a specific group isolation, briefly describe the process of resetting the isolation as described in Procedure 2.1.22, Recovering From A Group Isolation; COR002-03-02 LO Obj 13d, Describe the PCIS design features and/or interlocks that provide for the following: Bypassing of selected isolations Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(9),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - PCIS 54

Examination Outline Cross-Reference Level RO 600000 (APE 24) Plant Fire On Site / 8 Tier# 1 AK3.04 - Knowledge of the reasons for the following Group# 1 responses or actions as they apply to Plant Fire on K/A # 600000 AK3.04 Site: Actions contained in the fire response Rating 3.6 procedures for a plant fire on site. Revision 1 (CFR: 41.5, 41.10 / 45.6 / 45.13)

Revision Statement: Rev 1 - Swapped first and second bullets per validator comment.

Question 19 The plant is in Mode 3 with the following conditions:

• A fire in the reactor building results in a spurious High Drywell Pressure signal

• Reactor pressure is 200 psig 60 seconds later the following is identified:

• NO Service Water pumps are running IAW Procedure 5.4POST-FIRE-REACTOR [Reactor Building Post-Fire Operational Information],

Service Water pumps are required to be immediately started to provide cooling to A. HPCI room B. Fuel Pool Cooling C. Shutdown Cooling D. Diesel Generator(s)

Answer: D Explanation:

This question satisfies the K/A because it tests knowledge of the reason for a particular subsequent action listed in a fire response procedure is taken. This 55

question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated AOP.

Procedure 5.4POST-FIRE-REACTOR is entered from procedure 5.1INCIDENT due to a fire in the RB. The first action listed in procedure 5.4POST-FIRE-REACTOR is subsequent action step 4.2, which states if DG(s) running without SW flow, THEN immediately Start Service Water (SW) pumps from Control Room. If that is unsuccessful, SW pumps are started from the Critical Switchgear room. If a DG runs for 5 minutes without SW, then it must be shutdown using Emergency Stop push button.

Distracters:

Answer A is plausible because HPCI automatically initiates on High Drywell Pressure.

HPCI is important because it is the primary system for RPV level and pressure control during shutdown from outside the control room, and much emphasis is placed on preserving HPCI operation. SW is the heat sink for REC, which is the normal cooling water supply for the HPCI room cooler. Eventually in 5.4FIRE-S/D Att. 1, SW is cross-tied to REC to directly supply the HPCI room cooler. This answer is wrong because HPCI room cooling is not the reason SW pumps may have to be manually started as soon as 5.4POST-FIRE-REACTOR is entered. HPCI room temperature is not as time limiting as DG cooling. IF DG operation is required, SW must be supplied within 5 minutes to avoid DG damage.

Answer B is plausible because SW serves as the heat sink for Fuel Pool Cooling, and loss of cooling could eventually result in uncovery of spent fuel and fuel damage. The effects of loss of Fuel Pool Cooling have received much emphasis related to the Fukushima Daiichi disaster. This answer is wrong because Fuel Pool cooling is not the reason SW pumps may have to be manually started as soon as 5.4POST-FIRE-REACTOR is entered. Spent Fuel Pool temperature is not as time limiting as DG cooling. IF DG operation is required, SW must be supplied within 5 minutes to avoid DG damage.

Answer C is plausible because of the emphasis placed on loss of shutdown cooling.

SW serves as the heat sink for Shutdown Cooling, and loss of cooling could eventually result in uncovery of fuel and fuel damage. This answer is wrong because Shutdown cooling is not the reason SW pumps may have to be manually started as soon as 5.4POST-FIRE-REACTOR is entered. Reactor coolant temperature and inventory is not as time limiting as DG cooling. IF DG operation is required, SW must be supplied within 5 minutes to avoid DG damage.

Technical

References:

Procedure 5.4POST-FIRE-REACTOR [Reactor Building Post-Fire Operational Information] (Rev 8), Procedure 5.1INCIDENT [Site Emergency Incident] (Rev 41), 5.4FIRE-SD [Fire Induced Shutdown from Outside Control Room]

(Rev 77)

References to be provided to applicants during exam: none 56

Learning Objective: INT032-01-34 EO-G, Given plant condition(s) and the applicable Abnormal/Emergency Procedure, discuss the correct subsequent actions required to mitigate the event(s)

Question Source: Bank # 2015-11 NRC ILT Q#19 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10),(8)

Level of Difficulty: 2 SRO Only Justification: N/A PSA applicability:

Top 10 Risk Significant Systems - Service Water, Diesel Generators 57

Examination Outline Cross-Reference Level RO 700000 (APE 25) Generator Voltage and Electric Tier# 1 Grid Disturbances / 6 Group# 1 AA1.02 - Ability to operate and/or monitor the K/A # 700000 AA1.02 following as they apply to Generator Voltage and Rating 3.4 Electric Grid Disturbances: Turbine/generator Revision 1 controls.

(CFR: 41.5 / 41.10 / 45.5 / 45.7 / 45.8)

Revision Statement: Rev 1 - Per CE comment, enhanced plausibility justifications for distractors C and D by stating one out of four validators chose the GEN VOLTAGE ADJUST distractor portion during each of three validations (25% selection rate)

Question 20 Procedure 5.3GRID [Degraded Grid Voltage] has been entered due to grid voltage swings.

The GEN VOLTAGE REGULATOR switch has been placed to OFF per the procedure.

With the conditions shown above, the DCC System Operator requests you to adjust Main Generator output to 100 MVARs IN (LEADING).

How do you make this adjustment on Panel C?

58

A. Place GEN BASE ADJUST to RAISE B. Place GEN BASE ADJUST to LOWER C. Place GEN VOLTAGE ADJUST to RAISE D. Place GEN VOLTAGE ADJUST to LOWER Answer: B Explanation:

This question satisfies the K/A because it tests ability to interpret generator indications and operate generator voltage regulator controls during a grid disturbance IAW the AOP/EP. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated AOP/EP.

This question is a modified version of 2017-3 NRC ILT Q#63. It was modified by changing the GEN VOLTAGE REGULATOR switch position from ON to OFF, which changes which switch must be used to change the voltage regulator setting.

The photo indicates generator reactive load is positive (OUT) 72 MVARs. To adjust to 100 MVAR IN is to pick up negative MVARS. With the voltage regulator in OFF, GEN BASE ADJUST control switch adjusts voltage regulator output. To pick up negative (IN) MVARs, the switch is placed to LOWER.

Distracters:

Answer A is plausible because the target value of 100 is a larger number than the current MVAR value of 72. It is wrong because MVAR IN is a leading power factor, or negative MVAR value, which would be obtained by lowering voltage regulator output from its current value.

Answer C is plausible because GEN VOLTAGE ADJUST adjusts voltage regulator output if the voltage regulator is in AUTO. RAISE direction is plausible because the target value of 100 is a larger number than the current MVAR value of 72. One out of four validators chose the GEN VOLTAGE ADJUST distractor portion during each of three validations (25% selection rate). Knowledge deficiencies related to voltage regulator operation have been exhibited on past exams. For the original 2017 question that tested knowledge with the generator voltage regulator switch in ON, approximately 25% of validators and examinees missed the portion of the question related to which voltage adjust switch affects voltage regulator output based on the position of the voltage regulator switch. This answer is wrong because GEN BASE ADJUST control switch adjusts voltage regulator output with the voltage regulator in OFF, and MVAR IN is a leading power factor, or negative MVAR value, which would be obtained by lowering voltage regulator output from its current value.

59

Answer D is plausible because GEN VOLTAGE ADJUST adjusts voltage regulator output if the voltage regulator is in AUTO. One out of four validators chose the GEN VOLTAGE ADJUST distractor portion during each of three validations (25% selection rate). Knowledge deficiencies related to voltage regulator operation have been exhibited on past exams. For the original 2017 question that tested knowledge with the generator voltage regulator switch in ON, approximately 25% of validators and examinees missed the portion of the question related to which voltage adjust switch affects voltage regulator output based on the position of the voltage regulator switch.

This answer is wrong because GEN VOLTAGE ADJUST control switch adjusts voltage regulator output with the voltage regulator in automatic.

Technical

References:

Procedure 5.3GRID [Degraded Grid Voltage] (Rev 54),

Procedure 2.2.14 [22 KV Electrical System](Rev 90)

References to be provided to applicants during exam: none Learning Objective: COR001-13-02 obj LO-06d Question Source: Bank #

(note changes; attach parent) Modified Bank # 2017-3 NRC ILT Q#63 New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(5),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA applicability:

N/A 60

2017-3 NRC ILT Q#63 61

Examination Outline Cross-Reference Level RO 295002 (APE 2) Loss of Main Condenser Vacuum / Tier# 1 3 Group# 2 AA1.06 - Ability to operate and/or monitor the K/A # 295002 AA1.06 following as they apply to Loss of Main Condenser Rating 3.6 Vacuum: Reactor/turbine pressure regulating Revision 0 system.

(CFR: 41.7 / 45.6)

Revision Statement:

Question 21 2.4VAC [Loss of Condenser Vacuum] was entered due to air inleakage from the Turbine gland seals.

A power reduction to 60% has been performed.

Current conditions are:

• Delay Region of Condenser Pressure Trip Graph of Procedure 2.4VAC was entered two minutes ago

• Condenser vacuum is 23.2 inches Hg, lowering 0.2 inch Hg per minute (1) With NO further operator action, how many minutes remain before the Turbine AUTOMATICALLY trips due to low vacuum?

AND (2) How will Bypass Valves respond when the turbine automatically trips?

A. (1) one (2) Throttle open to maintain the DEH pressure setpoint B. (1) one (2) Rapidly open fully for 5 seconds, then throttle to maintain the DEH setpoint C. (1) three (2) Throttle open to maintain the DEH pressure setpoint D. (1) three (2) Rapidly open fully for 5 seconds, then throttle to maintain the DEH setpoint 62

Answer: D Explanation:

This question satisfies the K/A because it tests ability to monitor the main turbine and bypass valves during a loss of condenser vacuum IAW the AOP. This question meets Tier 1 requirements because it tests knowledge of information contained in the associated AOP.

This is a modified version of 2017-3 NRC ILT Q#62. It was modified by replacing part 2 with a different question.

Procedure 2.4VAC [Loss of Condenser Vacuum] Att. 3 Condenser Pressure Trip Graph depicts the vacuum limits that will cause an automatic turbine trip. The turbine trip on low condenser vacuum is a dynamically calculated value depicted by the 5 Minute Delay region. When operation degrades into the region bounded by the blue 5-Minute Delay line, a timer starts, and if the region is not exited, the Turbine trips 5 minutes following region entry. In this question, the 5 Minute Delay Region was entered 2 minutes ago; therefore, 3 minutes remain until the turbine automatically trips, since after a power reduction, vacuum is still lowering and will not improve, and power will not be raised to exit the delay region. The No Delay line of the Condenser Pressure Trip Graph at 22Hg will not be reached, which would take 6 more minutes, before the 5 minute delay setpoint causes an automatic turbine trip, since vacuum is falling only 0.2Hg/min. Operators call up the Condenser Pressure Trip Graph on the DEH HMI to monitor the point of operation.

At 60% power, generator load is ~463 MWe, which is above 106 MWe. For a turbine trip above 106 MWe, the bypass valve actuator dump valves open, causing the bypass valves to fully and rapidly open for 5 seconds before they begin to throttle based on the DEH pressure control setpoint.

Distracters:

Answer A part 1 is plausible because it reflects the time remaining until 23Hg vacuum is reached for the given rate of fall, 0.2Hg/min. 23Hg is the manual Turbine trip criteria per 2.4VAC: If vacuum cannot be maintained 23Hg, THEN a manual turbine trip is required. It is wrong because the automatic turbine trip is dynamically calculated and will occur 5 minutes after the Delay Region has been entered. In this case, 3 minutes from the present, since the delay region was entered 2 minutes ago.

Part 2 is plausible because upon a turbine trip below 106 MWe, bypass valves throttle open to maintain the DEH setpoint but do not fully and rapidly open for 5 seconds.

This answer is wrong because Generator output is above 106 MWe at 60% power, so bypass valves fully and rapidly open for 5 seconds, initially, then they throttle based on the DEH setpoint.

Answer B part 1 is is plausible and wrong for the same reasons as stated for distractor A. Part 2 is correct.

63

Answer C part 1 is correct. Part 2 is plausible and wrong for the same reasons as stated for distractor A.

Technical

References:

Procedure 2.4VAC [Loss of Condenser Vacuum](Rev 28),

Lesson Plan COR002-09-02 [Ops Digital Electro-Hydraulic Control] (Rev 21)

References to be provided to applicants during exam: none Learning Objective: INT032-01-32 Obj H, J, K Question Source: Bank #

(note changes; attach parent) Modified Bank # 2017-3 NRC ILT Q#62 New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(5),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA applicability:

N/A 64

2017-3 NRC ILT Q#62 65

Examination Outline Cross-Reference Level RO 295012 (APE 12) High Drywell Temperature / 5 Tier# 1 AA2.03 - Ability to determine and/or interpret the Group# 2 following as they apply to High Drywell K/A # 295012 AA2.03 Temperature: Drywell Humidity. Rating 2.8 (CFR: 41.10 / 43.5 / 45.13) Revision 1 Revision Statement: Rev 1 - Per CE comment, changed temperature values in stem so plotting will be different that the original question. The plotting results change from humidity lowering from 50% to 40% to humidity lowering from 40% to 30%.

Question 22 From previous 2 NRC exams: 2020-4 NRC ILT Q#40 Reference Provided The plant is at 100% power.

Procedure 2.4PC [Primary Containment Control] has been entered due to changes in the following drywell parameters over the last 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />s:

• Drywell pressure has risen 0.3 psig

• Drywell FCU B inlet and outlet temperatures are converging

• Inlet/Outlet Temp Unit B, PC-TR-500B (inlet) has risen from 131°F to 144°F

• Inlet Moisture Unit B, PC-MR-500B has risen from 99°F to 101°F Which one of the following describes the effect of this condition on drywell relative humidity and what would have caused these indications?

DW relative humidity has A. risen due to a steam leak.

B. risen due to a DW FCU tube leak.

C. lowered due to a DW FCU shaft shear.

D. lowered due to drywell nitrogen supply PCV-513 leak-by.

Answer: C 66

Explanation:

This question satisfies the K/A because it requires determining and interpreting DW humidity based on DW FCU temperatures IAW the AOP. This question meets Tier 1 requirements because it tests knowledge of information contained in the associated AOP.

Procedure 2.4PC Attachment 1 is used to determine DW relative humidity by plotting DW FCU inlet wet bulb temperature PC-MR-500 (A-D) versus DW FCU inlet dry bulb temperature PC-TR-500 (A-D). For the conditions given, plotting the initial values of wet bulb and dry bulb temperature yield a relative humidity of ~40%. Plotting the final values yields ~30% relative humidity. Therefore, relative humidity has lowered. This is expected because DW atmosphere water vapor content will not change significantly, and if the water vapor content stays the same and the temperature rises, the relative humidity decreases. This is because warmer air requires more moisture to become saturated than does colder air. Of the answers given, the only failure that would cause DW temperature to rise, reflected by the inlet to DW FCU B inlet temperature rising, and relative humidity to lower is loss of heat removal by another DW FCU due to shaft shear.

Shaft cracking on DW FCUs was documented in 2018 by CR-CNS-2018-02868 and 03180.

This is from 2 previous exams, 2020-4 NRC ILT Q#40 with the temperature values in the stem changed so plotting is different than on the original question, per CE comment. Also, the 2nd bullet was added per the Ops Rep Distracters:

Answer A is plausible because DW pressure and temperature have risen. The examinee who misreads 2.4PC Att. 1 graph and believes relative humidity increased because the final operating point is higher than the initial operating point on the graph will choose this answer. It is wrong because 2.4PC states a short-term rise in DW relative humidity would accompany a rise in DW pressure and temperature if due to a steam leak; however, DW relative humidity has lowered.

Answer B is plausible for the examinee who misreads 2.4PC Att. 1 graph, as discussed for distractor A, and because the answer reflects water leakage into the DW, which would eventually raise DW atmosphere moisture content. Also, a tube leak could result in decreased effectiveness of the affected DW FCU, which would result in elevated DW temperature and pressure. It is wrong because DW relative humidity has actually lowered.

Answer D is plausible because leak-by of DW nitrogen supply PCV-510 would cause DW pressure to rise and relative humidity to lower. It is wrong because it would have negligible effect on DW temperature and not cause DW temperature to rise significantly.

67

Technical

References:

CR-CNS-2018-02868, CR-CNS-2018-03180, Procedure 2.4PC [Primary Containment Control] (Rev 21)

References to be provided to applicants during exam: 2.4PC [Primary Containment Control] Attachment 1 [Primary Containment Relative Humidity] (Rev 21)

Learning Objective: INT032-01-28 EO-J, Given plant condition(s) and the applicable Abnormal/Emergency Procedure, discuss the correct subsequent actions required to mitigate the event(s).

Question Source: Bank # From previous 2020-4 NRC ILT 2 NRC Exams Q#40 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(4),(5)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability:

N/A 68

2020-4 NRC ILT Q#40 69

Examination Outline Cross-Reference Level RO 295013 (APE 13) High Suppression Pool Tier# 1 Temperature. / 5 Group# 2 G2.4.31 - Knowledge of annunciator alarms, K/A # 295013 G2.4.31 indications, or response procedures. Rating 4.2 (CFR: 41.10 / 45.3) Revision 1 Revision Statement: Rev 1 - Per validator comment, removed Channel 9 column since recorder only has 8 channels, and replaced alarm tile image with prose.

Question 23 The plant is at 100% power with the following conditions:

• RCIC Turbine is in operation for a maintenance leak check

• Suppression Pool Cooling is NOT in service Annunciator J-1/A-1, SUPPR POOL DIV 1 WATER HIGH TEMP is received.

Indications on PC-TR-24 [SUPPR POOL TEMP RECORDER (DIV 1)] are:

CH1 CH2 CH3 CH4 CH5 CH6 CH7 CH8 92°F 94°F 96°F 94°F 91°F 91°F 90°F 90°F What action is required NOW by plant procedures for this condition?

Place at least one RHR subsystem in Suppression Pool Cooling IAW the SOP, A. ONLY.

B. AND enter EOP-3A.

C. AND immediately suspend RCIC testing.

D. AND verify Suppression Pool temperature is < 110°F once per hour.

Answer: A 70

Explanation:

This question satisfies the K/A because it tests knowledge of the SP Temperature High annunciator, associated SP Temperature indications, and action required by the annunciator response procedure. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated ARP.

The subject annunciator is actuated when any of eight temperature elements feeding SP Temperature Recorder PC-TR-24 exceeds the setpoint, 92°F. The associated alarm card action is to Initiate RHR suppression pool cooling per Procedure 2.2.69.3, as required.

Actions in the distractors are based on Average SP Temperature. The EOP-3A entry condition for SP Temperature is >95°F. The TS 3.6.2.1 limit is 95°F.

Average SP Temperature, from the readings provided is 92.4°F,

[(92+94+96+94+91+91+90+90)/8] = 92.3. None of the other actions listed in the distractors are required, since SP Average Temperature is only 92.3°F.

Distracters:

Answer B is plausible because SP temperature channel 3 indicates 96°F, and EOP-3A is required to be entered when Average SP temperature exceeds 95°F. An examinee who does not know the EOP-3A entry condition is based on average SP temperature may choose this answer. This answer is wrong because the Average temperature is below the EOP-3A entry condition.

Answer C is plausible because the alarm card references TS 3.6.2.1 and TS 3.6.2.1 Action C.1 requires immediately suspending all testing that adds heat to the SP when Average SP temperature is >105°F. The examinee who does not know TS 3.6.2.1 is based on Average SP temperature and does not know the TS action limit of 105°F for suspending testing that adds heat to the SP may choose this answer. This answer is wrong because the Average SP temperature is within the limit of TS LCO 3.6.2.1, so no TS action is required. This is RO level, since it involves a one hour LCO action.

Answer D is plausible because the alarm card references TS 3.6.2.1 and TS 3.6.2.1 Action A.1 requires verifying SP temperature <110°F once per hour when the LCO is entered. The examinee who does not know the TS LCO limit, 95°F, is based on Average SP temperature may choose this answer. This answer is wrong because the Average SP temperature is within the limit of TS LCO 3.6.2.1, so no TS action is required. This is RO level, since it involves a one hour LCO action.

Technical

References:

Alarm Card J-1/A-1 [SUPPR POOL DIV ! WATER HIGH TEMP] (Rev 8), TS 3.6.2.1 [Suppression Pool Average Temperature], EOP-3A

[Primary Containment Control] (Rev 18)

References to be provided to applicants during exam: none 71

Learning Objective: COR002-16-02 Obj LO-7j, Given a specific NPR malfunction, determine the effect on any of the following: Primary Containment Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - Primary Containment 72

Examination Outline Cross-Reference Level RO 295014 (APE 14) Inadvertent Reactivity Addition / 1 Tier# 1 AK1.06 - Knowledge of the operational implications Group# 2 and/or cause and effect relationships of the following K/A # 295014 AK1.06 as they apply to Inadvertent Reactivity Addition: Rating 4.3 Reactivity changes. Revision 2 (CFR: 41.8 to 41.10)

Revision Statement: Rev 1 - Replaced stem and answers with CE recommendation Rev 2 - Per Ops Rep comment, added initially to question in stem to ensure distractor B is not challenged, because rod insertion may be required later to lower rod line or power.

Question 24 The plant is at 100% power.

Alarm point 3233 Feedwater Heater 5A High Level alarms and the following annunciator is received:

HEATER HIGH PANEL/WINDOW:

LEVEL TRIP A-2/C-6 What is the concern related to this event and how is this concern initially mitigated?

A. Positive reactivity addition - manually lower power by lowering core flow IAW Procedure 2.4EX-STM [Extraction Steam Abnormal]

B. Positive reactivity addition - manually lower power by driving in control rods IAW Procedure 2.4EX-STM [Extraction Steam Abnormal]

C. Negative reactivity addition - turbine control valves automatically throttle closed to maintain reactor pressure and temperature D. Negative reactivity addition - manually adjust DEH setpoint to maintain reactor pressure and temperature IAW Procedure 2.2.77 [Digital Electro-Hydraulic (DEH)

Control System]

Answer: A Explanation:

73

This question satisfies the K/A because it tests knowledge of the effect of an inadvertent reactivity addition on reactivity and immediate operator action from the AOP required to be entered.

This question meets Tier 1 requirements because it involves diagnosis that leads to selection of the appropriate AOP and immediate operator action required to respond to the event.

The conditions given represent a rising level in high pressure FWH 5A, which has resulted in automatic isolation of the FWH. Isolation of FWH-5A results in a reduction in FW temperature, which causes a positive reactivity addition. Isolation of FWH-5A at 100% power results in power rising above 100%. Feedwater heater trip is an entry condition for Procedure 2.4EX-STM. The immediate operator action 3.1 of Procedure 2.4EX-STM states: lF reactor power rises to > 100% RTP, THEN reduce power to maintain 100% RTP per Procedure 2.1.10. Procedure 2.1.10 step 7.1 states: Lower power by lowering RR pump flow.

Distracters:

Answer B first part is correct with respect to positive reactivity addition. The mitigating action to insert control rods is plausible because with FW temperature lowering, 2.4EX-STM steps 4.4.2 and 4.4.3 require control rod insertion IAW Procedure 10.13 to maintain rod line <118% or to avoid the Stability Exclusion Region of the Power-To-Flow Map. Procedure 10.13 requires core flow reduction before inserting control rods.

If core flow was 40 Mlbm/hr, insertion of Emergency Power Reduction Rods would be the next step of a Rapid Power Reduction or, in some situations, to exit the Buffer Region of the Power-To-Flow Map. This answer is wrong because Procedure 2.4EX-STM first requires lowering core flow to maintain power below 100%.

