Text

Initial Exam 2010-301 Draft SRO Written Exam
	ML101590078
Person / Time
Site:	Brunswick
Issue date:	05/03/2010
From:	; NRC/RGN-II
To:	; Progress Energy Carolinas
References
	50-324/10-301, 50-325/10-301
	Download: ML101590078 (122)
	v • d • e

76. Which one of the following correctly completes the statement below?

Technical Specifications do NOT require the RWCU isolation from the SLC control switch in Mode (1) due to (2)

A (1) 3 (2) control rods are not able to be withdrawn since the reactor mode switch must be in the shutdown position and a control rod block is applied B. (1)3 (2) the operability of each individual control rod scram accumulator is required which will ensure that the control rods can be inserted C. (1)5 (2) control rods are not able to be withdrawn since the reactor mode switch must be in the shutdown position and a control rod block is applied D. (1)5 (2) the operability of each individual control rod scram accumulator is required which will ensure that the control rods can be inserted Feedback K/A: 204000 G2.02.25 Knowledge of the bases in Technical Specifications for limiting conditions for operations and safety limits.

Reactor Water Cleanup System (CFR: 41.5 / 41.7 /43.2)

There are no safety limits associated with RWCU system, so question is written directly to the TS.

ROISRO Rating: 3214.2 Objective:

Reference:

Cog Level: Low Explanation: Are no safety limits for RWCU. SLC is required in mode 3 (RO knowledge) and the bases for the mode 3 requirement is SRO knowledge.

Distractor Analysis:

Choice A: Correct answer from the bases document.

Choice B: Plausible becasue this is the bases for Mode 4/5 from the bases document.

Choice C:

Choice D: Plausible because the scram accumulators are capable of inserting the control rods with low reactor pressure conditions, but the accumulators are not required to be operable in Mode 3.

SRO Basis: 10 CFR 55.43(b)-2, Facility operating limitations in the TS and their bases.

Knowledge of TS bases that is required to analyze TS required actions and terminology.

76. Which one of the following correctly completes the statement below?

Technical Specifications do NOT require the RWCU isolation from the SLC control switch in Mode (1) due to (2)

A!I (1) 3 (2) control rods are not able to be withdrawn since the reactor mode switch must be in the shutdown position and a control rod block is applied B. (1) 3 (2) the operability of each individual control rod scram accumulator is required which will ensure that the control rods can be inserted C. (1) 5 (2) control rods are not able to be withdrawn since the reactor mode switch must be in the shutdown position and a control rod block is applied D. (1) 5 (2) the operability of each individual control rod scram accumulator is required which will ensure that the control rods can be inserted Feedback KIA: 204000 G2.02.25 Knowledge of the bases in Technical Specifications for limiting conditions for operations and safety limits.

Reactor Water Cleanup System (CFR: 41.5/41.7/43.2)

There are no safety limits associated with RWCU system, so question is written directly to the TS.

RO/SRO Rating: 3.2/4.2 Objective:

Reference:

Cog Level: Low Explanation: Are no safety limits for RWCU. SLC is required in mode 3 (RO knowledge) and the bases for the mode 3 requirement is SRO knowledge.

Distractor Analysis:

Choice A: Correct answer from the bases document.

Choice B: Plausible becasue this is the bases for Mode 4/5 from the bases document.

Choice C:

Choice D: Plausible because the scram accumulators are capable of inserting the control rods with low reactor pressure conditions, but the accumulators are not required to be operable in Mode 3.

SRO Basis: 10 CFR 55.43(b)-2, Facility operating limitations in the TS and their bases.

Knowledge of TS bases that is required to analyze TS required actions and terminology.

Notes RECTC MODE AVERA3E REACTOR MDDE TTLE S1TCH POSfIICN COOLANT EMPERTURE (F:

1 Pr Cperatbn Run 2

S1aiup Reftle? o-SatupHot NA Sanby 3

Hot hutdon Sutcii

> 21.2 4

Cold Sutdcn

iuchr, 212 5

Reje1g Sttubcii or ReieI From Bases 3.3.6.1 One channel of the SLC System Initiation Function is available and required to be OPERABLE only in MODES 1 and 2, since these are the only MODES where the reactor can be critical, and these MODES are consistent with the Applicability for the SLC System (LCO 3.1.7).

From bases 3.1.7 APPLICABILITY In MODES I and 2, shutdown capability is required. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in the shutdown position and a control rod block is applied. This provides adequate controls to ensure that the reactor remains subcritical. In MODE 6, only a single control rod can be withdrawn from a core cell containing fuel assemblies. Determination of adequate SDM (LCD 3.1.1, SHUTDOWN MARGIN (SDM)) ensures that the reactor will not become critical with the analytically determined strongest control rod withdrawn.

Therefore, the SLC System is not required to be OPERABLE when only a single control rod can be withdrawn.

Categories K/A:

204000 G2.02.25 Tier / Group:

T2G2 RO Rating:

3.2 SRO Rating:

4.2 LP Obj:

05-11 Source:

NEW Cog Level:

LOW Category 8:

Notes RE~.CTOR MODE AVERIo.GE REACTOR MODE TiTLE SWlTCH POSfllON COOLANTIEMPERA Th'RE

(=-l-t,,'

1 P'))VI,'Er Operatoo Run N."'.

2 Slartup Refuer"'),or S;,artup;'HD1 Nt.!;.

S1aoooji 3

Hot Shutdall.m'1I)

Shutdb~\\T1

>2'&2 4

Cold Silub:i'o\\'ltnt*,

Sh,utdbltn S; 21:2 5

RefueEflg(ll1 From Bases 3.3.6.1 From bases 3.1.7 APPLICABILITY Categories Silutdoltn or R~ilel NI!...

One channel of the SLC System Initiation Function is available and required to be OPERA.BLE only in MODES 'I and 2, since these are the only MODES where the reactor can be critical, and these MODES are consistent with the Applicability for the SLC System (LCO 3.'1.7).

[n MODES 'I and 2, shutdown capability is required. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in the shutdown position and a control rod block is applied. This provides adequate controls to ensure that the reactor remains sub criticaL In MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies. Determination of adequate SDM {LCO 3. '1.'1,

"SHUTDOWN MARGIN (SDM}") ensures that the reactor... vill not become critical with the analytically determined strongest control rod withdrawn.

Therefore, the SLC System is not required to be OPERA.BLE when only a single control rod can be withdrawn.

KIA:

204000 G2.02.25 Tier / Group: T2G2 RORating:

3.2 SRORating

4.2 LP Obj:

05-11 Source:

NEW Cog Level:

LOW Category 8:

77. Unit One is operating at full power when the following plant conditions occur:

- Load Reject Signal received

- Line 31 (Whiteville Line) PCBs red lights are lit

- Line 31 (Whiteville Line) white VOLT lights are not lit

- All other line PCBs green lights are lit

- 230 KV BUS IA BUS POT UNDERVOLTAGE is in alarm

- 230 KV BUS lB BUS POT UNDERVOL TAGE is in alarm Which one of the following identifies the initial RPS trip signal and the procedure which contains the guidance to trip the Whiteville Line PCBs?

A Control Valve Fast Closure; OAOP-36.1, Loss of Any 4160V Buses or 480V E-Buses.

B. Stop Valve Closure; OAOP-36. 1, Loss of Any 41 60V Buses or 480V E-Buses.

C. Control Valve Fast Closure; OAOP-22, Grid Instability.

D. Stop Valve Closure; OAOP-22, Grid Instability.

77. Unit One is operating at full power when the following plant conditions occur:

- Load Reject Signal received

- Line 31 (Whiteville Line) PCBs red lights are lit

- Line 31 (Whiteville Line) white VOLT lights are not lit

- All other line PCBs green lights are lit

- 230 KV BUS 1A BUS POT UNDER VOL TAGE is in alarm

- 230 KV BUS 1B BUS POT UNDERVOLTAGE is in alarm Which one of the following identifies the initial RPS trip signal and the procedure which contains the guidance to trip the Whiteville Line PCBs?

A'I Control Valve Fast Closure; OAOP-36.1, Loss of Any 4160V Buses or 480V E-Buses.

B. Stop Valve Closure; OAOP-36.1, Loss of Any 4160V Buses or 480V E-Buses.

C. Control Valve Fast Closure; OAOP-22, Grid Instability.

D. Stop Valve Closure; OAOP-22, Grid Instability.

Feedback K/A: 212000 A2.12 Ability to (a) predict the impacts of the following on the REACTOR PROTECTION SYSTEM ; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations:

Main turbine stop control valve closure (CFR: 41.5/ 45.6)

RO/SRO Rating: 4.0/4.1 Objective: CLS-LP-03, Obj. 8.

List the RPS trip signals, including setpoints and how/when each signal is bypassed.

Reference:

SD-03 Reactor Protection System, section 3.1 RPS Trips Cog Level High Explanation:

A load reject signal at any reactor power level will cause a turbine control valve fast closure scram. The load reject signal does not input into the turbine stop valve closure scram logic. During a loss of offsite power, if the grid is lost all PCBs are opened per OAOP-36. 1.

Distractor Analysis:

Choice A: Correct answer, see explanation Choice B: Incorrect Load reject initiates a TCV fast closure scram not a TSV. A misconception of the difference between TCV and TSV scrams may cause a student to select this answer.

Choice C: Incorrect. OAOP-22 does not have an action for loss of grid only for degraded.

Choice D: Incorrect. Load reject initiates a TCV fast closure scram not a TSV. A misconception of the difference between TCV and TSV scrams may cause a student to select this answer. OAOP-22 does not have an action for loss of grid only for degraded.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Feedback KIA: 212000A2.12 Ability to (a) predict the impacts of the following on the REACTOR PROTECTION SYSTEM; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations:

Main turbine stop control valve closure (CFR: 41.5 145.6)

RO/SRO Rating: 4.0/4.1 Objective: CLS-LP-03, Obj. 8.

List the RPS trip signals, including setpoints and how/when each signal is bypassed.

Reference:

SD-03 Reactor Protection System, section 3.1 RPS Trips Cog Level High Explanation:

A load reject signal at any reactor power level will cause a turbine control valve fast closure scram. The load reject signal does not input into the turbine stop valve closure scram logic. During a loss of offsite power, if the grid is lost all PCBs are opened per OAOP-36.1.

Distractor Analysis:

Choice A: Correct answer, see explanation Choice B: Incorrect Load reject initiates a TCV fast closure scram not a TSV. A misconception of the difference between TCV and TSV scrams may cause a student to select this answer.

Choice C: Incorrect. OAOP-22 does not have an action for loss of grid only for degraded.

Choice D: Incorrect. Load reject initiates a TCV fast closure scram not a TSV. A misconception of the difference between TCV and TSV scrams may cause a student to select this answer. OAOP-22 does not have an action for loss of grid only for degraded.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Notes An example of Turbine Control Valve Fast Closure is a load reject.

The definition of a load reject is greater than 40% mismatch between electrical output and mechanical input as sensed by generator stator amps and the Cross Around Piping pressure. This is to prevent excessive overspeed of the Turbine on loss of load.

A load reject signal will energize the fast acting Solenoid Valves on the control valve actuators, which removes hydraulic trip fluid pressure. The trip signal comes from pressure switches on the Vast acting trip control (FATC) supply to the control valve disc dumps (refer to EHC Hydraulics). Loss of this pressure will cause a rapid closure of the control valves. Circuitry is designed such that the pressure switch on either control valve 1 or 3 will trip RPS Trip System A. Either control valve 2 or 4 will trip RPS Trip System B.

These switches will also provide a Scram signal on loss of hydraulic trip fluid pressure when a load reject signal is not present - loss of hydraulic fluid pressure can result in a fast closure of the control valves SD-03 Rev. 9 Page 21 of 89 7.

IF the SAT was lost due to loss of power on the Progress Energy System, THEN PERFORM the following:

a.

PLACE AUTO RELOSE switches in MANUAL.

LI b.

PLACE transmission line PCB SUPERVISORY LOCAL/REMOTE switches in LOCAL.

c, TRIP all transmission line PCBs.

LI OAOP-36.2 Rev.

I Page 4 of 196 Categories K/A:

212000 A2.12 Tier / Group:

T2G1 RO Rating:

4.0 SRO Rating:

4.1 LP Obj:

03-08 Source:

PREV Cog Level:

HIGH Category 8:

Y Notes 1 SD-03 An example of Turbine Control Valve Fast Closure is a load reject.

The definition of a load reject is greater than 40% mismatch betvveen electrical output and mechanical input as sensed by generator stator amps and the Cross Around Piping pressLire. This is to prevent excessive overs peed of the Turbine on loss of load.

A load reject signal will energize the fast acting Solenoid Valves on the control valve actuators, which removes hydraulic trip fluid pressure. The trip signal comes from pressure switches on the fast acting trip control (FATC) supply to the control valve disc dumps (refer to EHC Hydraulics). Loss of this pressure will cause a rapid closure of the control valves. Circuitry is designed such that the pressure switch on either control valve 'lor 3 Will trip RPS Trip system A. Either control valve 2 or 4 will trip RPS Trip System B.

These switches will also provide a Scram signal on loss of hydraulic trip fluid pressure when a load reject signal is not present - loss of hydraulic fluid pressure can result in a fast closure of the control valves.

Rev. 9 Page 2'1 of 891 7,

IF tile SAT was lost due to loss of power on the Progress Energy System, THEN PERFORM the following:

a.

.PLACE AUTO RECLOSE switches in MANUAL.

D

b.

PLACE transmission line PCB SUPERVISORY D

LOCAUREMOTE switches in LOCAL

c.

TRIP all transmission line PCBs.

D IOAOP-36.2 Rev. 4'1 Page 4 of 1961 Categories KIA:

212000 A2.12 RO Rating:

4.0 LP Obj:

03-08 Cog Level:

HIGH Tier / Group: T2G 1 SRO Rating:

4.1 Source

PREY Category 8:

Y

78. The Unit is at 7% power during reactor startup.

The operator withdraws control rod 26-27 to position 48.

The following indications are noted:

- ROD DRIFT alarm seals in

- ROD OVER TRAVEL alarm seals in

- Rod 26-27 full core display red light out Which one of the following identifies:

(1) the indication that would be displayed on the four-rod group display and (2) the required action for the inoperable control rod lAW Technical Specification 3.1.3, Control Rod Operability?

A. (1)48 (2) Fully insert control rod 26-27 and disarm the HCU B. (1)48 (2) Verify 1 2 control rods are withdrawn and implement GP-1 1, Second Operator Rod Sequence Checkoff Sheets C (1) Blank (2) Fully insert control rod 26-27 and disarm the HCU D. (1) Blank (2) Verify 1 2 control rods are withdrawn and implement GP-1 1, Second Operator Rod Sequence Checkoff Sheets

78. The Unit is at 7% power during reactor startup.

The operator withdraws control rod 26-27 to position 48.

The following indications are noted:

- ROD DRIFT alarm seals in

- ROD OVER TRAVEL alarm seals in

- Rod 26-27 full core display red light out Which one of the following identifies:

(1) the indication that would be displayed on the four-rod group display and (2) the required action for the inoperable control rod lAW Technical Specification 3.1.3, Control Rod Operability?

A. (1) 48 (2) Fully insert control rod 26-27 and disarm the HCU B. (1) 48 (2) Verify ~12 control rods are withdrawn and implement GP-11, Second Operator Rod Sequence Checkoff Sheets C!I (1) Blank (2) Fully insert control rod 26-27 and disarm the HCU D. (1) Blank (2) Verify ~12 control rods are withdrawn and implement GP-11, Second Operator Rod Sequence Checkoff Sheets

Feedback K/A: 214000 A2.03 Ability to (a) predict the impacts of the following on the ROD POSITION INFORMATION SYSTEM; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations:

Overtravel/in-out (CFR: 41.5 / 45.6)

RO/SRO Rating: 3.6/3.9 Objective: CLS-LP-07 Obj 5b Given plant conditions, determine if the following conditions exist: b. Indications of an uncoupled control rod.

Reference:

SD-07 page 27 TS 3.1.3 Cog Level Low Explanation:

If the control rod is in the overtravel out position, the corresponding digital indicator will be blank since the magnet will not be near any of the 00 to 48 reed switches. lAW TS the rod is declared inoperable then inserted to 00 (within 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months ) and disarmed (within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ). TS 3.1.6 if the RWM is inoperable then if

>12 control rods are withdrawn GP-1 1 would be implemented, unless the rod is at 00 and is not intended to be moved.

Distractor Analysis:

Choice A: Plausible because the full in and 00 indications are at the same point or the exam inee may think that the rod may settle to the 48 position.

Choice B: Plausible because the full in and 00 indications are at the same point or the examinee may think that the rod may settle to the 48 position. These are TS actions for an inoperable RWM, not control rod.

Choice C: Correct answer, see explanation.

Choice D: Plausible because this is the correct indication but these are TS actions for an inoperable RWM, not control rod.

SRO Basis: 10 CFR 55.43(b)-2, Facility operating limitations in the technical specifications and their bases. Application of required actions statements.

Feedback KIA: 214000 A2.03 Ability to (a) predict the impacts of the following on the ROD POSITION INFORMATION SYSTEM; and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal conditions or operations:

Overtravel/in-out (CFR: 41.5 /45.6)

RO/SRO Rating: 3.6/3.9 Objective: CLS-LP-07 Obj 5b Given plant conditions, determine if the following conditions exist: b. Indications of an uncoupled control rod.

Reference:

SO-07 page 27 TS 3.1.3 Cog Level Low Explanation:

If the control rod is in the overtravel out position, the corresponding digital indicator will be blank since the magnet will not be near any of the 00 to 48 reed switches. lAW TS the rod is declared inoperable then inserted to 00 (within 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months ) and disarmed (within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ). TS 3.1.6 if the RWM is inoperable then if

.=::12 control rods are withdrawn GP-11 would be implemented, unless the rod is at 00 and is not intended to be moved.

Oistractor Analysis:

Choice A: Plausible because the full in and 00 indications are at the same point or the examinee may think that the rod may settle to the 48 position.

Choice B: Plausible because the full in and 00 indications are at the same point or the examinee may think that the rod may settle to the 48 position. These are TS actions for an inoperable RWM, not control rod.

Choice C: Correct answer, see explanation.

Choice 0: Plausible because this is the correct indication but these are TS actions for an inoperable RWM, not control rod.

SRO Basis: 10 CFR 55.43(b)-2, Facility operating limitations in the technical specifications and their bases. Application of required actions statements.

Notes From SD-07 Coupling integrity of a control rod shall be checked anytime a control rod is fully withdrawn by verifying that the rod does not reach the overtravel position. An uncoupling check can be performed by maintaining the continuous withdraw signal for approximately 3 to 5 seconds when the control rod has reached position 48 and verifying the control rod does not retract beyond position 48. If the rod is uncoupled, then the four rod display indication will go out for the uncoupled rod and the Rod Over Travel Annunciator A-05 4-2 will illuminate.

SD-07 Rev. 6 Page 27 of 57 C.

One or more control rods C. 1 inoperable for reasons other Inoperable control rod may than Condition A or 8.

be bypassed in the RWM or RWM may be bypassed as allowed by LCO 3.3.2.1, if required, to allow insertion of inoperable control rod and continued operation.

Fully insert inoperable 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months control rod.

AND (continued)

C.

(continued)

C.2 Disarm the associated 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months CRD.

From GP-11:

This procedure provides a method for a second licensed operator or qualified member of the plant technical staff to verify control rod movement and compliance with the prescribed BPWS control rod pattern with the rod worth minimizer (RWM) inoperable in conformance with the requirements of Technical Specification 332.1. If the RWM is inoperable due to bypassed control rod(s) that will not be moved during the startup/shutdow, then this procedure is not required.

Categories K/A:

214000 A2.03 Tier / Group:

T2G2 RO Rating:

3.6 SRO Rating:

3.9 LP Obj:

07-5B Source:

NEW Cog Level:

HIGH Category 8:

Y Notes From SD-07 Coupling integrity of a control rod st"lall be checked anytime a control rod is fully withdrawn by verifying that the rod does not reacl) the overtravel position. An uncoupling check can be performed by maintaining the continuous withdraw signal for approximately 3 to 5 seconds when the control rod t"las reached position 48 and verifying the control rod does not retract beyOnd position 48. If the rod is uncoupled, then the four rod display indication will go out for the uncoupled rod and the Rod Over Travel Annunciator A-05 4-2 will illuminate.

I SD-07 Rev.S Page 27 of 571 C.

One or more control rods C.*1 inoperable for reasons other than Condition A or B.

AND C.

(continued)

C.2 From GP-11:

NOTE--------

Inoperable control rod may be bypassed in the RWM or RWM may be bypassed as allowed bv LCO 3.3.2.1: if required, to allow insertion of inoperable control rod and continued operation.

Fully insert inoperable control rod.

Disarm the associated CRD.

3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months (continued) 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months This procedure provides a method for a second licensed operator or qualified member of the plant technical staff to verify control rod movement and compliance with the prescribed BPWS control rod pattern with the rod worth minimizer (RWM) inoperable in conformance with the requirements of Technical Specification 3.3.2.1. If the RWM is inoperable due to bypassed control rod{s) that Will not be moved during the startup/shutdown, then this procedure is not required.

Categories KIA:

214000 A2.03 Tier / Group: T2G2 RORating:

3.6 SRORating

3.9 LPObj

07-SB Source:

NEW Cog Level:

HIGH Category 8:

Y

79. Given the following ATWS conditions on Unit Two:

2A CRD Pump Overcurrent trip 2B CRD Pump Shaft uncoupled HPCI System Under Clearance SLC Both squib valves failed to fire RCIC Running with an unisolable steam supply leak Suppression Pool Level

-24 inches Reactor Power 10%

Reactor Water Level 160 inches Which one of the following identifies the action that would be taken concerning the RCIC system based on the conditions above?

The RCIC system would:

A. be isolated to secure the source of the steam leak lAW OAOP-05.0, Radioactive Spills, High Radiation, and Airborne Activity.

B. have the high suppression pool water level transfer defeated and its suction transferred back to the CST lAW SEP-i 0, Circuit Alterations Procedure.

C remain running because it is needed for boron injection lAW LEP-03, Alternate Boron Injection.

D. be terminated and prevented to reduce level to 90 inches lAW LPC.

79. Given the following ATWS conditions on Unit Two:

2A CRD Pump 2B CRD Pump HPCI System SLC RCIC Suppression Pool Level Reactor Power Reactor Water Level Overcurrent trip Shaft uncoupled Under Clearance Both squib valves failed to fire Running with an unisolable steam supply leak

-24 inches 10%

160 inches Which one of the following identifies the action that would be taken concerning the RCIC system based on the conditions above?

The RCIC system would:

A. be isolated to secure the source of the steam leak lAW OAOP-05.0, Radioactive Spills, High Radiation, and Airborne Activity.

B. have the high suppression pool water level transfer defeated and its suction transferred back to the CST lAW SEP-1 0, Circuit Alterations Procedure.

C~ remain running because it is needed for boron injection lAW LEP-03, Alternate Boron Injection.

D. be terminated and prevented to reduce level to 90 inches lAW LPC.

Feedback K/A: 217000 G2.04.08 Knowledge of how abnormal operating procedures are used in conjunction with EOPs.

Reactor Core Isolation Cooling System (RCIC)

(CFR: 41.10/43.5/45.13)

ROISRO Rating: 3.8/4.5 Objective: CLS-LP-300-J Obj 4 Given plant conditions and a copy of the LEPs, determine which method of alternate boron injection is appropriate.

Reference:

AOP-50/SCCP/LEP-03/LPC Cog Level high Explanation: EOP action that supercedes the AOP action is what the question is asking.

AOP-5 does have a step to isolate the system that is leaking, but SCCP overrides that if the system is required by EOPs. With the ATWS the RCIC system is required for alternate boron injection. The Suppression Pool level is high but this will only transfer the HPCI suction valves as RCIC only transfers on CST level. LEP-03 would first want to use CRD then RCIC as long as suction is from CST.

Distractor Analysis:

Choice A: Plausible because AOP-5 does have a step to isolate the system that is leaking, but SCCP overrides that if the system is required by EOPs.

Choice B: Plausible because the high suppression pool level would transfer HPCI and SEP-10 has a section for transferring the suction to the CST from the Suppression Pool.

Choice C: Correct answer, see explanation Choice D: Plausible becasue LPC does have a step for terminating and preventing but this does not address RCIC.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Feedback KIA: 217000 G2.04.08 Knowledge of how abnormal operating procedures are used in conjunction with EOPs.