Answer C is plausible with respect to the reactivity change for the examinee who does not understand the effects of FWH-5A trip. An examinee may not know the event results in isolation of FWH-5A and reduction of feedwater temperature, or they may not understand a reduction in feedwater temperature results in a positive reactivity addition. This answer is plausible with respect to the mitigating action because for a negative reactivity addition, turbine control valves throttle closed to maintain the DEH pressure setpoint. This answer is incorrect because the event results in isolation of FWH-5A, a reduction in FW temperature, and a positive reactivity addition. Entry into Procedure 2.4EX-STM is required, and power must be lowered to offset the reactivity addition in order to maintain power below the licensed limit.

Answer D part is plausible with respect to the reactivity change for the same reason stated for distractor C. It is plausible with respect to the mitigating action because changing the DEH pressure setpoint is a manual action governed by Procedure 2.2.77.1, and changing the setpoint affects reactivity. This answer is incorrect because the event results in isolation of FWH-5A, a reduction in FW temperature, and a positive reactivity addition. Entry into Procedure 2.4EX-STM is required, and power must be lowered to offset the reactivity addition in order to maintain power below the licensed limit.

74

Technical

References:

Procedure 2.4EX-STM [Extraction Steam Abnormal] (Rev 21), Procedure 2.1.10 [Station Power Changes] (Rev 120), Procedure 2.2.77.1 [Digital Electro-Hydraulic (DEH) Control System] (Rev 43), Procedure 10.13 [Control Rod Sequence and Movement Control] (Rev 77)

References to be provided to applicants during exam: none Learning Objective: INT032-01-23 EO-F, Given plant condition(s), state from memory the appropriate Abnormal/Emergency Procedure(s) to be utilized to mitigate the event(s); EO-G, Given plant condition(s), state from memory all immediate operator actions required to mitigate the event(s)

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(1),(5),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability:

N/A 75

Examination Outline Cross-Reference Level RO 295029 (EPE 6) High Suppression Pool Water Level Tier# 1

/5 Group# 2 EK2.01 - Knowledge of the relationship between K/A # 295029 EK2.01 High Suppression Pool Water Level and the Rating 3.1 following systems or components: RHR/LPCI. Revision 0 (CFR: 41.7 / 45.8)

Revision Statement:

Question 25 EOP-3A has been entered due to high Torus water level.

(1) Which system is specified by EOP-3A for use to lower Torus water level?

AND (2) If EOP-3A must be re-entered due to High Drywell Pressure sealed in, can this system be used to lower Torus water level?

A. (1) RHR (2) Yes B. (1) RHR (2) No C. (1) Core Spray (2) Yes D. (1) Core Spray (2) No Answer: B Explanation:

This question satisfies the K/A because it tests knowledge of RHR when it is used to lower a high SP water level IAW EOP-3A and the RHR SOP. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated EOP.

EOP-3A Step SP/L-1 and SP/L-3 for high SP level specify using RHR to lower SP level. To lower SP level using RHR, Procedure 2.2.69.3 specifies aligning an RHR 76

loop in SPC mode, then rejecting water to radwaste via valves RHR-MO-56 and 57, controlled from Panel 9-3. RHR-MO-56 and 57 automatically isolate on a PCIS Group 2 signal:

1) Reactor water level low, +3 inches

2) Drywell pressure high, 1.84 psig The EOP-3A entry condition for high DW pressure is >1.84 psig. Therefore, if EOP-3A had to be re-entered due to high DW pressure, PCIS Group 2 isolation would have initiated, RHR-MO-56 and 57 would have closed, and RHR could not be used to lower SP level. There are not PTMs to bypass this isolation signal for RHR reject to radwaste.

Distracters:

Answer A part 1 is correct. Part 2 is plausible to the examinee who does not correlate the EOP-3A entry condition for high DW pressure to the isolation signal for RHR-MO-56 and 57. It is plausible because RHR SPC mode is the base alignment for lowering SP level, and other RHR valves needed for SPC do not receive a Group 2 isolation signal. It is also plausible to the examinee who knows the reject valves isolate on high DW pressure but believes there is a procedural method for bypassing the isolation signal. This answer is wrong because PCIS Group 2 isolation would have initiated, RHR-MO-56 and 57 would have closed, and RHR could not be used to lower SP level. There are not PTMs to bypass this isolation signal for RHR reject to radwaste.

Answer C part 1 is plausible because CS is listed on EOP-3A as a system to use to mitigate SP out of limits. However, it is listed in EOP-3A Step SP/L-4 as a system used for SP makeup when SP level is low. The examinee who remembers CS is used to mitigate SP level issues but forgets it is only listed for raising SP level may choose this answer. It is also plausible because Procedure 2.2.9 contains Section 19 provides instructions for using CS to lower SP level. This answer is wrong because EOP-3A only specifies using RHR, not CS, to lower SP level. Answer C part 2 is plausible and wrong for the same reason as stated for distractor A.

Answer D part 1 is plausible and wrong for the same reason as stated for distractor C.

Part 2 is correct.

Technical

References:

EOP-3A [Primary Containment Control] (Rev 18), Procedure 2.2.69 [Residual Heat Removal System] (Rev 103), Procedure 2.2.69.3 [RHR Suppression Pool Cooling and Containment Spray] (Rev 52), Procedure 2.2.9 [Core Spray System] (Rev 87)

References to be provided to applicants during exam: none Learning Objective: COR002-23-02 Obj LO-4L, Describe the interrelationship between the RHR system and the following: PCIS; INT008-06-13 EO-1, List the entry 77

conditions for Flowchart 3A and briefly describe the importance of each.; EO-11, Given plant conditions and EOP Flowchart 3A, PRIMARY CONTAINMENT CONTROL, discuss required actions.

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - RHR 78

Examination Outline Cross-Reference Level RO 295035 (EPE 12) Secondary Containment High Tier# 1 Differential Pressure / 5 Group# 2 EK3.02 - Knowledge of the reasons for the following K/A # 295035 EK3.02 responses or actions as they apply to Secondary Rating 3.7 Containment High Differential Pressure: Secondary Revision 1 containment ventilations alignment.

(CFR: 41.5 / 45.6)

Revision Statement: Rev 1 - Per CE comments, replaced part 2 distractor.

Question 26 Procedure 2.4HVAC [Building Ventilation Abnormal] and EOP-5A have been entered due to high Reactor Building differential pressure (dP).

(1) For what situation is the operator instructed by Procedure 2.4HVAC to start SGT under these conditions?

AND (2) What is the reason for this action?

A. (1) High winds exist (2) Stabilize dP to ensure Reactor Building seals remain operable B. (1) High winds exist (2) Prevent release of radioactive material C. (1) Reactor Building supply and exhaust fans are off (2) Stabilize dP to ensure Reactor Building seals remain operable D. (1) Reactor Building supply and exhaust fans are off (2) Prevent release of radioactive material Answer: D Explanation:

This question satisfies the K/A because it tests knowledge of the reason for responses and actions contained in the AOP for high secondary containment differential pressure. This question meets Tier 1 requirements because it tests knowledge of instructions contained in the associated AOP.

79

EOP-5A is required to be entered when secondary containment differential pressure is 0 psid. A high dP condition would result in annunciator R-2/A-4 [Reactor Bldg High Pressure]. The operator would first address the high dP condition IAW the alarm card. Alarm card R-2/A-4 lists two possible situations that may be causing the high dP condition and mitigating actions for each. If the alarm is due to high winds outside, the alarm card directs placing control switches for running fans to RUN and attempting to stabilize DP using manual operation of Reactor Building dP controllers HV-DPIC-835A or HV-DPIC-835B. If the alarm is not being caused by high wind conditions, the alarm card directs ensuring Reactor Building H&V supply, booster, and exhaust fans are off and entering Procedure 2.4HVAC, and the operator would secure Reactor Building supply and exhaust fans, if they were running. Procedure 2.4HVAC is used in conjunction with EOP-5A for a high dP condition and contains the actions to mitigate the condition. Procedure 2.4HVAC Attachment 1, Step 3.4 directs starting SGT and is required for the situation where Reactor Building supply and exhaust fans are off.

Procedure 2.4HVAC Attachment 1, Step 3.4 states SGT is started to maintain Reactor Building pressure negative. Procedure 2.4HVAC Attachment 8, Step 1.1 states the purpose of maintaining pressure negative is to prevent release of radioactive material.

Distracters:

Answer A part 1 is plausible because high winds are a condition addressed in both alarm card R-2/A-4 and Procedure 2.4HVAC that could cause Reactor Building high dP and for which a distinct mitigation strategy is prescribed. This answer is wrong because the mitigation strategy for high winds is manual operation of Reactor Building Ventilation dP controllers, but the stem asks why SGT would be started. SGT is started for a high dP condition only when Reactor Building supply and exhaust fans are not running. Part 2 is plausible because Reactor Building doors have soft seals that could be damaged by excessive forces, and some types of seals can be damaged by pressure applied in the opposite direction for which the seals are designed. This answer is wrong because the reason SGT is started is to restore Reactor Building dP to negative in order to prevent release of radioactive material.

Answer B part 1 is plausible and wrong for the reason given for distractor A. Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the reason given for distractor A.

Technical

References:

2.4HVAC [Building Ventilation Abnormal] (Rev 25), EOP-5A

[Secondary Containment Control] (Rev 19), Alarm Card R-2/A-4 [Reactor Bldg High Pressure] (Rev 21)

References to be provided to applicants during exam: none 80

Learning Objective: INT032-01-29 EO-I, Given plant condition(s) and the applicable Abnormal/Emergency Procedure, discuss the correct subsequent actions required to mitigate the event(s)

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 81

Examination Outline Cross-Reference Level RO 500000 (EPE 16) High Containment Hydrogen Tier# 1 Concentration / 5 Group# 2 EA2.05 - Ability to determine and/or interpret the K/A # 500000 EA2.05 following as they apply to High Containment Rating 3.4 Hydrogen Concentration: Hydrogen concentration Revision 1 limits for containment.

(CFR: 41.10 / 43.5 / 45.13)

Revision Statement: Rev 1 - Per CE comments, changed answer C from 5.1% to 2.1% and answer D from 6.1% to 4.1%.

Question 27 Which one of the following is the LOWEST value for Primary Containment hydrogen concentration that requires entry into EOP-3A?

A. 0.1%

B. 1.1%

C. 2.1%

D. 4.1%

Answer: B Explanation:

This question satisfies the K/A because it requires knowledge of the limit for PC hydrogen concentration that requires entry into EOP-3A. This question meets Tier 1 requirements because it tests knowledge of entry conditions for the associated EOP.

EOP-3A is required to be entered when PC H2 concentration is above 1%. Answer B is the lowest answer given that is above 1%.

Distracters:

Answer A is plausible because H2 concentration, as indicated on Containment Hydrogen and Oxygen recorders PC-R-H2O2I and PC-R-H2O2II, is normally 0.00%.

Since H2 production is associated with fuel damage, an examinee may believe any indication of rising H2 concentration requires EOP-3A entry. This answer is wrong because the EOP-3A entry condition for PC H2 concentration is above 1%.

82

Answer C is plausible because it is slightly above the EOP entry condition and it is below a percentage value associated with H2 flammability listed in Procedure 5.8.21, which is required to be performed to vent primary containment IAW EOP-3A when H2 concentration is high. A caution in Procedure 5.8.21 states a 6% hydrogen concentration combined with a 5% oxygen concentration constitutes a combustible mixture. The examinee who believes the EOP-3A entry condition for H2 is when concentration is approaching the H2 flammability limit may choose this answer. This answer is wrong because the EOP-3A entry condition for PC H2 concentration is above 1%.

Answer D is plausible and wrong for the reasons stated for distractor C.

Technical

References:

EOP-3A [Primary Containment Control] (Rev 18), Procedure 5.8.21 [PC Venting and Hydrogen Control (Less Than Combustible Limits] (Rev 18)

References to be provided to applicants during exam: none Learning Objective: INT008-06-13 EO-1, List the entry conditions for Flowchart 3A and briefly describe the importance of each.

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 83

Examination Outline Cross-Reference Level RO 203000 (SF2, SF4 RHR/LPCI) RHR/LPCI: Injection Tier# 2 Mode Group# 1 K3.03 - Knowledge of the effect that a loss or K/A # 203000 K3.03 malfunction of the RHR/LPCI: Injection Mode will Rating 4.0 have on the following systems or system Revision 2 parameters: Automatic depressurization logic .

(CFR: 41.7 / 45.4)

Revision Statement: Rev 1 - Per CE comments, replaced K/A K3.04 with K3.03 and replaced question.

Rev 2 - Per Ops Rep comment, bolded ONLY in 2nd bullet Question 28 The plant has experienced a LOCA:

• RPV water level -150 inches wide range, slowly lowering

• RHR Pump C is operating on minimum flow AND is the ONLY low pressure ECCS pump available

• ADS has automatically initiated AND all ADS valves are open

• All ADS valve control switches are in AUTO Then, a loss of offsite power occurs and DGs restore power to their respective buses.

Which one of the following describes the response of ADS valves to this event?

A. ADS valves close and do not automatically reopen B. ADS valves remain open until ADS logic is manually reset C. ADS valves close and reopen as soon as DGs restore power D. ADS valves close and reopen approximately 5 to 10 seconds after DGs restore power Answer: D 84

Explanation:

This question satisfies the K/A because it requires knowledge of the effect of loss of RHR Pump C on ADS logic.

With all ADS logic related switches in their standby configuration, ADS valves automatically open when:

• Reactor water level is below -113

• Reactor water level is below +3 (confirmatory signal)

• 109 second time delay (the reactor water level signals seal-in after the time delay)

• At least one low pressure ECCS pump running with discharge pressure above the setpoint Once ADS valves have automatically opened, they can be closed and kept closed by placing ADS Inhibit switches to INHIBIT or by stopping all low pressure ECCS pumps.

In this case, ADS valves close due to de-energization of relays K15A(B) and K12A(B) in the ADS logic if low pressure ECCS pump discharge pressure falls below the setpoint, as occurs when the pump stops. Loss of offsite power results in loss of power to 4160V Bus 1G supplying RHR Pump C. RHR Pump C trips on undervoltage and its discharge pressure falls below the setpoint, 108 psig, and all ADS valves close. When Bus 1G is re-energized by DG2, RHR Pump C starts after a 5 second time delay, restoring discharge pressure to above the setpoint, re-energizing ADS logic relays K12A(B) and K15A(B), resulting in ADS valves reopening. The correct answer states 5 - 10 seconds to accommodate the time required for pump acceleration to develop 108 psig discharge pressure.

Distracters:

Answer A is plausible to the examinee who does realize RHR Pump C automatically restarts when power is restored or who does not understand ADS logic. If RHR Pump C had been stopped by placing its control switch to STOP, it would not automatically restart. This answer is wrong because RHR Pump C automatically restarts when bus power is restored, and ADS valves open as soon as RHR Pump C discharge pressure reaches the setpoint.

Answer B is plausible to the examinee who does not understand ADS logic and confuses the fact that low reactor water level seals in after the time delay. The examinee may believe instead ECCS pump discharge pressure is within the seal in portion of the circuit. If that were the case, ADS valves would remain open until the ADS timers were reset. This answer is wrong because the ECCS pump discharge pressure permissive does not seal in, and ADS valves close when RHR Pump C trips due to loss of power.

Answer C is plausible because RHR Pumps A and D start as soon as the respective bus power is restored by the respective DG. This answer is wrong because RHR 85

Pump C start upon bus re-energization is delayed 5 seconds to prevent overloading DG2, so ADS valves do not open as soon as bus power is restored.

Technical

References:

Lesson Plan COR002-16-02 [Ops Nuclear Pressure Relief]

(Rev 24), Procedure 2.2.69.1 [RHR LPCI Mode] (Rev 103)

References to be provided to applicants during exam: none Learning Objective: INT00806090010100 Describe the three mechanisms specified in the EOPs to assure adequate core cooling including the RPV water level band required and which is the preferred method Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability:

N/A 86

Examination Outline Cross-Reference Level RO 205000 (SF4 SCS) Shutdown Cooling Tier# 2 K4.08 - Knowledge of Shutdown Cooling System Group# 1 (RHR Shutdown Cooling Mode) design features K/A # 205000 K4.08 and/or interlocks that provide for the following: Rating 4.1 Prevent inadvertent vessel draining. Revision 1 (CFR: 41.7)

Revision Statement: Rev 1 - Per CE comments, revised stem, revised answers to include PCIS signal, and revised answer format.

Question 29 The plant is in Mode 4.

RHR Pump D is operating in Shutdown Cooling mode.

RHR-MO-16B [LOOP B MIN FLOW BYP VLV] begins to leak past the seat at 100 gpm due to an earthquake.

Considering the following components:

• RHR-MO-15D [PUMP D SDC SUCT VLV]

• RHR-MO-18 SHUTDOWN COOLING RHR SUPPLY INBD VLV]

• RHR Pump D What design feature prevents inadvertent drain down of the RPV level with these conditions?

A. When RPV level reaches Low (Level 3), MO-18 and MO-15D will close B. When RPV level reaches Low-Low (Level 2), MO-18 and MO-15D will close C. When RPV level reaches Low (Level 3), MO-18 closes, and RHR Pump D will trip D. When RPV level reaches Low-Low (Level 2), MO-18 closes, and RHR Pump D will trip Answer: C Explanation:

87

This question satisfies the K/A because it tests knowledge of RHR interlocks that prevent inadvertent draining of the RPV.

With RHR Pump D (Loop B) in SDC, RHR-MO-16B is tagged closed. Leakage past the seat of MO-16B would cause diversion of RHR flow to the Suppression Pool, resulting in lowering RPV level.

Group 2 (RHR) isolates on low RPV level, Level 3, at a setpoint of +3, The Reactor Vessel Water Level - Low, Level 3 Function associated with RHR System isolation may be credited for automatic isolation of penetration flow paths associated with the RHR System. Reactor Vessel Water Level - Low, Level 3 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

RHR SDC suction isolation valves MO-17 and MO-18 automatically isolate on a Group 2 isolation signal to terminate inadvertent drain down. RHR Pump D SDC Suction Valve MO-15D does not auto close on a Group 2 isolation signal, and it does not close if MO-17/18 close. If MO-17, or MO-18, or the associated MO-15 valve is not full open AND the associated MO-13, SP suction valve, is not full open, then the companion pump will trip. RHR Loop B SP suction valve MO-13B is closed during SDC operation. Therefore, a sensed low RPV level, Level 3, signal <+3, will result in closure of MO-17 and MO-18 and trip of RHR Pump D, but MO-15D will remain open.

Distracters:

Answer A is plausible because MO-18 closes on RPV water level Low (Level 3). It is also plausible because MO-15D is, like MO-18, a SDC suction valve and because it is interlocked with other RHR valves. MO-15D cannot be opened unless MO-39A, MO-21A, and MO-13A are fully closed. This answer is wrong because MO-15D does not receive a close signal from PCIS Group 2, nor does it automatically close due to isolation of SDC suction valves MO-17/18. It is also wrong because RHR Pump D trips when MO-17/18 reach not fully open position.

Answer B is plausible because some PCIS valve groups, such as Group 3 and Group 6, isolate on RPV water level Low-Low (Level 2). This answer is also plausible for the reasons stated for distractor A with respect to MO-15D. This answer is wrong because RHR isolation valves isolate on RPV water level Low (Level 3) and for the reasons stated for distractor A.

Answer D is plausible because some RHR SDC suction valves isolate on a Group 2 signal, while others do not, and because RHR Pump D trips due to closure of RHR SDC suction valves. This answer is wrong because MO-18 automatically isolates and MO-15D does not.

Technical

References:

Procedure 2.2.69 [Residual Heat Removal System] (Rev 103), Lesson Plan COR002-23-02 [Ops Residual Heat Removal System] (Rev 38) 88

References to be provided to applicants during exam: none Learning Objective: COR002-23-02 Obj. LO-03k, Describe RHR system design feature(s) and/or interlocks which provide for the following: Low reactor water level isolation; 3e, Adequate pump NPSH (suction valve interlock)

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant Systems - RHR, PCIS 89

Examination Outline Cross-Reference Level RO 206000 (SF2, SF4 HPCIS) High-Pressure Coolant Tier# 2 Injection Group# 1 K4.13 - Knowledge of High-Pressure Coolant K/A # 206000 K4.13 Injection System design features and/or interlocks Rating 3.2 that provide for the following: Turbine and pump Revision 2 lubrication.

(CFR: 41.7)

Revision Statement: Rev 1 - Per CE comment, revised part 1 distractor because the original had HPCI turbine starting with no lubrication from the HPCI AOP, which lacked credibility. Revised wording of part 1 correct answer to balance with revised part 1 distractor.

Rev 2 - Moved part 2 to part 1 and wrote new part 2 to better test interlocks associated with HPCI Aux Lube Oil Pump Question 30 The plant scrammed due a feedwater failure, causing RPV level to lower to -10 inches HPCI is manually started IAW the hard card.

(1) What is the status of the HPCI Auxiliary Oil Pump (AOP) one minute later?

AND (2) If a HPCI isolation signal is received, what will be the status of the HPCI AOP two minutes after the HPCI isolation occurs?

A. (1) Running (2) Stopped B. (1) Running (2) Running C. (1) Stopped (2) Stopped D. (1) Stopped (2) Running Answer: D 90

Explanation:

This question satisfies the K/A because it tests knowledge of HPCI Auxiliary Oil Pump function and interlocks.

Upon a HPCI initiation, two DC powered components must reposition for steam to be admitted to HPCI turbine in order for it to accelerate: 1) STM TO TURB VLV, HPCI-MO-14 opens to admit supply steam up to HPCI turbine stop valve, and 2) HPCI AOP starts and produces lube/control oil pressure to hydraulically open the HPCI turbine stop valve. As the turbine speed increases, the shaft driven main lube oil pump assumes the oil loads from the auxiliary lube oil pump and the auxiliary lube oil pump automatically shuts off when lube/control oil pressure reaches ~95 psig. HPCI is designed to reach rated speed within ~12 seconds after the turbine stop valve begins to open, by which time the turbine driven oil pump would have developed its maximum discharge pressure, signaling HPCI AOP to stop; therefore, after 1 minute, HPCI AOP will be stopped.

When an isolation signal is received, HPCI steam supply valves close, and HPCI Turbine stops. When shaft driven oil pump pressure lowers below 95 psig and the AOP automatically starts, since the control switch had been placed to START during manual start up. The control switch does not spring return from START back to AUTO.

Distracters:

Answer A part 1 is plausible because the AOP starts on a manual or automatic system initiation. Also, for manual initiation per the hard card, verifying the AOP automatically stops is not required. An examinee may believe it remains running based their experience of not checking it stopped during training. This answer is wrong because within 1 minute, HPCI turbine driven oil pump would have achieved at least 95 psig discharge pressure, which would have signaled the AOP to stop. Part 2 is plausible because the AOP automatically stops following HPCI Turbine start up.

This answer is wrong because the AOP automatically starts when lube oil pressure lowers < 95 psig, which occurs within one minute of the HPCI isolation.

Answer B part 1 is plausible and wrong for the reasons given for distractor A. Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the reasons given for distractor A.

Technical

References:

Lesson Plan COR002-11-02 [High Pressure Coolant Injection] (Rev 40), Procedure 2.2.33.1 [High Pressure Coolant Injection System Operations] (Rev 43), Procedure 2.2.33 [High Pressure Coolant Injection System]

(Rev 88)

References to be provided to applicants during exam: none 91

Learning Objective: COR002-11-2 LO Obj 8k, Describe the HPCI design features and/or interlocks that provide for the following: Turbine and pump lubrication Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7),(8)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - HPCI 92

Examination Outline Cross-Reference Level RO 206000 (SF2, SF4 HPCIS) High-Pressure Coolant Tier# 2 Injection Group# 1 K5.02 - Knowledge of the operational implications K/A # 206000 K5.02 or cause and effect relationships of the following Rating 2.6 concepts as they apply to the High-Pressure Revision 1 Coolant Injection System: Turbine shaft sealing.

(CFR: 41.5 / 45.3)

Revision Statement: Rev 1 - Replaced question based on Ops Rep recommendation Question 31 HPCI is being placed into operation for RPV pressure control from standby conditions IAW the hard card.

(1) The HPCI Gland Seal Exhauster (1) required to be manually started during this evolution.

AND (2) What would be the adverse consequence of failure of the HPCI Gland Seal Exhauster while HPCI is in operation?

A. (1) is (2) Overheating of HPCI pump seals B. (1) is (2) Release of radioactive steam to the environment C. (1) is NOT (2) Overheating of HPCI pump seals D. (1) is NOT (2) Release of radioactive steam to the environment Answer: B Explanation:

This question satisfies the K/A because it tests knowledge of operational implications of failure of HPCI turbine shaft sealing (gland seal exhauster).

93

The HPCI Gland Seal Exhauster takes suction on the gland seal condenser for extraction of non-condensable gases to facilitate condensation of HPCI turbine seal leak-off in the gland seal condenser. The Gland Seal Exhauster exhausts to SGT.

The Gland seal Exhauster automatically starts on a HPCI initiation signal, but it must be manually started from Panel 9-3 when HPCI is being manually started for pressure control.

Failure of the Gland Seal Exhauster would result in blanketing of the gland seal condenser with non-condensable gases, which would result in steam and/or water leakage from the seal exhaust gland and steam introduction to SGT.

Distracters:

Answer A part 1 is correct . Part 2 is plausible to the examinee who does not know the function of the HPCI gland seal subsystem and believes the exhauster provides ventilation for HPCI seal cooling. This answer is wrong because failure of the Gland Seal Exhauster would result in blanketing of the gland seal condenser with non-condensable gases, which would result in steam leakage from the seal exhaust gland and steam introduction to SGT.

Answer C part 1 is plausible because the Gland Seal Exhauster automatically starts upon a HPCI initiation and does not have to be manually started. It is also plausible because the HPCI Gland Seal Condenser Condensate Pump does not have to be manually started when HPCI is being manually started for pressure control. The HPCI condensate pump takes suction from the gland seal condenser and discharges this condensate back to the suction of the HPCI booster pump during system operation (MO-14 open). The condensate pump is operated off level switches (LS-356A and B) on the condenser to maintain a water level in the condenser as an aid in condensing gland sealing steam; therefore, it is not required to be started manually. Part 2 is plausible and wrong for the reasons stated for distractor A.

Answer D part 1 is plausible and wrong for the reasons stated for distractor C. Part 2 is correct.

Technical

References:

Procedure 2.2.33 [High Pressure Coolant Injection System]

(Rev 88), Procedure 2.2.33.1 [High Pressure Coolant Injection System Operations]

(Rev 43), Lesson Plan COR002-11-02 [Ops High Pressure Coolant Injection] (Rev 41)

References to be provided to applicants during exam: none Learning Objective: COR002-11-02 Obj LO-9b, Briefly describe the following concepts as they apply to the HPCI system: turbine shaft sealing Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X 94

Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7),(8)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - HPCI 95

Examination Outline Cross-Reference Level RO 209001 (SF2, SF4 LPCS) Low-Pressure Core Spray Tier# 2 K6.13 - Knowledge of the effect of the following Group# 1 plant conditions, system malfunctions, or component K/A # 209001 K6.13 malfunctions on the Low-Pressure Core Spray Rating 4.3 System: High drywell pressure. Revision 0 (CFR: 41.7 / 45.7)

Revision Statement:

Question 32 The plant is at 100% power.

Core Spray Pump A is operating at 5000 gpm during performance of Procedure 6.1CS.101

[Core Spray Test Mode Surveillance Operation (IST)(Div 1)].

A steam leak in the drywell causes drywell pressure to rise to 3 psig.

How do the following Core Spray A components respond?

• CS Pump A

• CS-MO-5A [MIN FLOW BYP VLV]

A. CS Pump A remains running CS-MO-5A opens B. CS Pump A remains running CS-MO-5A remains closed C. CS Pump A stops, then restarts after a time delay CS-MO-5A opens D. CS Pump A stops, then restarts after a time delay CS-MO-5A remains closed Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of the effect of high DW pressure on Core Spray A while it is operating in test mode.

96

CS A initiates on high DW pressure, 1.84 psig, or RPV water level low, -113. In standby, CS Pump A is off, CS-MO-26A is closed, and CS-MO-5A is open. Upon a CS A initiation from standby, CS Pump A starts after a nominal 10 second time delay, CS-MO-5A opens when CS-Pump A starts, and an automatic opening permissive is applied to injection valve CS-MO-12A.

For CS A operation per surveillance initial conditions, CS Pump A is operating, CS-MO-26A is throttled open, and CS-MO-5A is closed. An automatic initiation while in this system configuration results in automatic closure of CS-MO-26A and subsequent opening of CS-MO-5A, when CS A flow lowers below 1370 gpm.

Distracters:

Answer B is plausible because if reactor pressure was below 290 psig, upon system initiation CS A injection valve CS-MO-12A would open, injection flow would be established as test line flow reduced, CS A flow would remain above the automatic opening setpoint for CS-MO-5A, and CS-MO-5A would remain closed. This answer is wrong because reactor pressure is above the opening permissive setpoint for injection valve CS-MO-12A, 291 psig, so as flow lowers below 1370 gpm due to CS-MO-26A closure, CS-MO-5A automatically opens.

Answer C is plausible because from standby conditions, automatic start of CS Pump A is delayed 10 seconds to prevent overloading DG1 during a loss of offsite power.

An examinee who confuses a LOCA initiation with a LOOP/LOCA initiation, as in the DBA, may believe CS Pump A stops, then sequences on after 10 seconds. This answer is wrong because CS Pump A does not receive a shed signal due to a LOCA initiation, so it remains running.

Answer D is plausible with respect to CS Pump A for the reason stated for distractor C. It is plausible with respect to CS-MO-5A for the reason stated for distractor B.

This answer is wrong because CS Pump A remains running, and CS-MO-5A automatically opens.

Technical

References:

Procedure 6.1CS.101 [Core Spray Test Mode Surveillance Operation (IST)(Div 1)] (Rev 34), Lesson Plan COR002-06-02 [Ops Core Spray System] (Rev 30)

References to be provided to applicants during exam: none Learning Objective: COR002-06-02 Obj LO-12, Given plant conditions, determine if any of the following Core Spray actions should occur:

a. System initiation

b. Pump starts

c. Pump trips

d. Valve reposition 97

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 98

Examination Outline Cross-Reference Level RO 211000 (SF1 SLCS) Standby Liquid Control Tier# 2 A1.10 - Ability to predict or monitor changes in Group# 1 parameters associated with operation of the K/A # 211000 A1.10 Standby Liquid Control System, including: Lights Rating 3.6 and alarms. Revision 1 (CFR: 41.5 / 45.5)

Revision Statement: Rev 1 - Per CE comments, removed portions regarding RWCU and PCIS indications and replaced with question pertaining to SLC parameter (discharge pressure).

Question 33 The plant is at 30% power during an ATWS.

The control switch for SLC Pump A on panel 9-5 is placed to start.

(1) Which one of the following values on SLC-PI-65, PUMP PRESS indicates SLC A functioned correctly?

AND (2) What is the status of Squib Valve Ready white light DS-3A on Panel 9-5?

A. (1) Approximately 1330 psig (2) Off B. (1) Approximately 1330 psig (2) On C. (1) Approximately 1140 psig (2) Off D. (1) Approximately 1140 psig (2) On Answer: C Explanation:

This question satisfies the K/A because it tests the ability to predict changes in SLC parameters, an indicating light and discharge pressure, associated with operation of SLC system.

99

Squib Valve ready lights on panel 9-5 indicate continuity in the explosive valve circuit.

The explosive charges are fired when the associated SLC Pump control switch is placed to start. One SLC pump injecting through one squib valve at the design flow rate of 53 gpm results in a discharge pressure ~ 150 psig above reactor pressure. At rated RPV pressure, SLC discharge pressure is ~1140 psig. If SLC Pump A discharge relief valve opened, pressure would only be slightly more than RPV pressure. Neither, Procedure 2.2.74 nor the SLC lesson plan state the expected value for SLC discharge pressure.

The DS-3A and DS-3B white lights indicate continuity and that the valve is closed.

When SLC Pump A is started, squib valve A fires and ready light DS-3A extinguishes.

Distracters:

Answer A first part was chosen because the RPV safety limit is 1337 psig, and SLC discharge relief valve nominal setpoint is ~1540 psig. It is plausible because if the squib valve failed to fully open, discharge pressure would be elevated. It is wrong because with squib valve A open, discharge pressure is ~1140 psig at rated pressure.

Part 2 is correct.

Answer B part 1 is plausible and wrong for the same reason stated for distractor A.

Part 2 is plausible because some status lights illuminate to indicate actuated status, such as high reactor water level trip lights on Panel 9-5 and APRM downscale status lights on Panel 9-14. This answer is wrong because squib valve ready light DS-3A extinguishes when squib valve A fires, due to loss of continuity to the explosive charge igniter.

Answer D part 1is correct. Part 2 is plausible and wrong for the same reason stated for distractor B.

Technical

References:

Procedure 2.2.74 [Standby Liquid Control System] (Rev 56),

B&R dwg 2045 sheet 02 References to be provided to applicants during exam: none Learning Objective: COR002-29-2 Obj LO-8a, Given a SLC component manipulation, predict and explain the changes in the following: Squib valve indication; 8f, RWCU system lineup Question Source: Bank #

(note changes; attach parent) Modified Bank # 9/2018 ILT NRC Q#34 New Question Cognitive Level: Memory/Fundamental X 100

Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(6)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 2018-9 NRC ILT Q#34 101

Examination Outline Cross-Reference Level RO 212000 (SF7 RPS) Reactor Protection Tier# 2 A2.01 - Ability to (a) predict the impacts of the Group# 1 following on the Reactor Protection System and (b) K/A # 212000 A2.01 based on those predictions, use procedures to Rating 3.9 correct, control, or mitigate the consequences of Revision 0 those abnormal operations: RPS motor-generator set failure.

(CFR: 41.5 / 45.6)

Revision Statement:

Question 34 The plant is at 100% power.

Feeder breaker to MCC-L is inadvertently bumped by workers and opens.

(1) How is RPS affected?

AND (2) What is the FIRST action required by plant procedures to mitigate the effect of this condition on RPS?

A. (1) RPS A half scram (2) Reclose MCC-L feeder breaker IAW Procedure 5.3AC480 [480 VAC Bus Failure]

B. (1) RPS A half scram (2) Transfer RPS A power to its alternate source IAW Alarm Card C-1/F-1 [RPS PWR PANEL 1A VOLTAGE FAILURE]

C. (1) RPS B half scram (2) Reclose MCC-L feeder breaker IAW Procedure 5.3AC480 [480 VAC Bus Failure]

D. (1) RPS B half scram (2) Transfer RPS B power to its alternate source IAW Alarm Card C-1/F-2 [RPS PWR PANEL 1B VOLTAGE FAILURE]

Answer: B 102

Explanation:

This question satisfies the K/A because it tests knowledge of the effect of loss of RPS A MG Set on RPS and which procedure contains the actions necessary to re-energize RPS A.

MCC-L Breaker 3D, RPS-MG-RPSA, REACTOR PROT SYS A MOTOR GEN SET supplies power to RPS A MG Set. When MCC-L loses power, RPS A MG Set coasts down and RPS A EPA breakers trip, resulting in loss of power to RPS Power Panel 1A, (RPS Bus A), and an RPS A half scram. Alarm Card C-1/F-2 Step 2.1 directs the operator to transfer RPS Bus A to its alternate supply from Critical Distribution Panel 1B.

Distracters:

Answer A part 1 is correct. Part 2 is plausible because power to an MCC has been inadvertently lost and no repairs are required. An examinee may believe restoring power the RPS MG set will restore power to the RPS bus and believe the appropriate action is to restore power to MCC-L. Procedure 5.3AC480 is plausible because it contains instructions to mitigate loss of 480 VAC buses. This answer is wrong because 5.3AC480 does not contain specific instructions for loss of MCC-L. Also, there is urgency associated with loss of RPS power when the plant is at high power due to the resultant Group 6 isolation and loss of RRMG cooling. Power should be restored to RPS expediently to enable resetting Group 6 isolations. For this reason, Alarm Card C-1/F-2 directs the operator to transfer RPS Bus A to its alternate supply from Critical Distribution Panel 1B to enable the operator to quickly re-energize the RPS power panel and reset tripped logic systems. Also, restoring power to MCC-L would not immediately re-energize RPS. RPS MG Set startup would have to be performed, then the RPS A normal EPA breakers would have to be reset, since they would have tripped on undervoltage.

Answer C is plausible because RPS B MG Set is also supplied by an MCC, and loss of power from its MCC would result in an RPS B half scram. This answer is wrong because RPS B MG Set is supplied from MCC-T, which has not lost power, so there is no RPS B half scram. Part 2 is plausible and wrong for the same reason stated for distractor A.

Answer D part 1 is plausible and wrong for the same reason stated for distractor C.

Part 2 is plausible because the subject Alarm Card would apply if RPS B MG Set had lost power. This answer is wrong because RPS B MG Set has not lost power.

Technical

References:

Alarm Card C-1/F-1 [RPS PWR PANEL 1A VOLTAGE FAILURE] (Rev 34), Procedure 2.2.22 [Vital Instrument Power System] (Rev 84),

Procedure 5.3AC480 [480 VAC Bus Failure] (Rev 56)

References to be provided to applicants during exam: none 103

Learning Objective: COR002-21-02 Obj LO-9a, Predict the consequences a malfunction of the following would have on the RPS system: A.C. electrical distribution Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - RPS 104

Examination Outline Cross-Reference Level RO 215003 (SF7 IRM) Intermediate-Range Monitor Tier# 2 A3.04 - Ability to monitor automatic operation of the Group# 1 Intermediate Range Monitor System, including: K/A # 215003 A3.04 Control rod block signals. Rating 3.9 (CFR: 41.7 / 45.7) Revision 0 Revision Statement:

Question 35 The plant is in Mode 2.

IRM B is on Range 1.

IF ONLY the IRM B DOWNSCALE light is ON, a rod withdrawal block (1) present.

IF ONLY the IRM B INOP light is ON, a rod withdrawal block (2) present.

A. (1) Is (2) Is B. (1) Is (2) Is NOT C. (1) Is NOT (2) Is D. (1) Is NOT (2) Is NOT Answer: C Explanation:

This question satisfies the K/A because it requires knowledge of IRM B status lights used to monitor IRM B control rod block signals.

The IRM downscale rod block is automatically bypassed with IRM B on range 1; therefore, it being on would not be indicative of a rod withdrawal block under the given conditions. The IRM INOP rod block is always active when the plant is in Mode 2, based on Reactor Mode Switch position, STARTUP. Therefore, the INOP light being on is indicative of a rod withdrawal block being present under the given conditions.

105

The stem of the original question, 2017-3 NRC ILT Q#26, was enhanced for readability and the photo of IRM B status lights was removed to raise difficulty.

Distracters:

Answer A part 1 is plausible because IRM downscale is a familiar rod block in Mode 2.

It is wrong because downscale rod blocks are bypassed with the IRM on range 1.

The either/or logic of this answer makes the answer wrong since the second part is wrong. Part 2 is correct.

Answer B part 1 is plausible and wrong for the same reason stated for distractor A.

Part 2 is plausible because it is not unusual for operators to see the INOP light ON during power operation, due to maintenance or other conditions, and no rod block be present. The IRM INOP rod block and trip are bypassed with the RMS in RUN. It is wrong because in Mode 2, the Reactor Mode Switch is in STARTUP, and an INOP condition will generate a rod withdrawal block.

Answer D part 1 is correct. Part 2 is plausible and wrong for the same reason stated for distractor B.

Technical

References:

Lesson Plan COR002-12-02 [Ops Intermediate Range Monitor] (Rev 17)

References to be provided to applicants during exam: none Learning Objective: COR002-12-02 obj LO-05a, 09a Question Source: Bank # 3/2017 NRC #36 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(2),(6)

Level of Difficulty: 3 SRO Only Justification: N/A PSA applicability:

N/A 106

From 2017-3 NRC ILT Q#36:

107

Examination Outline Cross-Reference Level RO 215004 (SF7 SRMS) Source-Range Monitor Tier# 2 A4.08 - Ability to manually operate and/or monitor in Group# 1 the control room: SRMS channel bypass. K/A # 215004 A4.08 (CFR: 41.7 / 45.5 to 45.8) Rating 3.4 Revision 1 Revision Statement: Rev 1 - Per validator comments, changed to a failure downscale to prevent examinee postulating a reactivity excursion.

Question 36 The plant is in Mode 2 during power ascension.

IRMs are on range 2.

Then, the following annunciator is received due to failure of SRM A:

SRM PANEL/WINDOW:

DOWNSCALE 9-5-1/G-7 (1) If SRM A is manually bypassed, the Control Room status light(s) that indicate(s) SRM A has been placed into BYPASS can be monitored on (1) .

AND (2) When IRMs have reached Range 4, the SRM DOWNSCALE rod block (2) be automatically bypassed.

A. (1) Panel 9-5, ONLY (2) will NOT B. (1) Panel 9-5, ONLY (2) will C. (1) Panel 9-5 AND Panel 9-12 (2) will NOT D. (1) Panel 9-5 AND Panel 9-12 (2) will Answer: D 108

Explanation:

This question satisfies the K/A because it tests knowledge for monitoring operation of the SRM A bypass control and monitoring automatic bypass status.

The subject annunciator is indicative of SRM count rate at or below 3 cps..

Status lights, including bypass status, for SRMs are located on back panel 9-12 above the SRM drawers and on Panel 9-5.

SRM Downscale signal is bypassed when IRMs reach Range 3 during startup.

Distracters:

Answer A part 1 is plausible SRM status indication on Panel 9-12 is not required to be checked by the Alarm Card nor SOP after bypassing an SRM; therefore, it may not be familiar to an examinee. This answer is wrong because SRM status lights are located above the individual SRM drawers on Panel 9-12 and on Panel 9-5. Part 2 is plausible because SRM Upscale/INOP, another rod block signal, is not automatically bypassed until IRMs reach range 8 during startup. This answer is wrong because SRM Downscale signal is bypassed when IRMs reach Range 3 during startup.

Answer B part 1 is plausible and wrong for the same reasons given for distractor A.

Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the same reasons given for distractor A.

Technical

References:

Alarm Card 9-5-1/G-7 [SRM DOWNSCALE] (Rev38), Lesson Plan COR002-30-02 [Ops Source Range Monitor] (Rev 18)

References to be provided to applicants during exam: none Learning Objective: COR002-30-02 Obj LO-6a, Describe the SRM system design features and/or interlocks that provide for the following: Rod withdrawal blocks Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(2),(6) 109

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 110

Examination Outline Cross-Reference Level RO 215005 (SF7 PRMS) Average Power Range Tier# 2 Monitor/Local Power Range Monitor Group# 1 K2.02 - Knowledge of electrical power supplies to K/A # 215005 K2.02 the following: APRM channels. Rating 3.7 (CFR: 41.7) Revision 1 Revision Statement: Rev 1 - Per CE comments, added related breaker numbers to distractors C and D to enhance plausibility, then swapped C and D (for shorter to longer order).

Question 37 What is the power supply to APRM Channel C?

A. RPS A B. RPS B C. CPP breaker 1 D. NBPP breaker 19 Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of the power supply to APRM Channel C.

RPS Bus A supplies power to APRM Channels A, C, and E.

Distracters:

Answer B is plausible because RPS B supplies power to APRM Channels B, D, and F. This answer is wrong because RPS A supplies power to APRM C.

Answer C is plausible because CPP (Critical Power Panel) supplies power to the APRM UPSCL TRIP/INOP, UPSCL ALM, DNSCL, BYPASS lights on the apron section of Panel 9-5. This answer is wrong for the reason given for distractor B.

Answer D is plausible because NBPP (No Break Power Panel) supplies power to APRM recorders on Panel 9-5. This answer is wrong for the reason given for distractor B.

111

Technical

References:

Lesson Plan COR002-01-02 [Average Power Range Monitor]

(Rev 28), Procedure 2.2A_120CRIT.DIV2 [120/240 VAC Critical Instrument Power Checklist (Div 2)] (Rev 30), Procedure 2.2A_120VITAL.DIV3 [120/240 Vac Vital Instrument Power Checklist] (Rev 9)

References to be provided to applicants during exam: none Learning Objective: COR002-01-02 Obj LO-6b, Identify the electrical power supplies to the following: APRM channels Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(2),(6)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - RPS 112

Examination Outline Cross-Reference Level RO 215005 (SF7 PRMS) Average Power Range Tier# 2 Monitor/Local Power Range Monitor Group# 1 G2.2.22 - Knowledge of limiting conditions for K/A # 215005 G2.2.22 operation and safety limits. Rating 4.0 (CFR: 41.5 / 43.2 / 45.2) Revision 1 Revision Statement: Rev 1 - Per CE comment, changed the designated answer in the answer block from B to C (fixed typo)

Question 38 What is the total number APRM channels required to be OPERABLE in MODE 1?

A. 2 B. 3 C. 4 D. 6 Answer: C Explanation:

This question satisfies the K/A because it tests knowledge of the minimum number of APRM channels required operable per TS 3.3.1.1.

TS 3.3.1.1, Table 3.3.1.1-1, requires a total of four APRM channels, two per trip system for two trip systems, to be OPERABLE in Mode 1 for the scram function. TRM 3.3.1, Table T3.3.1-1, requires a total of four APRM channels to be operable for the rod block function in Mode 1 Distracters:

Answer A is plausible because two APRM channels per trip system are required to be operable in Mode 1. This answer is wrong because the total number of APRM channels required operable is four.

Answer B is plausible because there are three APRM channels per trip system and because three IRM channels per trip system are required, when required to be operable. This answer is wrong for the reason given for distractor A.

113

Answer D is plausible because there are six total APRM channels and because 6 total IRM channels are required, when required to be operable. This answer is wrong for the reason given for distractor A.

Technical

References:

TS Table 3.3.1.1-1 [Reactor Protection System Instrumentation], TRM Table T3.3.1-1 [Control Rod Block Instrumentation]

References to be provided to applicants during exam: none Learning Objective: INT007-05-04 EO-1, Given a set of plant conditions, recognize non-compliance with a Section 3.3 Requirement.

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(2),(6),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - RPS 114

Examination Outline Cross-Reference Level RO 217000 (SF2, SF4 RCIC) Reactor Core Isolation Tier# 2 Cooling Group# 1 K1.09 - Knowledge of the physical connections K/A # 217000 K1.09 and/or cause and effect relationships between the Rating 3.3 Reactor Core Isolation Cooling System and the Revision 0 following systems: Reactor vessel and internals.

(CFR: 41.2 to 41.9 / 45.7 to 45.8)

Revision Statement:

Question 39 RCIC injects (1) the RPV shroud.

AND The RPV steam dome is connected to the RCIC steam supply via the (2) Main Steam Line.

A. (1) outside (2) A B. (1) outside (2) C C. (1) inside (2) A D. (1) inside (2) C Answer: B Explanation:

This question satisfies the K/A because it tests knowledge of the physical connections between RCIC injection and steam supply piping and RPV internals.

The RCIC injection line ties into FW line A, via a common pipe with RWCU return, between the outboard FW line A check valve RF-15CV and the drywell. FW line A injects into the downcomer annulus through a sparger, which is outside the RPV shroud.

115

The RCIC steam supply line branches off of MSL C in the drywell downstream of SRVs 71E and 71F and upstream of MSIV 80C.

Distracters:

Answer A part 1 is correct. Part 2 is plausible because RCIC injects to FW Line A.

An examinee could confuse the MSL with the FW line associated with RCIC. This answer is wrong because steam is supplied from MSL C.