Reactor Core Isolation Cooling System (RCIC)

(CFR: 41.10/43.5/45.13)

RO/SRO Rating: 3.8/4.5 Objective: CLS-LP-300-J Obj 4 Given plant conditions and a copy of the LEPs, determine which method of alternate boron injection is appropriate.

Reference:

AOP-50 1 SCCP 1 LEP-03 1 LPC Cog Level high Explanation: EOP action that supercedes the AOP action is what the question is asking.

AOP-5 does have a step to isolate the system that is leaking, but SCCP overrides that if the system is required by EOPs. With the A TWS the RCIC system is required for alternate boron injection. The Suppression Pool level is high but this will only transfer the HPCI suction valves as RCIC only transfers on CST level. LEP-03 would first want to use CRD then RCIC as long as suction is from CST.

Distractor Analysis:

Choice A: Plausible because AOP-5 does have a step to isolate the system that is leaking, but SCCP overrides that if the system is required by EOPs.

Choice B: Plausible because the high suppression pool level would transfer HPCI and SEP-10 has a section for transferring the suction to the CST from the Suppression Pool.

Choice C: Correct answer, see explanation Choice D: Plausible becasue LPC does have a step for terminating and preventing but this does not address RCIC.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Notes Actions from AOP-05.O 1.

INITIATE a search to locate and isolate the source of any fl coolant or steam leak.

2.

IF radiography is in progress, AND personnel are in D

danger of abnormal exposure, THEN SECURE radiography.

3.

ENSURE all personnel in the area monitor their dosimetry and report unusual exposure to E&RC.

OAOP-05.C Rev. 23 Page 6 of 10 From SCCP has the actions to leave the system running:

ISOLATE ALL SYSTEMS DISCHARGING INTO THE AREA EXCEPT SYSTEMS REQUIRED:

TO BE OPERATED BYAN EMERGENCY OPERATING PROCEDURE

FOR DAMAGE CONTROL I

SCCP-14 From LEP-03 A

NOTE:

HPCI/RCIC should be used only if suction is from the CST A

From LPC, RCIC is not on list to Terminate and prevent (HPCI is):

LOWER REATQR WATER LEVEL J!UEsrECTIvE OF ANY REACTOR POWER OR REACTOR WATER LEVELOSCILLATIONS ry TERMflIAJ1NO AND P4flTMflN tNJFCTIOU FRCM TIlE FOLLO%1NG SYSTE1S UNLESS THE SYSTEM IS SEINO USED IO NJEC1 CORON

GQNDENSATEFEECWATER

NPCI

RHR

CORE SPRAY

ALTERNATE COCL?.NT NJTCtIflN YTPM!

RC)L-17 Categories KJA:

217000 G2.04.08 Tier! Group:

T2G1 RO Rating:

3.8 SRO Rating:

4.5 LP Obj:

300J-4 Source:

NEW Cog Level:

HIGH Category 8:

Y Notes Actions from AOP-05.0

1.

2.

3.

INITIATE a search to locate and isolate the source of any coolant or steam leak.

IF radiography is in progress, AND personnel are in danger of abnormal exposure, THEN SECURE radiography.

ENSURE all personnel in the area monitor their dosimetry and report unusual exposure to E&RC.

o o

o IOAOP-05.0 Rev. 23 Page 6 of"10 I From SCCP has the actions to leave the system running:

ISOLATE ALL SYSTEMS DISCHARGING INTO THE AREA EXCEPT SYSTEMS REQUIRED:

TO BE OPERATED BY AN EMERGENCY OPERATING PROCEDURE

FOR DAMAGE CONTROL From LEP-03 NOTE:

HPGIIRCIC should be used only it suction is from the CST.

From LPC, RCIC is not on list to Terminate and prevent (HPCI is):

LOWEll; ReACTOR WATER LEVEL IRlIE$PEC11VE OF ANY REACTOR POWER OR REACTOR

\\VATER I.EVELOSCILLAllONS BY TI"~MIIIAliNG AND PRlilfliNTING IN.I~cnOIJ FRQM THE FOLlOVlIHG SYSTEMS UHLESSTHE

~ YSTEM IS BEING USElJ TO INJECT IIOItOH;

CO.'lDENSATelFESOWATI!R

IIPCI

' IIHR

CORESPRAY Categories KIA:

217000 G2.04.08 RORating:

3.8 LPObj

300J-4 Cog Level:

HIGH Tier / Group:

SRORating:

Source:

Category 8:

T2G1 4.5 NEW Y

80. Unit Two was operating at rated power with the following conditions:

- A dual Unit Loss Of Offsite Power (LOOP)

- Spent Fuel Pool level is lowering rapidly due to a dropped test weight

- RRCP has been entered due to high rad conditions on the refuel floor Which one of the following is the first makeup source to be used for filling the fuel pool and identifies the procedure to perform the action?

A. Emergency Diesel Makeup Pump via hoses lAW OAOP-38.0, Loss of Fuel Pool Cooling B RHR B Loop via Fuel Pool Cooling System lAW OAOP-38.0, Loss of Fuel Pool Cooling C. Emergency Diesel Makeup Pump via hoses lAW OEDMG-002, Spent Fuel Pool Makeup/Spray and Refuel Floor Enhanced Ventilation under Conditions of Extreme Damage D. RHR B Loop via Fuel Pool Cooling System lAW OEDMG-002, Spent Fuel Pool Makeup/Spray and Refuel Floor Enhanced Ventilation under Conditions of Extreme Damage

80. Unit Two was operating at rated power with the following conditions:

- A dual Unit Loss Of Offsite Power (LOOP)

- Spent Fuel Pool level is lowering rapidly due to a dropped test weight

- RRCP has been entered due to high rad conditions on the refuel floor Which one of the following is the first makeup source to be used for filling the fuel pool and identifies the procedure to perform the action?

A. Emergency Diesel Makeup Pump via hoses lAW OAOP-38.0, Loss of Fuel Pool Cooling B!'" RHR B Loop via Fuel Pool Cooling System lAW OAOP-38.0, Loss of Fuel Pool Cooling C. Emergency Diesel Makeup Pump via hoses lAW OEDMG-002, Spent Fuel Pool Makeup/Spray and Refuel Floor Enhanced Ventilation under Conditions of Extreme Damage D. RHR B Loop via Fuel Pool Cooling System lAW OEDMG-002, Spent Fuel Pool Makeup/Spray and Refuel Floor Enhanced Ventilation under Conditions of Extreme Damage

Feedback K/A: 233000 G2.04.06 Knowledge of EOP mitigation strategies.

Fuel Pool Cooling and Clean-up (CFR: 41.10/43.5/45.13)

There are no direct EOP actions associated with FPC, a loss of level in the fuel pool will cause entty into RRCP which is an EOP. So these actions are mitigation strategies to RRCP.

RO/SRO Rating: 3.7/4.7 Objective:

CLS-LP-1 3, Obj. 11. State the sources of makeup water for the Fuel Pool in order of preference.

Reference:

OAOP-38.0 Loss of Fuel Pool Cooling Cog Level High Explanation:

The order of the makeup sources is from the normal fill, Demin water hose stations, Fire protection hose stations, demin water through RHR keepfill, and then other sources that are not service water. For a high capacity water source and the gates installed RHR Loop B would be used via the FPC system. With a LOOP the demin pumps have no power. If no other sources are availble then the proceudre has injection from the EDMP.

Distractor Analysis:

Choice A: Plausible because although this is a makeup source it is not the preferred source (last resort per the procedure) and is performed per the EDMG procedures. Although upon entering the AOP there is a step to start lining this system up for injection because of the time required to get all of the hoses run in the procedure up to the fuel pool.

Choice B: Correct answer see explanation Choice C: Plausible because although this is a makeup source it is not the preferred source (last resort per the procedure). Although upon entering the AOP there is a step to start lining this system up for injection because of the time required to get all of the hoses run in the procedure up to the fuel pool.

Choice D: Plausible because RHR is the high capacity source that will need to be used, but the EDMG procedure does not provide this guidance.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Feedback KIA: 233000 G2.04.06 Knowledge of EOP mitigation strategies.

Fuel Pool Cooling and Clean-up (CFR: 41.10/43.5/45.13)

There are no direct EOP actions associated with FPC, a loss of level in the fuel pool will cause entry into RRCP which is an EOP. So these actions are mitigation strategies to RRCP.

RO/SRO Rating: 3.7/4.7 Objective:

CLS-LP-13, Obj. 11. State the sources of makeup water for the Fuel Pool in order of preference.

Reference:

OAOP-38.0 Loss of Fuel Pool Cooling Cog Level High Explanation:

The order of the makeup sources is from the normal fill, Demin water hose stations, Fire protection hose stations, demin water through RHR keepfill, and then other sources that are not service water. For a high capacity water source and the gates installed RHR Loop B would be used via the FPC system. With a LOOP the demin pumps have no power. If no other sources are availble then the proceudre has injection from the EDMP.

Distractor Analysis:

Choice A: Plausible because although this is a makeup source it is not the preferred source (last resort per the procedure) and is performed per the EDMG procedures. Although upon entering the AOP there is a step to start lining this system up for injection because of the time required to get all of the hoses run in the procedure up to the fuel pool.

Choice B: Correct answer see explanation Choice C: Plausible because although this is a makeup source it is not the preferred source (last resort per the procedure). Although upon entering the AOP there is a step to start lining this system up for injection because of the time required to get all of the hoses run in the procedure up to the fuel pool.

Choice 0: Plausible because RHR is the high capacity source that will need to be used, but the EDMG procedure does not provide this guidance.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Notes 2.

IMMEDIATELY ENTER OEDMG-002, Spent Fuel Pool Makeup/Spray and Enhanced Refuel Floor Ventilation Under Conditions of Extreme Damage, AND make preparations to makeup to the fuel pool using the EDMP.

3.2.12 IF a high capacity makeup source of water through the RI-IR System is required to maintain fuel pool level AND the fuel pool gates are installed, THEN PERFORM the following:

CONFIRM one of the following ow paths available for use with the Fuel Pool Cooling System:

RHR Loop B only (RHR Loop B Shutdown Cooling must be secured)

RHR Loop A through RHR Loop Cross-Tie to the RHR Loop B discharge. (Both RHR Loop A and Loop B Shutdown Cooling must be secured).

QAOP-38.O Rev. 22 Page 11 of 35 Actions for Emergency Diesel Makeup Pump:

3.2.19 IF no actions have been successful, THEN ENTER LI OEDMG-OD2, Spent Fuel Pool Makeup/Spray and Refuel Floor Enhanced Ventilation under Conditions of Extreme Damage.

From EMG-002:

3.3 Normal fuel pool makeup methods and the B.5.b requirement for a diverse internal strategy (using installed plant equipment) are contained in OAOP-38.O, Loss of Fuel Pool Cooling. OEDMG-002 is entered when the methods contained in OAOP-38.O have proven to be inadequate or cannot be performed.

Categories K/A:

233000 G2.04.06 Tier / Group:

T2G2 RO Rating:

3.7 SRO Rating:

4.7 LPObj

13-11 Source:

NEW Cog Level:

HIGH Category 8:

LI Li Notes

2.

3.2:12

1.

IMMEDIATELY ENTER OEDMG-002, Spent Fuel Pool Makeup/Spray and Enhanced Refuel Floor Ventilation Under Conditions of Extreme Damage, AND make preparations to makeup to the fuel pool using the EDfvIP.

IF a high capacity makeup source of water through the RHR System is required to maintain fuel pool level AND tt1e fuel pool gates are installed, THEN PERFORM tile following:

CONFIRM one of the following flow paths available for use with the Fuel Pool Cooling System:

D RHR Loop B only (RHR Loop 6 Shutdown Cooling D

must be secured)

RHR Loop A through RHR Loop Cross-Tie to the D

RHR Loop 6 discharge. (60th RHR Loop A and Loop 6 Shutdown Cooling must be secured).

IOAOP-38.0 Rev. 22 Page 1-1 of 351 Actions for Emergency Diesel Makeup Pump:

3.2:19 From EMG-002:

IF no actions have been successful, THEN ENTER OEDMG-002, Spent Fuel Pool Makeup/Spray and Refuel Floor Enhanced Ventilation under Conditions of Extreme Damage.

D 3.3 Normal fuel pool makeup methods and the 6.S.b requirement for a diverse internal strategy (using installed plant eqUipment) are contained in OAOP-38.0, Loss of Fuel Pool Cooling. OEDMG-002 is entered when the methods contained in OAOP-38.0 have proven to be inadequate or cannot be performed.

Categories KIA:

233000 G2.04.06 Tier / Group: T2G2 RORating:

3.7 SRORating

4.7 LPObj:

13-11 Source:

NEW Cog Level:

HIGH Category 8:

81. With Unit Two at rated power, which one of the following identifie (1) the required number of operable SRVs for safety function lAW Technical Specification 3.4.3, Safety/Relief Valves and (2) the bases for this number of operable SRVs?

A. (1)9 (2) prevent overpressurization associated with an ATWS event B (1) 10 (2) prevent overpressurization associated with an ATWS event C. (1)9 (2) prevent overpressurization associated with an MSIV closure D. (1)10 (2) prevent overpressurization associated with an MSIV closure Feedback K/A: 239002 G2.02.25 Knowledge of the bases in Technical Specifications for limiting conditions for operations and safety limits.

Safety Relief Valves (CFR: 41.5 / 41.7/43.2)

ROISRO Rating: 3.2/4.2 Objective: CLS-LP-25, Obj. 10 Given plant conditions and TS, including the Bases, TRM, ODCM, and COLR determine the required actions to be taken in accordance with TS associated with the Reactor Recirculation System. (SRO only)

Reference:

TS 3.4.3 and bases document Cog Level Low Explanation:

TS 3.4.3 states 10 must be operational for the safety function, the bases states the reason, ATWS.

Distractor Analysis:

Choice A: Plausible because the bases states that 9 are required for the MSIV closure.

Choice B: Correct answer, see explanation Choice C: Plausible because the bases states that 9 are required for the MSIV closure and the MSIV closure is not the binding failure mode.

Choice D: Plausible because 10 are required for the ATWS and the MSIV closure is not the binding failure mode.

SRO Basis: 10 CFR 55.43(b)-2, Facility operating limitations in the technical specifications and their bases. This is knowledge of tech spec bases to determine the reason 10 are required.

81. With Unit Two at rated power, which one of the following identifies:

(1) the reql:lired number of operable SRVs for safety function lAW Technical Specification 3.4.3, Safety/Relief Valves and (2) the bases for this number of operable SRVs?

A. (1) 9 (2) prevent overpressurization associated with an ATWS event B!'" (1) 10 (2) prevent overpressurization associated with an ATWS event C. (1) 9 (2) prevent overpressurization associated with an MSIV closure D. (1) 10 (2) prevent overpressurization associated with an MSIV closure Feedback KIA: 239002 G2.02.25 Knowledge of the bases in Technical Specifications for limiting conditions for operations and safety limits.

Safety Relief Valves (CFR: 41.5/41.7/43.2)

RO/SRO Rating: 3.2/4.2 Objective: CLS-LP-25, Obj. 10 Given plant conditions and TS, including the Bases, TRM, ODCM, and COLR determine the required actions to be taken in accordance with TS associated with the Reactor Recirculation System. (SRO only)

Reference:

TS 3.4.3 and bases document Cog Level Low Explanation:

TS 3.4.3 states 10 must be operational for the safety function, the bases states the reason, ATWS.

Distractor Analysis:

Choice A: Plausible because the bases states that 9 are required for the MSIV closure.

Choice B: Correct answer, see explanation Choice C: Plausible because the bases states that 9 are required for the MSIV closure and the MSIV closure is not the binding failure mode.

Choice D: Plausible because 10 are required for the ATWS and the MSIV closure is not the binding failure mode.

SRO Basis: 10 CFR 55.43(b)-2, Facility operating limitations in the technical speCifications and their bases. This is knowledge of tech spec bases to determine the reason 10 are required.

Notes 3.4.3 Safetv?Rehef Valves (SRVs)

LCO 3.4.3 The safety function of 10 SRVs shall be OPERASLE.

APPUCABILITY:

MODES 1. 2. and 3.

From the Bases document:

APPLICABLE The overpressure protection system must accommodate the most SAFETY ANALYSES severe pressunzattan transient EvaIatioi aac1eterrnined that the rnoLseere4ransient icioit1flar&fres (MP7 fIod by readorscrt n

1f1hr{ie fiIure of the direct scrani i+/-tdith MSIV position) (Ref. 1 For the purpose of the analyses, 9 SRVs are assumed to operate in the safety mode. The analysis results demonstrate that the design SRV capacity is capable of maintaining reactor pressure below the ASME Code limit of 110% of vessel design pressure (110% x 1250 psig 1375 psig). This LCO helps to ensure that the acceptance limit of 1375 psig is met during the Design Basis Event.

(continued APPLICABLE For overpressurization associated with an ATWS event, 10 SRVs are SAFETY ANALYSES assumed to operate in the safety mode. The analysis (Ref. 2)

(continued) results demonstrate that the design capacity is capable of maintaining reactor pressure below the ASME Section Ill Code Serice Level C limits (1500 psig).

From an overpressure standpoint, the design basis events are bounded by the overpressurization associated with the ATWS event described above. Reference 3 discusses additional events that are expected to actuate the SRVs.

SRVs satisfy Criteiion 3 of 10 CER 50.36(cX2)(ii) (Ref. 4).

Categories KJA:

239002 G2.02.25 Tier / Group:

T2G1 RO Rating:

3.2 SRO Rating:

4.2 LP Obj:

25-10 Source:

NEW Cog Level:

LOW Category 8:

Y Notes 3A.3 Safety/Relief Valves (SRVs)

LCO 3.4.3 The safety function of '10 SRVs shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

From the Bases document:

APPLICABLE The overpressure protection system must accommodate the most SAFETY ANAL YSES severe pressurization transient.

of the direct purpose of the analyses;* 9SR\\lsare assumed,tooperate.in,the safety mode. The analysis results demonstrate that the design SRV capacity is capable of maintaining reactor pressure below the ASME Code limit of 110% of vessel design pressure P'l 0% x '1250 psig = 1375 psig). This LCO helps to ensure that the acceptance limit of '1375 psig is met during the Design Basis Event.

(continued)

APPLICABLE For overpressurization associated with an A nNS event. 10 SRVs are SAFETY ANALYSES assumed to operate in the safety mode. The analysis (Ref. 2)

(continued}

results demonstrate that the design capacity is capable of maintaining reactor pressure below the ASME Section III Code Service Level C limits (1500 psig).

Categories KIA:

RORating:

LP Obj:

Cog Level:

From an overpressure standpoint, the design basis events are bounded by the overpressurization associated with the AnNS event described above. Reference 3 discusses additional events that are expected to actuate the SRVs.

SRVs satisfy Criterion 3 of '10 CFR 50.36(c){2)(ii) (Ref. 4).

239002 G2.02.25 Tier / Group: T2G1

3.2 SRORating

4.2 25-10 Source:

NEW LOW Category 8:

Y

82. Unit One is operating at full power when the Main Stack Rad Monitor lost its norm power supply.

Which one of the following identifies the procedure that contains the steps to transfer the Main Stack Rad Monitor to its alternate power supply?

A. IOP-52, 120 Volt AC UPS, Emergency, and Conventional Electrical Systems Operating Procedure B 20P-52, 120 Volt AC UPS, Emergency, and Conventional Electrical Systems Operating Procedure C. 1APP UA-03 6-3, PROCESS SMPL OG VENT PIPE DNSC/INOP D. 2APP UA-03 6-3, PROCESS SMPL OG VENT PIPE DNSC/INOP Feedback K/A: 262002 G2.0l.23 Ability to perform specific system and integrated plant procedures during all modes of plant operation.

Uninterruptable Power Supply (A.C.ID.C.)

(CFR: 41.10/43.5145.2/45.6)

ROISRO Rating: 4.3/4.4 Objective: CLS-LP-11.0, 15a Given plant conditions and a trip or failure of one of the following Radiation Monitors, determine appropriate plant response and use procedures to determine the actions required to control and/or mitigate the consequences of the event:

a. Main Stack.

Reference:

20P-52, Section 8.7, Stack Radiation Monitor UPS Power Supply Transfer Cog Level High Explanation:

The normal power supply for the Main Stack Rad Monitor is from Unit Two. On a loss of power the from the normal power supply the operators will need to transfer to the alternate power supply. This direction is only in the U2 procedure. There is no directions to perform this in the Ui procedure or the APPs for either Unit.

Distractor Analysis:

Choice A: Plausible because the stem states this is Ui but the actions are in the U2 procedure.

Choice B: Correct answer, see explanation.

Choice C: Plausible because the downscale imp annunciator will be actuated on a loss of power but the APP5 do not address transfer of power to backup supply.

Choice D: Plausible because the downscale / mop annunciator will be actuated on a loss of power but the APPs do not address transfer of power to backup supply. U2 is the normal power supply to the rad monitor.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

82. Unit One is operating at full power when the Main Stack Rad Monitor lost its normal power supply.

Which one of the following identifies the procedure that contains the steps to transfer the Main Stack Rad Monitor to its alternate power supply?

A. 10P-52, 120 Volt AC UPS, Emergency, and Conventional Electrical Systems Operating Procedure B~ 20P-52, 120 Volt AC UPS, Emergency, and Conventional Electrical Systems Operating Procedure C. 1APP UA-03 6-3, PROCESS SMPL OG VENT PIPE DNSCIINOP D. 2APP UA-03 6-3, PROCESS SMPL OG VENT PIPE DNSCIINOP Feedback KIA: 262002 G2.01.23 Ability to perform specific system and integrated plant procedures during all modes of plant operation.

Uninterruptable Power Supply (A.C'/D.C.)

(CFR: 41.10 143.5 1 45.2 145.6)

RO/SRO Rating: 4.3/4.4 Objective: CLS-LP-11.0, 15a Given plant conditions and a trip or failure of one of the following Radiation Monitors, determine appropriate plant response and use procedures to determine the actions required to control and/or mitigate the consequences of the event:

a. Main Stack.

Reference:

20P-52, Section 8.7, Stack Radiation Monitor UPS Power Supply Transfer Cog Level High Explanation:

The normal power supply for the Main Stack Rad Monitor is from Unit Two. On a loss of power the from the normal power supply the operators will need to transfer to the alternate power supply. This direction is only in the U2 procedure. There is no directions to perform this in the U1 procedure or the APPs for either Unit.

Distractor Analysis:

Choice A: Plausible because the stem states this is U1 but the actions are in the U2 procedure.

Choice B: Correct answer, see explanation.

Choice C: Plausible because the downscale 1 inop annunciator will be actuated on a loss of power but the APPs do not address transfer of power to backup supply.

Choice D: Plausible because the downscale 1 inop annunciator will be actuated on a loss of power but the APPs do not address transfer of power to backup supply. U2 is the normal power supply to the rad monitor.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Notes 8.0 INFREQUENT OPERATIONS.

32 8.1 Transferring UPS Loads From Alternate Source to Primary UPS Unit 2A 32 8.2 Transferring UPS Loads From Alternate Source to Standby UPS Unit 28 35 8.3 Transferring UPS Loads From Standby UPS Unit 2B to Alternate Source 39 8.4 Transferring UPS Loads From Primary UPS Unit 2A to Alternate Source 41 8.5 Alignment of Standby UPS Unit 2B After a Loss of Alternate Source Power 43 8.6 Returning Standby UPS Unit 2B to Normal Operating Condition Upon Regaining Alternate Source Power Supply 45 8.7 Stack Radiation Monitor UPS Power Supply Transfer 47 20P-52 Rev. 53 Page2of78 8.0 INFREQUENT OPERATIONS 34 8.1 Transferring UPS Loads From Alternate Source to Primary UPS Unit 1A 34 8.2 Transferring UPS Loads From Alternate Source to Standby UPS Unit 18 38 8.3 Transferring UPS Loads From Standby UPS Unit I B to Alternate Source 42 8.4 Transfening UPS Loads From Primary UPS Unit IA to Alternate Source 44 8.5 Alignment of Standby UPS Unit lB After a Loss of Alternate Source Power 46 8.6 Returning Standby UPS Unit 1 B to Normal Operating Condition Upon Regaining Alternate Source Power Supply 48 I OP-52 Rev. 35 Page 3 of 74 Unit2 APP UA-03 6-3 Page 1 of 1 PROCESS SMPL OG VENT PIPE DNSCIINOP (Process Sample Off-Gas Pipe Down-Inoperable)

AUTO ACTIONS NONE CAUSE 1.

Off-gas vent pipe (stack) radiation monitor downscale or out of service.

2.

Circuit malfunction.

3.

Change in background counts, possibly from unit power reduction.