Answer C part 1 is plausible because HPCI and Core Sprays inject inside the RPV shroud. An examinee may believe Core in Reactor Core Isolation Cooling implies it injects into the core, as does Core Spray. This answer is wrong because RCIC injects into FW line A, which injects into the downcomer annulus through a sparger, outside of the shroud. Part 2 is plausible and wrong for the same reason given for distractor A.

Answer D part 1 is plausible and wrong for the same reason given for distractor C.

Part 2 is correct.

Technical

References:

B&R dwgs 2041, 2043 References to be provided to applicants during exam: none Learning Objective:

Question Source: Bank #

(note changes; attach parent) Modified Bank # 2017-3 NRC ILT Q#39 New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(2),(3),(8)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - RCIC 116

2017-3 NRC ILT Q#39 117

Examination Outline Cross-Reference Level RO 218000 (SF3 ADS) Automatic Depressurization Tier# 2 K2.01 - Knowledge of electrical power supplies to Group# 1 the following: ADS logic. K/A # 218000 K2.01 (CFR: 41.7) Rating 4.0 Revision 0 Revision Statement:

Question 40 What is the backup power supply to Div 2 ADS Logic?

A. CPP B. NBPP C. 125 VDC Battery A D. 125 VDC Battery B Answer: C Explanation:

This question satisfies the K/A because it tests knowledge of ADS logic power supplies.

The normal power supply to Div 1 ADS logic is 125 VDC panel AA2. The normal power supply to Div 2 ADS logic is 125 VDC panel BB2. If Div 1 ADS logic loses power, there is no automatic transfer to another power source. If Div 2 ADS logic loses power, it will automatically transfer to its backup source, 125 VDC panel AA2, supplied from 125 VDC Battery A, via contact repositioning resulting from de-energization of relay 2E-K1B.

Distracters:

Answer A is plausible because Critical Power Panel (CPP) is supplied by safety related AC power and supplies some critical instrument and control power. The unprepared applicant might not know ADS Logic is DC powered and select this answer. This answer is wrong because Div 2 ADS logic is automatically backed up by power from 125 VDC battery A, via panel AA2.

118

Answer B is plausible because No Break Power Panel (NBPP), supplied by an inverter, supplies uninterruptible AC power to some important instrument and control circuits during a failure of normal AC power. The unprepared applicant might not know ADS Logic is DC powered and select this answer. It is wrong because 125 VDC panel AA2, supplied from 125 VDC Battery A, is the backup power supply for Div 2 ADS Logic.

Answer D plausible because there is no advantage to the unprepared applicant for selecting one DC power supply versus the other. The unprepared applicant who does not know the normal power supply to Div 2 ADS Logic is Battery B or who knows it is panel BB2 might conclude the backup power would come from another Div 2 125 VDC panel, such as BB3, in order to maintain divisional separation and, thereby, select this answer. This answer is wrong because Div 2 ADS logic is automatically backed up by power from 125 VDC battery A, via panel AA2.

Technical

References:

GE drawings 791E253 sheets 01 and 02 References to be provided to applicants during exam: none Learning Objective: COR002-16-02/ COR002-16-01 obj LO-02a, 08f Question Source: Bank # 2017-3 NRC ILT Q#40 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA applicability:

Top 10 Risk Significant System - ADS/SRV Top 10 Risk Sensitive Components - 125 VDC Distribution Panels AA2/BB2 119

Examination Outline Cross-Reference Level RO 223002 (SF5 PCIS) Primary Containment Tier# 2 Isolation/Nuclear Steam Supply Shutoff Group# 1 K3.15 - Knowledge of the effect that a loss or K/A # 223002 K3.15 malfunction of the Primary Containment Isolation Rating 4.0 System/Nuclear Steam Supply Shutoff will have on Revision 0 the following system or system parameters: Reactor core isolation cooling.

(CFR: 41.7 / 45.4)

Revision Statement:

Question 41 The plant is at 100% power.

RCIC Steam Line High Flow Channel B, RCIC-DPIS-84, fails upscale resulting in the following indications:

(1) How does RCIC respond?

AND (2) What TS LCO(s) is/are NOT met as a result of this event?

A. (1) Only RCIC-MO-15, INBD ISOL VLV closes (2) TS 3.3.6.1 [Primary Containment Isolation Instr.], only B. (1) Only RCIC-MO-15, INBD ISOL VLV closes (2) TS 3.3.6.1 [Primary Containment Isolation Instr.] and TS 3.5.3 [RCIC]

C. (1) RCIC-MO-15, INBD ISOL VLV and RCIC-MO-16, OUTBD ISOL VLV close (2) TS 3.3.6.1 [Primary Containment Isolation Instr.], only D. (1) RCIC-MO-15, INBD ISOL VLV and RCIC-MO-16, OUTBD ISOL VLV close (2) TS 3.3.6.1 [Primary Containment Isolation Instr.] and TS 3.5.3 [RCIC]

120

Answer: B Explanation:

This question satisfies the K/A because it tests knowledge of the effect of a PCIS instrumentation failure on the RCIC system.

The applicant must determine RCIC-DPIS-84 is associated with RCIC STEAM LINE HIGH FLOW CHANNEL B, which only closes MO-15. Channel A closes MO-16. With MO-15 closed, RCIC steam supply is isolated, so RCIC is inoperable. Failure of the Channel B instrument requires entry into TS LCO 3.3.6.1, and RCIC inoperability requires entry into TS LCO 3.5.3.

Distracters:

Answer A part 1 is correct. Part 2 is plausible because only an instrument channel failed. The unprepared applicant who does not consider the full impact of the instrument failure would select this answer. It is wrong because with MO-15 closed, RCIC steam supply is isolated, so RCIC is inoperable, too.

Answer C part 1 is plausible because high steam flow is an auto close signal for both MO-15 and MO-16, and Alarm Card 9-4-1/A-2 section 1.1 states both valves close and does not specify for which instrument. Procedure 2.1.22 states only MO-15 closes for channel B, but it does not state which instrument is associated with channel B. It is wrong because channel A would have to trip to auto close MO-16. Part 2 is plausible and wrong for the same reasons as stated for distractor A.

Answer D part 1 is plausible and wrong for the same reasons as stated for distractor C. Part 2 is correct.

Technical

References:

TS 3.3.6.1, TS 3.5.3, GE Dwgs 791E264 sheets 02,03,06, Alarm Card 9-4-1/A-2 [RCIC STEAM LINE HIGH DP] (Rev 56)

References to be provided to applicants during exam: none Learning Objective: COR002-03-02 24. Predict the consequences of a malfunction of the following on PCIS: d. Containment/process instrumentation Question Source: Bank # Audit for 3/2017 NRC Q#43 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental 121

Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7),(9)

Level of Difficulty: 4 SRO Only Justification: N/A 122

Examination Outline Cross-Reference Level RO 239002 (SF3 SRV) Safety Relief Valves Tier# 2 K4.09 - Knowledge of Safety Relief Valves design Group# 1 features and/or interlocks that provide for the K/A # 239002 K4.09 following: Manual opening of the SRV. Rating 4.0 (CFR: 41.7) Revision 0 Revision Statement:

Question 42 A spurious scram from 100% power occurred 20 minutes ago.

EOP-1A has been entered.

All isolations resulting from the scram have been restored.

The operator is directed by the CRS to manually open SRVs to reduce reactor pressure to 800 psig.

Under these conditions, when the control switch for SRV 71A is placed to OPEN, its solenoid valve is energized from 125 VDC Panel (1) and the motive force for opening the SRV actuator comes from the (2) system.

A. (1) BB2 (2) Nitrogen B. (1) BB2 (2) Instrument Air C. (1) AA2 (2) Nitrogen D. (1) AA2 (2) Instrument Air Answer: C Explanation:

123

This question satisfies the K/A because it tests knowledge of design features of SRVs that provide for manual opening of an SRV.

Under normal conditions (relief valve closed), the pressure across the main piston is equalized due to internal passages within the relief valve. Passage "C" allows system pressure to be applied to the front side of the main piston. The back side of the main piston also senses the system pressure through passage "A", the stabilizer valve, and through passage "B". The pilot disc is seated due to the pilot spring overcoming the force of system pressure acting on the pilot disc. The main disc is held shut by the main piston spring and the differential pressure acting across the main disc. Over-pressure actuation occurrs when system pressure overcomes the pilot valve spring force causing the pilot disc to unseat and the stabilizer disc to seat. This action allows the back side of the main piston to be vented through channel "B", the pilot valve, and channel "D" to the discharge piping. System pressure acting on the front of the main piston overcomes main piston spring pressure to open the main disc and relieve system pressure. Pneumatic actuation of the safety/relief valve is identical to over-pressure actuation with the exception that the pneumatic actuator provides the force to unseat the pilot disc against spring pressure, allowing the relief valve to open while system pressure is below the valve setpoint pressure. Actuating air or nitrogen is applied to the pneumatic actuator of the safety/relief valve by means of a solenoid control valve. This solenoid control valve is normally de-energized and must be energized to allow pneumatic actuation of the safety/relief valve.

Power for the pneumatic actuated solenoid valves for all SRVs is normally supplied from Panel AA2, with backup power available from Panel BB2. On a loss of power from AA2, power will automatically transfer to BB2.

During normal operation, nitrogen supplies the motive force with Instrument Air as a backup. Should the nitrogen supply be lost, IA-SOV-SPV21 can be opened with a control switch on Panel 9-3 in the Control Room, or Instrument Air can be manually valved in, and Instrument Air will supply the motive force.

Upon an APRM scram from 100% power, RPV level shrinks to below the Group 2 isolation setpoint, +3, causing Nitrogen supply valves to the Drywell, and SRVs, to close. RPV level recovers above +3 within one minute, so the isolation can be reset.

The stem states all isolations have been restored to imply the Nitrogen supply to the Drywell is not isolated.

Distracters:

Answer A part 1 is plausible because BB3 supplies backup power to SRV solenoids.

This answer is wrong because AA2 is the normal supply to SRV solenoids, and it has not been lost. Part 2 is correct.

Answer B part 1 is plausible and wrong for the reason stated for distractor A. Part 2 is plausible because IA is the backup supply to SRV actuators and can be manually valved into service in the event Nitrogen is lost. This answer is wrong because Nitrogen is available to the Drywell, so it is supplying SRV pneumatics.

124

Answer D part 1 is correct. Part 2 is plausible and wrong for the same reason as stated for distractor B.

Technical

References:

Lesson Plan COR002-16-02 [Ops Nuclear Pressure Relief]

(Rev 23), Procedure 2.1.22 [Recovering from a Group Isolation] (Rev 63)

References to be provided to applicants during exam:

Learning Objective: Cor002-16-02 Obj LO-2b, State the electrical power supply to the following NPR components: SRV solenoids; 3d, Describe the interrelationships between the Nuclear Pressure Relief system and the following: Plant Air systems/Drywell Pneumatics Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(3),(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - SRVs 125

Examination Outline Cross-Reference Level RO 239002 (SF3 SRV) Safety Relief Valves Tier# 2 A3.01 - Ability to monitor automatic operation of the Group# 1 Safety Relief Valves, including: SRV operation after K/A # 239002 A3.01 ADS actuation. Rating 4.1 (CFR: 41.7 / 45.7) Revision 1 Revision Statement: Rev 1 - Changed 10 seconds ago to 5 seconds ago in stem 1st bullet per validators comments Question 43 A Reactor Recirculation leak occurred at 100% power.

• Automatic ADS initiation occurred 5 seconds ago.

• Reactor pressure is 800 psig, lowering (1) How many SRVs are open?

AND (2) Which light(s) above SRV control switches are illuminated?

A. (1) 6 (2) red light, ONLY B. (1) 6 (2) red light AND amber light C. (1) 8 (2) red light, ONLY D. (1) 8 (2) red light AND amber light Answer: B Explanation:

This question satisfies the K/A because it tests knowledge for monitoring the number of SRVs opening in ADS mode and indication of an SRV opening in ADS mode.

126

For Automatic Depressurization, six of the eight safety/relief valves are utilized. They are SRV-71A and SRV-71B on Main Steam line A; SRV-71C on Main Steam line B; SRV-71E on Main Steam line C; and SRV-71G, and SRV-71H on Main Steam line D.

These valves will open and remain open for Automatic Depressurization upon concurrent signals of:

a. Low reactor water level (+3.0"), and

b. Low reactor water level (-113"), and

c. Discharge pressure of any CS or RHR pump greater than 108 psig (AV > 108 psig and < 160 psig), and

d. 109 second time delay relay timed out.

ECCS pumps would have started on high drywell pressure, 1.84 psig, or low reactor water level, -113 inches, at least 109 sec ago, since the ADS timer has timed out.

ADS initiation results in energizing SRV-71A pilot solenoid valve, which results in the red light above SRV-71A control switch illuminating and the green light extinguishing.

There is a pressure switch on each relief valve discharge pipe. When SRV-71A opens, pressure in its discharge pipe rises. When pressure in the SRV71A discharge pipe reaches 30 psig, annunciator RELIEF VALVE OPEN (9-3-1/A-2) will alarm and the amber light above the SRV-71A control switch on Panel 9-3 will illuminate.

Distracters:

Answer A part 1 is correct. Part 2 is plausible because the amber light may be off in some situations where the SRV is open, and pressure at the pressure switch sensing line may not be high enough to cause the switch to actuate, even though reactor pressure is above the setpoint. The pressure switch may not be picked up at reduced RPV pressure, due to the reduced static head, the pressure drop across the SRV, and the venturi effect of the steam flow in the SRV discharge piping. This answer is wrong because the amber light would be on with reactor pressure at 900 psig and low reactor water level.

Answer C part 1 is plausible because there are 8 total SRVs with automatic opening functions. In addition to the 6 ADS valves, 2 other SRVs automatically open in Low-Low Set Mode. This answer is wrong because only 6 valves automatically open in ADS mode. Reactor Pressure is below the lowest Low-Low Set closing setpoint, 835 psig, so Low-Low Set valves are closed. Part 2 is plausible and wrong for the same reason stated for distractor A.

Answer D part 1 is plausible and wrong for the same reason stated for distractor C.

Part 2 is correct Technical

References:

Lesson Plan COR002-16-02 [Nuclear Pressure Relief System] (Rev 23)

References to be provided to applicants during exam: none 127

Learning Objective: COR002-16-02 LO-5a, Describe the Nuclear Pressure Relief system design features and/or interlocks that provide for the following: Allows prevention of inadvertent initiation of ADS blowdown; 12b, Given plant conditions, determine if the following should occur: ADS valve closure after initiation; 06d, Briefly describe the following concepts as they apply to NPR: Tail pipe temperature monitoring; 06e, Safety/Relief Valve tailpipe temperature/pressure relationship Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(5),(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - ADS and Pressure Relief 128

Examination Outline Cross-Reference Level RO 259002 (SF2 RWLCS) Reactor Water Level Control Tier# 2 K5.06 - Knowledge of the operational implications Group# 1 or cause and effect relationships of the following K/A # 259002 K5.06 concepts as they apply to the Reactor Water Level Rating 3.2 Control System: Pump runout. Revision 0 (CFR: 41.5 / 45.3)

Revision Statement:

Question 44 RFP B is being operated in Manual Direct Valve Position (MDVP) mode.

RFP A is NOT in service.

In order to prevent runout, Procedure 2.2.28.1 [Feedwater System Operations] Precautions and Limitations direct the Operator to NOT exceed a MAXIMUM of Mlbm/hr for RFP B.

A. 6.5 B. 7.5 C. 8.5 D. 9.5 Answer: C Explanation:

This question satisfies the K/A because it tests knowledge of the administrative limit for single RFP flow to prevent runout during operation of a RFP in MDVP mode of the RVLCS. This tests the cause/effect relationship between runout and the flowrate that causes it.

In MDVP control, the operator is required to enter an inlet valve (V1) demand, which corresponds to the turbine valve rack position. The demand signal is a one-to-one relationship to the inlet valve position and no limits are imposed on the demand.

MDVP control is the default mode of control when entering Shutdown Mode (0) or 129

when all speed input signals are detected failed. 8.5 Mlbm/hr could possibly be exceeded in MDVP mode of the RVLCS.

Procedure 2.2.28.1 Precaution and Limitation 2.36 states: Do not exceed 8.5 Mlbm/hr FW flow steady-state in single RFP operation. The RFP runout calc recommends limiting single RFP flow to 8.5 x 106 lbm/hr due to the high pump suction line velocity.

Distracters:

Answer A is plausible because Procedure 2.2.28.1 Note before Step 6.2 states single RFP operation above 6.5 Mlbm/hr feed flow may cause RFP to run on HP steam, resulting in reduced plant efficiency. This answer is wrong because the RFP runout calculation and Procedure 2.2.28.1 Step 2.36 lists 8.5 Mlbm/hr as the flow limit for a single RFP.

Answer B is plausible because it is a round number that reflects a high flow condition halfway between answers A and C. It is wrong for the reason stated for distractor A.

Answer D is plausible because it is a round number that reflects a high flow condition at the same delta as that between other answers. It is also plausible because that amount of flow might be possible based on RFP horsepower. 8.4 Mlbm/hr has been observed at only 70% valve lift. It is wrong for the reason stated for distractor A.

Technical

References:

Procedure 2.2.28.1 [Feedwater System Operation] (Rev 101),

Lesson Plan COR002-02-02 [Ops Condensate and Feedwater] (Rev 39)

References to be provided to applicants during exam:

Learning Objective: COR002-02-02 Obj LO-10a, Given a Condensate and Feedwater component manipulation, predict and explain the changes in the following parameters: System Flow Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 2 SRO Only Justification: N/A 130

PSA Applicability N/A 131

Examination Outline Cross-Reference Level RO 259002 (SF2 RWLCS) Reactor Water Level Control Tier# 2 A1.07 - Ability to predict and/or monitor changes in Group# 1 parameters associated with operation of the Reactor K/A # 259002 A1.07 Water Level Control System, including: TDRFP Rating 3.3 speed. Revision 0 (CFR: 41.5 / 45.5)

Revision Statement:

Question 45 The plant is at 100% power near the end of the operating cycle.

RFP B is the preferred RFP.

A spurious Main Turbine trip occurs.

What is the status of the speed of Reactor Feed Pumps (RFPs) three minutes later?

A. Both RFPs speeds are modulating based on reactor level.

B. Both RFPs speeds are modulating based on reactor pressure.

C. RFP A is fixed at 2000 rpm, and RFP B speed is modulating based on reactor level.

D. RFP A is fixed at 2000 rpm, and RFP B speed is modulating based on reactor pressure.

Answer: D Explanation:

This question satisfies the K/A because it tests the ability to predict changes in RFP speed produced by RVLCS operation in response to a transient.

At 100% power, one RFP is designated, using the RVLCS HMI, as the preferred RFP in RVLCS. On reactor scram, the non-preferred RFPT, if both RFPTs in AUTO control, will transfer to MDEM control and ramp down to a RFPT speed of 2000 rpm.

The preferred RFPT, or the RFPT in AUTO control, if there is only one RFP in AUTO control, will remain in AUTO until the RFP discharge valves (RF-MO-29 and RF-MO-30) are fully closed. When the RFPT discharge valves are fully closed, the Feedwater Sequence transfers to Mode 2 and the preferred (or AUTO) RFPT transfers to Reactor Pressure Follow Control.

132

Setpoint Setdown is normally enabled at 100% power and initiates upon a reactor scram. The RVLCS level setpoint is set to -15" and then commences ramping to 25" at 5" per minute. When SETPOINT SETDOWN switch is in the ENABLED position, a Main Turbine trip or reactor scram causes the following valves to reposition to place Startup FCVs in service as follows:

• RF-MO-31, RFP A STARTUP VALVE OUTLET, opens.

• RF-MO-32, RFP A STARTUP VALVE INLET, opens.

• RF-MO-33, RFP B STARTUP VALVE OUTLET, opens.

• RF-MO-34, RFP B STARTUP VALVE INLET, opens.

• RF-MO-29, RFP A DISCHARGE VALVE, closes.

• RF-MO-30, RFP B DISCHARGE VALVE, closes.

Startup FCVs then modulate to control RPV level at the RVLCS setpoint, with the preferred RFP in Reactor Pressure Follow Control. Three minutes following the turbine trip/scram, RVLCS will be in this configuration, since RFP discharge valves RF-MO-29 and RF-MO-30 take less than two minutes to stroke fully closed.

Distracters:

Distractor A is plausible to the examinee who does know the implications of RFP B being preferred and thinks preferred status is an administrative designation used to equalize wear and tear, as it is when designating one SGT exhaust fan as preferred.

The examinee may believe both RFPs modulate based on reactor water level feedback to control reactor water level post-scram, because that is their operational mode during high power operations. This answer is wrong because RVLCS automatically fixes the non-preferred RFP speed to minimum, 2000 rpm, and the preferred RFP modulates speed to control discharge pressure per a schedule based on reactor pressure.

Answer B is plausible to the examinee who does know the implications of RFP B being preferred and thinks preferred status is an administrative designation used to equalize wear and tear, as it is when designating one SGT exhaust fan as preferred.

This answer is wrong because RVLCS automatically fixes the non-preferred RFP speed to minimum, 2000 rpm.

Answer C is correct with respect to RFP A speed. It is plausible with respect to RFP B speed being based on RPV level because the preferred RFP will remain in AUTO, controlling the setpoint setdown RPV level setpoint until RFP discharge valves are fully closed. This answer is wrong because three minutes after the scram, RFP discharge valves will be fully closed, since they take less than two minutes to fully stroke closed. Therefore, RFP B will have shifted to Reactor Pressure Follow Control.

Technical

References:

Lesson Plan COR002-32-02 [Ops Reactor Vessel Level Control] (Rev 24), Procedure 2.2.28 [Feedwater System Startup and Shutdown] (Rev 109), Procedure 2.2.28.1 [Feedwater System Operation] (Rev 101) 133

References to be provided to applicants during exam: none Learning Objective: COR002-32-02 Obj LO-6c, Predict the consequences of the following on the RVLC system: Reactor Scram Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(5)

Level of Difficulty: 4 SRO Only Justification: N/A PSA Applicability N/A 134

Examination Outline Cross-Reference Level RO 261000 (SF9 SGTS) Standby Gas Treatment Tier# 2 K6.09 - Knowledge of the effect of the following Group# 1 plant conditions, system malfunctions, or component K/A # 261000 K6.09 malfunctions on the Standby Gas Treatment Rating 3.4 System: Primary containment high pressure. Revision 0 (CFR: 41.7 / 45.7)

Revision Statement:

Question 46 The plant is at 100% power.

Drywell pressure quickly rises to 3 psig due to a steam leak.

What is the impact on exhaust fans for SGT A and B trains?

A. Both SGT A and B exhaust fans start immediately.

B. Both SGT A and B exhaust fans start after a 30 second time delay.

C. Only SGT A exhaust fan starts immediately. SGT B exhaust fan remains idle.

D. Only SGT B exhaust fan starts immediately. SGT A exhaust fan remains idle.

Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of the effects of high primary containment pressure on SGT.

Both SGT subsystems are normally aligned in AUTO mode at 100% power. SGT receive start signals from Group 6 (PCIS) isolation logic. High drywell pressure, 1.84 psig, results in a Group 6 isolation/initiation, which will cause both SGTs to start while in the AUTO mode. With ALL channels failing downscale, both SGTs start.

Distracters:

Answer B is plausible if the high drywell pressure is not recognized as an auto start or if the examinee believes both SGT A and B are aligned to STBY Mode. Any SGT exhaust fan in STBY Mode will start 30 seconds after receipt of an initiation signal if 135

SGT flow remains <800 scfm. This answer is incorrect due to both SGTs starting immediately, since they are both aligned to AUTO Mode at 100% power.

Answer C is plausible if the initial condition of the stem listed SGT B in STANDBY Mode. Any SGT in STBY mode does not immediately start. SGTs in STBY will auto start only if the following conditions are met: a Group 6 isolation/initiation signal is received AND low flow (<800 scfm) in the opposite SGT subsystem AND ~30 second time delay. Since the SGT train that immediately starts develops >800 cfm flow within 30 seconds, the SGT train in STBY would not start. The examinee who confuses normal rated power SGT alignment and recognizes high drywell pressure being SGT auto start would select this answer. This answer is wrong because SGT B is not initially in STBY. Its normal mode switch lineup is AUTO. So both SGT fans start immediately.

Answer D is plausible if the initial condition of the stem listed SGT A in STANDBY Mode, the effects of which are described for distractor C.. It is also plausible because SGT B is listed as the preferred train, which for SGT is only an administrative control used for equalizing run times between trains. The examinee who confuses normal rated power SGT alignment or misunderstands the preferred label and yet recognizes high drywell pressure being SGT auto start would select this answer. This answer is incorrect due to both SGTs starting.

Technical

References:

Procedure 2.2.73 [Standby Gas Treatment System] (Rev. 61)

References to be provided to applicants during exam: none Learning Objective:

COR0022802001080A Describe the Standby Gas Treatment design features and/or interlocks that provide for the following: Automatic system initiation COR0022802001130A Given plant conditions, determine if any of the following should occur: SGT automatic initiation Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(7)

Level of Difficulty: 2 SRO Only Justification: N/A 136

PSA Applicability:

Top 10 Risk Significant System - PCIS 137

Examination Outline Cross-Reference Level RO 262001 (SF6 AC) AC Electrical Distribution Tier# 2 A1.07 - Ability to predict and/or monitor changes in Group# 1 parameters associated with operation of the AC K/A # 262001 A1.07 Electrical Distribution, including: System frequency. Rating 3.2 (CFR: 41.5 / 45.5) Revision 0 Revision Statement:

Question 47 The plant was at 100% power when a loss of offsite power occurred.

DG1 automatically started and is supplying 4160V Bus 1F.

4160V Bus 1F frequency is 60.0 Hz.

Then, an Operator starts an RHR pump supplied by 4160V Bus 1F.

How does 4160 Bus 1F frequency respond?

A. Lowers slightly, then returns to ~ 60 Hz B. Lowers slightly and remains at the lower frequency C. Rises slightly, then returns to ~ 60 Hz D. Rises slightly and remains at the higher frequency Answer: A Explanation:

This question satisfies the K/A because it requires the examinee to predict the impact of closing a 4160V AC breaker on bus frequency.

With 4160V Bus 1F being supplied solely by DG1, changing the loading on the bus directly affects DG1 speed and voltage. DG1 speed control and voltage control circuits are designed to automatically maintain bus frequency and voltage. If the load on the generator is increased, without increasing its driving force, then the speed of the generator will drop. As generator speed decreases, the frequency of the generated electricity would also decrease. The reduction in speed would be proportional to the amount of load applied. This decrease in generator speed with an 138

increase in load is called "speed droop". When DG1 is paralleled to Bus 1F for testing, the Droop Parallel switch is placed to PARALLEL. This puts a small amount of speed drop into the circuit to prevent DG1 from picking up a disproportionate amount of load. When DG1 is in standby, the Droop Parallel switch is in ISOCH, and zero speed drop is inserted. This allows the governor to respond more quickly to restore voltage and frequency to nominal as large loads are connected to the bus or removed from the bus.

Distracters:

Answer B is plausible because it reflects bus frequency response if the DG1 Droop Parallel switch was in PARALLEL. This answer is wrong because the DG1 Droop Parallel switch is in ISOCH when DG1 is in standby.

Answer C is plausible because it reflects bus frequency response if the breaker for a large load was being opened, rather than closed. This answer is wrong because load is being applied to the bus, not removed, so DG1 speed, and hence, bus frequency, will lower slightly, then return to ~60 Hz as the governor quickly responds to recover DG1 speed.

Answer D is plausible and wrong for the reasons given for distractors B and C.

Applying a load will result in reduction of bus frequency and with the Droop Parallel switch in ISOCH, DG1 governor will restore DG1 speed, and hence, bus frequency, to nominal.

Technical

References:

Lesson Plan COR0002-08-02 [Ops Diesel Generators] (Rev 41)

References to be provided to applicants during exam: none Learning Objective: COR0002-08-02 Obj LO-9c, Describe the Diesel Generator design feature(s) and/or interlock(s) that provide for the following: Speed droop control; 10e, Describe the following concepts as they apply to the Diesel Generator system: Speed droop Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(5)

Level of Difficulty: 3 139

SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - Emergency AC Power 140

Examination Outline Cross-Reference Level RO 262002 (SF6 UPS) Uninterruptable Power Supply Tier# 2 (AC/DC) Group# 1 A2.05 - Ability to (a) predict the impacts of the K/A # 262002 A2.05 following on the Uninterruptible Power Supply Rating 3.8 (AC/DC) and (b) based on those predictions, use Revision 0 procedures to correct, control, or mitigate the consequences of those abnormal operations: Loss of UPS.

(CFR: 41.5 / 43.5 / 45.6)

Revision Statement:

Question 48 The plant is at 50% power.

The No-Break Power Panel (NBPP) inverter cabinet has been aligned to its alternate supply from the control room in preparation for preventive maintenance.

Then, the alternate supply to the NBPP inverter cabinet is lost due to a blown fuse.

The normal supply to NBPP is still available.

(1) How is NBPP affected?

AND (2) Which procedures are required to be entered?

A. (1) NBPP is automatically resupplied from AC power via the static switch.

(2) Alarm Cards, ONLY B. (1) NBPP is automatically resupplied from DC power via the static switch.

(2) Alarm Cards AND associated Emergency Procedure C. (1) NBPP de-energizes and must be manually transferred to its AC power supply to re-energize it.

(2) Alarm Cards, ONLY D. (1) NBPP de-energizes and must be manually transferred to its DC power supply to re-energize it.

(2) Alarm Cards AND associated Emergency Procedure 141

Answer: D Explanation:

This question satisfies the K/A because it requires the examinee to predict the impact of loss of power to NBPP (UPS) and determine AOP/EP entry is required.

The No-Break Power system provides power at 115VAC/230 VAC for equipment and instrumentation which must have an uninterruptible power supply. Power to the No-Break Power Panel (NBPP) #1 is normally supplied from 250 VDC bus 1A through inverter 1A and a static switch. An emergency (alternate) AC power source for the NBPP #1 is provided from MCC-R through a step-down transformer in the event that inverter 1A fails. An automatic transfer from the inverter to the AC supply will occur on any of a variety of conditions. However, there is no automatic transfer from the emergency AC source to the inverter. The static switch can also be operated with the NBPP PWR TRANSFER switch on Panel C (MCC or IVTR) or by pressing the ALTERNATE SOURCE SUPPLYING LOAD or INVERTER SUPPLYING LOAD button on the inverter.

Conditions given in the stem state NBPP inverter cabinet has been aligned to MCC-R from control room (Panel C), so when the fuse from MCC-r blows, power is lost to NBPP. NBPP would have to be manually transferred back to its normal source, 250 VDC Bus 1A, and Procedure 5.3NBPP entry would be required because NBPP would be de-energized.

Distracters:

Answer A part 1 is plausible because NBPP automatically transfers from one power supply to another under certain conditions. The examinee who confuses which is the normal source, AC or DC, and believes NBPP will automatically transfer from Alternate to normal source may choose this answer. This answer is wrong because NBPP is already aligned to its alternate source, AC, and it will not automatically transfer back to its normal source. Part 2 is plausible because is NBPP was initially aligned to its normal source and the normal source was lost, NBPP would automatically transfer to is alternate source via static switch fast enough that NBPP would remain energized, so Emergency Procedure 5.3NBPP entry would not be required. This answer is wrong because NBPP will de-energize, since it does not automatically transfer back to its normal source, so Procedure 5.3NBPP entry is required.

Answer B part 1 is plausible and wrong for the reasons stated for distractor A. Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the reasons stated for distractor A.

142

Technical

References:

Lesson Plan COR001-01-01 [Ops AC Electrical Distribution]

(Rev 51), Procedure 5.3NBPP [No Break Power Failure] (Rev 24)

References to be provided to applicants during exam: none Learning Objective: COR001-01-01 Obj LO-17d, Describe the effect of the following on No Break Power Supply operation: Low AC supply voltage Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(5),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 143

Examination Outline Cross-Reference Level RO 263000 (SF6 DC) DC Electrical Distribution Tier# 2 A3.02 - Ability to monitor automatic operation of the Group# 1 DC Electrical Distribution, including: K/A # 263000 A3.02 Breaker trips. Rating 3.5 (CFR: 41.7 / 45.7) Revision 0 Revision Statement:

Question 49 The plant is at 50% power.

The following alarm is received:

125V DC SWGR PANEL/WINDOW:

BUS 1A BLOWN FUSE C-1/A-2 Indicated 125 VDC Bus 1A voltage has lowered several volts.

(1) Which one of the following caused these indications?

AND (2) What is the status of the associated red fuse status light on the front of 125 VDC Switchgear 1A?

A. (1) 125 VDC BATTERY 1A BLOWN FUSE (2) On B. (1) 125 VDC BATTERY 1A BLOWN FUSE (2) Off C. (1) 125 VDC FEEDER FROM BATT CHARGER 1A BLOWN FUSE (2) On D. (1) 125 VDC FEEDER FROM BATT CHARGER 1A BLOWN FUSE (2) Off Answer: C 144

Explanation:

At CNS, the 125 VDC system uses fused disconnects for power distribution. K/A 263000 A3. does not distinguish the different types of circuit protection/switching devices. Breaker in a generic sense, as used in the K/A, includes protective switching devices like fused disconnects. At CNS, indication of fused disconnect status is provided by annunciators on Panel C. Operation of the fused disconnects are local, only. This question satisfies the K/A because it tests the ability to monitor DC switchgear trips.

125 VDC Battery Charger 1A supplies 125 VDC Bus 1A via a fused disconnect. 125 VDC Battery 1A is also connected to 125 VDC Bus 1A via a fused disconnect. 125 VDC Charger 1A maintains 125 VDC Bus 1A at ~ 129 VDC to supply the various DC loads and to maintain 125 VDC Battery 1A charged. 125 VDC Bus 1A supplies the following loads via fused disconnects:

• 125 VDC Rx Bldg Starter Rack Emergency Feeder

• 125 VDC RCIC Starter Rack Normal Feeder

• 125 VDC HPCI Starter Rack Emergency Feeder

• 125 VDC Distribution Panel 1A Normal Feeder The following are inputs to annunciator C-1/A-2:

• 125 VDC BATTERY 1A BLOWN FUSE

• 125 VDC FEEDER FROM BATT CHARGER 1A BLOWN FUSE

• 125 VDC HPCI EMERG FEEDER BLOWN FUSE

• 125 VDC DIST PANEL A NORMAL FEEDER BLOWN FUSE

• 125 VDC DIST PANEL B EMERG FEEDER BLOWN FUSE

• 125 VDC RCIC SR NORMAL FEEDER BLOWN FUSE

• 125 VDC RX BLDG SR EMERG FEEDER BLOWN FUSE Since the subject alarm was the only alarm received, only failure of the charger fuse or battery fuse could have caused the alarm with the absence of any other alarm.

Since 125 VDC Bus 1A voltage has lowered, the charger must not be supplying the bus, since its supply voltage is higher than battery terminal voltage alone and because it is a full capacity charger. Bus voltage has lowered because the battery is alone supplying the bus.

The red fuse status light for the Battery Charger fused disconnect on the front of 125 VDC Switchgear 1A illuminates when the fuse blows.

Phraseology that indicated 125 VDC Bus 1A voltage has lowered several volts was used in the stem, because sufficient empirical data to support an exact degree of change could not be located.

Distracter:

Answer A part 1 is plausible because it represents an input to the subject alarm. It would be correct if 125 VDC bus voltage remained stable. It is wrong because with the charger not connected to the bus, 125 VDC Battery 1A is supplying the load, and 145

its terminal voltage is several volts lower than charger output voltage, and battery terminal voltage lowers as the battery discharges. Part 2 is correct Answer B part 1 is plausible and wrong for the reason given for distractor A. Part 2 is plausible because some status indicating lights, such as RPS bus power available lights on Panel 9-16, are illuminated when conditions are normal and power is available, and they extinguish when something has resulted in a loss of power. It is wrong because the red fuse status light for the Battery Charger fused disconnect on the front of 125 VDC Switchgear 1A illuminates when the fuse blows.

Answer D part 1 is correct. Part 2 is plausible and wrong for the reasons stated for distractor B.

Technical

References:

Alarm card C-1/A-2 [125V DC Swgr Bus 1A Blown Fuse](Rev 34), Procedure 2.2.25.1 [125 VDC Electrical System (Div 1)](Rev 27)

References to be provided to applicants during exam: none Learning Objective: COR002-07-02 Obj LO-6c, Describe the interrelationship between the DC Electrical Distribution System and the following: Battery charger and battery; 8e, Given a specific DC Electrical Distribution system malfunction, determine the effect on any of the following: Batteries Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability:

Top 10 Risk Significant System - Emergency DC Power 146

Examination Outline Cross-Reference Level RO 264000 (SF6 EGE) Emergency Generators Tier# 2 (Diesel/Jet) EDG Group# 1 A4.03 - Ability to manually operate and/or monitor in K/A # 264000 A4.03 the control room: Transfer of emergency control Rating 3.6 between manual and automatic. Revision 1 (CFR: 41.7 / 45.5 to 45.8)

Revision Statement: Rev 1 - Per validators comment, added due to repositioning of all associated switches to stem because individual switches have different effects.

Question 50 The plant is at 100% power.

The following annunciator is received due to repositioning of all associated switches:

DIESEL GEN 2 PANEL/WINDOW:

ISOLATION SW IN LOCAL C-4/C-4 Which one of the following identifies the availability of DG2 automatic start capability and remote control from Panel C capability for this condition?

Automatic start Control from Panel C available? available?

A. Yes Yes B. No Yes C. Yes No D. No No Answer: D Explanation:

This question satisfies the K/A because it tests the ability to monitor the annunciator associated with transfer of emergency control from automatic control to local manual control.

147

A fire in the cable spreading room could damage the control cabling to both Diesel Generators such that their operation would be inhibited. Each Diesel Generator has been provided with four NORMAL-ISOLATE control switches, two mounted on their respective diesel engine panels and two on the EG1 (EG2) breaker cubicles. The isolation switches are normally kept in their NORMAL position. When these red handled switches are concurrently placed in the ISOLATE position, the control cabling running between the Diesel Generator and the Control Room is isolated and bypassed. These switches protect the plant's safe shutdown capability in the event of a fire.

If the DG isolation switches are placed in the ISOLATE position, automatic start of the diesel is blocked, the operator loses Panel C Diesel Generator and breaker (EG1/2) control, Panel C indicating lights for diesel control extinguish and annunciator C-1/C-3(C-4/C-4) DIESEL GEN 1(2) ISOLATION SW IN LOCAL alarms. The diesel can only be started from the local engine panel. The 1F (1G) bus voltage indicators and synchroscope on the diesel metering panel are inoperative. Since the instrumentation for paralleling is inoperative, breakers 1FA and 1FS (1GB and 1GS) are verified open prior to closing EG1 (EG2). EG1 (EG2) can only be closed by depressing the CLOSE button on its breaker.

Distracters:

Answer A is plausible to the examinee who confuses the isolation switches with the DG2 control mode switch on the local DG2 panel. The control mode switch enables local control of the DG governor. This answer is wrong because automatic features and remote control from Panel C are not available.

Answer B is plausible to the examinee who remembers DG2 automatic start functions are disabled but believes all manual DG2 start/stop functions remain available. This answer is wrong because remote start/stop functions from Panel C are disabled.

Answer C is plausible to the examinee who remembers remote start/stop functions from Panel C are disabled but believes DG2 automatic start functions are unaffected.

This answer is wrong because automatic start functions are disabled.

Technical

References:

Lesson Plan COR002-08-02 [Ops Diesel Generators] (Rev 41), Procedure 2.2.20 [Standby AC Power System (Diesel Generator)] (Rev 111)

References to be provided to applicants during exam: none Learning Objective: COR002-08-02 Obj LO-9g, Describe the Diesel Generator design feature(s) and/or interlock(s) that provide for the following: Local Operation and Control Question Source: Bank #

148

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - Emergency DG 149

Examination Outline Cross-Reference Level RO 300000 (SF8 IA) Instrument Air Tier# 2 G2.1.30 - Ability to locate and operate components, Group# 1 including local controls. K/A # 300000 G2.1.30 (CFR: 41.7 / 45.7) Rating 4.4 Revision 0 Revision Statement:

Question 51 Loss of all offsite power has occurred with the following conditions:

• Procedure 5.3EMPWR [Emergency Power during Modes 1, 2, or 3] has been entered.

• NO Station Air Compressor (SAC) is running.

• Service Air header pressure is 100 psig.

SAC B COMPRESSOR COOLANT selector switch is located on (1) and is required to be placed to (2) position IAW Procedure 5.3EMPWR.

A. (1) a local panel (Control Building Basement)

(2) REC B. (1) a local panel (Control Building Basement)

C. (2) TEC D. (1) control room VBD-M (2) REC E. (1) control room VBD-M (2) TEC Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of the location of a control for Instrument Air and its operation during a loss of power.

SACs are capable of being provided cooling water from either TEC or from REC.

LRP-PNL-710, COMPRESSORS A, B, C COOLANT SELECTOR PANEL is located in the Control Building Basement, elevation 882. LRP-PNL-710 houses three controls, 150

A/B/C COMPRESSOR COOLANT selector switches, which can be positioned to TEC or REC for each SAC. SAC B is normally aligned to be cooled by TEC. TEC pumps are powered by BOP 480 VAC buses 1A or 1B, which lose power during a loss of offsite power. REC pumps are powered from MCC-K and MCC-S, which are powered by DG1 and DG2 during a loss of offsite power. Procedure 5.3EMPWR directs aligning SAC B COMPRESSOR COOLANT selector switch to REC during a loss of offsite power to ensure SAC B is provided cooling water and is available to supply instrument air.

Distracters:

Answer B part 1 is correct. Part 2 is plausible because SAC B COMPRESSOR COOLANT selector switch is normally aligned to TEC. This answer is wrong because during a loss of offsite power, TEC is not available, and Procedure 5.3EMPWR directs aligning the switch to REC.

Answer C part 1 is plausible because controls for TEC and REC pumps and many valves are located on control room back panel VBD-M. This answer is wrong because the SAC B COMPRESSOR COOLANT selector switch is located on LRP-PNL-710, which is located in C-882. Part 2 is correct.

Answer D part 1 is plausible and wrong for the reason stated for distractor C. Part 2 is plausible and wrong for the reason stated for distractor B.

Technical

References:

Procedure 5.3EMPWR [Emergency Power during Modes 1, 2, or 3] (Rev 71)

References to be provided to applicants during exam: none Learning Objective: COR001-17-01 Obj LO-6b, Predict the consequences the following would have on Plant Air system: TEC failure Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(4),(10)

Level of Difficulty: 3 SRO Only Justification: N/A 151

PSA Applicability N/A 152

Examination Outline Cross-Reference Level RO 400000 (SF8 CCS) Component Cooling Water Tier# 2 K1.13 - Knowledge of the physical connections Group# 1 and/or cause and effect relationships between K/A # 400000 K1.13 Component Cooling Water System and the following Rating 3.6 systems: Revision 0 Reactor water cleanup system.

(CFR: 41.4 to 41.5 / 41.7 to 41.9 / 45.6 to 45.8)

Revision Statement:

Question 52 The plant is operating at 100% when the following indications are received:

• REC SURGE TANK HIGH LEVEL (M-1/A-4) is alarming

• REC temperatures are rising Which one of the following is the cause of these indications?

A. RHR pump seal cooler leak B. REC heat exchanger tube leak C. RWCU non-regenerative heat exchanger tube leak D. Reactor Building equipment drain sump heat exchanger tube leak Answer: C Explanation:

This question satisfies the K/A because it tests knowledge of the cause/effect of a tube leak in RWCU non-regenerative heat exchanger (NRHX), which is an interface with REC (CCWS) system.

REC supplies the shell side of RWCU NRHX. REC operates at ~75 psig and ~80°F.

At 100% power, RWCU in the tube side of NRHX operates at ~1100 psig and ~190°F at the NRHX inlet. Since the RWCU system operates at a higher temperature and pressure than REC, a RWCU NRHX tube leak would cause an increase in REC surge tank level and elevated REC temperatures.

153

Distracters:

Answer A is plausible because REC supplies cooling to RHR pump seal coolers. This answer is wrong because RHR pumps are not normally in service, and the stem does not state RHR is in service, so a leak in this cooler would cause a reduction in REC surge tank level and not raise system temperature.

Answer B is plausible because REC interfaces with Service Water system in the REC heat exchangers. This answer is wrong because Service Water operates at ~50 psig in its normal lineup at 100% power, which is lower than REC pressure, ~75 psig.

Therefore REC would leak into Service Water system and surge tank level would fall, not rise.

Answer D is plausible because REC interfaces with Reactor Building equipment drain sump heat exchangers. This answer is wrong because Reactor Equipment drain sumps are at approximately atmospheric pressure, so leakage would be from REC into the sump, and REC surge tank level would fall, not rise.

Technical

References:

Alarm Card M-1/A-4 [REC Surge Tank High Level] (Rev 22)

References to be provided to applicants during exam: none Learning Objective: COR0021902001050A Briefly describe the following concepts as they apply to REC: Leak or lowering system pressure during accident and transient conditions COR0021902001060C Given a specific REC malfunction, determine the effect on any of the following: REC system temperature COR0021902001030G Describe the interrelationship between the REC System and the following: Reactor Water Cleanup Question Source: Bank # 19071 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(4),(5)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 154

Examination Outline Cross-Reference Level RO 510000 (SF4 SWS*) Service Water (Normal and Tier# 2 Emergency) Group# 1 K2.02 - Knowledge of electrical power supplies to K/A # 510000 K2.02 the following: Rating 3.4 Service water system valves (Class 1E). Revision 0 (CFR: 41.7)

Revision Statement:

Question 53 What is the power supply to SW-MO-650, REC HX A SERVICE WATER OUTLET?

A. MCC-Q B. MCC-R C. MCC-Y D. MCC-RB Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of the power supply to SW-MO-650, which is a Class 1E powered Service Water valve.

Class 1E 4160V Bus 1F supplies 480V bus 1F, which supplies MCC-K which supplies MCC-Q. SW-MO-650 is powered by MCC-Q.

Distracters:

Answer B is plausible because MCC-R supplies power to Service Water to REC cross-tie valve SW-MO-886, SW SUPPLY TO NORTH CRITICAL LOOP. This answer is wrong because SW-MO-650 is powered from MCC-Q.

Answer C is plausible because MCC-Y supplies power to SW-MO-651, REC HX B SERVICE WATER OUTLET. This answer is wrong because SW-MO-650 is powered from MCC-Q.

155

Answer D is plausible because MCC-RB supplies power to Service Water to REC cross-tie valve SW-MO-887, SW SUPPLY TO SOUTH CRITICAL LOOP. This answer is wrong because SW-MO-650 is powered from MCC-Q.

Technical

References:

Lesson Plan COR002-27-02 [Ops Service Water] (Rev 46)

References to be provided to applicants during exam: none Learning Objective: COR002-27-02 Obj LO-2a, State the electrical power supply to the following Service Water components: Service Water valves Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(8)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - Service Water 156

Examination Outline Cross-Reference Level RO 201002 (SF1 RMCS) Reactor Manual Control Tier# 2 K3.02 - Knowledge of the effect that a loss or Group# 2 malfunction of the Reactor Manual Control System K/A # 201002 K3.02 will have on the following systems or system Rating 3.2 parameters: Rod block monitor Revision 1 (CFR: 41.7 / 45.4)

Revision Statement: Rev 1 - Per validators comment, spelled out RMCS in stem for consistency.

Question 54 The plant is at 30% power during startup.

Control rod withdrawal is in progress.

With respect to the Rod Block Monitor (RBM),

A failure in Reactor Manual Control System (RMCS) could prevent (1) associated with the selected control rod from being routed to the RBM, allowing (2) limits to be exceeded.