Categories K/A:

262002 G2.0 1.23 Tier / Group:

T2G1 RO Rating:

4.3 SRO Rating:

4.2 LP Obj:

I 1-15A Source:

NEW Cog Level:

HIGH Category 8:

Y Notes 8.0 INFREQUENT OPERATIONS.................................................................................. 32 8.1 Transferring UPS Loads From Alternate Source to PrimalY UPS Unit 2A..... 32 8.2 Transferring UPS Loads From Alternate Source to Standby UPS Unit 28.... 35 8.3 Transferring UPS Loads From Standby UPS Unit 2B to Alternate Source.... 39 8.4 Transferring UPS Loads From Primary UPS Unit 2A to Alternate Source..... 4'1 8.5 Alignment of Standby UPS Unit 2B After a Loss of Alternate Source Power. 43 8.6 Returning Standby UPS Unit 2B to Normal Operating Condition Upon Regaining Altemate Source Power Supply..................................................... 45 8.7 Stack Radiation Monitor UPS Power Supply Transfer.................................... 47 120P-52 Rev. 53 Page 2 of 78 I 8.0 INFREQUENT OPERATIONS............................................................................... 34 8.1 Transferring UPS Loads From Alternate Source to PrimalY UPS Unit 1A..... 34 8.2 Transferring UPS Loads From Alternate Source to Standby UPS Unit 18.... 38 8.3 Transferring UPS Loads From Standby UPS Unit '1 B to Alternate Source.... 42 8.4 Transferring UPS Loads From Primary UPS Unit 'lA to Alternate Source..... 44 8.5 Alignment of Standby UPS Unit 1 B After a Loss of Alternate Source Power................................................................................................................. 46 8.6 Returning Standby UPS Unit 1 B to Normal Operating Condition Upon Regaining Alternate Source Power Supply..................................................... 48 l'lOP-52 Rev. 35 Page 3 of 74 I PROCESS SMPL OG VENT PIPE DNSCllNOP (Process Sample Off-Gas Pipe Down-Inoperable)

AUTO ACTIONS NONE CAUSE Unit 2 APP UA-03 6-3 Page 1 of'l

'I.

Off-gas vent pipe (stack) radiation monitor downscale or out of service.

2.

Circuit malfunction.

3.

Change in background counts, possibly from unit power reduction.

Categories KIA:

262002 G2.0 1.23 Tier / Group: T2Gl RORating:

4.3 SRORating

4.2 LPObj

11-15A Source:

NEW Cog Level:

HIGH Category 8:

Y

83. The following conditions exist on Unit Two following a spurious Main Turbine trip at rated power:

SDV HI-HI WTR LVL TRIP BYPASS OTBD NSSS VALVES MTR OVERLOAD Reactor level Reactor Pressure All Control Rods Scram RWCU System In alarm In alarm 185 inches and steady 900 psig with BPVs controlling Fully inserted Being reset lAW LEP-02 Isolated by 2-G31 -FOOl The 2-G31-F004 (RWCU Outboard lsol VIv) failed to automatically close on a valid isolation signal due to motor overload.

Which one of the following identifies the Technical Specification requirements when the RSP is exited?

The RSP can be exited to OGP-05, Unit Shutdown, provided an active LCO is implemented for Technical Specification (1)

The start time of the LCO action completion time is when the (2)

A.

(1) 3.3.1.1, Reactor Protection System (RPS) Instrumentation (2) condition occurred B.

(1) 3.3.1.1, Reactor Protection System (RPS) Instrumentation (2) RSP is exited C. (1) 3.6.1.3, Primary Containment Isolation Valves (PCIV5)

(2) condition occurred D (1) 3.6.1.3, Primary Containment Isolation Valves (PCIV5)

(2) RSP is exited

83. The following conditions exist on Unit Two following a spurious Main Turbine trip at rated power:

SDV HI-HI WTR LVL TRIP BYPASS OTBD NSSS VALVES MTR OVERLOAD Reactor level Reactor Pressure All Control Rods Scram RWCU System In alarm In alarm 185 inches and steady 900 psig with BPVs controlling Fully inserted Being reset lAW LEP-02 Isolated by 2-G31-F001 The 2-G31-F004 (RWCU Outboard Isol Vlv) failed to automatically close on a valid isolation signal due to motor overload.

Which one of the following identifies the Technical Specification requirements when the RSP is exited?

The RSP can be exited to OGP-05, Unit Shutdown, provided an active LCO is implemented for Technical Specification (1)

The start time of the LCO action completion time is when the (2)

A. (1) 3.3.1.1, Reactor Protection System (RPS) Instrumentation (2) condition occurred B. (1) 3.3.1.1, Reactor Protection System (RPS) Instrumentation (2) RSP is exited C. (1) 3.6.1.3, Primary Containment Isolation Valves (PCIVs)

(2) condition occurred D!'" (1) 3.6.1.3, Primary Containment Isolation Valves (PCIVs)

(2) RSP is exited

Feedback K/A: S295006G 2.02.22 Knowledge of limiting conditions for operations and safety limits.

SCRAM (CFR: 41.5/43.2/45.2)

RO/SRO Rating: 4.0/4.7 Objective: CLSLP300C*1 I

11. Given plant conditions, the Unit Shutdown Procedure (GP-05), and the Reactor Scram Procedure, determine if conditions allow exiting the Reactor Scram Procedure.

Reference:

1 OCFR5O.36 OEOP-01-UG, Revision 55, Page 31, Section 3.5 Cog Level: High Explanation:

The EOPs authorize actions outside of technical specifications to mitigate the consequences of an emergency condition. The EOPs also provide for returning the system or component to service, If the system or component is not returned to its standby or operable condition prior to exiting the EOP5, then the appropriate limiting condition of operation shall be implemented in accordance with Technical Specifications The starting time for the limiting condition of operation is the time that the EOPs were exited.

In order to exit EOP, compatibilty with GP-05 along with active LCOs need to be implemented. PCIV G31-F004 is inoperable, TS 3.6.1.3 Condition A (A1)requires isolating the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, blind flange, or check valve witf witj pursQ() jerify the affected penetration flow path is isolated Once per 31 days for isolation devices outside primary containment AND Prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment.

Distractor Analysis:

Choice A: Plausible because OGP-01 would be entered in order to restart the reactor and TS 3.3.1.1 would be correct if the unit was in Mode I or 2

- SDV Hi level is not required in Mode 3.

Choice B: Plausible because OGP-05 is correct and TS 3.3.1.1 would be correct if the unit was in Mode 1 or 2

- SDV Hi level is not required in Mode 3.

Choice C: Plausible because OGP-01 would be entered in order to restart the reactor and TS 3.6.1.3 is correct.

Choice D: Correct Answer SRO Only Basis: Requires assessment of plant conditions (RPS SDV Hi Level Bypass and Failed open PCIV) and prescribing a procedure with which to proceed (OGP-05).

Notes Feedback KIA: S295006G 2.02.22 Knowledge of limiting conditions for operations and safety limits.

SCRAM (CFR: 41.5 1 43.2 1 45.2)

RO/SRO Rating: 4.0/4.7 Objective: CLS-LP-300-C*11

11. Given plant conditions, the Unit Shutdown Procedure (GP-05), and the Reactor Scram Procedure, determine if conditions allow exiting the Reactor Scram Procedure.

Reference:

10CFR50.36 OEOP-01-UG, Revision 55, Page 31, Section 3.5 Cog Level: High Explanation:

The EOPs authorize actions outside of technical specifications to mitigate the consequences of an emergency condition. The EOPs also provide for returning the system or component to service. If the system or component is not returned to its standby or operable condition prior to exiting the EOPs, then the appropriate limiting condition of operation shall be implemented in accordance with Technical Specifications. The starting time for the limiting condition of operation is the time that the EOPs were exited.

In order to exit EOP, compatibilty with GP-05 along with active LCOs need to be implemented. PCIV G31-F004 is inoperable, TS 3.6.1.3 Condition A (A1)requires isolating the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, blind flange, or check valve wi1~q9Ll~l~J~q~~ilbiml&~l:Ii~(.~ify the affected penetration flow path is isolated Once per 31 days for isolation devices outside primary containment AND Prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment.

Distractor Analysis:

Choice A: Plausible because OGP-01 would be entered in order to restart the reactor and TS 3.3.1.1 would be correct if the unit was in Mode 1 or 2 - SDV Hi level is not required in Mode 3.

Choice B: Plausible because OGP-05 is correct and TS 3.3.1.1 would be correct if the unit was in Mode 1 or 2 - SDV Hi level is not required in Mode 3.

Choice C: Plausible because OGP-01 would be entered in order to restart the reactor and TS 3.6.1.3 is correct.

Choice D: Correct Answer SRO Only Basis: Requires assessment of plant conditions (RPS SDV Hi Level Bypass and Failed open PCIV) and prescribing a procedure with which to proceed (OGP-05).

Notes

3.5 Technical Specifications The EOPs authorize actions outside of technical specifications to mitigate the consequences of an emergency condition. The EOPs also provide for returning the system or component to service.

If the system or component is not returned to its standby or operable condition prior to exiting the EOPs, then the appropriate limiting condition of operation shall be implemented in accordance with Technical Specifications. The starting time for the limiting condition of operation is the time that the EOPs were exited.

OEOP-01-IJG Rev. 55 Page 31 of 151 Completion Times 1.3 1.0 USE AND APPLICATION 1.3 Completion Times PURPOSE The purpose of this section is to establish the Completion Time convention and to provide guidance for its use.

BACKGROUND Limiting Conditions for Operation (LCOs) specify minimum requirements for ensuring safe operation of the unit. The ACTIONS associated with an LCO state Conditions that typically describe the ways in which the requirements of the LCO can fail to be met. Specified with each stated Condition are Required Action(s) and Completion Times(s).

DESCRIPTION The Completion Time is the amount of time allowed for completing a Required Action. it is referenced to the time of discovery of a situation (e.g, inoperable equipment or variable not within limits) that requires entering an ACTIONS Condition unless otherwise specified, providing the unit is in a MODE or specified condition stated in the Applicability of the LCO. Required Actions must be completed prior to the expiration of the specified Completion Time. An ACTIONS Condition remains in effect and the Required Actions apply until the Condition no longer exists or the unit is not within the LCO Applicability.

3.5 Technical Specifications The EOPs authorize actions outside of technical specifications to mitigate the consequences of an emergency condition. The EOPs also provide for returning the system or component to service. If the system or component is not returned to its standby or operable condition prior to exiting the EOPs, then the appropriate limiting condition of operation shall be implemented in accordance with Technical Specifications. The starting time for the limiting condition of operation is the time that the EOPs were exited.

IOEOP-01-UG Rev. 55

'1.0 USE AND APPLICATION Page 31 of 'IS" I Completion Times 1.3

'1.3 Completion Times PURPOSE BACKGROUND DESCRIPTION The purpose of this section is to establish the Completion Time convention and to provide guidance for its use.

Limiting Conditions for Operation (LCOs) specify minimum requirements for ensuring safe operation of the unit. The ACTIONS associated *with an LCO state Conditions that typically describe the ways in which the requirements of the LCO can fail to be met. Specified with each stated Condition are Required Action(s) and Completion Times(s).

The Completion Time is the amount of time allowed for completing a Required Action. It is referenced to the time of discovery of a situation (e.g., inoperable equipment or variable not within limits) that requires entering an ACTIONS Condition unless otherwise specified, providing the unit is in a MODE or specified condition stated in the Applicability of the LCO. Required Actions must be completed prior to the expiration ofthe specified Completion Time. An ACTIONS Condition remains in effect and the Required Actions apply until the Condition no longer exists or the unit is not within the LCO Applicability.

WHITE 55 OTBD NSSS VALVES MTR OVERLOAD Page 1 of 2 1.0 OPERATOR ACTIONS:

1.1 OBSERVE Automatic Functions:

1.1.1 IF one of the affected valves was being operated. THEN:

1. Valve motion will stop

2. Valve will NOT respond to control signals

3. Valve position will still be indicated 1.2 PERFORM Corrective Actions:

NOTE: Resetting valve motor overload devices or manual operaon of tripped motor-operated valves should only be attempted in emergency situations as directed by the Unit SCO.

CAUTION During manual oPeration of motor-operated valves, personnel should stand clear of the valve vhiIe either:

1. Resetting the thermal 3verload device or 2.

Operating the valve remo:ely.

1.2.1 IF the affected valve is required for operation, THEN PERFORM the following steps:

1. RESET the thermal overload device at the affected valve breaker compartment AND OPERATE the valve again.

2.

IF the themal overload device actuates again. THEN MANUALLY OPERATE the valve.

3. WHEN the valve is broken off its closed or open seat, THEN RESET the themial overload device at the affected valve breaker compartment AND OPERATE the valve.

1.2.2 REFERt0TS. 3.6.1.3 and TRMApp DTable 3.6.1.3-2.

24,PP-A-02 Rev. 32 Page 57 of 5-5 OTBD NSSS VALVES MTR OVERLOAD Page 1 of2 1.0 OPERATOR ACTIONS:

1.1 OBSERVE Automatic Functions:

1.1.1 IF one of the affected valves was being operated, THEN:

1. Valve motion will stop

2. Valve will NOT respond to control signals

3. Valve position will still be indicated 1.2 PERfORM Corrective Actions:

NOTE: Resetting valve motor overload devices or manual operation of tripped motor-operated valves sl10uld only be attempted in emergency Situations as directed by the Unit SeQ.

CAUTION During manual operation of motor-operated valves, personnel sh.ould stand clear of the valve while either:

1. Resetting the thermal overload device Of

2. Operating the valve remotely.

1.2.1 IF the affected valve is required for operation, THEN PERFORM the following steps:

1. RESET the thermal overload device at the affected valve breaker compartment AND OPERATE the valve again.

2. IF the themlal overload device actuates again, THEN MANUALLY OPERATE the valve.

3. WHEN the valve is broken off its closed or open seat, THEN RESET the themlal overload device at the affected valve breaker compartment AND OPERATE the valve.

1.2.2 REFER to T.S. 3.6.1.3 and TRM App. 0 Table 3.6.1.3-2.

12APp-A-02 Page 57 of 791

PCIVs 3.6.1.3 3.6 CONTAINMENT SYSTEMS 3.6.1.3 Primary Containment Isolation Valves (PCIVs)

LCO 16.1.3 Each PC1V, except reactor building-to-suppression chamber vacuum breakers, shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, When associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, Primary Containment Isolation Instrumentation.

CONDITION REQUIRED ACTION COMPLETION TIME A.

NOTE-------

A.l Isolate the affected B hours Only applicable to penetration flow path by penetration flow paths with use of at least one closed two PCIVs.

and de-activated automatic

valve, closed manual valve, blind flange, or check valve One or more penetration with flow through the valve flow paths with one PCIV secured.

inoperable except for MSIV leakage not within limit.

3.6 CONTAINMENT SYSTEMS 3.6.'1.3 Primary Containment Isolation Valves (PCIVs)

LCO 3.6. '1.3 Each PCIV, except reactor building-to-suppression chamber vacuum breakers, shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3, VV'hen associated instrumentation is required to be OPERABLE per LCO 3.3.6:1, "Primary Containment Isolation Instrumentation."

CONDITION A.

NOTE-----------

A:I Only applicable to penetration flow paths 'Nith two PCIVs.

One or more penetration flo.... ' paths with one PCIV inoperable except for MSIV leakage not within limit.

AND REQUIRED ACTION COMPLETION TIME Isolate the affected 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.

3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation LCO 3.3.1.1 The RPS instrumentation for each Function in Table 3.3.l.1I shall be OPERABLE.

APPLICABILITY:

According to Table 3.3.1.1-i.

ACTIONS

NOTE---

Separate Condition entry is allowed for each channel.

RPS Instrumentation 3.3.1.1 Tt 3l.t 3 c R: Pn:r Oy: i:Irc

,%PPLICABLE OC:NOION MOD O REOAED REHCE OTHER CHANNEL2 FO 2PECWE TA QLLAE 2URVELLArCE ALLOWABLE FL4O2N OCNDI:ON 3OTE3 AOT2r D.

REOLJIREVENTO VALUE 7.

Ccr CEcharc Vr 1,2 2

OR WLHh OR OR OR CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required Al Place channel in trip.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channels inoperable.

OR A.2 NOTE 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Not applicable for Functions 2.a, 2.b, 2.c, 24, or 2.f.

Place associated trip system in trip.

Categories KJA:

S2950006G 2.02.22 Tier! Group:

T1GI RO Rating:

4.0 SRO Rating:

4.7 LP Obj:

CLSLP300C*11 Source:

NEW Cog Level:

HIGH Category 8:

3.3.1 :1 3.3 INSTRUMENTATION 3.3.*'.'1 Reactor Protection System (RPS) Instrumentation LCO 3.3.-l.'I The RPS instrumentation for each Function in Table 3.3.'U-*1 shall be OPERABLE APPLICABILITY:

According to Table 3.3.1.. 1-*1.

ACTIONS

NOT E ---------------------------------------------------------

Separate Condition entry is allowed for each channel.

FUNCttON

7.

ScramOtscharoeVO\\\\m""e W3!er Le'o!et-HIgn CONDITION A.

One or more required channels inoperable.

Categories KIA:

S2950006G 2.02.22 RORating:

4.0 LPObj

CLS-LP-300-C* 11 Cog Level:

HIGH RPS Instrumentation 3.3.1.*'

Tatfe :t 3~ 1.1'"~ (~3J~.:. o~ 3t R~3-:'>>r Pf\\:t~,:.~or. Sj':~m. !n:.~".m~r:~l!:':f:

.'V'PLICASLE

!.. ~ooszc,:(

C*"iHER.

(lPECIFIE::l CC'NOI7'ICNS 1,;:

CO~OI7fONS RSQIJt:tED

,:t5FERENCEO CHANNeLS AAOM i=E?t r,:w=

3'V!l"iE\\1 FtEQIJ1,"iEO aVR\\'EII.LAJIoICE.

ACtiON 0.1 RSQUIREAlEma

~

OR ~.l.4.1";

a.=t

.3: .~.4.:S a,;:( 3.3."L~LH

a,=\\ 3.3:.il.L1':'

"'1.L!:JW *.r..sLE VAL,VE REQUIRED ACTION COMPLETION TIME A.'I Place channel in trip.

12 hours OR A.2

NOTE-------------

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Not applicable for Functions 2.a, 2.b, 2.c, 2.d, or 2.f.

Place associated trip system in trip.

Tier / Group: TIG!

SRORating: 4.7 Source:

NEW Category 8:

84. Following a scram on Unit Two, which one of the following correctly identifies:

(1) the initial response of reactor water level if an SRV is opened and (2) the procedure that contains the guidance to close the MSIVs due to water level?

A. (1) Shrink (2) Reactor Scram Procedure B. (1) Shrink (2) 2APP-A-07, REACTOR WATER LEVEL HIGH/LOW C (1) Swell (2) Reactor Scram Procedure D. (1) Swell (2) 2APP-A-07, REACTOR WATER LEVEL HIGH/LOW Feedback K/A: 295008 A2.05 Ability to determine andlor interpret the following as they apply to HIGH REACTOR WATER LEVEL:

Swell (CFR: 41.10/43.5/45.13)

ROISRO Rating: 2.9/3.1 Objective: CLS-LP-300-C, 10 Given plant conditions and the RSP, determine the required operator actions.

Reference:

RSP I 001-37.3 2APP-A-07, page 12 Cog Level: High Explanation:

Opening of the SRV will cause the reactor water level to swell up due to the reduction in pressure in the vessel and if level reaches the value in figure 1 on the RSP then closure of the MSIVs is directed. The MSIVs will close automatically but only on low level 3, not high level.

Distractor Analysis:

Choice A: Plausible if the examinee thinks that opening the SRV would reduce the water volume in the RPV, The RSP does contain the actions to close the MSIVs.

Choice B: Plausible if the examinee thinks that opening the SRV would reduce the water volume in the RPV, the examinee may think that the closure is an auto action, which are contained in the APP.

Choice C: Correct see explanation Choice D: Plausible because reactor water level will swell, and the examinee may think that the closure is an auto action, which are contained in the APP.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Notes

84. Following a scram on Unit Two, which one of the following correctly identifies:

(1) the initial response of reactor water level if an SRV is opened and (2) the procedure that contains the guidance to close the MSIVs due to water level?

A. (1) Shrink (2) Reactor Scram Procedure B. (1) Shrink (2) 2APP-A-07, REACTOR WATER LEVEL HIGH/LOW c~ (1) Swell (2) Reactor Scram Procedure D. (1) Swell (2) 2APP-A-07, REACTOR WA TER LEVEL HIGH/LOW Feedback KIA: 295008 A2.05 Ability to determine and/or interpret the following as they apply to HIGH REACTOR WATER LEVEL:

Swell (CFR: 41.10/43.5/45.13)

RO/SRO Rating: 2.9/3.1 Objective: CLS-LP-300-C, 10 Given plant conditions and the RSP, determine the required operator actions.

Reference:

RSP 1001-37.3 2APP-A-07, page 12 Cog Level: High Explanation:

Opening of the SRV will cause the reactor water level to swell up due to the reduction in pressure in the vessel and if level reaches the value in figure 1 on the RSP then closure of the MSIVs is directed. The MSIVs will close automatically but only on low level 3, not high level.

Distractor Analysis:

Choice A: Plausible if the examinee thinks that opening the SRV would reduce the water volume in the RPV, The RSP does contain the actions to close the MSIVs.

Choice B: Plausible if the examinee thinks that opening the SRV would reduce the water volume in the RPV, the examinee may think that the closure is an auto action, which are contained in the APP.

Choice C: Correct see explanation Choice 0: Plausible because reactor water level will swell, and the examinee may think that the closure is an auto action, which are contained in the APP.

SRO Basis: 10 CFR 55.43(b)-5, Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Notes

REACTOR WATER LEVEL I-IIGHFLOW PaOe 1 012 1.0 OPERATOR ACTIONS:

1.1 CONFIRM by multiple indications actual high or low reactor water level:

1.1.1 Reactor water level indication on RTGB Panel P603 may be used ror verification of water level:

1, Reactor Water Level A, C32-Ll-R606A.

2. Reactor Water Level B, C32-Ll-R6066.

3. Reactor Water Level C, C32-Ll-R606C.

4. Reactor Level/Pressure Recorder, C32-R608.

1.2 OBSERVE Automatic Functions:

1.2.1 IF reactor level decreases to 136 inches, THEN a reactor Scram results.

1.2.2 IF reactor level increases to 206 inches. THEN the Main Turbine, RFPTs, RCIC and HPCI turiines will trip.

1.2.3 IF either of the RFPs have tripped AND reactor water level is less than 182 inches. TI-lEN a Recirculation Pump runback will occur.

2APP-A-07 Rev. 32 Page 12 of 45 From the Reactor Scram Procedure:

flWAN J_Yt PL.CLALLMIV lTCHE1OCLO o1 LOWER REAtOR WATER WH RWCU REACTOR WATER LEVEL HIGHlLOW Page 1 of 2 1.0 OPERATOR ACTIONS:

1.1 CONFIRM by multiple indications actual high or low reactor water level:

1.1.1 Reactor water level indication on RTGB Panel P603 may I)e used for verification of water level:

1. Reactor Water Level.4" C32-Ll-R606.'\\.

2. Reactor Water Level B, C32-Ll-R606B.

3. Reactor Water Level C, C32-U-R606C.

4. Reactor Level/Pressure Recorder, C32-R608.

1.2 OBSERVE Automatic Functions:

1.2.1 IF reactor level decreases to '166 inches, THEN a reactor Scram results.

1.2.2 IF reactor level increases to 206 inclles, THEN the Main Turbine. RFPTs, RCIC and HPCI tUri)ines '.vill trip.

1.2.3 IFeitller of tile RFPs have tripped AND reactor water level is less than 182 inches, THEN a Recirculation Pump runback will occur.

12APP-A-07 Page 12 of 451 From the Reactor Scram Procedure:

Cl)

LUI (U)

-J LU>

LU

-j a

z ATTACHMENT 6 Page 19 of 19 FIGURE 21 Reactor Water Level at MSL (Main Steam Line Flood Level>

WHEN REACTOR PRESSURE IS LESS THAN 60 PSIG, USE INDICATED LEVEL.

MSL IS+250 INCHES.