A. (1) LPRM signals (2) Minimum Critical Power Ratio B. (1) LPRM signals (2) Average Planar Linear Heat Generation Rate C. (1) Control rod position (2) Minimum Critical Power Ratio D. (1) Control rod position (2) Average Planar Linear Heat Generation Rate Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of the effect of a malfunction of RMCS on the Rod Block Monitor and its design function.

157

RMCS select relay matrix selects and routes the LPRM signals to the RBM averaging circuit. RBM supplies a trip signal to Reactor Manual Control System to inhibit control rod withdrawal. The trip is initiated whenever RBM output exceeds a variable setpoint. RBM channels accomplish their function by averaging LPRM inputs (based on the control rod selected in RMCS and operation of the RMCS Rod Select Matrix) and applying resultant voltage to a trip circuit for comparison with a reference voltage.

The safety design basis for the RBM is in the worst case situation for a rod withdrawal error during power operation, protective action from the Rod Block Monitor is required to prevent violating the Safety Limit MCPR by enforcing control rod withdrawal blocks.

A malfunction in the RMCS could prevent the application of rod blocks from the RBM, which could allow violation of MCPR limits.

Distracters:

Answer B part 1 is correct. Part 2 is plausible because APLHGR is a power dependent thermal limit. This answer is wrong because the safety design basis of the RBM is to protect MCPR limits, not APLHGR limits.

Answer C part 1 is plausible because RMCS communicates control rod position to other systems. The examinee who confuses the RBM with the Rod Withdrawal Limiter, which uses control rod position information from RMCS upon which to enforce control rod withdrawal blocks, may chose this answer. This answer is wrong because the RBM uses LPRM data from the RMCS Rod Select Matrix, not control rod position, to enforce control rod withdrawal blocks. Part 2 is correct.

Answer D part 1 is plausible and wrong for the reason given for distractor C. Part 2 is plausible and wrong for the reason given for distractor B.

Technical

References:

Lesson Plan COR002-24-02 [Rod Block Monitor] (Rev 23)

References to be provided to applicants during exam: none Learning Objective: COR002-24-02 Obj LO-6d, Predict the consequences of the following on the RBM: RMCS failure Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(6) 158

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 159

Examination Outline Cross-Reference Level RO 201006 (SF7 RWMS) Rod Worth Minimizer Tier# 2 K4.06 - Knowledge of Rod Worth Minimizer System Group# 2 design features and/or interlocks that provide for the K/A # 201006 K4.06 following: Correction of out-of-sequence rod Rating 3.5 positions. Revision 1 (CFR: 41.7)

Revision Statement: Rev 1 - Per CE comment, changed stem to What are the MINIMUM actions that will restore RWM rod pattern compliance?

Question 55 Given the following conditions:

• A reactor Startup is in progress at 5% power

• The current Rod Worth Minimizer (RWM) group has insert AND withdraw limits of 24 AND 36 respectively

• Two of the four Control Rods in the current Group are at 36 AND two are at 24

• The next rod is then selected AND withdrawn to 36 where the reed switch is failed open What are the MINIMUM actions that will restore RWM rod pattern compliance?

A. Without bypassing RWM, insert the control rod with the failed reed switch to 34 B. Without bypassing RWM, select AND withdraw last control rod in the group to 36 C. Bypass RWM using the keylock switch, THEN insert the rod with the failed limit switch to 34 D. Bypass RWM using the keylock switch, THEN withdraw the rod with the failed limit switch to 38 Answer: C Explanation:

This question satisfies the K/A because it tests knowledge of RWM design features for correction of out of sequence control rod positions. For this question, RWM imposes 160

a new in-sequence position for the subject control rod, resulting in it being out of sequence.

With the notch 36 reed switch failed, RWM will generate an OUT OF SEQUENCE alarm and apply Insert and Withdraw Blocks. The Blocks are cleared by bypassing the RWM and moving the rod to the Alternate Limit of 34. The RWM will accept notch 34 as the Alternate Limit and the RWM can be returned to service and the Blocks cleared. (Alternate Limits are one notch below (farther inserted) the normal limit. The only exception is 00 where it's Alternate limit is 02).

Distracters:

Answer A is plausible because it involves selecting an in-sequence control rod other than the one with the failed reed switch. An examinee may believe the failed reed switch for the third control rod in the group will not affect any other control rods. This answer is wrong because RWM imposes insert and withdraw blocks for all control rods when any one control rod is moved to a position with a failed reed switch.

Without clearing the control rod block by inserting the third rod to the RWM alternate limit, 34, or otherwise bypassing the RWM, the RWM block for the fourth rod will remain.

Answer B is plausible because the RWM will impose an alternate limit of 34 for the control rod with the failed reed switch, and the resolution is to insert the subject control rod to 34. An examinee may believe only a withdraw block for the third rod and select this answer. This answer is wrong because RWM imposes both withdraw and insert blocks for all control rods for this failure, so RWM must first be bypassed using the keylock switch before the subject control rod can be inserted to 34.

Answer D is plausible because RWM imposes an alternate limit that is one notch position away from the original limit. It is also plausible because for a RWM position limit of 00, the alternate limit is one notch further out, 02. The examinee who believes the alternate limit is one notch further out may choose this answer. This answer is wrong because the alternate limit for limit positions other than 00 are always one notch further in, which in this case is 34.

Technical

References:

Lesson Plan COR002-26-02 [Rod Worth Minimizer] (Rev 24)

References to be provided to applicants during exam: none Learning Objective: COR002-26-02 5i, Describe the following concepts as they apply to the RWM: Withdraw block; 5j, Insert block; 5l, Alternate withdraw and insert limits Question Source: Bank # 5010 (note changes; attach parent) Modified Bank #

New 161

Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(6)

Level of Difficulty: 4 SRO Only Justification: N/A PSA Applicability N/A 162

Examination Outline Cross-Reference Level RO 202002 (SF1 RSCTL) Recirculation Flow Control Tier# 2 K5.08 - Knowledge of the operational implications Group# 2 or cause and effect relationships of the following K/A # 202002 K5.08 concepts as they apply to the Recirculation Flow Rating 3.7 Control System: Reactor water level. Revision 1 (CFR: 41.5 / 45.3)

Revision Statement: Rev 1 - Per CE comment, added a space between 45% and speed in answer D.

Question 56 The plant is at 100% reactor power:

• Reactor Recirculation Pumps are NOT locked out RFP A trips on low lube oil pressure.

A Reactor Recirc runback towards (1) will be initiated but will terminate if reactor water level rises above a minimum of (2) .

A. (1) 22% speed (2) 3 inches B. (1) 22% speed (2) 27.5 inches C. (1) 45% speed (2) 3 inches D. (1) 45% speed (2) 27.5 inches Answer: D Explanation:

This question satisfies the K/A because it tests knowledge of the effect of and operational implications of lowering reactor water level on Recirc flow control.

163

Reactor water level is controlled at ~35 inches narrow range at 100% power.

Feedwater flow is ~9.7 Mlbm/hr at 100% power. Trip of one RFP causes reactor water level to lower, because the remaining RFP has a design capacity of ~6.4 Mlbm/hr and cannot provide 9.7 Mlbm/hr required to maintain reactor water level. Therefore, reactor water level will lower when on RFP trips at 100% power.

If both Reactor Recirculation Pumps are running and not locked out, RR pumps run back towards 45% speed if any of the following conditions are met:

• Total steam flow > 8.25 Mlbm/hr concurrent with a condensate pump low discharge header pressure < 110 psig and a condensate pump tripped.

• Total steam flow > 8.25 Mlbm/hr concurrent with a condensate booster pump low discharge header pressure < 450 psig and a condensate booster pump tripped.

• Total steam flow > 8.25 Mlbm/hr with at least both RFP suction pressures < 350 psig.

• Total steam flow > 9 Mlbm/hr with at least 1 RFP tripped/flow < 1 Mlbm/hr and selected reactor water level < 27.5".

RR runback towards 45% stops when the condition causing the runback is no longer true and no other 45% runback conditions exist.

Therefore, when reactor water level lowers <27.5 inches narrow range with one RFP tripped, a RR runback will occur, reducing power and the feedwater flow required to maintain reactor water level. When power lowers below the capacity of the remaining RFP, reactor level will begin to rise. If reactor water level rises above 27.5 inches, the RR runback will terminate.

Distracters:

Answer A part 1 is plausible because a RR runback 22% is also a design feature. If feedwater flow to the reactor is less than 20% of rated, increasing pump speed could cause pump cavitation since the necessary inlet subcooling effect that feedwater has on the downcomer annulus would be lacking. The reduced inlet subcooling would reduce the Net Positive Suction Head (NPSH) felt at the suction of the Recirc pump.

A RR runback to 22% always occurs upon a normal reactor scram, because FW flow lowers to <20% rated upon a scram. The examinee who confuses the 22% runback with the 45% runback or who believes reactor water level will lower to the scram setpoint, +3 inches narrow range, will select this answer. This answer is wrong because a RR runback to 45% will occur as level falls below 27.5 inches. Reactor power will lower to within the capacity of the remaining RFP before reactor water level lowers below the scram setpoint, so no RR runback to 22% will occur. Part 2 is plausible to the examinee who believes reactor water level will lower to the scram setpoint, +3 inches, and because the 22% and 45% RR runbacks automatically terminate when an initiation condition clears. This answer is wrong because a RR runback to 45% occurs, and it will only terminate in this case if reactor water level rises above 27.5 inches.

164

Answer B part 1 is plausible and wrong for the reasons stated for distractor A. Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the reasons stated for distractor A.

Technical

References:

Lesson Plan COR002-22-02 [Reactor Recirculation] (Rev 35), Lesson Plan COR002-02-02 [Ops Condensate and Feedwater] (Rev 39)

References to be provided to applicants during exam:

Learning Objective: COR002-22-02 Obj LO-13c, Given plant conditions, determine if any of the following should occur: Recirculation pump runback to the 45% speed limiter Question Source: Bank #

(note changes; attach parent) Modified Bank # 2020-9 NRC ILT Q#65 New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(5)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 165

2020-9 NRC ILT Q#65 166

Examination Outline Cross-Reference Level RO 204000 (SF2 RWCU) Reactor Water Cleanup Tier# 2 K6.02 - Knowledge of the effect of the following Group# 2 plant conditions, system malfunctions, or component K/A # 204000 K6.02 malfunctions on the Reactor Water Cleanup System: Rating 2.6 Main condenser. Revision 0 (CFR: 41.7 / 45.7)

Revision Statement:

Question 57 The plant is in Mode 2 with the following conditions:

• Reactor water level 36 inches, steady

• RWCU Pump B operating at 200 gpm.

• RWCU blowdown to main condenser flow rate 45 gpm

• RWCU Filter/Demins are bypassed A manual valve in the RWCU blowdown pathway to the condenser is closed in error during a valve lineup, resulting in the following annunciator:

RWCU PANEL/WINDOW:

BLOWDOWN HI/LOW PRESS 9-4-2/D-5 Which one of the following occurs as a result of this condition?

A. RWCU-FCV-55, Blowdown Control Valve closes, ONLY.

B. RWCU-MO-56, Blowdown To Main Cndsr Valve closes, ONLY.

C. RWCU-FCV-55, Blowdown Control Valve closes and RWCU Pump B trips on low flow.

D. RWCU-MO-56, Blowdown To Main Cndsr Valve closes and RWCU Pump B trips on low flow.

Answer: A 167

Explanation:

This question satisfies the K/A because it tests knowledge of the effects of a condition related to the RWCU interconnection with the condenser on the RWCU system.

The setpoint for Annunciator 9-4-2/D-5 with respect to blowdown piping to the condenser is 40 psig. RWCU Blowdown Control Valve RWCU-FCV-55 automatically closes when RWCU blowdown is aligned to the condenser if pressure downstream of RWCU-MO-56 rises to 40 psig. Therefore, when a partial blockage occurs at the condenser, pressure in the blowdown line rises to at least 40 psig, and RWCU-FCV-55 closes.

Distracters:

Answer B is plausible because RWCU-MO-56 is also in the blowdown to condenser flow path, and other RWCU MOVs, such as RWCU-MO-15, have automatic close functions. The pressure switch that senses high pressure in the blowdown to condenser line, RWCU-PS-108B, is downstream of RWCU-MO-56. The examinee who confuses MO-56 with FCV-55 may choose this answer. It is wrong because only RWCU-FCV-55 automatically closes on RWCU blowdown line to condenser high pressure.

Answer C is plausible because RWCU flow is reduced when FCV-55 closes, and RWCU pumps trip on low flow, <50 gpm. It is wrong because flow lowers a maximum of 45 gpm, to 155 gpm, due to loss of blowdown, so the low flow pump trip is not reached.

Answer D is plausible and wrong with respect to RWCU-MO-56 for the reasons stated for distractor B. It is plausible and wrong with respect to RWCU Pump B for the reasons stated for distractor C.

Technical

References:

Procedure 2.2.66 [Reactor Water Cleanup System](Rev 121),

Lesson plan COR001-20-01 [Ops Reactor Water Cleanup System](Rev 26), Alarm Card 9-4-2/D-5 [RWCU Blowdown Hi/Lo Pressure] (Rev 23), B&R Dwg 2042 sheet 3, B&R Dwg 2030 sheet 1, B&R Dwg 2005 sheet 1, References to be provided to applicants during exam: none Learning Objective: COR001-20-01 Obj LO-9d, Describe the RWCU design features and/or interlocks that provide for the following: Piping over-pressurization protection; 10b, Describe the following concepts as they apply to RWCU: Blowdown Flow Control valve controller operation including automatic closure Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental 168

Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(4)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 169

Examination Outline Cross-Reference Level RO 226001 (SF5 RHR CSS) RHR/LPCI: Containment Tier# 2 Spray Mode Group# 2 A1.03 - Ability to predict and/or monitor changes in K/A # 226001 A1.03 parameters associated with operation of the Rating 4.4 RHR/LPCI: Containment Spray System Mode, Revision 0 including:

Suppression chamber pressure (Mark I, II)

(CFR: 41.5 / 45.5)

Revision Statement:

Question 58 A steam leak in the Drywell occurred 5 minutes ago:

• Drywell pressure is 9.5 psig, slowly rising

• Torus pressure is 8 psig, slowly rising

• Suppression Pool water temperature is 85°F, slowly rising

• EOP-3A has been entered The CRS has directed you to place Torus Sprays in operation.

Torus pressure will (1) immediately after Torus sprays are placed into service under these conditions.

AND RHR-MO-38A, Torus Spray Inboard Throttle Valve, will AUTOMATICALLY close as soon as Drywell pressure falls below (2) .

A. (1) continue to slowly rise (2) 2 psig B. (1) continue to slowly rise (2) 0 psig C. (1) quickly lower (2) 2 psig D. (1) quickly lower (2) 0 psig 170

Answer: A Explanation:

This question satisfies the K/A because it requires predicting the effect of Torus spray operation on suppression chamber pressure.

A steam leak in the Drywell pressurizes the Drywell and forces non-condensable gases to be forced through the Drywell to Torus vents into the Torus, causing Torus pressure to rise. EOP-3A requires Torus sprays to be operated before Torus pressure reaches 10 psig. In the short term, before the suppression pool and the suppression chamber air space heats up significantly, Torus Sprays do not lower Torus pressure, because no steam exists in the suppression chamber air space, and the suppression chamber air space is at essentially the same temperature as the spray coolant, which comes from the suppression pool. Therefore, Torus pressure continues to slowly rise as Drywell pressure rises.

Over time, all non-condensable gases will be pushed into the Torus, and steam will begin to be forced into the suppression pool, where it is condensed. The suppression will begin to heat up due to the steam influx. If Drywell pressure reaches the Pressure Suppression Limit, steam can begin to form in the suppression chamber air space. At that point, operation of Torus sprays would cause Torus pressure to lower due to it condensing steam in the suppression chamber air space.

RHR-MO-38A can be opened if the following permissives are met:

1) LPCI initiation signal (Drywell pressure 1.84 psig or reactor water level -113)

2) Containment Spray Valve Control switch in MANUAL

3) Drywell pressure confirmatory spray permissive (Drywell Pressure >2 psig [TS])

RHR-MO-38A automatically closes if any of the permissives are lost; so, when Drywell pressure lowers to 2 psig (TS), RHR-MO-38A automatically closes.

Distracters:

Answer B part 1 is correct. Part 2 is plausible because EOP-3A Step TS-2 requires securing Torus sprays before Torus pressure falls below 0 psig. Also, EOP-3A Step DS-4 requires securing Drywell sprays before Drywell pressure falls below 0 psig.

This answer is wrong because RHR-MO-38A automatically closes when Drywell pressure lowers below 2 psig. This ensures Torus spray is secured before Torus pressure falls below 0 psig, accommodating the time it takes for RHR-MO-38A to stroke fully closed.

Answer C part 1 is plausible because Torus pressure would quickly lower if there was steam in the suppression chamber air space. This answer is wrong because for the conditions given, Drywell pressure well below PSP and suppression pool temperature on 85°F, there is no steam in the suppression chamber air space, only non-condensable gases, so Torus spray does not lower Torus pressure. Part 2 is correct.

171

Answer D part 1 is plausible and wrong for the reason given for distractor C. Part 2 is plausible and wrong for the reason given for distractor B.

Technical

References:

Lesson plan COR002-23-02 [Ops Residual Heat Removal System] (Rev 39), EOP-3A [Primary Containment Control] (Rev 18), PSTG AMP00 App. B (Rev 10),

References to be provided to applicants during exam: none Learning Objective: COR002-23-02 Obj LO-3p, Describe RHR system design feature(s) and/or interlocks which provide for the following: spray flow cooling; 6l, Given an RHR control manipulation, predict and explain changes in the following:

Containment parameters (pressure, temperature)

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(5),(7),(9)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant Systems - RHR 172

Examination Outline Cross-Reference Level RO 233000 (SF9 FPCCU) Fuel Pool Cooling/Cleanup Tier# 2 A2.14 - Ability to (a) predict the impacts of the Group# 2 following on the Fuel Pool Cooling and Cleanup and K/A # 233000 A2.14 (b) based on those predictions, use procedures to Rating 3.1 correct, control, or mitigate the consequences of Revision 0 those abnormal operations: Low system flow.

(CFR: 41.5 / 43.5 / 45.6)

Revision Statement:

Question 59 The plant is in Mode 4.

Fuel Pool Cooling (FPC) Pump A and Filter/Demineralizer (F/D) A are in service.

A leak occurs in Fuel Pool piping resulting in annunciators on Panel 9-4.

A building operator reports the Fuel Pool Skimmer Surge Tank level indicator is pegged low, AND normal makeup is NOT available.

(1) What is the status of FPC F/D A HOLD pump?

AND (2) What procedures are required to be entered?

A. (1) Stopped (2) Associated Alarm Cards, ONLY B. (1) Stopped (2) Associated Alarm Cards AND Procedure 2.4FPC [Fuel Pool Cooling Trouble]

C. (1) Running (2) Associated Alarm Cards, ONLY D. (1) Running (2) Associated Alarm Cards AND Procedure 2.4FPC [Fuel Pool Cooling Trouble]

Answer: D Explanation:

173

This question satisfies the K/A because it tests knowledge of the effect of low Skimmer Surge Tank level on FPC pumps (results in FPC pump trip, which results in low FPC flow), the result of low FPC flow on FPC Filter Demineralizers, and the procedures required to be entered to mitigate the low FPC flow condition.

The following control room annunciators would alarm for the conditions given:

• 9-4-2/A-3, Fuel Pool Cooling Trouble

• 9-4-2/C-3, Skimmer Tank Low Level (Annunciators are not specifically listed in the stem to prevent cueing based on tile description for 9-4-2/C-3.)

Low FPC Skimmer Surge Tank level, 50 ft3, results in trip of the running FPC Pump B.

Trip of FPC Pump A results in loss of FPC system flow, including flow through Filter Demineralizer A. When Filter Demineralizer A flow lowers to 120 gpm, its holding pump automatically starts. The Skimmer Surge Tank Level indicator is pegged low when volume is 50 ft3 (6 inches indicated).

Low Skimmer Surge Tank level results in loss of all FPC pumps, which is an entry condition for Procedure 2.4FPC.

Distracters:

Answer A part 1 is plausible because Filter/Demineralizer holding pumps are stopped when the Filter/Demineralizer is in service. This answer is wrong because the holding pump automatically starts when FPC flow falls below 120 gpm, as it would when the running FPC pump trips on low Skimmer Surge Tank level. Part 2 is plausible to the examinee who does not realize FPC Pump A trips and all FPC pumps are unavailable because of low Skimmer Surge Tank level or who does not know loss of FPC pumps is an entry condition for Procedure 2.4FPC. This answer is wrong because, for the conditions stated in the stem, all FPC flow is lost, which is an entry condition for Procedure 2.4FPC.

Answer B part 1 is plausible and wrong for the same reason stated for distractor A.

Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the same reason stated for distractor A.

Technical

References:

Alarm Card 9-4-2/C-3 [Skimmer Tank Low Level] (Rev 23),

Alarm Card 9-4-2/A-3 [Fuel Pool Cooling Trouble] (Rev 23), Procedure 2.4FPC [Fuel Pool Cooling Trouble] (Rev 39), Lesson Plan COR001-06-01 [Fuel Pool Cooling] (Rev 33)

References to be provided to applicants during exam: none 174

Learning Objective: COR001-06-01 Obj LO-10a, Given plant conditions, determine if: FPC pumps should have tripped; 10b, Filter/Demineralizers should have gone into HOLD Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(4)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 175

Examination Outline Cross-Reference Level RO 223001 (SF5 PCS) Primary Containment and Tier# 2 Auxiliaries Group# 2 A3.06 - Ability to monitor automatic operation of the K/A # 223001 A3.06 PCS and Aux, including: Drywell/suppression Rating 3.9 chamber differential pressure Revision 0 (CFR: 41.7 / 45.7)

Revision Statement:

Question 60 LOCA conditions exist:

• RHR Pump A is operating in Drywell Spray

• Drywell pressure is 6.8 psig, slowly lowering

• Torus pressure is 4.8 psig, stable Which one of the following identifies the HIGHEST Drywell pressure at which Torus pressure will begin to lower?

A. 2.0 psig B. 4.3 psig C. 5.3 psig D. 6.3 psig Answer: B Explanation:

This question satisfies the K/A because it tests the ability to determine/monitor Drywell to Torus differential pressure given stable Torus pressure and lowering Drywell pressure due to the effects of automatic operation of Torus-to-Drywell vacuum breakers based on Drywell/Torus differential pressure.

The Torus-to-Drywell Vacuum Breakers relieve pressure from the Torus to the Drywell if there is a pressure differential greater than 0.5 psid (actual opening setpoint ~0.1 176

psid). This pressure differential could be present following a LOCA. As the steam released into the Drywell condenses, it could develop a vacuum in the Drywell, and the atmospheric pressure from the outside could then collapse the Drywell. The vacuum breakers will open under these conditions to equalize pressure between the Drywell and Torus. A differential pressure of 0.5 psid from the Torus to the Drywell, with Torus pressure 4.8 psig, equates to 4.3 psig Drywell pressure.

Distracters:

Answer A is plausible because 2.0 is a familiar number associated with DW pressure and vacuum relief, since the external design pressure limit for containment, DW Spray automatically isolates when Drywell pressure falls below 2 psig, and one set of Reactor Building to Torus vacuum breakers are designed to maintain Reactor Bldg to Torus dp <2 psid. It is wrong because Torus-to-DW vacuum breakers open and reduce differential pressure when DW falls below Torus pressure by 0.5 psid.

Answer C is plausible because vacuum breakers control dp between the DW and Torus to -0.5 psid. The examinee who reverses operation of the vacuum breakers and places DW pressure higher than Torus pressure to open vacuum breakers may choose this answer. It is wrong because Torus-to-DW vacuum breakers open and reduce differential pressure when DW falls below Torus pressure by 0.5 psid.