DEOP-Ol-UG I

Rev. 55 Page 106 of 151 300 250 REF LEG TEMP ABOVE OR EQUAL TO 200F REF LEG TEMP BELOW 2COF 200 11111 IIIIII lIIlllII!1lllIJIjI1,15o 100 300 500 700 900 13100 60 200 400 600 800 1,000 REACTOR PRESSURE (PSIG)

(J)

W J:

()

Z --

..J W >

W

..J C

W

~

o -c z

250 200 OEOP-01-UG ATTACHMENT 6 Page 19 of 19 FIGURE 21 Reactor Water Level at MSL (Main Steam Line Flood Level)

MSL 00 300 500 60 200 400 600 800 1,000 REACTOR PRESSURE (PSIG)

WHEN REACTOR PRESSURE IS LESS THAN 60 PSIG, USE INDICATED LEVEL.

MSL IS +250 INCHES.

Rev. 55 REF lEG TEMP ABQVEOR EQUAL TO 200-F

.r REF LEG

,. TEMP BELOW 200"F Page 106 of 151

Categories KJA:

295008 A2.05 Tier / Group:

T1G2 RU Rating:

2.9 SRO Rating:

3.1 LP Ubj:

300-C, 10 Source:

NEW Cog Level:

HIGH Category 8:

Y Categories KIA:

295008 A2.05 Tier / Group: TlG2 RORating:

2.9 SRORating

3.1 LP Obj:

300-C,1O Source:

NEW Cog Level:

HIGH Category 8:

Y

85. Unit Two is operating at 74% power when the FW-V120,FW HTRS 4 & 5 BYP VLV, is inadvertantly opened by mechanics. The valve is bound and can not be reclosed.

Initial Final Feedwater Temperature was 404°F.

Conditions are now stable with reactor power at 81% and Final Feedwater Temperature at 314°F.

(Reference provided)

Which one of the following identifies the required action based on the information above?

Continued operation:

Av is not allowed and reactor shutdown is required lAW OGP-05, Unit Shutdown.

B. is not allowed and a manual reactor scram is required lAW 001-01.01, BNP Conduct of Operations Supplement.

C. is allowed provided the FW Heaters 4 & 5 are isolated lAW 20P-32, Condensate and Feedwater Operating Procedure.

D. is allowed provided reduced thermal limits are established within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months as required by Technical Specifications.

85. Unit Two is operating at 74% power when the FW-V120, "FW HTRS 4 & 5 BYP VLV, is inadvertantly opened by mechanics. The valve is bound and can not be reclosed.

Initial Final Feedwater Temperature was 404°F.

Conditions are now stable with reactor power at 81 % and Final Feedwater Temperature at 314°F.

(Reference provided)

Which one of the following identifies the required action based on the information above?

Continued operation:

A'! is not allowed and reactor shutdown is required lAW OGP-05, Unit Shutdown.

B. is not allowed and a manual reactor scram is required lAW 001-01.01, BNP Conduct of Operations Supplement.

C. is allowed provided the FW Heaters 4 & 5 are isolated lAW 20P-32, Condensate and Feedwater Operating Procedure.

D. is allowed provided reduced thermal limits are established within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months as required by Technical Specifications.

Feedback K/A: 295014 G2.01.25 Ability to interpret reference materials, such as graphs, curves, tables, etc.

Inadvertent Reactivity Addition (CFR: 41.10 / 43.5 / 45.12)

ROISRO Rating: 3.9/4.2 Objective: CLS-LP-34, Obj. 1 Ic Given plant conditions, describe the effect a loss/malfunction of the feedwater heaters will have on:

c. Feedwater Temperature

Reference:

20P-32, Attachment 4 (provided)

Cog Level HI Explanation:

From Attachment 4 of 20P-32 operation is outside of the allowable range (<1 10.3°F) this wil require a Unit shutdown lAW GP-05.

Distractor Analysis:

Choice A: Correct see explanation Choice B: Plausible because the 01 has a table with the Selected Out-of-Service Equipment Contingencies. In this case the FW heater meets the definition of the heater OOS and operation is permitted.

Choice C: Plausible because operation is allowed if the FW heaters are isolated but not with the final temperature greater than the 110.3 limit.

Choice D: Plausible because if turbine bypass is inoperable with a FW Heater OOS then TS 3.7.6 requires this action.

SRO Basis: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations (43(b)(5) a. Assessement of the plant conditions and then prescribing the shutdown lAW the GP.

Notes Feedback KIA: 295014 G2.01.25 Ability to interpret reference materials, such as graphs, curves, tables, etc.

Inadvertent Reactivity Addition (CFR: 41.10/43.5/45.12)

RO/SRO Rating: 3.9/4.2 Objective: CLS-LP-34, Obj. 11c Given plant conditions, describe the effect a loss/malfunction of the feedwater heaters wi" have on:

c. Feedwater Temperature

Reference:

20P-32, Attachment 4 (provided)

Cog Level HI Explanation:

From Attachment 4 of 20P-32 operation is outside of the a"owable range <<11 0.3°F) this wil require a Unit shutdown lAW GP-05.

Distractor Analysis:

Choice A: Correct see explanation Choice B: Plausible because the 01 has a table with the Selected Out-of-Service Equipment Contingencies. In this case the FW heater meets the definition of the heater OOS and operation is permitted.

Choice C: Plausible because operation is allowed if the FW heaters are isolated but not with the final temperature greater than the 110.3 limit.

Choice 0: Plausible because if turbine bypass is inoperable with a FW Heater OOS then TS 3.7.6 requires this action.

SRO Basis: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations (43(b)(5) a. Assessement of the plant conditions and then prescribing the shutdown lAW the GP.

Notes

U 0

C 1)

C C C4 CJ cN C c C C4 C C c4 - - - - - -

C C) C C) C) C C C C C CrJ j cl)c

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t 1 t 1

t i t t J f f C) C C (V) C C3 Cr)

Cr) cc Lfl in in in in cc cc cc cc r r-r cc cc cc in in ci - cc L -r c cJ

cc in

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ci) 0 Co>

I-ci)0 Ea)

I ci)a)

U (5

LL Ca)

E

-c C)

(5 (4

a0 E

2 LL From OP-32, Attachment 4, Final Feedwater Temperature Vs Power RX Nominal Nominal

1*1O.3°F PWR FVV Temp RlV Temp Reduced F'vV Reduced Temp

'10°F 100 429.0 4'19.0 328.7 99 427.6 4'17.6 327.7 98 426.5 4'16.. 6 327.0 97 425.5 4'15.6 326.3 96 424.. 4 4']4.6 325.7 95 423.4 4'13.6 325.0 94 422.4 4'12.6 324.3 93 42'1.4 4'I'L7 323.7 9,2 420.4 4'10..7 323.0 91 419.5 409.8 322.4 90 4-18.5 408.8 321.7 89 4'17.5 407.9 32'1.'1 88 416.5 406.. 9 320.4 87 415.6 406.0 319.8 86 4'14.6 405.0 319:1 85 413.6 404.1 318.5 84 4-12.6 403.. 1 317.8 83 41'1.7 402.2 317.2 82 4-10.7 40'1.2 316.5 81 409.7 400.3 315.8 80 408.7 399.3 315.2 79 407.6 398.3 314.5 78 406.6 397.3 313.8 77 405.6 396.3 313:1 76 404.5 395.3 312.4 75 403.5 394.2 31'1.7 74 402.4 393.2 311.0 73 40'1.3 392.1 310.3

CAUTION Unit operation outside the bounds of the Loss of Feedwater Heating analysis is prohibited.

9.

IF Step 8.7.2.8c criteria is NOT met. THEN PERFORM the following:

a.

IMMEDIATELY NOTIFY the Unit SCO b

RESTORE unit operation within the bounds of the cycle Loss of Feedwater Heating analysis OR c

COMMENCE unit shutdown in accordance with OGP-05.

20P-32 Rev. 165 Page 117 of 300 Permitted Condition Operation Comment 005 SingI (See NOTES)

FWHOOS Yes Defined as a ID F or greater reduction n nominal feedwater temperature.

FWR FFrR Yes Defined as a 10 F or greater reduction n feecwater temperature.

Defined as a cycle extension strategy.

MSIVOOS Yes-base MSIVOOS permits I MSIV to be inoperable.

IF MSIVOOS. THEN thermal power shall be limited to 70% of rated.

TBPCCS Yes TSPOOS assumes a! turbine bypass valves (ThV) are incoerable.

SLO Yes Permitted with a thermal limi: penalty.

005 Combination (See NOTES)

TBPOOS & WH003 Yes Combined 003 condition is permtted with a thermal limit penalty.

TBPOOS Yes Combined 003 condtion s permitted with a thermal imit penatty.

& FWTR (FFTR)

Operefinq Power/Flow Map ICF Yes-base Permitted operations with thermal limits defined by 003 condition.

Power Coas:down Yes-base Permitted operations with thermal limits detned by OCS condition.

Turbine Control Mode Yes-base Partial arc cpera:ion is supported by safety analysis for all 005 conditions RCR Pump Per Source Yes-base Power source can be protiided by the UAT or SAT or all ODS conditions.

Yes:

Operations are permitted with restrictive thermal limits.

Yes-base:

Operations are permitted with base thermal limits. fo thermal flnit changes are required.

001-01.01 Rev. 29 Page 121 of 177 Categories K/A:

295014 G2.01.25 Tier/Group:

T1G2 RO Rating:

3.9 SRO Rating:

4.2 LPObj

34-11C Source:

NEW Cog Level:

HIGH Category 8:

CAUTION Unit operation outside tile bounds of the Loss of Feedwater Heating analysis is prohibited.

9.

IF step 8.7.2.8.c criteria is NOT met, THEN PERFORM the following:

120P-32 Condition

a.

IMMEDIATELY NOTIFY the Unit seo.

b.

RESTORE unit operation within the bounds of the cycle Loss of Feedvvater Heating analysis OR

c.

COMMENCE unit shutdown in accordance 'ljVith OGP-05.

Rev. 165 Page 1-17 of 300 1 Permitted Operation Comment DOS Single (See NOTES)

FWHOOS Yes Defined as a 10°F or greater reduction in nom inal feedwater temperature.

FW,R I,FFTR)

Yes Delined as a 10 'F or greater reduction in feedwater temperature.

Defined as a cycle extension strategy.

MSIIfOOS Yes-base

MSIVOOS permits 1 MSIV to be inoperable.

IF MSIVOOS_ THEN thermal power shall be limited to 70% of rated.

TepOOS Yes TSPOOS assumes all turbine bypass valves (I BV) are inoperable.

SLO Yes Permitted with a ihemlallimii penalty.

ODS Combination (See NOTES)

TSPOOS & FlNHOOS Yes Combined OOS condition is permitted with a thermal limit penalty.

TBPOOS Yes Combined 005 condition is permitted with a thermal limit penalty.

& FltHR (FFTR)

Operating Power/Flow Map'" ICF Yes-base

Pem,iited operations with thermal limits defined by OOS condition.

Power Coastdown Yes-base

Pemlitted operations with thermal limits defined by OOS condition.

Turbine Control Mode Yes-base

Partial aro operation is supported by saier{ analysis for all OOS conditions.

RCR Pump Pwr Source Yes-base

Power source can be provided by the UA T or SAT for all OOS conditions.

Yes:

Operations are permitted with restrictive thermal limits.

Ye.s-base:

Operations are permitted with base thermal limits. No thermallirnit changes are required.

1001-01.01 Categories KIA:

RORating:

LPObj:

Cog Level:

295014 G2.01.25 3.9 34-11C HIGH Rev. 29 Tier / Group: T1 G2 SRO Rating:

4.2 Source

NEW Category 8:

Page 12-1 of '1771

8.7.2 Procedural Steps Initials CAUTION Opening the Feedwater Heater tube side vents will release hot discharges under pressure to the drain trough.

z.

PERFORM the following to vent the tube side of the 4A(B) feed water heater:

OPEN FEEDWA TER HEA TER 4A (B)

CHANNEL INBOARD VENT VALVE, MVD-V69(V76).

CRACK OPEN FEED WA TER HEA TER 4A(B) OUTBOARD CHANNEL VENT VALVE, MVD-V70(V75), to establish a vent path.

aa.

PERFORM the following to vent the tube side of the 5A(B) feed water heater:

OPEN FEED WA TER HEA TER 5A(B)

CHANNEL INBOARD VENT VALVE, MVD-V8 I (V88).

CRACK OPEN FEED WA TER HEA TER 5A(B) CHANNEL OUTBOARD VENT VALVE, MVD-V82(V87), to establish a vent path.

NOTE:

Step 8.7.2.8 ensures unit operation with reduced feedwater temperature is bounded by the cycle Loss of Feedwater Heating analysis.

8.

EVALUATE reduction in final feedwater temperature for compliance with Loss of Feedwater Heating analysis as follows:

a.

RECORD current final feedwater temperature from PPC Display 825.

20P-32 Rev. 166 Page 116 of 301 8.7.2 Procedural Steps CAUTION Opening the Feedwater Heater tube side vents will release hot discharges under pressure to the drain trough.

Z.

PERFORM the following to vent the tube side of the 4A(B) feed water heater:

OPEN FEEDWATER HEATER 4A(B)

CHANNEL INBOARD VENT VAL VE, MVD-V69(V76).

CRACK OPEN FEEDWATER HEATER 4A(B) OUTBOARD CHANNEL VENT VALVE, MVD-V70(V75), to establish a vent path.

aa.

PERFORM the following to vent the tube side of the 5A(B) feed water heater:

OPEN FEEDWATER HEATER 5A(B)

CHANNEL INBOARD VENT VALVE, MVD-V81 (V88).

CRACK OPEN FEEDWATER HEATER 5A(B) CHANNEL OUTBOARD VENT VALVE, MVD-V82(V87), to establish a vent path.

Initials NOTE:

Step 8.7.2.8 ensures unit operation with reduced feedwater temperature is bounded by the cycle Loss of Feedwater Heating analysis.

120P-32

8.

EVALUATE reduction in final feedwater temperature for compliance with Loss of Feedwater Heating analysis as follows:

a.

RECORD current final feedwater temperature from PPC Display 825.

Sllj of.

Rev. 166 Page 116 of 301 I

8.7.2 Procedural Steps Initials b.

RECORD 110.3°F Reduced FFWT value for current reactor power from Attachment 4.

c.

CONFIRM reduction in final feedwater temperature is less than 110.3°F by comparing the following:

8.7.2.8.a 8.7.2.8.b CAUTION Unit operation outside the bounds of the Loss of Feedwater Heating analysis is prohibited.

9.

IF Step 8.7.2.8.c criteria is NOT met, THEN PERFORM the following:

a.

IMMEDIATELY NOTIFY the Unit CRS.

b.

RESTORE unit operation within the bounds of the cycle Loss of Feedwater Heating analysis qj c.

COMMENCE unit shutdown in accordance with OGP-05.

10.

IF feedwater temperature is more than 10°F below nominal (refer to Attachment 4), AND reactor power is greater than or equal to 30% of rated thermal power, THEN PERFORM the following:

a.

ENSURE reactor operation in accordance with applicable FWTR Power to Flow Map.

b.

REFER to 201-03.2 for required actions.

20P-32 Rev. 166 Page 117 of 301 8.7.2 Procedural Steps

b.

RECORD 110.3°F Reduced FFWT value for current reactor power from Attachment 4.

c.

OF CONFIRM reduction in final feedwater temperature is less than 11 0.3°F by comparing the following:

3/)(

OF B.7.2.B.a B.7.2.B.b CAUTION Unit operation outside the bounds of the Loss of Feedwater Heating analysis is prohibited.

9.

IF Step B.7.2.B.c criteria is NOT met, THEN PERFORM the following:

a.

IMMEDIATELY NOTIFY the Unit CRS.

b.

RESTORE unit operation within the bounds of the cycle Loss of Feedwater Heating analysis

c.

COMMENCE unit shutdown in accordance with OGP-05.

10.

IF feedwater temperature is more than 10°F below nominal (refer to Attachment 4), AND reactor power is greater than or equal to 30% of rated thermal power, THEN PERFORM the following:

a.

ENSURE reactor operation in accordance with applicable FWTR Power to Flow Map.

b.

REFER to 201-03.2 for required actions.

Initials 120P-32 Rev. 166 Page 117 of 301 I

8.7.2 Procedural Steps Initials 11.

CONFIRM feedwater flow temperature compensation is accurate by performing the following:

NOTE:

Feedwater Line A temperature can be obtained from any of the following:

PPC Point U2CP_B050 PPC Point U2CP_B051 Feedwater Lines Temperature Recorder, B21-TR-5515 (20 el. Reactor Building) a.

DETERMINE Feedwater Line A temperature AND RECORD temperature and instrument used below:

FW Line A temp Instrument NOTE:

Feedwater Line B temperature can be obtained from any of the following:

PPC Point U2CP_B052 PPC Point U2CP_B053 Feedwater Lines Temperature Recorder, B21TR-5515, (20 el. Reactor Building) b.

DETERMINE Feedwater Line B temperature AND RECORD temperature and instrument used below:

FW Line B temp Instrument c.

OBTAIN Feedwater Line A feedwater flow compensation value using Feedwater Line A temperature recorded in Step 8.7.2.11.a and AND RECORD on Attachment 10, column 1.

20P-32 Rev. 166 Page 1 18 of 301 8.7.2 Procedural Steps Initials NOTE:

NOTE:

120P-32

11.

CONFIRM feedwater flow temperature compensation is accurate by performing the following:

Feedwater Line A temperature can be obtained from any of the following:

PPC Point U2CP B050 PPC Point U2CP B051 Feedwater Lines Temperature Recorder, 821-TR-5515 (20' el. Reactor Building)

a.

DETERMINE Feedwater Line A temperature AND RECORD temperature and instrument used below:

OF FW Line A temp Instrument Feedwater Line B temperature can be obtained from any of the following:

PPC Point U2CP B052 PPC Point U2CP B053 Feedwater Lines Temperature Recorder, 821-TR-5515, (20' el. Reactor Building)

b.

DETERMINE Feedwater Line B temperature AND RECORD temperature and instrument used below:

OF FW Line B temp Instrument

c.

OBTAIN Feedwater Line A feedwater flow compensation value using Feedwater Line A temperature recorded in Step 8.7.2.11.a and AND RECORD on Attachment 10, column 1.

Rev. 166 Page 118 of 301 I

8.7.2 Procedural Steps Initials d.

OBTAIN Feedwater Line B feedwater flow compensation value using Feedwater Line B temperature recorded in Step 8.7.2.11.b and AND RECORD on Attachment 10, column 1.

NOTE:

Process Computer compensation values are located on the second page of the C32B022/B023 screen under HANDLING PARAMETERS, CORRECTION TYPE FACTOR 0.

e.

OBTAIN CORRECTION TYPE FACTOR 0 compensation value for PPC Point U2C32B022 (Feedwater Line A) AND RECORD on 0, column 2.

f.

OBTAIN CORRECTION TYPE FACTOR 0 compensation value for PPC Point U2C32B023 (Feedwater Line B) AND RECORD in 0, column 2.

NOTE:

IF the values compared in the following step are within 0.002, THEN feedwater flow temperature compensation is accurate.

g.

VERIFY the values on Attachment 10, columns 1 and 2 for Feedwater Line A are within 0.002 AND DOCUMENT on Attachment 10.

h.

VERIFY the values on Attachment 10, columns I and 2 for Feedwater Line B are within 0.002 AND DOCUMENT on Attachment 10.

i.

IF feedwater flow temperature compensation is NOT accurate, THEN IMMEDIATELY NOTIFY the duty Reactor Engineer.

2OP-32 Rev. 166 Page 119 of 301 8.7.2 Procedural Steps

d.

OBTAIN Feedwater Line B feedwater flow compensation value using Feedwater Line B temperature recorded in Step 8.7.2.11.b and AND RECORD on Attachment 10, column 1.

Initials NOTE:

Process Computer compensation values are located on the second page of the C32B022/B023 screen under HANDLING PARAMETERS, CORRECTION TYPE FACTOR O.

e.

OBTAIN CORRECTION TYPE FACTOR 0 compensation value for PPC Point U2C32B022 (Feedwater Line A) AND RECORD on 0, column 2.

f.

OBTAIN CORRECTION TYPE FACTOR 0 compensation value for PPC Point U2C32B023 (Feedwater Line B) AND RECORD in 0, column 2.

NOTE:

IF the values compared in the following step are within 0.002, THEN feedwater flow temperature compensation is accurate.

\\20P-32

g.

VERIFY the values on Attachment 10, columns 1 and 2 for Feedwater Line A are within 0.002 AND DOCUMENT on Attachment 10.

h.

VERIFY the values on Attachment 10, columns 1 and 2 for Feedwater Line B are within 0.002 AND DOCUMENT on Attachment 10.

i.

IF feedwater flow temperature compensation is NOT accurate, THEN IMMEDIATELY NOTIFY the duty Reactor Engineer.

Rev. 166 Page 119 of 301 \\

86. While in Mode 3 with Shutdown Cooling (SDC) in service on Unit One, a complete Loss of Off-site Power (LOOP) occurs.

The 1-E11-F009, RHR Shutdown Cooling Inboard Isolation Valve, mechanically binds in a mid-position and cannot be fully opened.

Which one of the following is the minimum level required to support natural circulation and identifies the procedural method for Decay Heat removal that is available?

The minimum Reactor Water Level to support Natural Circulation is (1) inches.

The available method of decay heat removal is (2)

A.

(1) 200 (2) Alternate Decay Heat Removal Using Natural Circulation and FPCCS and SSFPC lAW lOP-I 7, Residual Heat Removal System Operating Procedure B(I) 200 (2) Alternate Shutdown Cooling lAW OAOP-l 5.0, Loss of Shutdown Cooling C. (1) 254 (2) Alternate Decay Heat Removal Using Natural Circulation and FPCCS and SSFPC lAW lOP-i 7, Residual Heat Removal System Operating Procedure D. (1) 254 (2) Alternate Shutdown Cooling lAW OAOP-15.0, Loss of Shutdown Cooling

86. While in Mode 3 with Shutdown Cooling (SDC) in service on Unit One, a complete Loss of Off-site Power (LOOP) occurs.

The 1-E11-F009, RHR Shutdown Cooling Inboard Isolation Valve, mechanically binds in a mid-position and cannot be fully opened.

Which one of the following is the minimum level required to support natural circulation and identifies the procedural method for Decay Heat removal that is available?

The minimum Reactor Water Level to support Natural Circulation is (1) inches.

The available method of decay heat removal is (2)

A. (1) 200 (2) Alternate Decay Heat Removal Using Natural Circulation and FPCCS and SSFPC lAW 1 OP-17, Residual Heat Removal System Operating Procedure B~ (1) 200 (2) Alternate Shutdown Cooling lAW OAOP-15.0, Loss of Shutdown Cooling C. (1) 254 (2) Alternate Decay Heat Removal Using Natural Circulation and FPCCS and SSFPC lAW 10P-17, Residual Heat Removal System Operating Procedure D. (1) 254 (2) Alternate Shutdown Cooling lAW OAOP-15.0, Loss of Shutdown Cooling

Feedback KIA: S295021 A2.03 Ability to determine andlor interpret the following as they apply to LOSS OF SHUTDOWN COOLING:

Reactor water level (CFR: 41.10/43.5/45.13)

ROISRO Rating: 3.5/3.5 Objective: CLS-LP-1 20*06

6. Describe how to determine when natural circulation exists within the Reactor Vessel.

Reference:

OAOP-15, Revision 23, Page 11, Section 3.2.14 Cog Level: High Explanation:

During conditions in which there is no circulation, the reactor vessel water level, as read on B21-LI-R605A(B), should be maintained between 200 and 220, or as directed by the Shift Superintendent based on plant conditions, until forced circulation is restored. With a LOOP present and no actions taken to restore Off-site power (not provided in the question), the only available means of decay heat removal is alternate shutdown cooling utilizing SRVs.

Distractor Analysis:

Choice A: Plausible because 200 inches is correct and OP-17 contains actions for using FPC and SSFPC, but these would only be available if the reactor head is removed and fuel pool gates removed.

Choice B: Correct Answer Choice C: Plausible because 254 inches is the level of the MSLs and could be confused with Natural Circulation level due to the requirement to be at this level during alternate SDC and OP-17 contains actions for using FPC and SSFPC, but these would only be available if the reactor head is removed and fuel pool gates removed.

Choice D: Plausible because Plausible because 254 inches is the level of the MSLs and could be confused with Natural Circulation level due to the requirement to be at this level during alternate SDC SRO Only Basis: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations (43(b)(5)a. Requires assessing plant conditions (LOOP, Mode 3, power availability, impact of power losses) and prescribing correct section of a procedure to provide DHR.

Notes Feedback KIA: S295021 A2.03 Ability to determine and/or interpret the following as they apply to LOSS OF SHUTDOWN COOLING:

Reactor water level (CFR: 41.10/43.5/45.13)

RO/SRO Rating: 3.5/3.5 Objective: CLS-LP-120*06

6. Describe how to determine when natural circulation exists within the Reactor Vessel.

Reference:

OAOP-15, Revision 23, Page 11, Section 3.2.14 Cog Level: High Explanation:

During conditions in which there is no circulation, the reactor vessel water level, as read on 821-Ll-R605A(8), should be maintained between 200" and 220", or as directed by the Shift Superintendent based on plant conditions, until forced circulation is restored. With a LOOP present and no actions taken to restore Off-site power (not provided in the question), the only available means of decay heat removal is alternate shutdown cooling utilizing SRVs.

Distractor Analysis:

Choice A: Plausible because 200 inches is correct and OP-17 contains actions for using FPC and SSFPC, but these would only be available if the reactor head is removed and fuel pool gates removed.

Choice B: Correct Answer Choice C: Plausible because 254 inches is the level of the MSLs and could be confused with Natural Circulation level due to the requirement to be at this level during alternate SDC and OP-17 contains actions for using FPC and SSFPC, but these would only be available if the reactor head is removed and fuel pool gates removed.

Choice D: Plausible because Plausible because 254 inches is the level of the MSLs and could be confused with Natural Circulation level due to the requirement to be at this level during alternate SDC SRO Only Basis: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations (43(b)(5)a. Requires assessing plant conditions (LOOP, Mode 3, power availability, impact of power losses) and prescribing correct section of a procedure to provide DHR.

Notes

2.0 AUTOMATIC ACTIONS

Loop A(B) INBOARD INJECTION V4LVE E11-FO15.4iB, will close (Low Level One Only)

The RHR Pump in service for Shutdown Cooling will trip on a loss of suction path.

3.0 OPERATOR ACTIONS 3,1 Immediate Actions None 3.2 Supplementary Actions ii 3.2.1 IF Shutdown Cooling has been lost due to a tripped RHR

[]

Pump, THEN START an RHR Pump in the loop being used for Shutdown Cooling.

NOTE:

During conditions in which there is no circulation, the reactor vessel water level, as read on 82f-LI-R6OA8, should be maintained between 200 and 220, or as directed by the Shift Superintendent based on plant conditions.

until forced circulation is restored.

3.2.2 IF forced circulation has been lost, AND natural circulation has NOT been established, THEN RESTORE AND MAINTAIN reactor vessel water level.

OAOP-15.0 Rev. 23 Page 3 of 21 CAUTION If reactor coolant ten,pera:ire is grea:er than 212rF and reac:or water level has l:ieen raised to greater than 212 inches or 10 minLtes or more, a false RPV low level signal could result when the reference leg condensing pot N12A(B: n3zzie is uncovered as level is subsequentl lowered below 21S inches.

2.0 AUTOMATIC ACTIONS Loop /\\(8) INBOARD INJECTION 1I.4L VE, 0

E11-F015A(B), will close (Low Level One Only)

The RHR Pump in service for Shutdown Cooling will trip 0

on a loss of suction path.

3.0 OPERATOR ACTIONS 3.1 Immediate Actions None 3.2 Supplementary Actions CAUT.lON If reactor coolant temperature is greater tllan 21.2°F and reactor water level has been raised to greater than 218 inches for 10 minutes or more, a false RPV low level signal could result when the reference leg condensing pot N12A(B) nozzle is uncovered as level is subsequently lowered below 218 inches.

3.2.1 IF Shutdown Cooling has been lost due to a tripped RHR Pump, THEN START an RHR Pump in the loop being used for Shutdown Cooling.

o NOTE:

During conditions in which there is no circulation, the reactor vessel water level, as read on B21-Ll-R605A(B), should be maintained between 200" and 220~, or as directed by the Shift Superintendent based on plant conditions, unol rorced circulation is restored.

3.2.2 IF forced circulation has been lost, AND natural 0

circulation has NOT been established, THEN RESTORE AND MAINTAIN reactor vessel water level.

IOAOP-15.0 Rev. 23 Page 3 of21 I

10 OPERATOR ACTIONS j,

IF the reactor coolant temperature is less than 212°F, THEN ENSURE the following valves are open:

INBOARD RX HE4D VENT VLV. 821-F003 OUTBOARD PXHEAD VENT VLY. B21-F004.

k.

MAINTAIN RHR in Shutdown Cooling in accordance with 1(2)OP-17.

IF RHR has NOT been restored in accordance with Step 3.2.11.5, THEN PLACE the RHR loop that was operating in Shutdown Cooling back in service in accordance with I (2)OP-1 7 as soon as conditions permit.

U U

U 3.2.12 IF necessary to minimize reactor coolant temperature rise, THEN PERFORM one of the following feed and I

bleed combinations:

FEED BLEED CONDIFW in accordance with RWCU Reject in accordance 1(2)OP-32 with 1(2)OP-14 CRD in accordance with Reactor Water Level Control 1(2)OP-08 using Main Steam Lines in accordance with 1 (2)OP-32.

Core Spray in accordance Maintaining RPV Level Using with 1(2)OP-18 the Main Steam Line Drains LPCI in accordance with with 1(2)OP-25.

1(2)OP-1 7 IF NEITHER RHR loop can be placed in Shutdown Cooling, THEN PLACE the Condensate System in Condenser Cooling in accordance with 1(2)OP-32.

OAOP-15.0 I

Rev.23 Page 10 of 21 Not AvaD (LOOP) jvail (LOOP)

I 3-23 U

Not Avail (RPS not reset)

U 3.0 OPERATOR ACTIONS

j.

IF the reactor coolant temperature is less than 212°F, THEN ENSURE the following valves are open:

iNBOARD RX HE.4D VENT VLV, B21-F003 0

OUTBOARD RX HEAD VENT VLV B21-F004.

0

k.

MAINTAIN RHR in Shutdown Cooling in accordance with 1 (2)OP-17.

IF RHR has NOT been restored in accordance with Step 3.2.11.5, THEN PLACE the RHR loop that was operating in Shutdown Cooling back in service in accordance with 1 (2)OP-17 as soon as conditions permit.

o o

3.2.12 IF necessary to minimize reactor coolant temperature rise THEN PERFORM one of the following feed and o

P) I bleed combinations:

I~ot Avail (RPS notJ reset)

FEED BLEED CONDJFW in accordance with RWCU Reject in accordance 1 (2)OP-32 with 1(2)OP-14 CRD in accordance with Reactor Water level Control 1 (2)OP-08 using Main Steam Lines in accordance with 1 (2)OP-32.

Core Spray in accordance Maintaining RPV Level Using I with 1(2}OP-18 the Main Steam Line Drains LPCI in accordance with with 1 (2)OP-25.

1(2)OP-17 IF NEITHER RHR loop can lJe placed in Shutdown 0

Cooling, THEN PLACE the Condensate System in Condenser Cooling in accordance "vith 1(2}OP-32.

IOAOP-15.0 Rev. 23 Page 10 of21 I

3.0 OPERATOR ACTIONS 3.2.14 IF ALL of the above methods can NOT maintain reactor vessel coolant temperature below 212°F, THEN INITIATE alternate Shutdown Cooling with the SRVs as follows:

1.

ENSURE ALL control rods are fully inserteth 2.

CONFIRM reactor vessel head is installed and tensioned.

3.

IF the Reactor Recirculation Pumps are running, THEN PERFORM the following:

a.

RAISE AND MAINTAIN reactor water level between 200 and 220 as read on 321-LI-R6O548J. or as directed by Shift Superintendent based on plant conditions.

b.

STOP the running Reactor Recirculation Pumps in accordance with 1(2)OP-02.

4.

SHUT DOWN the RI-IR loop that was operating in U

Shutdown Cooling in accordance with 1(2)OP-17.

5.

PLACE one RHR loop in the Suppression Pool Cooling U

mode in accordance with 1(2)OP-17.

6.

IF Suppression Pool temperature rises above 95°F.

U THEN GO TO OEOP-02-PCCP, Primary Containment Control Procedure AND PERFORM CONCURRENTLY with this procedure.

J OAOP-15.O Rev. 23 Page 11 of 21 Categories K/A:

S295021 A2.03 Tier/Group:

T1G1 RO Rating:

3.5 SRO Rating:

3.5 LP Obj:

CLSLP120*06 Source:

NEW Cog Level:

NIGH Category 8:

3.0 OPERATOR ACTIONS 3.2.14 IF ALL of the allove methods can NOT maintain reactor vessel coolant temperature below 212°F, THEN INITIATE alternate Shutdown Cooling with. the SRVs as follows:

1.

ENSURE ALL control rods are funy inserted.

0

2.

CONFIRM reactor vessel head is installed and 0

tensioned.

3.

IF the Reactor Recirculation Pumps are running: THEN PERFORM the following:

a.

RAISE AND MAINTAIN reactor water level 0

between 200" and 220" as read on B21-U-R605A(8), or as directed by Shift Superintendent I)ased on plant conditions.

b.

STOP the running Reactor Recirculation Pumps in 0

accordance with 1 (2)OP-02.

4.

SHUT DOWN the RHR loop that was operating in Shutdown Cooltng in accordance with 1(2)OP-17.

5.

PLACE one RHR loop in the Suppression Pool Cooling mode in accordance with 1 (2)OP-17.

6.

IF Suppression Pool temperature rises above 95QF, THEN GO TO OEOP-02-PCCP, Primary Containment Control Procedure AND PERFORM CONCURRENTLY with this procedure.

IOAOP-15.0 Rev. 23 Categories KIA:

S295021 A2.03 Tier / Group: T1 G 1 SRO Rating:

3.5 RO Rating:

3.5 LP Obj:

CLS-LP-120*06 Source:

~vv Cog Level:

HIGH Category 8:

0 0

0 Page 11 of 21 I

87. While performing refueling activities on Unit Two, a spent fuel bundle was dropped and the following alarms were received:

AREA RAD REFUEL FLOOR HIGH PROCESS FV( BLDG VENT RAD HIGH Which one of the following identifies:

(1) the immediate operator action that is required to be performed and (2) the bases for the performance of this action?

A. (1) Standby Gas Treatment (SBGT)

(2) Ensures control room operators will receive 2 Rem TEDE B.

(1) Standby Gas Treatment (SBGT)

(2) Ensures control room operators will receive. 5 Rem TEDE C. (1) Control Room Emergency Ventilation (CREV)

(2) Ensures control room operators will receive <2 Rem TEDE D (1) Control Room Emergency Ventilation (CREV)

(2) Ensures control room operators will receive 5 Rem TEDE

87. While performing refueling activities on Unit Two, a spent fuel bundle was dropped and the following alarms were received:

AREA RAD REFUEL FLOOR HIGH PROCESS RX BLDG VENT RAD HIGH Which one of the following identifies:

(1) the immediate operator action that is required to be performed and (2) the bases for the performance of this action?

A. (1) Standby Gas Treatment (SBGT)

(2) Ensures control room operators will receive.:5. 2 Rem TEDE B. (1) Standby Gas Treatment (SBGT)

(2) Ensures control room operators will receive.:5. 5 Rem TEDE C. (1) Control Room Emergency Ventilation (CREV)

(2) Ensures control room operators will receive.:5. 2 Rem TEDE D~ (1) Control Room Emergency Ventilation (CREV)

(2) Ensures control room operators will receive.:5. 5 Rem TEDE

Feedback K/A: S295023G 2.04.49 Ability to perform without reference to procedures those actions that require immediate operation of system components and controls.

Refueling Accidents (CFR: 41.10 /43.2/45.6)

ROISRO Rating: 4.6/4.4 Objective: CLSLP302..J*02

2. Given plant conditions with spent fuel damage and a high airborne activity problem in progress, determine if the appropriate automatic actions have occurred in accordance with OAOP-5.0, Radioactive Spills, High Radiation, and Airborne Activity.

Reference:

OAOP-05, Revision 23, Page 2, Section 3.1 Cog Level: High Explanation:

OAOP-05 immediate action for a dropped or damaged fuel assembly is to ENSURE CREVS is in operation.

The dose consequence calculation for the fuel handling accident does not credit the secondary containment or automatic CREVS start, however, it does assume that CREVS is manually initiated within 20 minutes of a dropped/damaged fuel assembly. Based on this analysis, Technical Specifications do not require secondary containment or CREVS automatic initiation instrumentation except during Modes 1, 2, or 3 or during operations with the potential to drain the Reactor vessel. The CREV System is designed to maintain a habitable environment in the CRE for a 30 day continuous occupancy after a DBA without exceeding 5 rem total effective dose equivalent (TEDE).

Knowledge of DBA analysis initial conditions.

Distractor Analysis:

Choice A: Plausible because PROCESS RX BLDG VENT RAD HIGH annunciator is easily confused with the auto start for SBGT verifing Auto actions can be confused with Immediate Actions. SBGT start is a supplemental action which will reduce control room dose and 2 Rem TEDE is a site administrative dose limit and can be confused with the actual Dose Analysis from FHA of 2.69 rem TEDE.

Choice B: Plausible because PROCESS RX BLDG VENT RAD HIGH annunciator is easily confused with the auto start for SBGT verifing Auto actions can be confused with Immediate Actions. SBGT start is a supplemental action which will reduce control room dose and 5 Rem TEDE is correct.

Choice C: Plausible because CREV is correct and 2 Rem TEDE is a site administrative dose limit and can be confused with the actual Dose Analysis from FHA of 2.69 rem TEDE.

Choice D: Correct Answer.

SRO Only Basis: Conditions and limitations in the facility license (43(b)(1)

Notes Feedback KIA: S29S023G 2.04.49 Ability to perform without reference to procedures those actions that require immediate operation of system components and controls.

Refueling Accidents (CFR: 41.10 / 43.2 /4S.6)

RO/SRO Rating: 4.6/4.4 Objective: CLS-LP-302-J*02

2. Given plant conditions with spent fuel damage and a high airborne activity problem in progress, determine if the appropriate automatic actions have occurred in accordance with OAOP-S.O, Radioactive Spills, High Radiation, and Airborne Activity.

Reference:

OAOP-OS, Revision 23, Page 2, Section 3.1 Cog Level: High Explanation:

OAOP-OS immediate action for a dropped or damaged fuel assembly is to ENSURE CREVS is in operation.

The dose consequence calculation for the fuel handling accident does not credit the secondary containment or automatic CREVS start, however, it does assume that CREVS is manually initiated within 20 minutes of a dropped/damaged fuel assembly. Based on this analysis, Technical Specifications do not require secondary containment or CREVS automatic initiation instrumentation except during Modes 1, 2, or 3 or during operations with the potential to drain the Reactor vessel. The CREV System is designed to maintain a habitable environment in the CRE for a 30 day continuous occupancy after a DBA without exceeding S rem total effective dose equivalent (TEDE).

Knowledge of DBA analysis initial conditions.

Distractor Analysis:

Choice A: Plausible because PROCESS RX BLDG VENT RAD HIGH annunciator is easily confused with the auto start for SBGT verifing Auto actions can be confused with Immediate Actions. SBGT start is a supplemental action which will reduce control room dose and 2 Rem TEDE is a site administrative dose limit and can be confused with the actual Dose Analysis from FHA of 2.69 rem TEDE.

Choice B: Plausible because PROCESS RX BLDG VENT RAD HIGH annunciator is easily confused with the auto start for SBGT verifing Auto actions can be confused with Immediate Actions. SBGT start is a supplemental action which will reduce control room dose and S Rem TEDE is correct.

Choice C: Plausible because CREV is correct and 2 Rem TEDE is a site administrative dose limit and can be confused with the actual Dose Analysis from FHA of 2.69 rem TEDE.

Choice D: Correct Answer.

SRO Only Basis: Conditions and limitations in the facility license (43(b)(1)

Notes

Unit 2 APP UA-03 3-7 Page 1 of 1 AREA RAD REFUEL FLOOR HIGH AUTO ACTIONS NONE CAUSE 1.

High radiation level in the cask wash area.

2.

Circuit malfunction.

3.

Refueling cavity water seal failure.

OBSERVATIONS 1.

ARM indicator and ip unit Upscale light illuminated on Panel H 12-P600.

ACTIONS 1.

Refer to EOP-03-SCCP, Table 3; enter EOP-03-SCCP as appropriate.

2.

Refer to AOP-05.0, Radioacte Spills, High Radiation, and Airborne Activity.

3.

Suspend refueling operation if due to fuel pool low level from refueling cavity water seal leakage.

4.

If a circuit malfunction is suspected, ensure that a Trouble Tag is prepared.

DEVICEISETPOINTS ARM Channel 29 1<2 40 rnRPhr POSSIBLE PLANT EFFECTS 1.

Suspension of refuel floor activities.

REFERENCES 1.

LL-9353-39 2.

AOP-05.0 3.

EOP-03-SCCP 2APP-LIA-03 Rev. 46 Page 34 of AREA RAD REfUEL FLOOR HIGH AUTO ACTIONS NONE

'1.

High radiation level in the cask wash area.

2.

Circuit malfunction.

3.

Refueling cavity water seal failure.

OBSERV.A.TIONS Unit 2 APP U.A.-03 3-7 Page 1 of 1

'1.

ARM indicator and trip unit Upscale light illuminated on Panel H 12-P600.

ACTIONS

1.

Refer to EOP-03-SCCP, Table 3; enter EOP-03-SCCP as appropriate.

2.

Refer to AOP-OS.O, Radioactive Spills, High Radiation, and Airborne Activity.

3.

Suspend refueling operation if due to fuel pool low !evel from refueling cavity water seal leakage.

4.

If a circuit malfunction is suspected, ensure that a Trouble Tag is prepared.

DE\\iICE/SETPOINTS ARM Channel 29 K2 40 mRlhr POSSIBLE PLANT EFFECTS

1.

Suspension of refuel floor activities.

REFERENCES

1.

LL-9353 - 39

2.

AOP-05.0

3.

EOP-03-SCCP 12APP-uA-03 Rev. 46 Page 34 of 631

Unit 2 APP UA-03 4-S Page 1 of 1 PROCESS RX BLDG VENT RAD HIGH AUTO ACTIONS NONE CAUSE 1.

High airborne activity in Reactor Suiding ventilation exhaust p!enum.

2.

Circuit malfunction.

OBSERVATIONS 1.

Reactor Building Vent Rad Recorder D12-RR-R605 ChannelA or B indicates high radiation level.

2.

Reactor Building Exhaust Plenum Rad Monitor Channel A or B indicates greater than 3 rnRlhr on Panel H12-P6G6.

ACTIONS 1.

Enter EOP-03.SCCP. Secondary Containment Conti-o.

2.

Refer to AOP-05.O, Radioacte SpiIs, High Radiation, and Airborne Activity.

3.

If a circuit malfunction is suspected, ensure that a Troube Tag is prepared.

DEVICEISETPOINTS D12-RR-R605 red or black pen 3 mRihr POSSIBLE PLANT EFFECTS 1.

Possible release to environs.

2.

If airborne activity increases to 4 niRihr. Reactor Building HVAC isolation, a Group 6 isolation, drjwell purge isolation, and initiation of the Standby Gas Treatment System ifl1 occur.

REFERENC ES 1.

LL-9353 - 35 2.

AOP-O5.O 3.

EOP-03-SCCP 4.

Plant Modification 85-081 2APP-UA-03 Rev. 46 Page 41 of 63 PROCESS RX BLDG VENT RAD HIGH AUTO ACTIONS NONE Unit 2 APP U.A.-03 4-5 Page'l of 1

1.

High airborne activity in Reactor Building ventilation exhaust plenum.

2.

Circuit malfunction.

OBSERV.A.TiONS

'1.

Reactor Building Vent Rad Recorder D12-RR-R605 Channel A or B indicates high radiation level.

2.

Reactor Building Exhaust Plenum Rad Monitor Channel A or B indicates greater than 3 mRlhr on Panel H12-P606.

ACTIONS

1.

Enter EOP-03-SCCP, Secondary Containment Control.

2.

Refer to AOP-OS.O, Radioactive Spills, High Radiation, and Airborne Activit'!.

3.

If a circuit malfunction is suspected, ensure that a Trouble Tag is prepared.

DEVICE/SETPOINTS D'12-RR-R605 red or black pen 3 mRlhr POSSIBLE PLANT EFFECTS

1.

Possible release to environs.

2.

If airborne activity increases to 4 mRlhr, Reactor Building HVAC isolation, a Group 6 isolation, dr'Jwell purge isolation, and initiation of the Standby Gas Treatment System \\'Iill occur.

REFERENCES

1.

LL-9353 - 35

2.

AOP-05.0

3.

EOP-03-SCCP

4.

Plant Modification 85-081 12APP-uA-03 Page 41 of 631

1.0 SYMPTOMS 1.1 AREA RAD REFUEL FLOOR HIGH (UA-03 3-7) is in alarm.

1.2 AREA RAD NEW FUEL STORAGE HIGH (UA-03 4-7) is in alarm.

1.3 PROCESS RX BLDG VENT RAD i-il (UA-03 4-5) is in alarm.

1.4 TVRB BLDG VENT RAD HIGH (U.4-03 3-3 is in alarm.

1.5 Area Radiation Monitor (ARM) is in alarm.

1.6 Continuous Air Monitor (CAM) is in alarm.

1.7 Turbine Building once-through effluent monitor indicates elevated (higher than expected or an unanticipated increase) activity.

1.8 Routine surveys indicate high radiation, contamination andlor airborne activity.

1.9 Report of spill. leak. or potential damage to new or spent fuel.

2.0 AUTOMATIC ACTIONS 2.1 IF PROCESS RX BLDG VENT RAD HI-HI (UA-03 3-5) is in alam, THEN the following actions occur:

Reactor Building Ventilation isolation

SBGTSautostart U

Group 6 Isolation.

3.0 OPERATOR ACTIONS 3.1 Immediate Actions

]

3.1.1 IF a fuel assembly was dropped or damaged, THEN U

ENSURE the Control Room Emergency Ventilation System (CREVS) is in operation.

OAOP-05.O Rev. 24 Page 2 of 10 1.0 SYMPTOMS 1.1 AREA RAD REFUEL FLOOR HIGH (UA-03 3-7) is in alarm.

1.2 AREA RAD NEW FUEL STORAGE HIGH (UA-03 4-7) is in alarm.

1.3 PROCESS RX BLDG VENT RAD HI (UA-03 4-5) is in alarm.

1.4 TURB BLDG VENT RAD H.IGH (U.4-03 3-3) is in alarm.

1.5 Area Radiation Monitor (ARM) is in alaml.

1.6 Continuous,",ir Monitor (CAM) is in alarm.

1.7 Turbine Building once-through effluent monitor indicates elevated (higher than expected or an unanticipated increase) activity.

1.8 Routine surveys indicate high radiation, contamination and/or airi)ome activity.

1.9 Report of spill, leak, or potential damage to ne'.v or spent fuel.

2.0 AUTOMATIC ACTIONS 2.1 IF PROCESS RX BLDG VENT RAD HI-HI (UA-03 3-5) is in alam1, THEN the following actions occur:

Reactor Building Ventilation isolation 0

SBGTS auto start 0

Group 6 Isolation.

0 3,0 OPERATOR ACTIONS 3.1 Immediate Actions

]

3.1.1 IF a fuel assembly was dropped or damaged, THEN 0

ENSURE the Control Room Emergency Ventilation System (CREVS) is in operation.

IOAOP-OS.O Rev. 24 Page 2 of 10 I

UPDATED FSAR evision:

21 r&L ENGInEERED SAFETYFruREs Chapter:

6

Pmm, Page:

108 o 121 6.44.12 Fuel Handling Accident

- Control Room Dose Section 15.7.1 discusses the release of activity and its transpoi to the environment following a postulated fuel handling accident (FHA).

The design inpiAs utilized to evalua:e tne ntake & ths acv,ty into the control room and to assess the resultant dose to the control room operators are tabulated in Table 6-22. A sensitivity study of unuttered outsde air inleakage nto the control room was performed evaluating inleakage rates of 10,030 ofm (bouxidirig case). 3000 cfrn {confrol room design), and 0 cfm, Acodent XIQ values are developed as discussed in Section 15..2. Section 1.9.S descr bes the parameters utilized in conjunction with the AQTRAO computer code Reterence 8-35} to convert the Alternative Source Temi activity drawn into the control room during the postulatec accident into a total effective dose equivalent TEDE) dose.

Th 30-day FHA dose to the control room operator from the internal cloud associated with the FHA is calculated to be 2.69 rem TEQE.

The onsi:e control room operator dose criterion established by Reference 8-36 for this accident is that the total control room operator dose should be less than the 10 CFR 50.67 guidelines: i.e., that the total dose should be less than S rem TEDE.