Answer D is plausible because one set of Reactor Building to Torus vacuum breakers are designed to maintain Reactor Bldg to Torus dp <2 psid. The examinee who confuses Torus to DW vacuum breakers with Reactor Bldg to Torus vacuum breakers and who reverses operation of the vacuum breakers and places DW pressure higher than Torus pressure to open vacuum breakers may choose this answer. It is wrong for the same reason stated for distractor A.

Technical

References:

lesson plan COR002-03-02 [Ops Containment](Rev 35)

References to be provided to applicants during exam: none Learning Objective: lesson plan COR002-03-02 Obj. LO-14f, Briefly describe the following concepts as they apply to the Primary Containment: Drywell to Torus Differential Pressure Question Source: Bank # 2018-9 NRC ILT Q#21 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 177

10CFR Part 55 Content: 55.41(b)(5),(9)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - Primary Containment Vacuum Relief 178

Examination Outline Cross-Reference Level RO 239001 (SF3, SF4 MRSS) Main and Reheat Steam Tier# 2 A4.02 - Ability to manually operate and/or monitor in Group# 2 the control room: Main steam line drain valves. K/A # 239001 A4.02 (CFR: 41.7 / 45.5 to 45.8) Rating 3.4 Revision 2 Revision Statement: Rev 1 - Per CE comment, added MSL drain to valve description in stem.

Rev 2 - Per CE comment, revised accordingly to switch Part 1 and Part 2 to prevent cueing and enhanced wording for stem and answers to more strictly bound question.

Question 61 The plant is in Mode 2 and:

• MSL drain Outboard Isolation Valve, MS-MO-77 is fully open.

You are directed to close MS-MO-77.

(1) Based on control circuit design, when closing MS-MO-77, Is its control switch required to be held in CLOSE after the green light comes on until the valve reaches fully closed position?

AND (2) If RPS B EPA breaker 1B1 trips before you get to the switch to close the valve, what is the expected position of the valve?

A. (1) Yes, because it is a throttle valve.

(2) It will close because it lost logic power and fails closed for this condition.

B. (1) Yes, because it is a throttle valve.

(2) It will remain open because its logic is powered from RPSPP1A.

C. (1) No, because the close signal seals in.

(2) It will close because it lost logic power and fails closed for this condition.

D. (1) No, because the close signal seals in.

(2) It will remain open because its logic is powered from RPSPP1A.

Answer: C 179

Explanation:

This question satisfies the K/A because it tests ability to operate (close) a MSL drain valve and it tests the ability to monitor MSL drain valves during a half Group 1 isolation signal .

MS-MO-77 is a Group 1 isolation valve. The control circuit for MS-MO-77 is a seal-in type circuit. Momentarily placing the control switch for MS-MO-77 to CLOSE results in the close signal sealing in until the valve is fully closed.

RPS B EPA breaker 1B1 causes loss of power to RPS Power Panel 1B, which results in loss of Group 1 Channel B logic power. Loss of Group 1 Channel B logic power results in automatic closure of MSL drain valve MS-MO-77.

Distracters:

Answer A part 1 is plausible because MSL drain valves MS-MO-78 and MS-MO-79 are throttle valves which must be held in CLOSE until the valve is fully close, since they do not have seal-ins in their control circuits. MS-MO-77 is adjacent to MS-MO-78 and MS-MO-79 on Panel 9-4. The examinee who confuses MS-MO-77 with MS-MO-78 or MS-MO-79 may chose this answer. This answer is wrong because MS-MO-77 is not a throttle valve; its close signal seals in when the control switch is momentarily placed to CLOSE, so the control switch does not have to be held in CLOSE in order to effect valve full closure. Additionally, Procedure 0.31MOV step 5.2 states Do not hold control switch for any seal-in Limitorque motor operated valve in CLOSE position any longer than momentarily after green indicating light turns on. Placing or holding control switch in CLOSE position after valve is closed can cause hammering of valve.

Part 2 is correct.

Answer B part 1 is plausible and wrong for the reasons stated for distractor A. Part 2 is plausible because a half Group 1 isolation signal due to Group 1 Channel B tripping does not cause any Group 1 valves to automatically close. Both a Group 1 Channel B trip and A Channel B loss of logic power look identical on the Group Isolations Status display on Panel 9-5, with both Channel A white lights on and both Channel B white lights extinguished. This answer is wrong because the condition given is not just a Group 1 Channel B trip, but a Group 1 Channel B logic loss of power, which results in automatic closure of MS-MO-77.

Answer D part 1 is correct. Part 2 is plausible and wrong for the reasons stated for distractor B.

Technical

References:

Procedure 2.1.22 [Recovering from a Group Isolation] (Rev 63), Procedure 0.31MOV [ GE Dwg 791E266 Sheets 4, 7, 8 References to be provided to applicants during exam: none 180

Learning Objective: COR002-03-02 Obj LO-18c, Predict the consequences of the following items on PCIS: System logic initiations/failures; 23e, Predict the consequences of a malfunction of the following on the Primary containment: AC/DC electrical Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7),(9)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability Top 10 Risk Significant System - PCIS 181

Examination Outline Cross-Reference Level RO 510001 (SF8 CWS*) Circulating Water Tier# 2 G2.1.23 - Ability to perform general or normal Group# 2 operating procedures during any plant condition. K/A # 510001 G2.1.23 (CFR: 41.10 / 43.5 / 45.2 / 45.6) Rating 4.3 Revision 2 Revision Statement: Rev 1 - Per CE comments changed the second part of distractor A to match the second part of answer C for balance. Per validators comments, changed from June to October in stem due to seasonal river temperatures. Added likely to answers per Ops Rep comment, because that is the verbiage used in the procedure.

Rev 2 - Replaced question due to validator comments.

Rev 3 - Per CE comment, added for after flow rate in Part 1 stem.

Question 62 Circulating Water Pumps B, C, and D are operating Circulating Water Pump A is being started.

IAW Procedure 2.2.3 [Circulating Water System],

(1) What is the MINIMUM required bearing water flow rate for Circulating Water Pump A?

AND (2) Which one of the following is an indication of proper Circulating Water Pump A bearing water flow?

A. (1) 2 gpm (2) NO water observable inside cavity between pump and motor B. (1) 2 gpm (2) Gland leakage from pump reaching cavity floor between pump and motor C. (1) 8 gpm (2) NO water observable inside cavity between pump and motor D. (1) 8 gpm (2) Gland leakage from pump reaching cavity floor between pump and motor 182

Answer: D Explanation:

This Question satisfies the K/A because it tests the ability to perform procedure steps within a normal operating procedure (SOP).

Procedure 2.2.3 Steps 4.15 and 5.3 establish proper bearing water flow for CWP A. A Caution before Steps 4.15 and 5.3 states: CW pump bearing damage will result from continued, long term operation with less than 8 gpm bearing water flow.

The third bullet in Steps 4.15 and 5.3 for ensuring proper bearing water flow states:

CW-FIS-351A, CW PUMP A SEAL WATER LOW FLOW SWITCH, greater than or equal to 8 gpm. This flow switch actuates control room annunciator A-4/C-3 when flow is < 8 gpm.

The fourth bullet of Steps 4.15 and 5.3 requires ensuring: Sufficient gland water leak-off. Note 2 before Steps 4.15 and 5.3 state: CW pump may continue to operate if gland water leak-off sufficient to reach cavity floor between pump and motor.

Distracters:

Answer A part 1 is plausible because it reflects the value of the low bearing water flow annunciator, A-4/D-6, for Service Water pump A. This answer is wrong because the minimum bearing water flow for CWP A is 8 gpm. Part 2 is plausible because other pumps, such as RHR, are not designed to have seal water leak-off external to the pump seal. Water coming out of the pump seal would be abnormal. This answer is wrong because CWPs are designed to have leak-off from the pump seal to the outboard side of the seal to ensure proper seal lubrication. Sufficient gland water leak-off from the top of the seal is required to be visually observed before pump start.

Answer B part 1 is plausible and wrong for the same reason as given for distractor A.

Part 2 is correct.

Answer C part 1 is correct. Part 2 is and wrong for the reasons given for distractor A.

Technical

References:

Procedure 2.2.3 [Circulating Water System] (Rev 156), Alarm Card A-4/C-3 [Circ Water Pump Brg Wtr Low Flow] (Rev 45), Alarm Card A-4/D-6

[Service Water Pump A/C Brg Wtr Low Flow] (Rev 45)

References to be provided to applicants during exam: none Learning Objective: COR001-02-01 Obj LO-bb, Given plant conditions, determine if the following should occur: CWP start Question Source: Bank #

(note changes; attach parent) Modified Bank #

183

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(4),(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 184

Examination Outline Cross-Reference Level RO 245000 (SF4 MTGEN) Main Turbine Tier# 2 Generator/Auxiliary Group# 2 K2.04 - Knowledge of electrical power supplies to K/A # 245000 K2.04 the following: Rating 2.9 Hydrogen seal oil pumps Revision 3 (CFR: 41.7)

Revision Statement: Rev -1 Per validators comments, changed MCC-G distractor to 250 VDC Bus Starter Rack for plausibility, then rearranged distractors long to short order.

Rev 2 - Replaced question due to Ops Rep comments.

Rev 3 - Per CE comments, replaced answers to include only voltage levels versus the specific power supplies to normalize the length of the correct answer, since it was much longer than the distractors, in order to eliminate cueing (changed correct answer from A to C)

Question 63 What is the power supply to the generator Air Side Seal Oil Backup Pump?

A. 480 VAC B. 460 VAC C. 250 VDC D. 125 VDC Answer: C Explanation:

This question satisfies the K/A because it tests knowledge of the power supply to a Hydrogen seal oil pump.

250 VDC Turbine Building Starter Rack powers the Air Side Seal Oil Backup Pump.

Distracters:

Answer A is plausible because 480 VAC (via 480V Switchgear 1A) powers some pumps, such as TEC Pump A. It is wrong because 250 VDC Turbine Building Starter Rack powers the Air Side Seal Oil Backup Pump.

185

Answer B is plausible because 460 VAC (via MCC-B) powers the normal Hydrogen Air Side Seal Oil Pump. It is wrong because 250 VDC Turbine Building Starter Rack powers the Air Side Seal Oil Backup Pump.

Answer D is plausible because 125 VDC powers some oil pumps, such as the DG1 Fuel Oil Booster Pump. It is wrong because 250 VDC Turbine Building Starter Rack powers the Air Side Seal Oil Backup Pump.

Technical

References:

Lesson Plan COR001-13-01 [OPS Main Generator and Auxiliaries] (Rev 37), Procedure 2.2.52A [Hydrogen Seal Oil System Component Checklist (Rev 13), Procedure 2.2A_480.TG [480 VAC Turbine Building Breaker Checklist] (Rev 32), Procedure 2.2A_125VDC.DIV1 [125 VDC Power Checklist] (Rev 8)

References to be provided to applicants during exam: none Learning Objective: COR001-13-01 Obj LO-4a, State the electrical power supplies to the following: Hydrogen side seal oil pump Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(4)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 186

Examination Outline Cross-Reference Level RO 271000 (SF9 OG) Offgas Tier# 2 K1.05 - Knowledge of the physical connections Group# 2 and/or cause and effect relationships between the K/A # 2271000 K1.05 Offgas System and the following systems: Radwaste Rating 3.1 system. Revision 0 (CFR: 41.4 to 41.5, 41.7, 41.13 / 45.6 to 45.8)

Revision Statement:

Question 64 The Elevated Release Point (ERP) drains to the (1) , which normally discharges to the (2) .

A. (1) Y-Sump (2) Floor Drain Collector Tank B. (1) Y-Sump (2) Waste Collector Tank C. (1) Z-Sump (2) Floor Drain Collector Tank D. (1) Z-Sump (2) Waste Collector Tank Answer: D Explanation:

This question satisfies the K/A because it test knowledge of the interconnection between Off Gas filters with the radwaste Floor Drain Collector Tank.

The Z-sump receives condensate drains from the following:

• Elevated Release Point

• Off Gas filter pit drains

• Off Gas Building floor drains

• 48-inch holdup pipe

• Mechanical Vacuum Pumps

• Off Gas dilution fans The ERP is part of the Off Gas system.

187

Two pumps, installed in the Z-sump, cycle on sump level to pump the condensate drains to the Waste Collector Tank (normal alignment) in Radwaste. During flooding conditions, the Z-sump discharge can be aligned to pump to the Floor Drain Collector Tank.

Distracters:

Answer A is plausible because the Y sump is located beyond the power block, as is the Z sump. This answer is wrong because the Z sump receives drains from the ERP, and the Z sump normally discharges to the Waste Collector Tank.

Answer B is plausible because the Y sump is located beyond the power block, as is the Z sump. This answer is wrong because the Z sump receives drains from the ERP Answer C is plausible because Z-sump can be aligned to discharge to the Floor Drain Collector Tank. This answer is wrong because the Z sump normally discharges to the Waste Collector Tank and is only aligned to the Floor Drain Collector Tank during flooding conditions where flood drainage can enter the sump.

Technical

References:

Lesson Plan COR001-16-01 [Ops Off Gas] (Rev 36), B&R Dwgs: 2005 sheet 2, Procedure 2.2.27 [Equipment, Floor , and Chemical Drain System] (Rev 61)

References to be provided to applicants during exam: none Learning Objective: COR001-16-01 Obj LO 10e, Recall the interrelationships between the Off Gas system and the systems/components below: Radwaste Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(4),(13)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 188

Examination Outline Cross-Reference Level RO 290003 (SF9 CRV) Control Room Ventilation Tier# 2 K3.04 - Knowledge of the effect that a loss or Group# 2 malfunction of the Control Room Ventilation will K/A # 290003 K3.04 have on the following systems or system Rating 3.4 parameters: Control room pressure. Revision 1 (CFR: 41.7 / 45.6)

Revision Statement: Rev 1 - Per CE comments, removed reference to a fuel handling accident from the stem, since that is more of the Tier 1 realm.

Rev 2 - Replaced question per validation comments.

Rev 3 - Per CE comment, replaced high radiation condition in stem (3rd sentence) with a spurious Group 6 initiation.

Question 65 The plant is in Mode 5.

Control Room SUPPLY FAN, SF-C-1B is tagged out of service for maintenance.

A spurious Group 6 initiation occurs.

One minute later, status of Control Room ventilation components are as follows:

• HV-270AV, CONTROL ROOM HVAC INLET VALVE is closed

• HV-271AV, CONTROL ROOM HVAC EMER BYPASS VLV is closed (1) Which one of the above listed components is NOT in the required position?

AND (2) With this alignment, Control Room pressure will be than required.

A. (1) HV-270AV (2) higher B. (1) HV-270AV (2) lower C. (1) HV-271AV (2) higher 189

D. (1) HV-271AV (2) lower Answer: D Explanation:

This question satisfies the K/A because it tests knowledge of what Control Room Ventilation components have malfunctioned and the effect of the malfunction on Control Room pressure.

The Control Room System has an Emergency Bypass System (Control Room Emergency Filtration System (CREFS)) consisting of a Pre-Filter PF-C-1A, High Efficiency Filter HEF-C-1A, Carbon Filter CF-C-1A, and Emergency Booster Fan BF-C-1A which can be supplied from either MCC-LX or MCC-TX via a manual transfer switch in the Auxiliary Relay Room. Upon a Group 6 Isolation signal, this Bypass System is energized and allows outside air to pass through it to the AC unit. During Bypass System operation, one AC unit supply fan is required to run in order to maintain positive Control Room pressure. Additionally, the exhaust booster fan is required to run to provide backpressure which prevents inlet air flow rates from exceeding the Tech Spec limit.

Reactor Building Exhaust Plenum Radiation high (49 mr/hr, TS setpoint) is a Group 6 isolation signal. Control Room Emergency Filtration (CREF) system initiates automatically from a Group 6 isolation. When CREF initiates, control room ventilation reconfigures as follows:

• BF-C-1A, EMER BSTR FAN starts

• EF-C-1B, TOILET EXHAUST FAN, trips

• HV-270AV, CONTROL ROOM HVAC INLET VALVE, closes

• HV-271AV, CONTROL ROOM HVAC EMERGENCY BYPASS SYSTEM INLET VALVE, opens

• HV-272AV, CONTROL ROOM PANTRY EXHAUST FAN ISOLATION VALVE, closes With HV-271AV closed, it is not in the required position. There is no inlet for Control Room Emergency Booster Fan or the normal supply fans, so positive pressure in the Control Room is not ensured, and pressure will be lower than required.

Distracters:

Answer A part 1 is plausible to the examinee who does not know the arrangement of control HVAC components, that a CREFS initiation has occurred, or system response to CREF initiation. This answer is wrong because HV-271AV opens on a CREFS initiation to provide a supply path to control room normal and emergency fans. Part 2 is plausible because SGT system initiates on the same signal in order to maintain the Reactor Building at a negative pressure. The examinee who confuses the required pressure for Control Room and Reactor Building may choose this answer. This 190

answer is wrong because the Control Room is required to be maintained at a positive pressure to protect Control Room personnel.

Answer B part 1 is plausible and wrong for the reason stated for distractor A. Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the reason stated for distractor A.

Technical

References:

Procedure 2.2.84 [HVAC Main Control Room and Cable Spreading Room] (Rev 59)

References to be provided to applicants during exam: none Learning Objective: COR001-08-01 Obj LO-12a, Describe the Control Room HVAC design features and interlocks that provide for the following: Control Room HVAC reconfigurations Question Source: Bank #

(note changes; attach parent) Modified Bank # 2018-9 NRC ILT Q#65 New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(7)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 191

From 2018-9 NRC ILT Q#65 192

Examination Outline Cross-Reference Level RO G2.1.5 Ability to use procedures related to shift Tier# 3 staffing, such as minimum crew complement or Group#

overtime limitations (reference potential). K/A # G2.1.5 (CFR: 41.10 / 43.5 / 45.12) Rating 2.9 Revision 0 Revision Statement:

Question 66 Bob is an RO who begins taking turnover at 0530 and assumes the watch at 0600 on his first work day, Tuesday, after a two week vacation.

Bob is relieved from watch duties at 1800.

Due to plant conditions, Bob is requested to return to take the watch for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> ONLY as soon as allowed by working hour limitations.

• Bob will be off work after he is relieved.

IAW Procedure 0.12 [Working Hour Limitations and Personnel Fatigue Management]

What is the EARLIEST time Bob can return and assume the watch without requiring a working hour limit waiver?

A. Wednesday at 0200 B. Wednesday at 0400 C. Wednesday at 0430 D. Wednesday at 0600 Answer: B Explanation:

At CNS, turnover time is considered to be before the shift and is reflected as a 30 minute period in the stem. Procedure 0.12 step 2.4.1.1 states workers are responsible for ensuring any schedule changes will not violate work hour rules.

Reactor Operators are governed by work hour limitations of procedure 0.12 per step 193

4.1.1. Step 4.3.1 states A rest break of at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> shall be required between work periods unless approved per Section 6, Waivers, of this procedure. Note 1 before step 4.3.1 states One period of shift turnover, either before or after shift, may be included in the rest break, but not both.

Including only their on-coming 30 minute turnover, the rest time 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> clock starts at 1800 on Tuesday and expires at 0400 on Wednesday. Since the rest time can include one 30 minute turnover period before 0400, the earliest turnover may begin is 0330.

Distracters:

Answer A is plausible because 0.12 step 4.2.2 limits work hours to no more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. Since Bob has only worked 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, the examinee may believe he can work 4 more hours before the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period expires, which began at 0600 on Tuesday. 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> before 0600 on Wednesday is 0200 on Wednesday. It is wrong because this would not provide the mandatory 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> break between work periods.

Answer C is plausible because it reflects a 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> break period plus 30 minutes turnover following when Bob was relieved at 1800. It is wrong because one 30 minute turnover is allowed to be included in the 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> break time, so it is not the earliest allowed time. Bob can actually begin 30 minute turnover a half hour earlier, at 0330, and assume the watch at 0400, 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> after he was last relieved.

Answer D is plausible because it reflects the normal break time between 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts. It is wrong because a minimum of only 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> break time, including one turnover, is required, so the RO can return earlier, at 0330.

Technical

References:

Procedure 0.12 [Working Hour Limitations and Personnel Fatigue Management] (Rev 33)

References to be provided to applicants during exam: none Learning Objective: INT032010100F0200 Given the previous working hours/days history of an individual, determine if the individual is in compliance with the working hours limitations set forth in Administrative Procedure 0.12, Working Hours Limitations and Personnel Fatigue Management.

Question Source: Bank # 2018-9 NRC ILT Q#67 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 194

10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 2018-9 NRC ILT Q#67 195

Examination Outline Cross-Reference Level RO G2.1.14 Knowledge of criteria or conditions that Tier# 3 require plantwide announcements, such as pump Group#

starts, reactor trips, and mode changes. K/A # G2.1.14 (CFR: 41.10, 43.5 / 45.12) Rating 3.1 Revision 2 Revision Statement: Rev 1 - Per CE comment, eliminated system specific nomenclature in stem and replaced event 3 in the stem. This changed the correct answer to all listed events require site wide announcements. Per validators comments, changed Air Compressors to normalize run time in 1st bullet of stem to mechanical vacuum pump for plant start up, since they do not shift air compressors to equalize run time any more.

Rev 2 - Per Final Ops Mgmt Reviewer comment, replaced event 1 related to a 480V component because large compressor as used in the procedure is interpretive, so correct answer could be challenged.

Question 67 Which of the events below are required to have a plant wide announcement made on the Gaitronics paging system IAW plant procedures?

1. High alarm condition indicated on an Area Radiation Monitor

2. Manual start of a 4160 VAC pump for maintenance retest

3. Manual start of a steam driven turbine for quarterly surveillance testing A. 1, 2, and 3 B. 1 and 2 ONLY C. 2 and 3 ONLY D. 3 ONLY Answer: A Explanation:

This question satisfies the K/A because it tests knowledge of conditions that require plantwide announcements.

196

Procedure 5.1RAD is required to be entered due to a high or unusual reading on any ARM or ARM recorder, and Step 4.2 requires notifying plant personnel to clear affected area via Gaitronics.

Procedure 0-CNS-02 Step 3.4.2 states when performing a planned start of major plant equipment (large pumps, turbines, or compressors), an announcement will be made to inform and warn personnel in the area that equipment is being started. Event 2 represents a planned manual start of a major pump, since it is 4160 VAC. Event 3 represents a start of a major turbine, since all permanent plant, steam driven turbines are considered major equipment.

Therefore, plant announcements are procedurally required for all three events Distracters:

Answer B is plausible because it represents a two, non-routine conditions. An examinee who does not remember turbines are included in Procedure 0-CNS-2 Step 3.4.2 or who believes announcements for routine events, such as surveillances, may choose this answer. This answer is wrong because announcements are also required for planned starts of steam turbines, which are all considered major equipment. One of two validators chose this answer.

Answer C is plausible because it represents the only two events related to planned starts of major equipment. The examinee who does not know the requirements of Procedure 5.1RAD may choose this answer. This answer is wrong because announcements are also required IAW Procedure 5.1RAD for a high alarm condition indicated on a plant ARM.

Answer D is plausible because it represents the only steam turbine among the answers. An examinee who does not remember electrically powered pumps are included in Procedure 0-CNS-2 Step 3.4.2 nor who remembers requirements of Procedure 5.1RAD may choose this answer. It is also plausible because it is the only component being started for surveillance testing. An examinee who recalls routine Gaitronics announcements for commencing surveillance tests may choose this answer. This answer is wrong because announcements are also required for starting major pumps and for a high alarm condition on a plant ARM.

Technical

References:

Procedure 0-CNS-2 [Site Work Practices] (Rev 48).

Procedure 5.1RAD [Building Radiation Trouble] (Rev 19)

References to be provided to applicants during exam: none Learning Objective: INT32-01-01 EO-A1b, Discuss the following as described in Administrative Procedure 0-CNS-02, Site Work Practices: CNS Communications and Gaitronics usage 197

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 198

Examination Outline Cross-Reference Level RO G2.1.34 Knowledge of RCS or balance of plant Tier# 3 chemistry controls, including parameters measures Group#

and reasons for the control. K/A # G2.1.34 (CFR: 41.0 / 43.5 / 45.12) Rating 2.7 Revision 0 Revision Statement:

Question 68 TRM 3.4.1 [RCS Chemistry] governs limits for (1) .