C l UPDA TED FSAR ENGINEERED SAFETY FEA TURES 6.4.4.1.2 Fuel Handling Accident - Control Room Dose Revision:

21 Chapter:

6 Page:

108 oi 121 Section 15.7.1 discusses the release of aotivity and its transport to the environment following a postulated fuel handling aoodent (FH..o,).

The design inputs utilized to ellaluate the intake of this acjjvjt~* into the conlrol room and to assess the resultant dose to the control room operators are tabulated in Table 6-28. A sensitivity study of unfiltered outside air inleakage into the oontrol room 'lias performed ellaluating in leakage rates of 10.000 ofm (bounding case). 3000 cfrn {control rcom design). and 0 cfm. Accident XiQ values are developed as discussed in Secticn 15.9.2. Section '15.9.3 describes the parameters utilized in conjunction with the RADTRAD computer code {Reference 8-35} to con~'ert the Alternative Source Tern, activity drawn into the contrcl room during the postulated accident into a total effeclive dose equivalent (TEDE) dose.

The 30-day FHA dose to the conirol room operator from the internal cloud associated with the FHA is c,3lculated to be 2.69 rem TEOE.

The onsile control room operator dose criterion established by Reference 8-36 for this accident is that the total contro!! room cperator dose should be less than the to CFR 50.67 guidelines; i.e.* that the total dose should be less than 5 rem TEDE.

3.0 OPERATOR ACTIONS 3.2.3 IF new or spent fuel damage is suspected, THEN PERFORM the following:

1.

PLACE any fuel that is being moved in a safe condition.

2.

SECURE further fuel movement.

3.

EVACUATE personnel from the following areas:

Refueling Floor 0

Drywell, if occupied Reactor Building, -17 Elev., if Shutdown Cooling in service.

ECCS Pipe Tunnel U

Any area determined to have the potential for high radiation.

4.

ISOLATE Secondary Containment.

5.

START Standby Gas Trains.

U 3.2.4 NOTIFY E&RC to perform the following as necessary:

Area radiation survey U

Air sampling U

Smear survey U

Posttheaffectedareaasnecessary U

Control access to reduce exposure and U

contamination.

DADP-05.0 Rev 23 Page 4 of 10 3.0 OPERATOR ACTIONS 3.2.3 IF new or spent fuel damage is suspected, THEN PERFORM the following:

1.

PLACE any fuel that is being moved in a safe condition.

D

2.

SECURE further fuel movement.

D

3.

EVACUATE personnel trom the following areas:

Refueling Floor D

Drywell, if occupied D

Reactor Building, -17' Elev., if Shutdown Cooling in D

service.

ECCS Pipe Tunnel D

Any area determined to have the potential for high D

radiation.

4.

ISOLATE Secondary Containment D

5.

START Standby Gas Trains.

D 3.2.4 NOTIFY E&RC to perform the following as necessary:

Area radiation survey D

Air sampling D

Smear survey D

Post the affected area as necessary D

Control access to reduce exposure and D

contamination.

IOAOP-05.0 Rev. 23 Page 4 of 10 I

4.0 GENERAL DISCUSSION Liquid radioactive spills may be caused by valve packing leaks, leaky fittings, system leaks, or system draining evolutions. Liquids spills should be covered with an absorbent material to minimize the spread of contamination. Solid spills may be caused by leaks from the containers or process streams which handle radioactive material or by an accident during the transport of new or spent fuel, radioactive sources, or other solid radioactive materials. Solid spills should be covered by a damp material to minimize the spread of airborne contamination. A spill of highly radioactive solid materials such as spent resin, filter sludge, neutron sources, or irradiated reactor internal components may create a serious personnel exposure problem and should be handled with extreme caution. In addition, high radiation and high airborne activity may accompany a spill.

High airborne activity may occur from reactor coolant leaks, coolant spills, radwaste leaks, sampling, grinding, draining, and other maintenance. High airborne activity in the turbine buildings may require ventilation shutdown or realignment to the recirculation lineup if the ventilation systems are operating in the once-through lineup.

High radiation levels may be caused by radiation streaming, loss of or degraded shielding, fuel element damage, high airborne activity, coolant spills, or radiography.

New or spent fuel damage may occur within the plant during fuel handling operations. Fuel may be damaged if it is inadvertently dropped or allowed to collide with objects. Damage may also be sustained if heavy objects (shipping casks, reactor vessel head, drywell head, etc.) are allowed to fall on the fuel. These accidents may release a substantial amount of radioactive noble gases, halogens, and other fission products into the secondary containment. The secondary containment will be automatically isolated due to high radiation at its ventilation exhaust plenum. Although Standby Gas Treatment (SBGT) System will reduce the activity released to the environs, there is a chance that technical specification limits may be exceeded.

The dose consequence calculation for the fuel handling accident does not credit the secondary containment or automatic CREVS start, however, it does assume that CREVS is manually initiated within 20 minutes of a dropped(damaged fuel assembly. Based on this analysis, Technical Specifications do not require secondary containment or CREVS automatic initiation instrumentation except during Modes 1, 2, or 3 or during operations with the potential to drain the Reactor vessel.

OAOP-05.0 Rev. 23 Page 8 of 10 4.0 GENERAL DISCUSSION Liquid radioactive spills may be caused by valve packing leaks, leaky fittings, system leaks, or system draining evolutions. Liquids spills should be covered with an absorbent material to minimize the spread of contamination. Solid spills may I)e caused by leaks from the containers or process streams which handle radioactive material or by an accident during the transport of new or spent fuel, radioactive sources, or other solid radioactive materials. Solid spills should be covered by a damp material to minimize the spread of airborne contamination. A spill of highly radioactive solid materials such as spent resin, filter sludge, neutron sources, or irradiated reactor internal components may create a serious personnel exposure problem and should be handled with extreme caution. In addition, high radiation and higl1 airborne acUvity may accompany a spill.

High airborne activity may occur from reactor coolant leaks, coolant spills, radwaste leal,s, sampling, grinding, draining, and other maintenance. High airborne activity in the turbine buildings may require ventilation shutdown or realignment to the recirculation lineup if the ventilation systems are operating in the once-through lineup.

High radiation [evels may be caused by radiation "streaming," loss of or degraded shielding, fuel element damage, high airi)orne activity, coolant spillS, or radiography.

New or spent fuel damage may occur within the plant during fuel handling operations. Fuel may be damaged if it is inadvertently dropped oral[owed to collide with objects. Damage may also be sustained if heavy objects (shipping casks, reactor vessel head, dlY'Nell head, etc.) are allowed to fall on the fuel. These accidents may release a substantial amount of radioactive noble gases, halogens, and other fission products into the secondary containment The secondary containment will be automatically isolated due to high radiation at its ventilation exhaust plenum. Although Standby Gas Treatment (SBGT) System will reduce the activir; released to the environs, there is a chance that technical speCification limits may be exceeded.

The dose consequence calculation for the fuel handling accident does not credit the secondary containment or automatic CREVS start, however, it does assume that CREVS is manually initiated within 20 minutes of a droppedfdamaged fuel assembly. Based on this analysis, Technical Specifications do not require secondary containment or CREVS automatic initiation instrumentation except during Modes 1, 2, or 3 or during operations with the potential to drain the Reactor vessel.

IOAOP-05.0 Rev. 23 Page B of 10 I

UPDATED FSAR Revion:

21 CP&L EzIGIIIEERED SAFETY FEA TURES Chapter:

3 CHAPTER 6 TABLES 1 of 1 TABLE 6-28 Control Room Design Inputs Design Basis Accidents Control Room 1.

Control room habitabi!ity vo ume

2g8,650 f 2.

Assumed unfiltered inIeakage 10.000 crn Control Room Ventilation 1.

Normal mode operation outside air intake 2,1C0 cm 2.

Normal mode roughing filter, aerosol removal 0%

3.

Normal mode roughing filter, elemental iod:ne removal 0%

4.

Normal mode roughing filter, organic iodine removal 0%

5.

Time of manual switchover from normal to radiation mode 20 minutes 0.

Radiation mode operation outsde sir ntake I.500 cfm 7.

Radiation mode HEPA ft ter. aerosol removal Radiation mode charcoal filter, elemental iodine removal Radiation mode charcoal fiter, organic iodine removal 10.

Radiation train charcoal depth 2 inches 11.

Radiation mode filtered recrculated airflow 40 cfm 12.

Radiation mode aerosol iodine removal 13.

Radiation mode elemental iodine removal 14.

Radiation mode organic iodne removal NOTES

Sensitivity cases using 3.00 cfm and 0 cThi unfiltered outside air inleakage into the control room were also evaluated. The 10,000 cfm unfiltered inleakage case is bounding for the LOCA, the FHA, and the CRDA events.

For the MSLB event, 0 cfm unfiltered outside air nleakage represents the bounding vaiue.

For the MSLB event, a 5ensitlvity study was performed, isolating the control room at various times between 5.0 seconds and 30 days.

TABLE 6-28 UPDA TED FSAR ENGmEERED SAFETY FEA TURES CHAPTER 6 TABLES Control Room Design Inputs - Design Basis Accidents e - roughing filter. aerosol removal

organic iodine removal

- aerosol iodine removal

- elemental iodine remollal NOTES Revision:

Chapter:

Page:

2gS.650 fl 10.000 cim' 2.100 cfm 0%

0%

20 minutes'"

1.500 cfm 95%

90%

2inehes 400 cfm 95%

90%

Sensitivity cases using 3.000 cfm a,nd 0 dm unfiliered outside air inleakage into the control room were also evaluated. The 10.000 cim unfiltered inleakage case is boundi,ng for the lOCA. the FHA. and the eRDA ellents.

For the MSLB ellent. 0 cfm unfiltered outside air inleakage represents the bounding value.

For the MSLB ellent. a sensitivity study was performed. isolating the contrel room at various times between 5.5 seconds and 30 days.

21 6

1 of

CREV System B 37.3 BASES BACKGROUND The CREV System is designed to maintain a habitable environment in the (connued}

CRE for a 30 day connuous occupancy after a DBA without exceeding 5 rem total effective dose equivalent (TEDE), A single CREV subsystem operating at a flow rate of 2200 cfm will slightly pressurize the CRE relative to outside atmosphere to minimize infiltration of air from surrounding areas adjacent to the CRE bounday. CREV System operation in maintaining CRE habitability is discussed in the UFSAR, Sections 6.4 and 9.4, (Refs. 1 and 2. respectively).

APPLICABLE The ability of the CREV System to maintain the habitability of the CRE SAFETY ANALYSES is an explicit assumption for the design basis accident presented in the UFSAR (Ref. 3). The radiation!smoke protection. mode of the CREV System is assumed (explicitly or implicitly) to operate following a DBA.

The radiological doses to the CRE occupants as a result of a DBA are summarized in Reference 3. Postulated single active failures that may cause the loss of outside or recirculated air from the CRE are bounded by BNP radiological dose calculations for CRE occupants.

Brunswick Unit 2 S 3.7,3-2 Revision No. 61 Categories K/A:

S295023G2.04.49 Tier/Group:

T1G1 RO Rating:

4.6 SRO Rating:

4.4 LP Obj:

CLSLP.3O2J*O2 Source:

NEW Cog Level:

HIGH Category 8:

BASES BACKGROUND (continued}

CREV System B 3.7.3 The CREV System is designed to maintain a habitable environment in the CRE for a 30 day continuous occupancy after a DBA without exceeding 5 rem total effecti.... e dose equivalent {TED E). A single CREV subsystem operating at a f10Vl rate of s: 2200 cfm ',viii sligh!ly pressurize the CRE relative to outside atmosphere to minimize infiltration of air from surrounding areas adjacent to the CRE boundary. CREV System operation in maintaining CRE habitability is discussed in the UFSAR, Sections 6.4 am! 9.4, (Refs. *1 and 2, respectively).

APPLICABLE The ability of the CREV System to maintain the habitability of the CRE SAFETY.ANAL YSES is an explicit assumption ror the design basis accident presented in the UfSAR (Ref. 3}. The radiation/smoke protection mode ofthe CREV System is assumed (explicitly or implicitly) to operate fol!owing a DBA.

The radiological doses to the CRE occupants as a result of a DBA are summarized in Reference 3. Postulated single active failures that may cause the loss of outside or recirculated air from the CRE are bounded by BNP radiological dose calculations for CRE occupants.

Brunswick Unit 2 B 3.7.3-2 Re.... ision No. 61 Categories KIA:

S295023G 2.04.49 Tier / Group: TIGl RORating:

4.6 SRORating

4.4 LP Obj:

CLS-LP-302-J*02 Source:

NEW Cog Level:

HIGH Category 8:

88. An event on Unit One has resulted in the following plant conditions:

Reactor pressure 1000 psig Reactor Water Level 120 inches Control Rod Positions All unknown APRMs Downscale Drywell pressure 3 psig Supp. Pool pressure 2 psig Supp. Pool water temp 150° F Supp. Pool water level

-4 feet (Reference provided)

Which one of the following identifies the status of the Heat Capacity Temperature Limit (HCTL) and the required procedure for reactor pressure control?

HCTL Pressure Control Leg of Procedure A. has been exceeded RVCP B has been exceeded LPC C. has NOT been exceeded RVCP D. has NOT been exceeded LPC

88. An event on Unit One has resulted in the following plant conditions:

Reactor pressure Reactor Water Level Control Rod Positions APRMs Drywell pressure Supp. Pool pressure Supp. Pool water temp Supp. Pool water level (Reference provided) 1000 psig 120 inches All unknown Downscale 3 psig 2 psig 150 0 F

-4 feet Which one of the following identifies the status of the Heat Capacity Temperature Limit (HCTL) and the required procedure for reactor pressure control?

HCTL Pressure Control Leg of Procedure A. has been exceeded RVCP By has been exceeded LPC C. has NOT been exceeded RVCP D. has NOT been exceeded LPC

Feedback K/A: S295026 A2.03 Ability to determine andlor interpret the following as they apply to SUPPRESSION POOL HIGH WATER TEMPERATURE:

Reactor pressure (CFR: 41.10/43.5/45.13)

RO/SRO Rating: 3.9/4.0 Objective: CLSLP300L*05a

05. Given the PCCP, determine the appropriate actions if any of the following limits are approached or exceeded:

a. Heat Capacity Temperature Limit.

Reference:

Heat Capacity Temperature Graph only is given to examinee PCCP.

Cog Level: High Explanation:

HCTL has been exceeded. With rods unknown the operator would be in LPC.

Distractor Analysis:

Choice A: Plausible because rods are unknown, would be in LPC.

Choice B: Correct Answer Choice C: Plausible because HCTL has been exceeded. rods are unknown, would be in LPC Choice D: Plausible because HCTL has been exceeded.

SRO Only Basis: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations (43(b)(5)

Notes Feedback KIA: S295026 A2.03 Ability to determine and/or interpret the following as they apply to SUPPRESSION POOL HIGH WATER TEMPERATURE:

Reactor pressure (CFR: 41.10 143.5 145.13)

RO/SRO Rating: 3.9/4.0 Objective: ClS-lP-300-l *05a

05. Given the PCCP, determine the appropriate actions if any of the following limits are approached or exceeded:

a. Heat Capacity Temperature Limit.

Reference:

Heat Capacity Temperature Graph only is given to examinee PCCP.

Cog level: High Explanation:

HCTl has been exceeded. With rods unknown the operator would be in lPC.

Distractor Analysis:

Choice A: Plausible because rods are unknown, would be in lPC.

Choice B: Correct Answer Choice C: Plausible because HCTl has been exceeded. rods are unknown, would be in lPC Choice D: Plausible because HCTl has been exceeded.

SRO Only Basis: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations (43(b)(5)

Notes

I I,,C CJ I

j) ti mm c

a 8 8 SUPPRESSION POOL WATER TEMPERATURE (°F)

C)

ç)ç)QQ C)

-4

0 rnti Z

0

--9 0

Z 0

rn rn cn r>

rn C) rn-n 0

0 om m

mm UI I

T1

-o 00 COO m

r-

.rngm CO rn C

0 It rn

-Ui Cl) o

11[

m.,..

D IE[

r rn U

0 TEl W

liii I

I I 1 z <

i-rn tit-r tW mm z

titt llttVtt rmi m

F

o ID 0

C Cl C

LII Cl 0 Cl UI CD fl 1flfll1

-I

---4 g

ATTACHMENT 5 Page '18 of 27 FIGURE 3 Heat Capacity Temperature Limit L1.

~ 220 W

$ 210

~

=f::l=Il

!;;c

=~I n:: 200 UNSAFE ABOVE ~

SELECTED LINE ~

~ 190 5j 180 l-n:: 170 W

~ 160 s:

..J 150 140 o o D..

Z o

=f:: f::

SAFE BELOW 130 =~~ SELECTED LINE (I) 120 (I)

~ 110 D..

D.. 100

J (I)

(-) 0.25 FT

(-) 1.25 FT

(-) 2.50 FT

~~~ (-) 3.25 FT

S:i~

=t=~ (-) 4.25 FT

=I=~

St=~

,-p.,~

=I::~ (-) 5.50 FT

=~~

=~I=

1=1

=I=~

,-I-f-I

-1,150 100 300 500 700 900 1,100 o

200 400 600 800 1,000 REACTOR PRESSURE (PSIG)

SUPPRESSION POOL WATER TEr.... 1PERATURE IS DETERMINED BY:

CAC-TR-4426-*1A, POINT WTR AVG OR CAC-TR-4426-2A, POINTWTRAVG OR COrvlPUTER POINT G050 OR COMPUTER POINT G051 OR CAC-TY -4426-1 OR CAC-TY -4426-2 SELECT GRAPH LINE IMMEDIATELY BELOW SUPPRESSION POOL WATER LEVEL AS THE LIMIT.

I OEOP-01-UG Rev. 55 Page 78 of 151 I

YES BNP VOLV1 IEOP-Ot-LPC REldlStONNO 9 NO MAiNTAIN IIEACTORPRE5S BELOW TIlE HEAT CAPACfY TEMP UM1 1RRESPECTPJE OF THE RESULTING tOOLDOWN RATE RCWI1 UNIT i ONLY MAINTAIN REACTOR PRESS BELOW THE HEAT CAPACITY TEMP Ur.tIT IRRESPECTIVE OFTHERESULTING COOLOOWN RATE

INITIATEA REACTOR SCRAM AND ENTER EOP-9i SPIT-99 REDUCE REACTOR PRE PER THE RCIP SECTION OF EOP-91 AS NECESSARY TO REMAIN IN SAFE REGION OF HEAT CAPACITf TEMP UMIT SPIT-b

/

CONSIDERANTICIRATIONOF EMERGENCY DEPRESSURIZA11ON

\\

PERRCIPSECTIONOF

\\

REACTOR VESSEL CONTROL

\\ PROCEDURE{EOP.01. RVCP)

HCTL (MERGENCY DEPRESSURI THE REACTOR PER THE RCIP SECTION OF EOP-91 SPIT-IS BNPVOL-VI OEOP-02-PCCP REVISION NO 10 Categories K/A:

S295026 A2.03 Tier / Group:

T1G1 RO Rating:

3.9 SRO Rating:

4.0 LP Obj:

CLSLP300L*05A Source:

PREV Cog Level:

HIGH Category 8:

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SPIT-13 BNP VOL-VI OEOP PCCP Categories KIA:

RORating:

LP Obj:

Cog Level:

REVISION NO: 10 S295026 A2.03 3.9 CLS-LP-300-L *05A HIGH Tier / Group: TIG!

SRORating: 4.0 Source:

PREY Category 8:

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89. Unit Two is operating at rated power when half of the Drywell (DW) Coolers are lost.

Which one of the following correctly completes the statements below?

(Assume initial DW and Suppression Pool pressures are equal)

As DW temperature rises, Suppression Pool pressure will rise at (1)

DW pressure.

If DW Air Temperature is not restored to within the LCO limit in (2) hours, the Unit is required to be in Mode 3 within the following 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months per TS 3.6.1.4 (Drywell Air Temperature).

A. (1) the same rate as (2) 8 B. (1) the same rate as (2) 12 C (1) a slower rate than (2) 8 D. (1) a slower rate than (2) 12

89. Unit Two is operating at rated power when half of the Orywell (OW) Coolers are lost.

Which one of the following correctly completes the statements below?

(Assume initial OW and Suppression Pool pressures are equal)

As OW temperature rises, Suppression Pool pressure will rise at (1)

OW pressure.

If OW Air Temperature is not restored to within the LCO limit in (2) hours, the Unit is required to be in Mode 3 within the following 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months per TS 3.6.1.4 (Orywell Air Temperature).

A. (1 ) the same rate as (2) 8 B. (1 ) the same rate as (2) 12 Cy (1) a slower rate than (2) 8 O. (1 ) a slower rate than (2) 12

Feedback K/A: S295028 A2.05 Ability to determine andlor interpret the following as they apply to HIGH DRYWELL TEMPERATURE:

Torus/suppression chamber pressure: Plant-Specific (CFR: 41.10 /43.5 /45.13)

RO/SRO Rating: 3.6/3.8 Objective: CLSLP004A*1 5a

15. Given plant conditions, determine the effects that the following will have on the Primary Containment, Primary Containment Ventilation and Primary Containment Monitoring:

a. Loss of Drywell cooling.

Reference:

SD-04, Revision 5, Page 25 TS Cog Level: High Explanation:

Reduced DW cooling or rising DW temperature results in DW pressure increases whose severity is dependent upon plant conditions. OAOP-14.0, Abnormal Primary Containment Conditions provides guidance on indications to be monitored and actions to be taken which include verification of cooling system lineups and reductions in power to maintain average temperature below 150°F. Failure to accomplish this may require entry into the OEOP-02-PCCP Primary Containment Control.

Elevated DW temperature causes DW pressure to rise. As DW pressure rises, SP water level rises causing a rise in SP pressure. Due to the downcomers extending 3 feet below the surface of the SP water level a differential pressure will always exist. Temperature response is different from LOCA response due to steam AND non-condensibles being forced into the SP

- steam condensing and non-condensibles collecting in SP air space.

TS 3.6.1.4 (DW Air Temperature) limit of < 150°F, CONDITION A - Drywell average air temperature not within limit, REQUIRED ACTION A.1 Restore drywell average air temperature to within limit has a COMPLETION TIME of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

If temperature is not restored to.

150°F, CONDITION B, REQUIRED ACTION 8.1 Be in MODE 3 has a COMPLETION TIME of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Distractor Analysis:

Choice A: Plausible because SP pressure is changed by the change in SP level only vs pressure, steam, and non-condensibles during a LOCA. The SP air space temperature is in equilibrium with SP water temperature (95°Fmax during normal operations) rising DW pressure would have a direct impact on SP level. However during temperature only (no steam), the DW pressure increase is cushioned by SP water, small changes in SP water level provides small change in SP pressure.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to restore temperature is correct.

Choice B: Plausible because SP pressure is changed by the change in SP level only vs pressure, steam, and non-condensibles during a LOCA. The SP air space temperature is in equilibrium with SP water temperature (95°Fmax during normal operations) rising DW pressure would have a direct impact on SP level. However during temperature only (no steam), the DW pressure increase is cushioned by SP water, small changes in SP water level provides small change in SP pressure.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is the time required to get to MODE 3 if not restored within the required Completion Time.

Choice C: Correct Answer Choice D: Plausible because rising at a slower rate is correct and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is the time required to get to MODE 3 if not restored within the required Completion Time.

SRO Only Basis: Application of required actions (Section 3) and surveillance requirements (Section 4) in accordance with rules of application requirements (Section 1). (43(b)(2)

Feedback KIA: S295028 A2.05 Ability to determine and/or interpret the following as they apply to HIGH ORYWELL TEMPERATURE:

Torus/suppression chamber pressure: Plant-Specific (CFR: 41.10/43.5/45.13)

RO/SRO Rating: 3.6/3.8 Objective: CLS-LP-004-A *15a

15. Given plant conditions, determine the effects that the following will have on the Primary Containment, Primary Containment Ventilation and Primary Containment Monitoring:

a. Loss of Drywell cooling.

Reference:

SD-04, Revision 5, Page 25 TS Cog Level: High Explanation:

Reduced OW cooling or rising DW temperature results in DW pressure increases whose severity is dependent upon plant conditions. OAOP-14.0, Abnormal Primary Containment Conditions provides guidance on indications to be monitored and actions to be taken which include verification of cooling system lineups and reductions in power to maintain average temperature below 150°F. Failure to accomplish this may require entry into the OEOP-02-PCCP Primary Containment Control.

Elevated DW temperature causes DW pressure to rise. As DW pressure rises, SP water level rises causing a rise in SP pressure. Due to the downcomers extending 3 feet below the surface of the SP water level a differential pressure will always exist. Temperature response is different from LOCA response due to steam AND non-condensibles being forced into the SP - steam condensing and non-condensibles collecting in SP air space.

TS 3.6.1.4 (DW Air Temperature) limit of ~ 150°F, CONDITION A - Drywell average air temperature not within limit, REQUIRED ACTION A.1 Restore drywell average air temperature to within limit has a COMPLETION TIME of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . If temperature is not restored to ~

150°F, CONDITION B, REQUIRED ACTION 8.1 Be in MODE 3 has a COMPLETION TIME of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Distractor Analysis:

Choice A: Plausible because SP pressure is changed by the change in SP level only vs pressure, steam, and non-condensibles during a LOCA. The SP air space temperature is in equilibrium with SP water temperature (95°Fmax during normal operations) rising DW pressure would have a direct impact on SP level. However during temperature only (no steam), the DW pressure increase is cushioned by SP water, small changes in SP water level provides small change in SP pressure.

8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to restore temperature is correct.

Choice B: Plausible because SP pressure is changed by the change in SP level only vs pressure, steam, and non-condensibles during a LOCA. The SP air space temperature is in equilibrium with SP water temperature (95°Fmax during normal operations) rising DW pressure would have a direct impact on SP level. However during temperature only (no steam), the DW pressure increase is cushioned by SP water, small changes in SP water level provides small change in SP pressure.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is the time required to get to MODE 3 if not restored within the required Completion Time.

Choice C: Correct Answer Choice D: Plausible because rising at a slower rate is correct and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is the time required to get to MODE 3 if not restored within the required Completion Time.

SRO Only Basis: Application of required actions (Section 3) and surveillance requirements (Section 4) in accordance with rules of application requirements (Section 1). (43(b)(2)

Notes 3.6 CONTAINMENT SYSTEMS 3.6.1.4 Drvwetl Air Temperature Drvwell Air Temperature 3.6.1.4 LCO 3.6.1.4 Drywell average air temperature shall be 150°F.

APPLICABIUTY:

MODES 1,2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Drywell average air A. 1 Restore drywell average air 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months temperature not within limit, temperature to within limit.

B.

Required Action and B.l Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met.

B.2 Be in MODE 4.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 4.

Drywell Temperature A loss of RBCCW to the drywell results in drywell temperature and pressure increases whose severity is dependent upon plant conditions. OAOP-14.0, Abnormal Primary Containment Conditions provides guidance on indications to be monitored and actions to be taken which include verification of cooling system lineups and reductions in power to maintain average temperature below 150°F.

Failure to accomplish this may require entry into the OEOP-02-PCCP Primary Containment Control.

Loss of RBCCW to the Drywell due to all RBCCW pumps tripping SD-21 Rev. 5 Page 25 of 42 Categories KJA:

RO Rating:

LP Obj:

Cog Level:

S295028 A2.05 CLSLPOO4A* I 5A HIGH Tier / Group:

SRO Rating:

Source:

Category 8:

T1G1 3.8 NEW YF 3.6 Notes Drywell Air Temperature 3.6.1.4 3.6 CONTAINMENT SYSTEMS 3.6.'1.4 Drywell Air Temperature LCO 3.6. '1.4 Drywell average air temperature shall be s '150°F.

APPLICABILITY:

MODES '1,2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A

DrY'Nell average air A.-I Restore drywell average air 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months temperature not within limit.

temperature to within limit B.

Required Action and B.-I Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met AND 1 SO-21 Categories KIA:

RORating:

LP Obj:

Cog Level:

B.2 Be in MODE 4.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

4.

Orywell Temperature A loss of RBCCW to the drywell results in drywell temperature and pressure increases whose severity is dependent upon plant conditions. OAOP-14.0, Abnormal Primary Containment Conditions provides guidance on indications to be monitored and actions to be taken which include verification of cooling system lineups and reductions in power to maintain average temperature below '150°F.

Failure to accomplish this may require entry into the OEOP-02-PCCP Primary Containment Control.

Loss of RBCCW to the Orywell due to all RBCCW pumps tripping S295028 A2.05 3.6 CLS-LP-004-A*15A mGH Rev. 5 Tier / Group: T1 G 1 SRO Rating:

3.8 Source

NEW Category 8:

YF Page 25 of 421

90. The following plant conditions exist on Unit Two:

- An ATWS with a spurious Group I Isolation has occurred

- HPCI is injecting to the RPV to maintain RPV level

- SUPPRESSION CHAMBER LVL HI-HI is in alarm Which one of the following identifies the action required for long term HPCI system operation and the reason for this action?

When suppression pool temperature reaches 140°F, (1) to prevent (2)

A. (1) lower HPCI flow to less than 2000 gpm lAW LPC (2) pump bearing damage B. (1) lower HPCI flow to less than 2000 gpm lAW LPC (2) a loss of NPSH C (1) defeat the automatic suction transfer logic and transfer HPCI suction to the CST lAW SEP-10 (2) pump bearing damage D. (1) defeat the automatic suction transfer logic and transfer HPCI suction to the CST lAW SEP-10 (2) a loss of NPSH

90. The following plant conditions exist on Unit Two:

- An ATWS with a spurious Group I Isolation has occurred

- HPCI is injecting to the RPV to maintain RPV level

- SUPPRESSION CHAMBER L VL HI-HI is in alarm Which one of the following identifies the action required for long term HPCI system operation and the reason for this action?

When suppression pool temperature reaches 140°F, (1) to prevent (2)

A. (1) lower HPCI flow to less than 2000 gpm lAW LPC (2) pump bearing damage B. (1) lower HPCI flow to less than 2000 gpm lAW LPC (2) a loss of NPSH C~ (1) defeat the automatic suction transfer logic and transfer HPCI suction to the CST lAW SEP-10 (2) pump bearing damage D. (1) defeat the automatic suction transfer logic and transfer HPCI suction to the CST lAW SEP-10 (2) a loss of NPSH

Feedback K/A: 295029 G2.01.07 Ability to evaluate plant performance and make operational judgments based on operating characteristics, reactor behavior, and instrument interpretation.

High Suppression Pool Water Level (CFR: 41.5/43.5/45.12/45.13)

ROISRO Rating: 4.4/4.7 Objective:

LOl-CLS-LP-0l 9-A, 26g: Given plant conditions and one of the following events, use plant procedures to determine the actions required to control and/or mitigate the consequences of the event:

High Suppression Pool water level.

Reference:

001-37.5 SUPPRESSION CHAMBER LVL HI-HI APP Cog Level

- High Explanation: HPCI system is normally aligned to the CST, with the torus high water level this transfers to the torus. this meets the KA by having to evaluate the suction path has transferred to the torus and the operational implications of the high torus tempeature on continued operation of the HPCI system. this requires the suction to be transferred back to the CST lAW SEP-I 0.

From : The lube oil and control oil for both HPCI and RCIC are cooled by the water being pumped. Very high lube oil temperatures can result in loss of lubricating qualities in the oil and thus cause damage to the bearings. Suction for HPCI and RCIC is aligned to the Condensate Storage Tank (CST) if it is available. The HPCI automatic suction transfer logic can be defeated to allow this lineup if necessary provided suppression pool temperature is approaching 140°F.

Distractor Analysis:

Choice A: Plausible because reducing flow would be a correct action if HPCI NPSH was the concern. At high temperatures with low level in the torus this could be a correct action. Pump bearing damage is a correct statement.

Choice B: Plausible because reducing flow would be a correct action if HPCI NPSH was the concern. At high temperatures with low level in the torus this could be a correct action. a loss of NPSH would be correct for the reason to reduce flow.

Choice C: Correct answer, see explanation Choice D: Plausible because transferring the suction is correct but the concern is for pump bearing damage.

SRO Basis: 10 CFR 55.43(b)-S Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Feedback KIA: 295029 G2.01.07 Ability to evaluate plant performance and make operational judgments based on operating characteristics, reactor behavior, and instrument interpretation.

High Suppression Pool Water Level (CFR: 41.5/43.5/45.12/45.13)

RO/SRO Rating: 4.4/4.7 Objective:

LOI-CLS-LP-019-A, 26g: Given plant conditions and one of the following events, use plant procedures to determine the actions required to control and/or mitigate the consequences of the event:

High Suppression Pool water level.

Reference:

001-37.5 SUPPRESSION CHAMBER LVL HI-HI APP Cog Level - High Explanation: HPCI system is normally aligned to the CST, with the torus high water level this transfers to the torus. this meets the KA by having to evaluate the suction path has transferred to the torus and the operational implications of the high torus tempeature on continued operation of the HPCI system. this requires the suction to be transferred back to the CST lAW SEP-10.

From: The lube oil and control oil for both HPCI and RCIC are cooled by the water being pumped. Very high lube oil temperatures can result in loss of lubricating qualities in the oil and thus cause damage to the bearings. Suction for HPCI and RCIC is aligned to the Condensate Sto(age Tank (CST) if it is available. The HPCI automatic suction transfer logic can be defeated to allow this lineup if necessary provided suppression pool temperature is approaching 140°F.

Distractor Analysis:

Choice A: Plausible because reducing flow would be a correct action if HPCI NPSH was the concern. At high temperatures with low level in the torus this could be a correct action. Pump bearing damage is a correct statement.

Choice B: Plausible because reducing flow would be a correct action if HPCI NPSH was the concern. At high temperatures with low level in the torus this could be a correct action. a loss of NPSH would be correct for the reason to reduce flow.

Choice C: Correct answer, see explanation Choice 0: Plausible because transferring the suction is correct but the concern is for pump bearing damage.

SRO Basis: 10 CFR 55.43(b )-5 Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

Notes MAXIMUM INJECTION

.,VSTEM PRESSURE (P5I)

CONDENSATE1FEEDWATER 1250 CRt FLOW NAY OE 1490 MAXIMIZED PER EOP0i. SEP-00 RCIC WITH SUCTION FROM CST IF AVAILABLE. DEFEAT LOW REACTOR 1190 PRESS AND HIGH AREA TEMPERATURE ISOLATION LOGIC IF NECESSARY PER CIRCUW ALTERATION PROC EDURE c,.oISEP-io HPCI WITH SUCTION FROM 1250 OST IF AVAILAbLE, OFIAT 1IPCI NI SUPPRESSION POOL I.EVEL SUCflO1 TRANSFER AND I-IGt-I AREA TEMPERATURE ISOLATION LOGIC IF NECESSARY PER CIRCUIt ALTERATION PROCEDURE EOP.0I-SEP-10)

IPUI-ESTALI5H RHR SERVICE 200 WATER FLOW AS SOON AS POSSIBLE CAUTION OPERATION OF HPGI OR ROIG WITH SUCTION TEMPERATURES ABOVE 140? MAY RESULT IN EQUIPMENT DAMAGE RC1L-23 Distractor plausibility:

CAUTION I

HPCI FLOW ABOVE 2000 GPM WITH SUCTION FROM CST AND GST LEVEL BELOW 5 FEET MAY RESULT IN VORTEXNG AND EQUIPMENT DAMAGE I

RCFL Categories K/A:

295029 G2.01.07 Tier/Group:

T1G2 RO Rating:

4.4 SRO Rating:

4.7 LP Obj:

19-A 26G Source:

BANK Cog Level:

HIGH Category 8:

TABLE I M1MUM SYSTEM INJECTION PRESSURES Notes 1

MAXIMUM SYSTEM INJECTlD.'I PRESSURES SYSTEM CONDENSATEIFEEDWA.TER CRD FI.OW NAY DIl:

MAXIMIZED PER eOP.Of. SEP. 09 RCiC WITH SUCTION FROM CST IF AVAILABLE. DEFEAT LOW REA.CTOR PRESS AND HIGH AREA TEMPERATURE ISOLATION LOGIC IF NECESSARY PER *CIRCUIT ALTERATION PROCEDURE" leop* Ot* sep* 10)

HPCI WITH SUCTION FROM CST II' AVAILABLe. OeFeAT HP(;I HI SUI"PRI!$$ION POOt. I.I!Yf!1.

SUCTION TAANSFSR ANI) HIGH ARIOA TIOMPERATURS ISOLATION lOGIC If: NeCeSSARY PER *CIRCUIT ALTeRATION PROCEDURe"

~EOP* 01* SEP* 10) lPCI* ESTABLISH RHR SERVICE WATER FI.OW AS 500H AS POSSIBLE CAUTION ERATION OF HPCI OR RCI H SUCTION TEMPERATURE OVE 140*' MAY RESULT IN EQUIPMENT DAMAGE Distractor plausibility:

CAUTION HPCI FLOW ABOVE 2000 GPM WITH SUCTION FROM CST AND CST LEVEL BELOW 5 FEeT MAY RESULT IN VORTEX<<NG AND EQUIPMENT DAMAGE Categories KIA:

RORating:

LPObj:

Cog Level:

295029 G2.01.07 4.4 19-A 26G HIGH MAXIM LIM INJECTION PRESSURE (PSIG) 1250 141)0 1190 12110 200 Tier / Group: T1 G2 SRO Rating:

4.7 Source

BANK Category 8:

91. Which one of the following identifies the controlling document and the required action to be taken if SJAE Offgas Radiation monitor readings increase 50% during steady state rated power operation?

Notify E&RC to perform the Surveillance I Test Requirement (SRITR) required by (1)

, which confirms the SJAE release rate is within limits within (2) following the monitor reading increase.

A. (1) ODCM 7.3.2, Radioactive Gaseous Effluent Monitoring Instrumentation (2) 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months B. (1) ODCM 7.3.2, Radioactive Gaseous Effluent Monitoring Instrumentation (2) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C (1) T.S. 3.7.5, Main Condenser Offgas (2) 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months D. (1) T.S. 3.7.5, Main Condenser Offgas (2) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

91. Which one of the following identifies the controlling document and the required action to be taken if SJAE Offgas Radiation monitor readings increase 50% during steady state rated power operation?

Notify E&RC to perform the Surveillance I Test Requirement (SRITR) required by (1)

,which confirms the SJAE release rate is within limits within (2) following the monitor reading increase.

A. (1) ODCM 7.3.2, Radioactive Gaseous Effluent Monitoring Instrumentation (2) 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months B. (1) ODCM 7.3.2, Radioactive Gaseous Effluent Monitoring Instrumentation (2) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months C~ (1) T.S. 3.7.5, Main Condenser Offgas (2) 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months D. (1) T.S. 3.7.5, Main Condenser Offgas (2) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

Feedback K/A: S295038G 2.02.42 Ability to recognize system parameters that are entry-level conditions for Technical Specifications.

High Off-Site Release Rate (CFR: 41.7/41.10 / 43.2/43.3/45.3)

RO/SRO Rating: 3.9/4.6 Objective: CLSLP30*08

08. Given plant conditions and Technical Specifications, including the Bases, TRM, ODCM, and COLR, determine whether given plant conditions meet minimum Technical Specifications, TRM, or ODCM requirements associated with the Condenser Air Removal/Augmented Offgas System.

Reference:

101-03.1, Revision 10, Page 44, Item #57 (CODSR)

Cog Level: High Explanation:

NOTIFY E&RC to confirm release rate is within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months following a monitor reading increase of greater than or equal to 50% without an accompanying increase in thermal power. SR 3.7.5.1 Distractor Analysis:

Choice A: Plausible because the SJAE Rad Monitor operability is required by ODCM 7.3.2 and 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is correct.

Choice B: Plausible because the SJAE Rad Monitor operability is required by 00CM 7.3.2 and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is a timeframe for another Required Action in this spec.

Choice C: Correct Answer Choice D: Plausible because TS 3.5.7 is correct and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is a timeframe for another Required Action in this spec.

SRO Only Basis: Application of Surveillance Requirements and timeframe greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Notes Feedback KIA: S29503BG 2.02.42 Ability to recognize system parameters that are entry-level conditions for Technical Specifications.

High Off-Site Release Rate (CFR: 41.7/41.10/43.2/43.3/45.3)

RO/SRO Rating: 3.9/4.6 Objective: CLS-LP-30*OB OB. Given plant conditions and Technical Specifications, including the Bases, TRM, ODCM, and COLR, determine whether given plant conditions meet minimum Technical Specifications, TRM, or ODCM requirements associated with the Condenser Air Removal/Augmented Offgas System.

Reference:

101-03.1, Revision 10, Page 44, Item #57 (CODSR)

Cog Level: High Explanation:

NOTIFY E&RC to confirm release rate is within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months following a monitor reading increase of greater than or equal to 50% without an accompanying increase in thermal power. SR 3.7.5.1 Distractor Analysis:

Choice A: Plausible because the SJAE Rad Monitor operability is required by ODCM 7.3.2 and 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is correct.

Choice B: Plausible because the SJAE Rad Monitor operability is required by ODCM 7.3.2 and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is a timeframe for another Required Action in this spec.

Choice C: Correct Answer Choice D: Plausible because TS 3.5.7 is correct and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is a timeframe for another Required Action in this spec.

SRO Only Basis: Application of Surveillance Requirements and timeframe greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Notes

ATTACHMENT 1 Page 39 of 67 ITEM SI-ilF CHECK LIST NOTES OPER FREQ TIME TSOPER NO.

MODE LIMITS RECORD SJAE OFF(4S RAD MONiTOR DD

1. 2. 3 b

07-13 012-RM-K60tA. NOTIFY E&RC to confirm release rate is within lmits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months oIIowing a monitor reading increase of greater than or equal to 50% without an l3-1 accompanying increase in thermal pcwer.

SR 3.7.5.1 RECORD S4E OFFGAS R40 MON.TOR CD

1. 2. 3 07-12 D12-RM-K6018. NOTIFY E&RC to confirm reLease rate is within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months following a nionitor reading increase of greater than or equal to 50% without an accompanying increase in thermal pcf.ver.

SR 3.7.5.1 PERFORM channel check utilizing the

07-13 Reference calculabon on Table I SJAE OFF-GAS RAE) calcufaton on MONITORS 012-RM-keoIA and B 00CM Table I TR 7.3.2-1 FunctionS, TR 7.3.2.1 PERFORM channel check on SERViCE R

c 07-13 channel WATER EFFLLJENTRAD MONITOR operabe 012-RM-K605. 00CM Tabie 7,3. 1-i Function 3, TR 7.3.1.1 i

PERFORM channel check on RAE)WASTE 8

c 07-13 channel EFFLUENT RAD MONITOR D12-RM-K6C4 operabe on Control Room Panel 2-H12-P804 with recorder D12-ROO1 on XU-2. CCCM Tab!e 7.3.1-i, Item 1. TR7.3.l.I During operation of the main condenser air ejector.

SHIFT Dayshift BRUNSWICK STEAM ELECTRIC PL4NT DAILY SURVE1LLANCE REPORT CONTROL OPERATORS 101-03.1 Rev. 101 ITEM SHIFT CHECK LIST NOlES NO.

57 RECORD SJAE OFFGAS RADMONITOR DD D12-RM-K6Cl"IA. NOTIFY E&RC to confilm rel~ase rate is within limits,... ijhin 4 hrurs follO\\lotng a monitor reading increase o*f greater than or equal to 50% without an accompanying increase in thermal pow~r.

SR3.7.5.1 58 RECORD SJAE OFFGAS RAD MONITOR DD D12-RM-K601B. NOTIFY E&RC to confirm re!~ase rate is within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months follo',\\;ng a monitor reading increase of greater than or equal to 50% without an accompanying increase in thermal pow~r.

SR 3.7.5.1 59 PERFORM ohannel check utilizing the calculation on Table SJAE OFF-GAS RAD MONITORS D'12-RM-K601A and B ODCM TR 7.3.2-1 Function 6, rn 7.3.2.1 00 PERFORM channel cheok on SERVICE R