AND This limit is designed to prevent (2) .

A. (1) silicas (2) fouling of jet pump nozzles B. (1) silicas (2) cracking of reactor internals C. (1) chlorides (2) fouling of jet pump nozzles D. (1) chlorides (2) cracking of reactor internals Answer: D Explanation:

This question satisfies the K/A because it requires knowledge of chemistry parameters governed by TRM 3.4.1 and because it requires knowledge of the reason for controlling the chemistry parameters.

TRM 3.4.1 governs RCS chemistry for three parameters: chlorides, conductivity, and pH.

Materials in the primary system are primarily Type-304 stainless steel and Zircaloy cladding. The reactor water chemistry limits are established to provide an environment 199

favorable to these materials. Limits are placed on conductivity and chloride concentrations. Conductivity is limited because it can be continuously and reliably measured and gives an indication of abnormal conditions and the presence of unusual materials in the coolant. Chloride limits are specified to prevent Intergranular Stress Corrosion Cracking (IGSCC) of stainless steel.

Distracters:

Answer A part 1 is plausible because silica is a common contaminant found in plant water systems. Silica is present in river water, which provides cooling to the main condenser tubes. Condenser tube leaks are a major concern related to RCS chemistry, because contaminants in the hotwell could make their way to the RCS.

Procedure 2.4CHEM contains limits and strategies for condenser tube leakage. An An examinee who remembers river water intrusion is detrimental to RCS chemistry but cannot remember the chemical compounds involved and confuses silicas for sulfates may select this answer. This answer is wrong because silica concentration is not governed by TRM 3.4.1. Part 2 is plausible because RCS chemistry affects jet pump fouling, plating of corrosion products on jet pump nozzles, which results in the undesirable effect of limiting core flow capability. This answer is wrong because RCS chemistry limits of TRM 3.4.1 are required and designed to prevent IGSCC of RCS stainless steel components.

Answer B part 1 is plausible and wrong for the reason given for distractor A. Part 2 is correct.

Answer C part 1 is correct. Part 2 is plausible and wrong for the reason given for distractor A.

Technical

References:

Procedure 2.4CHEM [Chemistry Parameter Out of Limit]

(Rev 13), TRM 3.4.1 [RCS Chemistry]

References to be provided to applicants during exam: none Learning Objective: INT032-01-36 EO A, Given plant condition(s), determine from memory the appropriate Abnormal/Emergency Procedure(s) to be utilized to mitigate the event(s).

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(3),(10) 200

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 201

Examination Outline Cross-Reference Level RO G2.2.6 Knowledge of the process for making Tier# 3 changes to procedures. Group#

(CFR: 41.10 / 43.3 / 45.13) K/A # G2.2.6 Rating 3.0 Revision 0 Revision Statement:

Question 69 While performing a Reference Use procedure, a step is encountered which contains an incorrect unit of measure (psia instead of psig). The unit of measure is correctly used earlier in the procedure for the same indicator.

A procedure change is required.

IAW Procedure 0.4 [Procedure Change Process],

What is the lowest classification of procedure change required?

A. Intent change B. Instant change C. Editorial change D. Pen-and-Ink change Answer: D Explanation:

Procedure 0.4 [Procedure Change Process] Step 3.4.7 defines a pen-and-ink change:

202

PEN-AND-INK - A pen-and-ink correction may be made to a procedure if it is simple and obvious:

• Items normally considered simple and obvious:

• Obvious typographical errors.

• Obvious incorrect units of measure.

• Obvious errors in step and table references.

• Obvious equipment identification inconsistencies.

• Obvious equipment location inconsistencies.

• Changing values that are obviously incorrect and are referenced correctly elsewhere in the procedure.

• Items normally not considered simple and obvious:

• Changes to setpoint values and tolerances.

• Changes to commitments.

• Changes in step sequence.

• Changes to values that are not referenced correctly elsewhere in the procedure.

• Addition or deletion of steps.

• Changes to acceptance criteria.

Procedure 0.4 [Procedure Change Process] Step 3.4.8 defines an editorial change:

EDITORIAL CHANGE - The TSG (or Procedure Owner) may approve the following types of changes as editorial changes:

• A procedure change that has no material change, other than to perhaps undo a change that should not have been made (the revision number should always increment forward; for instance, if returning a Revision 11 change to its Revision 10 state, the new revision number will be 12, not 10).

• A "Documentation Only" package that makes no change to the procedure.

• Deletion of a Vendor Procedure, Special Procedure, or change that was previously approved for a limited duration.

• Reinstituting a deleted Vendor Procedure that is still on the same revision (component classification or system must not be changed).

• For situations where an approved procedure revision is sitting on the shelf, awaiting pre-implementation actions, and there is a need for partial implementation (for example, only one division of a plant configuration change has been made and the procedure changes to support operation of that division need to be put into place).

• Any change that could be processed as an electronic file update.

This question involves a case of an obvious incorrect unit of measure, which is a specific example of a pen-and-ink correction listed in Step 3.4.7.

Distracters:

203

Answer A is plausible because Intent Change is a type of procedure change defined in procedure 0.4. It is wrong because this correction to a unit of measure would pass the Non-Intent change screening of procedure 0.4 Att. 6. The definition of Intent Change reflects a change that would not pass this screening Answer B is plausible because Instant Change is a type of procedure change defined in procedure 0.4. It is wrong because an Instant change requires preapproval by an ITR and a SRO and is not necessary for conditions that satisfy requirements for Pen-and-Ink changes. An Instant Change is a higher classification than Pen-and-Ink change.

Answer C is plausible to the unprepared applicant who does not know the classifications of pen-and-ink or editorial as defined in procedure 0.4. The word Editorial may seem appropriate due to its commonly accepted usage. IT is wrong because this question involves a case of an obvious incorrect unit of measure, which is a specific example of a pen-and-ink correction listed in procedure 0.4 step 3.4.7 and does not meet the definition of an editorial change given in step 3.4.8.

Technical

References:

Procedure 0.4 [Procedure Change Process] (Rev 70)

References to be provided to applicants during exam: none Learning Objective: INT032-01-01 EO E.1.a Question Source: Bank # 2018-9 NRC ILT Q#69 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 2 SRO Only Justification: N/A PSA applicability:

N/A 204

2018-9 NRC ILT Q#69 205

Examination Outline Cross-Reference Level RO G2.2.22 Knowledge of limiting conditions for Tier# 3 operation and safety limits Group#

(CFR: 41.5 / 43.2 / 45.2) K/A # G2.2.20 Rating 4.0 Revision 0 Revision Statement:

Question 70 The plant is at 25% power.

In addition to restoring compliance with Safety Limits, what is the MINIMUM action required by TS if a Safety Limit is violated?

A. reduce power to <25% within two hours.

B. insert all insertable control rods within two hours.

C. immediately place mode switch in shutdown.

D. immediately enter TS 3.0.3.

Answer: B Explanation:

TS 2.2 states the required actions for Safety Limit violations must be performed within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. These are to restore compliance with all SLs and insert all insertable control rods.

Distracters:

Answer A is plausible because MCPR is a safety limit and the answer is similar to required actions related to MCPR (operating limit) not met. If the MCPR operating limit is not met, TS 3.2.2 requires restoring it to within the limit within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or reducing power to <25% within the following 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The examinee who confuses the safety limit MCPR with the operating limit MCPR but remembers the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> time requirement for TS 2.2.2 may choose this answer. It is wrong because safety limit violations require inserting all control rods within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> per TS 2.2.2.

206

Answer C is plausible because a safety limit violation represents operation outside of the design basis of the plant. An examinee may believe this requires immediate plant shutdown by scram, since other TS, such as TS 3.6.2.1 Condition D for suppression pool temperature >110°F, require immediate scram. It is wrong because TS 2.2.2 applies, which requires inserting all control rods within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, not immediately.

Since the stem asks for the minimum required action, this answer is inappropriate.

Answer D is plausible because compliance with the various TS should prevent a safety limit violation, and TS 3.0.3 is provided for conditions where other TS actions are not listed. An examinee may consider TS 3.0.3 as the most severe TS action and believe it is fitting for a safety limit violation. It is wrong because TS 2.2.2 is specifically provided for a safety limit violation and is more severe than TS 3.0.3 requirements.

Technical

References:

TS 2.0 [Safety Limits], TS 3.6.2.1 [Suppression Pool Average Temperature], TS 3.2.2 [MCPR]

References to be provided to applicants during exam: none Learning Objective: INT007-05-01 EO-9, State the actions which must be performed should a Safety Limit violation occur at CNS Question Source: Bank # 2018-9 NRC ILT Q#71 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability N/A 207

2018-9 NRC ILT Q#71 208

Examination Outline Cross-Reference Level RO G2.2.41 Ability to obtain and interpret station Tier# 3 electrical and mechanical drawings (reference Group#

potential). K/A # G2.2.41 (CFR: 41.10 / 45.12 / 45.13) Rating 3.5 Revision 0 Revision Statement:

Question 71 Consider the following excerpt from a GE electrical drawing:

Relay 23A-K23 is ENERGIZED when relay 23A-K6 is (1) .

Full size hardcopies of Controlled Distribution drawings maintained by Document Control are located in the (2) .

A. (1) ENERGIZED (2) Control Room B. (1) ENERGIZED (2) Mechanical Shop C. (1) DE-ENERGIZED (2) Control Room D. (1) DE-ENERGIZED (2) Mechanical Shop Answer: C Explanation:

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This question satisfies the K/A because it tests ability to interpret and obtain an electrical drawing.

The excerpt of the drawing reflects a normally closed contact in series with a relay coil. Normally closed contacts are closed when the relay is in its shelf state (de-energized). A normally closed contact opens when its relay is energized. Therefore, relay 23A-K23 is energized when relay 23A-K6 in in its shelf state, de-energized.

Controlled hard copies of GE electrical prints are located in the TSC, EOF, Control Room, Simulator Control Room, I&C Shop, E-Shop, Work Control Center (WCC), and Central Alarm Station (CAS), but not in the Mechanic shop.

Distracters:

Answer A part 1 is plausible because the drawing depicts a closed (b) contact in series with a relay coil. The examinee who does not know GE electrical drawings depict contacts in their shelf state, de-energized, may select this answer. This answer is wrong because energizing relay 23A-K6 will cause the contact to open, de-energizing relay 23A-K23. Part 2 is correct.

Answer B part 1 is plausible and wrong for the reason stated for distractor A. Part 2 is plausible because hardcopies of controlled electrical drawings are maintained in the I&C Shop and Electrical Shop (E-Shop). This answer is wrong because hardcopies of the controlled drawings are not maintained in the Mechanical Shop.

Answer D part 1 is correct. Part 2 is plausible and wrong for the reason stated for distractor B.

Technical

References:

GE drawing 791E271 sheet 3, Procedure 3.DRAWING

[Drawing Control] (Rev 12), Lesson Plan SKL012-01-02 [OPS Print Reading for Non-Licensed Nuclear Plant Operators] (Rev 8)

References to be provided to applicants during exam: none Learning Objective: SKL014-02-03 EO-1, Describe the operation and identification of "a" and "b" type contacts on relays and breakers; EO-10, Given a set of Burns &

Roe and/or GE electrical prints and a set of plant conditions, discuss the expected state/condition of any relay or logic circuit associated with a specific system.

SKL012-01-02 EO-4, State the primary plant locations where copies of all plant drawings are filed which can be used by all station personnel.

Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental 210

Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability 211

Examination Outline Cross-Reference Level RO G2.3.5 Ability to use radiation monitoring systems, Tier# 3 such as fixed radiation monitors and alarms or Group#

personnel monitoring equipment. K/A # G2.3.5 (CFR: 41.11 / 41.12 / 43.4 / 45.9) Rating 2.9 Revision 1 Revision Statement: Rev 1 - Per validators comments, changed initial counts from 205 to 203 Question 72 Given the following conditions:

• A standard pancake Geiger-Muller detector is being used to perform a whole body frisk

• Background radiation is at 203 counts per minute (cpm)

Which of the following is the MINIMUM reading on the detector that meets the threshold for a Personnel Contamination Event (PCE) in accordance with radiation protection Procedure 9.EN-RP-104 [Personnel Contamination]?

A. 255 cpm B. 315 cpm C. 375 cpm D. 435 cpm Answer: B Explanation:

This question satisfies the K/A because it tests ability to use personnel radiation monitoring equipment.

This is a modified version of 2020-9 NRC ILT Q#66. It was modified by changing the background radiation reading in the stem and the radiation levels in all of the answers.

A different premise was used for distractor D than was used for any of the distractors in the original question. The original premise for distractor A was not used. The correct answer is now B versus C in the original question.

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Procedure 9.EN-RP-104 note before Step 7.2 defines the PCE threshold as 100 cpm. Answer B is the lowest answer that is above the threshold (203 + 100 = 303, Answer B, 315>303).

Distracters:

Answer A is plausible because to the examinee who believes a frisker reading of 50 cpm above background constitutes a PCE. This answer is wrong because it does not exceed the PCE threshold of 100 cpm above background.

Answer C is plausible because to the examinee who believes a frisker reading of 150 cpm above background constitutes a PCE. This answer is wrong because it is not the lowest value that exceeds the PCE threshold of 100 cpm above background.

Answer D is plausible because to the examinee who believes a frisker reading of 200 cpm above background constitutes a PCE. This answer is wrong because it is not the lowest value that exceeds the PCE threshold of 100 cpm above background.

Technical

References:

Procedure 9.EN-RP-104 [Personnel Contamination] (Rev 17)

References to be provided to applicants during exam: none Learning Objective: INT032-01-100 EO-F1, Discuss the levels of radioactive contamination limits Question Source: Bank #

(note changes; attach parent) Modified Bank # 2020-9 NRC ILT Q#66 New Question Cognitive Level: Memory/Fundamental Comprehensive/Analysis X 10CFR Part 55 Content: 55.41(b)(10),(12)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 213

2020-9 NRC ILT Q#66 214

Examination Outline Cross-Reference Level RO G2.3.11 Ability to control radiation releases. Tier# 3 (CFR: 41.11 / 43.4 / 45.10) Group#

K/A # G2.3.5 Rating 3.8 Revision 0 Revision Statement:

Question 73 The plant is at 100% power when the following valid alarms are received:

MAIN STM LINE PANEL/WINDOW:

HI HI RAD 9-4-1/A-4 OFFGAS PANEL/WINDOW:

HIGH RAD 9-4-1/C-5 Which procedure contains the strategy to manually limit operation of Reactor Building sump pumps in order to minimize the spread and release of radioactivity?

A. 5.2FUEL [Fuel Failure]

B. 2.4OG [Off-Gas Abnormal]

C. EOP-5A [Secondary Containment Control]

D. 2.2.27 [Equipment, Floor, and Chemical Drain System]

Answer: A Explanation:

This question tests overall mitigative strategy of a procedure and is, therefore, RO level knowledge. Procedure 5.2FUEL Att. 2 directs placing all pumps for sumps A, B, C, D, and E in the Reactor Building to off and only starting the pumps manually as necessary to maintain secondary containment area water levels below Maximum Safe Operating levels.

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Procedure 5.2FUEL states: Placing secondary containment sump pump switches in off will limit the release of radioactive material from secondary containment. By disabling these pumps, any radioactive material that migrates to these sumps can be given time to decay and then be processed in a controlled manner during recovery.

However, guidance is provided to allow operation of Reactor Building sumps only, as necessary, to maintain affected secondary containment areas below Maximum Safe Operating Water Level per EOPs. This is consistent with EOP strategy to prevent water accumulation in secondary containment from challenging continued OPERABILITY of ECCS needed to maintain adequate core cooling. Considering procedure hierarchy, it would appear that the Operator would ignore Procedure 5.2FUEL and just follow the EOPs; however, the intent is that if in 5.2FUEL, the designated sump pumps should be considered to be unavailable in the context of Flowchart 5A; therefore, the sump pumps would only be used to maintain the area below the max safe operating level. This approach is a compromise to prevent water accumulation in the secondary containment from challenging ECCS and limit the release of radioactive material. In addition, the use of the term "available" in the context used, is consistent with the EPG definition (i.e., capable of performing an identified function), unless plant conditions (e.g., hi rad indicative of fuel element failure) or physical restrictions preclude system use, it is not considered to be available.

Distracters:

Answer B is plausible because OG high radiation is present and because 2.4OG contains directions for operation of sump pumps. It is wrong because 2.4OG only directs operation of Z sump pumps related to filling OG loop seals.

Answer C is plausible because EOP-5A contains instructions for operation of Reactor Building sump pumps. It is wrong because EOP-5A directs operation of sump pumps to maintain water levels below the Maximum Normal Operating values strictly on the basis of area water level, with no regard to limiting the spread of radioactive water.

Answer D is plausible because SOP 2.2.27 contains instructions for operation of Reactor Building sump pumps. It is wrong because it provides instructions for normal alignment of sump pumps to control sump levels automatically based on sump level and instructions for operation of sump pumps with failed level instrumentation.

Technical

References:

Alarm Cards 9-4-1/A-4 [Main Stm Line Hi-Hi Rad](Rev 62), 9-4-1/C-5 [Offgas High Rad](Rev 62), Procedure 5.2FUEL [Fuel Failure](Rev 23),

Procedure 2.4OG [Off-Gas Abnormal](Rev 29), EOP-5A [Secondary Containment Control](Rev 19), Procedure 2.2.27 [Equipment, Floor, and Chemical Drain System]

(Rev 61)

References to be provided to applicants during exam: none 216

Learning Objective: INT032-01-30 EO-E, Given plant condition(s), determine from memory the appropriate Abnormal/Emergency Procedure(s) to be utilized to mitigate the event(s).

Question Source: Bank # 2018-9 NRC ILT Q#73 (note changes; attach parent) Modified Bank #

New Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10),(12)

Level of Difficulty: 2 SRO Only Justification: N/A PSA Applicability N/A 217

2018-9 NRC ILT Q#73 218

Examination Outline Cross-Reference Level RO G2.4.14 Knowledge of general guidelines for Tier# 3 emergency and abnormal operating procedure Group#

usage. K/A # G2.4.14 (CFF: 41.10 / 43.1 / 45.13) Rating 3.8 Revision 2 Revision Statement: Rev 1 - Per CE comments, replaced original question with new one.

Rev 2 - Replaced part 2, which was testing a vague exemption to Procedure 0-EN-HU-106 requirement for use of human performance tools based on Ops Rep and validators recommendation since human performance tools are always used by operators. Changed to test on a specific exemption for Procedures 0-EN-HU-106 and 1.10 listed in Procedure 2.0.1.2.

Question 74 IAW Procedure 2.0.1.2 [Operations Procedure Policy],

Subsequent actions in Abnormal and Emergency Procedures are classified as (1) Use.

AND Procedure 1.10 [Control of Documents] requirements to verify revision (2) waived during Abnormal or Emergency Procedure response.

A. (1) Reference (2) is B. (1) Reference (2) is NOT C. (1) Continuous (2) is D. (1) Continuous (2) is NOT Answer: C Explanation:

This question satisfies the K/A because it tests general requirements associated with AOP and EP usage. EPs are similar to AOPs and are not the same as EOP Flowcharts at CNS.

219

Procedure 2.0.1.2 Step 6.1.1 states APs and EPs shall be classified as Continuous Use. The exception to Continuous Use is when performing Immediate Operator Actions from memory.

Procedure 2.0.1.2 step 6.1.4 states: Procedures 0-EN-HU-106 and 1.10 requirements to verify revision is waived during an unanticipated plant transient and AP/EP response.

Distracters:

Answer A part 1 is plausible because immediate operator actions are not classified as Continuous use but are treated as Reference Use in that they are required to be subsequently verified with the applicable procedure. This answer is wrong because subsequent actions are required to be performed as Continuous Use with procedure in hand and in the order listed. Part 2 is correct Answer B is plausible and wrong for the same reason given for distractor A. Part 2 is plausible because Procedures 1.10 and 0-EN-HU-106 are applicable to all procedures, unless specifically exempted. The examinee who does not remember the exemption to verifying revision for APs/EPs in may choose this answer. This answer is wrong because Procedure 2.0.1.2 step 6.1.4 states verification of revision per Procedure 1.10 for APs/Eps is waived.

Answer D part 1 is correct. Part 2 is plausible and wrong for the same reason given for distractor B.

Technical

References:

Procedure 2.0.1.2 [Operations Procedure Policy] (Rev 50),

Procedure 0-EN-HU-106 [Procedure and Work Instruction Use and Adherence] (Rev 3C2), Procedure 1.10 [Control of Documents] (Rev 33)

References to be provided to applicants during exam: none Learning Objective: INT032-01-01 EO-R1a, Discuss the following as described in 2.0.1.2, Operations Procedure Policy: Operations Procedure Use; R1e, Abnormal and Emergency Procedures Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10) 220

Level of Difficulty: 3 SRO Only Justification: N/A PSA Applicability:

N/A 221

Examination Outline Cross-Reference Level RO G2.4.5 Knowledge of the organization of the Tier# 3 operating procedures network for normal, abnormal, Group#

and emergency evolutions K/A # G2.4.5 (CFR: 41.10 / 43.5 / 45.13) Rating 3.7 Revision 3 Revision Statement: Rev 1 - Per CE comments, replaced original question with a new one.

Rev 2 - Replaced question again because ROs are not qualified as communicators, as previously and erroneously thought. Changed to test a specific duty for which ROs are responsible.

Rev 3 - Per CE comments, replaced K/A G2.4.39 with G2.4.5 and replaced question with a new one.

(Changed correct answer from C to B)

Question 75 The Emergency Procedure numeric series for individual piping system emergencies is .

A. 5.1 B. 5.2 C. 5.3 D. 5.4 Answer: B Explanation:

This question satisfies the K/A because it tests knowledge of the organization of the operating procedure network for Emergency Procedures.

Procedure 2.0.1.2 Step 6.1.3 lists the numeric-alpha numbering scheme for Emergency Procedures as follows:

5.1 series typically address whole plant or large area emergencies.

5.2 series typically address individual piping system emergencies.

5.3 series typically address electrical system emergencies.

5.4 series typically address fire emergencies.

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5.5 series typically address security emergencies.

Distracters:

Answer A is plausible because it reflects an Emergency Procedure numeric series.

This answer is wrong because 5.1 is the Emergency Procedure numeric series for whole plant or large area emergencies.

Answer C is plausible because it reflects an Emergency Procedure numeric series.

This answer is wrong because 5.3 is the Emergency Procedure numeric series for electrical system emergencies.

Answer D is plausible because it reflects an Emergency Procedure numeric series.

This answer is wrong because 5.4 is the Emergency Procedure numeric series for fire emergencies.

Technical

References:

Procedure 2.0.1.2 [Operations Procedure Policy] (Rev 50)

References to be provided to applicants during exam: none Learning Objective: INT032-01-01 EO-18.a.5, Discuss the following as described in 2.0.1.2, Operations Procedure Policy: Operations Procedure Use; Abnormal and Emergency Procedures Question Source: Bank #

(note changes; attach parent) Modified Bank #

New X Question Cognitive Level: Memory/Fundamental X Comprehensive/Analysis 10CFR Part 55 Content: 55.41(b)(10)

Level of Difficulty: 2 SRO Only Justification: N/A PSA applicability:

N/A 223

2021-6 NRC Written Exam Specific References to be provided to examinee:

RO Q#11 EOP Graph 10 [Pressure Suppression Pressure]

RO Q#15 EOP Vortex Limits (Graphs 4A,B 6A,B)

RO Q#22 2.4PC [Primary Containment Control] Attachment 1 [Primary Containment Relative Humidity] (Rev 21)

Provided Reference for Question #11 Provided Reference for Question #15 Provided Reference for Question #22