~\\-:41ER EFFLUENT RAD MONITOR D12-RM-K605, ODCM Table 7.3.1-1, Function 3, TR 7.3.1.1 61 PERFORM ohannel check on P.ADI*lIASTE EFFLUENT RAD MOM TOR D12-RM-K604 en Control Room Pan~12-H12-Pa04 'Qi1h recorder D'12-ROOt on XU-3, o!)CM Table 7.3.1-1, !t~m I, TR 7.3.1.1

'During operation of the main oondenser air ejector.

SHIFT Davshift 1'101-03.1 OPER MODE 1,2' 3' 1,2',3'

'6 6

6 ATTACHMENT 'I Page 39 of6?

FREQ TIME':

b 07-13 13-19 b

07-13 13-19 0

07-13 e

07-13 TSiOPER LIMITS Refer~nce calculation on Table 1 channel operable channel operable BRUNSWICK STEAM ELECTRIC PL4.NT DAilY SURVEIllANCE REPORT CONTROL OPERATORS Rev. 101

Main Condenser Offgas 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Main Condenser Offgas LCO 3.7.5 The gross gamma activity rate of the noble gases measured at the main condenser air ejector shall be 243,600 pCiisecond after decay of 30 minutes.

APPLICABILITY:

MODE 1, MODES 2 and 3 with any main steam line not isolated and steam jet air ejector (SJAE) in operation.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Gross gamma activity rate of A.1 Restore gross gamma 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months the noble gases not within activity rate of the nobie

limit, gases to within limit.

B.

Required Action and B.1 Isolate all main steam lines. 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months associated Completion Time no met.

B.2 Isolate SJAE.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR B.3.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND B.3.2 Be in MODE 4.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Brunswick Unit 1 3.7-18 Amendment No. 203 3.7 PLANT SYSTEMS 3.7.5 Main Condenser Offgas Main Condenser Offgas 3.7.5 LCO 3.7.5 The gross gamma activity mte of the noble gases measured at the main condenser air ejector shall be ::; 243,600 jJCilsecond after decay of 30 minutes.

APPLICABILITY:

MODEl, MODES 2 and 3 with any main steam line not isolated and steam jet air ejector (SJAE) in operation.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Gross gamma activity rate of.1l.* 1 Restore gross gamma 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months the noble gases not within activity mte of the noble limit.

gases to within limit B.

Required Action and B.1 Isolate all main steam lines. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met.

OR B.2 Isolate SJAE.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months OR B.3.1 Be In MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND B.3.2 Be in MODE4.

313 hours0.00362 days 0.0869 hours 5.175265e-4 weeks 1.190965e-4 months Brunswick Unit 1 3.7-18 Amendment No. 203

Main Condenser Offgas 3.7.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1,

NOTE

Not required to be performed until 31 days after any main steam line not isolated and SJAE in operation.

Verify the gross gamma activity rate of the noble 31 days gases is 243600 pCiisecond after decay of 30 minutes.

AND Once within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months afteraa5O%

increase in the nominal steady state fission gas release after factoring out increases due to changes in THERMAL POWER level 8runswick Unit 1 3.7-19 Amendment No. 203 SUR'.,.'EILLANCE REQUIREMENTS SURVEILLANCE Main Condenser Offgas 3.7.5 FREQUENCY SR 3.7.5.1

NOTE----------------------------

Brunswick Unit 1 Not required to be performed until 31 days after any main steam line not isolated and SJAE in operation.

Verify the gross gamma activity rate of the noble gases is ::; 243,600 ~Cilseoond after decay of 30 minutes.

3.7-19 31 days Once within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after a :::50%

increase in the nominal steady slate fission gas release after factoring oul increases due to changes in THERMAL POWER level Amendment 1\\10. 2113

Radioactive Gaseous Effluent Monitoring Instrumentation 7.3.2 Table 7.12-aage 2 of 4)

Radactie I3asecus Effluent Mitang reburrentatcn FJNC.

PJCA6_E aL:iEt ccrilyr1cr4 TE&T ftp tLC0S 3ft C%NLS 9EFEfNCO aECuIRE,lETS 3TPCNT OThER ZER ft REJIRD S,CIFIED FJt2TDt CCt.FEriSArOv CCt4DrIC?3 tE4.SLL9E3 Al 2.

Rea,tsor Buildng Ventilatcn Ffonhtorir System (continueo}

e.

£airplerFlcwRaie At at tme; 1

0 TR 7.3.2.1 srernent Device TR 7.12.6 TR 7.3.2. C 3.

Turbine Buildng Venblatcn Monito,ir System a.

NobieOasMtWiy Atalmes 1

3 TR 7.a2.

(b Atnikr TR 7.3.2.3 TR 7.3.15 TR 7.3.2.10 b.

bineSanpIer Ata[tmes 1

C TR 7.3.12 NA Cartroge o.

Parclate Sampler Ata[ bmes 1

C TR 7.3.2.2 NA Ftter d.

System Effluent Fbiw At a tines 1

0 TR 7.3.2i NA Rate Measurement TR 7.3.2.

Device TR 7.3.2.10 e.

Lcv Rar,e Lairpler At al tines 1

0 TR 7.3.21 (Cl F Rate TR 7.3.2.5 easarernent Desice TR 7.3.2.10 f.

Md:High Rante (rn:

1 0

TR 7.3.2.10 NA Sampler F1cv Rate Measurenrent 0eioe 4.

ManCondenserOtf-Gas (ei 1

B TR 7.32.1 Treatment System Ncble TR 7.3.2.3 Gsa Acbiity Mcnhtor TR 7.12.6 (0onseam of AOG R 7.3.2.10 Treatment System)

(continued)

(a)

Specif a inatn.anentatii dentlicaban nuntere are provided in Appendix 3.

b)

Alarnscrp setpcints ahat be detemiine in accocdaie teth 00CM methodacgy and set ia ensure the limta of 000MS 7.3.7, Dose RateGaseous Effluents, are nt eteeeded.

Ic)

Alarmr seoints shall be deterntined in aconntiartce eith asscctsed desi9n specitcatiDn(5) and setto ensure the ltnit.s at COCMS 7.3.7, Dose RateGaseous Effluents, are na exceeded.

d)

Provides alarm.

ie)

Doring Main Condenser 0ff-Gas Tresurent System operatcn irn)

During MWHig RareSymaacn Brunswidc Units 1 and 2 7.3.2-18 Rev. 32 I Categories K/A:

S295038G2.02.42 Tier/Group:

T1G1 RO Rating:

3.9 SRO Rating:

4.6 LP Obj:

CLSLP3O*O8 Source:

NEW Cog Level:

HIGH Category 8:

Y Radioactive Gaseous Effluent Monitoring Instrumentatlon T<ible 7.:?.2-1 ipage 2 off 4)

Radioacti ** -e C-,aSECUS Effluent ~,'itocn!! 1nslrurr,entat'crI FUNCTlml '"

,.P?LlCA8:'E REaLiI.~EO CCNDlTICNS TEST fb:::O:SOR CH>.NNELS REfERIENCEO REQUIREMENTS OThER

?ER fROM REQUIRED S"=:CIFIEO F;Jr..;:::TiO:-I CCI/PEN!l"'TO.RY CCN:)liIC/,"S MEASU~ES"

. l

2.

Re:actor Build\\!1g Ventilation Monitoring Systsm (rontinuec}

e.

Sarrpler Row Rate At all fmas D

TR 7.3.2.1 Measurerr,ent Device; TR 7.3.2.6 TR 7.3.2.10

3.

TLiltine Buildillg Venlilaton Monitorir" Systam

3.

Notle Gas Acti'.i.ly

.<\\t all tim;;s TR 7.32.;

M::fIitcr TR 7.3.2.3 TR 7.3.2.5 TR 7.3.2.10

b.

looine Sarrpler At 'II! limss C

TR 7.3.22 Cmr:dge

c.

PartiCIIlate S<1mj:ler AtaN lim;;s C

TR 7.3.2.2 Fiiter

d.

System Effiuem Flem At all lim;;s 0

TR 7.3.2.*

Rate Measurement TR 7.3.2.0 De-~ice TR 7.3.2.10

e.

low Range Sarrpler At aU lim;;s 0

TR 7.3.2.1 FbwRate TR 7.3.2.0 Measurement Device; TR 7.3.2.10

f.

MeiHigh Rang;;

(m) 0 TR 7.. 3.2.10 Sarrpler ReI'.' Rate ME-<1SlJrement Device;

4.

Main Condenser Off-Gas (e)

B TR 1.3.2.1 Treatment Systam Noble TR 7.3..2.3 Gas Activity Monitor '"

TR 7.3..2.6 (Dovmstream of AOG TR 7.3.2.10 T reafment Systam)

(a)

Speci/a instrumentatioo idE!1~licalion numbers <ire provided in AppEIldix E.

(b)

AlarJl1l~rip setpoinfs shall be determined in acoocdance \\";th ODCM melhodo:cgy and set 10 ensure the lim(s oi ODCMS 7.3.7. 'Dose Rate-Gaseous Effluents; are no! elQOeeaed.

7.3.2 Al.ARWiRiP S:=TPO!NT V,.LUE (0;1 (b)

NA NA NA (e)

NA (bJ (CQntinued)

(c}

AJarll1/tr,p setpoints shall be detemlined in oY..o::roance \\\\;th assccia:;ed desig\\!1specifoation{s) and set to anS!!re the limits of COCMS 7.:'..7. 'Dose Rate---Gaseous Effluents; are not exceec'ed.

(d)

Provides alaml.

(e)

During Main Coodenser Oft-Gas Treatment System operation (m)

During MdiHigll Rang;; System opeaIion Brunswick Units 1 and 2 Categories KIA:

RORating:

LPObj:

Cog Level:

S295038G 2.02.42 3.9 CLS-LP-30*08 HIGH 7.3.2-10 Rev. 32 1 Tier / Group: TIGl SRORating:

4.6 Source

NEW Category 8:

Y

92. The following plant conditions exist on Unit Two due to a malfunction of the Air Dryer:

- SERVICE AIR PRESS-LOW is in alarm

- RB INSTR AIR RECEIVER 2A PRESS LOWis in alarm

- RB INSTR AIR RECEIVER 2B PRESS LOW is in alarm

- Instrument Air pressure is 93 psig and recovering Based on the above indications, which one of the following correctly identifies:

(1) the status of the Service Air Dryer Bypass Valve, SA-PV-5067, and (2) the procedure that contains the steps to close the Reactor Building Inboard and Outboard Isolation Valves (BFIVs)?

A (1) open (2) OAOP-20.O, Pneumatic (Air/Nitrogen) System Failures B. (1) open (2) 2APP-UA-O1, Service Air Press-Low C. (1) closed (2) OAOP-20.O, Pneumatic (Air/Nitrogen) System Failures D. (1) closed (2) 2APP-UA-O1, Service Air Press-Low

92. The following plant conditions exist on Unit Two due to a malfunction of the Air Dryer:

- SERVICE AIR PRESS-LOW is in alarm

- RB INSTR AIR RECEIVER 2A PRESS LOW is in alarm

- RB INSTR AIR RECEIVER 2B PRESS LOW is in alarm

- Instrument Air pressure is 93 psig and recovering Based on the above indications, which one of the following correctly identifies:

(1) the status of the Service Air Dryer Bypass Valve, SA-PV-5067, and (2) the procedure that contains the steps to close the Reactor Building Inboard and Outboard Isolation Valves (BFIVs)?

A'I (1) open (2) OAOP-20.0, Pneumatic (Air/Nitrogen) System Failures B. (1) open (2) 2APP-UA-01, Service Air Press-Low C. (1) closed (2) OAOP-20.0, Pneumatic (Air/Nitrogen) System Failures D. (1) closed (2) 2APP-UA-01, Service Air Press-Low

Feedback K/A: 300000 A2.01 Ability to (a) predict the impacts of the following on the INSTRUMENT AIR SYSTEM and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal operation:

Air dryer and filter malfunctions (CFR: 41.5/45.6)

RO/SRO Rating: 2.9/2.8 Objective:

CLS-LP-46, 07i: Given plant conditions, determine if the following automatic actions should occur: Air Dryer is bypassed.

CLS-LP-037.1, 8b: State how the RBHVAC is affected by the following: Loss of Instrument Air.

Reference:

RB INSTR AIR RECEIVER 28 PRESS LOW (UA-01 1-2)

SERVICE AIR PRESS LOW (UA-01 5-4)

OAOP-20, Pneumatic (Air/Nitrogen) System Failures Cog Level: High Explanation:

The air dryer malfunction has caused air pressure to lower. The Service Air low pressure alarms comes in at 107 psig. At 105# decreasing the Service Air system isolates, thus the 0 psig indication on Service Air.

The alarms for the receivers low pressure come in at 95# and are located in the Reactor Building. With these alarms in the operators are required to close the BFIVs while there is still sufficient air pressure remaining to make the secondary containment isolation valves close in accordance with the AOP supplemental actions.

Distractor Analysis:

Choice A: Correct answer; The air dryer bypass valve opens at 98# and dropping and the steps are in the AOP for closing the BFIVs.

Choice B: Plausible because the air dryer bypass valve is open, but the guidance for closure of the BFIVs is contained in the AOP or RB INSTRAIR RECEIVER 2A(B) PRESS LOWAPP.

Choice C: Plausible because the AOP is the correct procedure for closure of the BFIVs, but the air dryer bypass valve would be open (requires system knowledge to know the setpoint for the bypass opening).

Choice D: Plausible because the student may not know the setpoint of the bypass valve opening and the guidance for closure of the BFIVs is contained in the AOP or RB INSTR AIR RECEIVER 2A(B) PRESS LOWAPP.

SRO Basis: 10 CFR 55.43(b)-5 Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

The first part of the question is RO knowledge (setpoint for the auto opening of the air dryer bypass valve the second part is Assessing plant conditions (normal, abnormal, or emergency) and then prescribing a procedure to mitigate, recover, or with which to proceed.

Notes Feedback KiA: 300000 A2.01 Ability to (a) predict the impacts of the following on the INSTRUMENT AIR SYSTEM and (b) based on those predictions, use procedures to correct, control, or mitigate the consequences of those abnormal operation:

Air dryer and filter malfunctions (CFR: 41.5 /45.6)

RO/SRO Rating: 2.9/2.8 Objective:

CLS-LP-46, 07i: Given plant conditions, determine if the following automatic actions should occur: Air Dryer is bypassed.

CLS-LP-037.1, 8b: State how the RBHVAC is affected by the following: Loss of Instrument Air.

Reference:

RB INSTR AIR RECEIVER 2B PRESS LOW (UA-01 1-2)

SERVICE AIR PRESS LOW (UA-01 5-4)

OAOP-20, Pneumatic (Air/Nitrogen) System Failures Cog Level: High Explanation:

The air dryer malfunction has caused air pressure to lower. The Service Air low pressure alarms comes in at 107 psig. At 105# decreasing the Service Air system isolates, thus the 0 psig indication on Service Air.

The alarms for the receivers low pressure come in at 95# and are located in the Reactor Building. With these alarms in the operators are required to close the BFIVs while there is still sufficient air pressure remaining to make the secondary containment isolation valves close in accordance with the AOP supplemental actions.

Distractor Analysis:

Choice A: Correct answer; The air dryer bypass valve opens at 98# and dropping and the steps are in the AOP for closing the BFIVs.

Choice B: Plausible because the air dryer bypass valve is open, but the guidance for closure of the BFIVs is contained in the AOP or RB INSTR AIR RECEIVER 2A(B) PRESS LOW APP.

Choice C: Plausible because the AOP is the correct procedure for closure of the BFIVs, but the air dryer bypass valve would be open (requires system knowledge to know the setpoint for the bypass opening).

Choice D: Plausible because the student may not know the setpoint of the bypass valve opening and the guidance for closure of the BFIVs is contained in the AOP or RB INSTR AIR RECEIVER 2A(B) PRESS LOWAPP.

SRO Basis: 10 CFR 55.43(b)-5 Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, and emergency situations.

The first part of the question is RO knowledge (setpoint for the auto opening of the air dryer bypass valve the second part is Assessing plant conditions (normal, abnormal, or emergency) and then prescribing a procedure to mitigate, recover, or with which to proceed.

Notes

4.

IF RB INSTR AiR RECEIVER IA(2A) PRESS LOW (UA-O1 1-1) OR RB IWSTR AIR RECEiVER IB(2B,)

PRESS LOW (UA-Ol 1-2) alarm is received, THEN PERFORM the following:

NOTE:

Isolation of the Reactor Building supply and exhaust dampers will render the building ventilation system inoperable. Consideration should be given for starting the Standby Gas Treatment System to ensure the Reactor Building differential pressure remains negative.

a.

IF necessary. THEN START the Standby Gas 0

Treatment System.

NOTE:

Local Tee Handles may be used to close the Reactor Building Isolation Dampers if insufficient control air is available. 1 (2)OP-37.1 provide L

instructions for manual operation of Reactor Building Isolation Valves.

b.

CLOSE the following dampers:

RB VENT 1NBO VALVES, 1A2A)-BFiV-RB and iCi2C)-BF1V-RB RB VENT OUTBD VALVES, 1B(2B)-BF1V-RB and ID(2D)-BF1 V-RB

) OAOP-20.O Rev. 35 Page 5 of 18 Unit 2 APP UA-O1 5-3 Page 1 of 2 AIR DRYER 2A TROUBLE AUTO ACTIONS 1.

Service air dryer bypass valve SA-PV-5067 will begin to open if service air header pressure decreases to 98 psig.

2.

If control power is lost or interrupted the dryer will fail safe, providing continued air flow through one tower.

3.

If a dryer tower moisture sensing probe related fault or malfunction occurs, the dryer control system will default to a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months drying cycle.

4.

IF RB INSTR AIR RECEIVER 1A(2A) PRESS LOW (UA-01 1-1) OR RB INSTR AIR RECElVER 1B(2B)

PRESS LOW (UA-01 1-2) alarm is received, THEN PERFORM the following:

NOTE:

Isolation or the Reactor Building supply and exhaust dampers will render the building ventilation system inoperable. Consideration should be given ror starting the Standby Gas Treatment System to ensure me Reactor Building differential pressure remains negative.

a.

IF necessary, THEN START the Standby Gas Treatment System.

o NOTE:

Local "Tee Handles" may be used to close the Reactor Building Isolation Dampers if insufficient control air is available. 1 (2)OP-37.1 provide instructions for manual operation of Reactor Building Isolation Valves.

b.

CLOSE the following dampers:

IOAOP-20.0 AIR DRYER.2A TROUBLE AUTO ACTIONS

,~B VENTJNBD VALVES, 0

1A(2A)-BFlV-RB and tC(2C)-BFIV-RB

.~B VENTOUTBD VALVES, 0

1B(2B)-BFlV-RB and 1D(2D)-BFIV-RB Rev. 35 Page50f18 I Unit 2 APP UA-01 5-3 Page*lof2

1.

Service air dryer bypass valve SA-PV-5067 will begin to open if service air header pressure decreases to 98 psig.

2.

If control power is lost or interrupted the dryer will fail safe, providing continued air flow through one tower.

3.

If a dryer tower moisture sensing probe related fault or malfunction occurs, the dryer control system will default to a 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months drying cycle.

RB INSTR AIR RECEIVER 2B PRESS LOW AUTO ACTIONS 1.

Standby Instrument Air Compressor 2B starts and loads.

2.

High Pressure Bottle Rack Isolation Valve, RNA-SV-5481 opens, supplying SRVs and AC-V17 with a pneumatic source.

CAUSE 1.

Low air pressure (95 psig) in instrument air receiver 2B.

2.

Loss of plant air compressors.

3.

Instrument air pipe rupture or air leak.

4.

Circuit malfunction.

OBSERVATIONS 1.

Standby compressor starts automatically and loads (it will unload at 105 psig).

2.

Service air header may have isolated.

3.

Pressure Indicator 2-RNA-Pl-5268 (XU-51) indicates approximately 100 psig.

ACTIONS 1.

Check that standby compressor is running.

2.

Check to see if instrument air pressure is maintaining or increasing above 95 psig.

3.

Check plant compressors.

4.

Check for instrument air ruptures.

5.

Isolate any instrument air piping leaks or ruptures.

6.

Isolate nonessential air supplies in order to maintain more than 95 psig on instrument heade[

7.

Ensure the High Pressure Bottle Rack Isolation Valve, RNA-SV-5481 (XU-51) opens.

8.

If a circuit malfunction is suspected, ensure that a WRIJO is prepared.

9.

If secondary containment isolation is required, close secondary containment isolation valves 2B-BFIV-RB and 2D-BFIV-RB prior to accumulator air pressure bleedoff.

2APP-UA-0i Rev. 64 Page 6 of 102 Categories K/A:

300000 A2.01 Tier/Group:

T2G1 RO Rating:

2.9 SRO Rating:

2.8 LP Obj:

46-71 Source:

NEW Cog Level:

HIGH Category 8:

Y RB INSTR AIR RECEIVER 2B PRESS LOW AUTO ACTIONS

'I.

standby Instrument Air Compressor 2B starts and loads.

2.

High Pressure BoUIe Rack Isolation Valve, RNA-SV-548'1 opens, supplying SRV's and CAC-V17 with a pneumatic source.

CAUSE

'I.

Low air pressure (95 psig) in instrument air receiver 2B.

2.

Loss of plant air compressors.

3.

Instrument air pipe rupture or air leak.

4.

Circuit malfunction.

OBSERVATIONS

'1.

Standby compressor starts automatically and loads (it will unload at '105 psig).

2.

Service air header may have isolated.

3.

Pressure Indicator 2-RNA-PI-5268 (XU-51) indicates approximately 100 psig.

ACTIONS

'1.

Check tllat standby compressor is running.

2.

Check to see if instrument air pressure is maintaining or increasing above 95 psig.

3.

Check plant compressors.

4.

Cl1eck for instrument air ruptures.

5.

Isolate any instrument air piping leaks or ruptures.

6.

Isolate nonessential air supplies in order to maintain more than 95 psig on instrument header.

7.

Ensure the High Pressure Bottle Rack Isolation Valve, RNA-SV-548'1 (XU-51) opens.

8.

If a circuit malfunction is suspected, ensure that a WRfJO is prepared.

9.

If secondary containment isolation is required, close secondary containment isolation valves 2B-BFIV-RB and 20-BFIV-RB prior to accumulator air pressure bleedoff.

!2APP-UA-O'l Categories KIA:

300000 A2.0 1 RO Rating:

2.9 LP Obj:

46-71 Cog Level:

HIGH Rev. 64 Tier / Group: T2G 1 SRO Rating:

2.8 Source

~vv Category 8:

Y Page 6 of 1021

93. Unit Two is operating at power with Reactor Recirculation Loop A isolated due to abnormal seal leakage. A fire in the reactor building occurs and the Site Incident Commander has requested that MCC 2XA-2 be de-energized for fire suppression.

Which one of the following identifies the impact that deenergizing MCC 2XA-2 has on RHR Loop A availability and the procedure which provides this guidance under the above plant conditions?

Deenergizing MCC 2XA-2 will make RHR Loop A Inoperable but Available provided that the 2-El l-FO15A, Inboard Injection Vlv, (1) to support LPCI lAW (2)

A.

(1) is maintained (de-energized) opened (2) OAP-025, BNP Integrated Scheduling B. (I) is maintained (de-energized) opened (2) 001-01.08, Control of Equipment and System Status C (1) has a Dedicated Operator is assigned for manual operation (2) OAP-025, BNP Integrated Scheduling D. (1) has a Dedicated Operator is assigned for manual operation (2) 001-01.08, Control of Equipment and System Status

93. Unit Two is operating at power with Reactor Recirculation Loop A isolated due to abnormal seal leakage. A fire in the reactor building occurs and the Site Incident Commander has requested that MCC 2XA-2 be de-energized for fire suppression.

Which one of the following identifies the impact that deenergizing MCC 2XA-2 has on RHR Loop A availability and the procedure which provides this guidance under the above plant conditions?

Deenergizing MCC 2XA-2 will make RHR Loop A Inoperable but Available provided that the 2-E11-F015A, Inboard Injection Vlv, (1) to support LPCIIAW (2)

A. (1) is maintained (de-energized) opened (2) OAP-025, BNP Integrated Scheduling B. (1) is maintained (de-energized) opened (2) 001-01.08, Control of Equipment and System Status C~ (1) has a Dedicated Operator is assigned for manual operation (2) OAP-025, BNP Integrated Scheduling D. (1) has a Dedicated Operator is assigned for manual operation (2) 001-01.08, Control of Equipment and System Status

Feedback K/A: S600000G 2.02.37 Ability to determine operability andlor availability of safety related equipment.

Plant Fire On Site (CFR: 41.7 /43.5 / 45.12)

ROISRO Rating: 3.6/4.6 Objective: CLS-LP

Reference:

OAP-025, Revision 39, Page 9, Section 3.1 Cog Level: High Explanation:

Requires knowledge of equipment powered from MCC 2XA-2 (opposite Unit power E5). With the RR Loop A isolated (RR Discharge and Disch Bypass valves will be close

- required for LPCI) and FO15A (located in ECCS Pipe Tunnel - RB 20) can be manually opened by a dedicated operator. 001-01.08 has recently been revised to support implementation of OPS-NGGC-1 000, Fleet Conduct of Operations. Risk assessment and equipment removal from service guidance has been removed from 01-01.08.

Distractor Analysis:

Choice A: Plausible because if the valve is de-energized in its intended state (such as a PCIV in the closed dierection) this could be considered correct although for this case the open direction for this normally closed valve would have to have interlocks defeated to have both the F015 and F017 both open (potential to pressurize low pressure piping). OAP-025 is correct.

Choice B: Plausible because if the valve is de-energized in its intended state (such as a PCIV in the closed dierection) this could be considered correct although for this case the open direction for this normally closed valve would have to have interlocks defeated to have both the F015 and F017 both open (potential to pressurize low pressure piping). 001-01.08 no longer provides guidance for evaluating MR/PSA system availability.

Choice C: Correct Answer Choice D: Plausible because RHR Loop is available and 001-01.08 no longer provides guidance for evaluating MRIPSA system availability.

SRO Only Basis: Knowledge of administrative procedures that specify implementation, and/or coordination of plant normal procedures.

Notes Feedback KIA: S600000G 2.02.37 Ability to determine operability and/or availability of safety related equipment.

Plant Fire On Site (CFR: 41.7/43.5/45.12)

RO/SRO Rating: 3.6/4.6 Objective: CLS-LP-

Reference:

OAP-025, Revision 39, Page 9, Section 3.1 Cog Level: High Explanation:

Requires knowledge of equipment powered from MCC 2XA-2 (opposite Unit power E5). With the RR Loop A isolated (RR Discharge and Disch Bypass valves will be close - required for LPCI) and F015A (located in ECCS Pipe Tunnel - RB 20') can be manually opened by a dedicated operator. 001-01.08 has recently been revised to support implementation of OPS-NGGC-1000, Fleet Conduct of Operations. Risk assessment and equipment removal from service guidance has been removed from 01-01.08.

Distractor Analysis:

Choice A: Plausible because if the valve is de-energized in its intended state (such as a PC IV in the closed dierection) this could be considered correct although for this case the open direction for this normally closed valve would have to have interlocks defeated to have both the F015 and F017 both open (potential to pressurize low pressure piping). OAP-025 is correct.

Choice B: Plausible because if the valve is de-energized in its intended state (such as a PCIV in the closed dierection) this could be considered correct although for this case the open direction for this normally closed valve would have to have interlocks defeated to have both the F015 and F017 both open (potential to pressurize low pressure piping). 001-01.08 no longer provides guidance for evaluating MRIPSA system availability.

Choice C: Correct Answer Choice D: Plausible because RHR Loop is available and 001-01.08 no longer provides guidance for evaluating MRIPSA system availability.

SRO Only Basis: Knowledge of administrative procedures that specify implementation, and/or coordination of plant normal procedures.

Notes

3.0 DEFINITIONS 3.1 Available (Availability)

The status of a system, structure or component (SSC) that is OPERABLE, in service or can be placed in a FUNCTIONAL state within a reasonably short period of time consistent with its intended need. The SSC must be capable of meeting all of its most limiting requirements for the plant mode under consideration Using a manual means for placing an SSC in service requires a dedicated operator assigned to be cognizant of the SSC along with a written procedure for its restoration. A dedicated operator for the purpose of this definition is one who is specifically assigned the task and 2vailable, as necessary, to perform the required actions.

3.2 Backbone Schedule A preliminary schedule consisting of work items that are either required to he performed or have been designated by management as high priority items.

The following items would nomally comprise the backbone schedule:

Implementing Supervisor recommendations KeyI(a)(1 Equipment priority action items Required SurveillancesiPMs System Outages Committed Items Priority 1 & 2 CAPRs, CORRs. and regulatory committed items Modification ECs determined a priority by Engineering representative or Scheduler (must be ready to work with work orders in ready or approved status)

Engineering recommendations Reactivity Management flagged Work Orders 13 Compensatory Actions Measures that are used to niitigate the impact and minimize the duration of an ELEVATED RISK activity. These measures may include CONTINGENCY PLANS or procedural controls.

3.4 Contingency Planning A look ahead process whereby potential problems are systematically identified, assessed, and addressed by adding plans or mitigating actions.

The necessity for a contingency plan is based on the potential consequences as well as the probability of a problem occurring.

DAP-025 Rev 39 I

Page 9 of 121 3.0 DEFINITIONS 3.1 Available (Availability)

The status of a system, structure or component (SSC) that is OPERABLE, in service or can be placed in a FUNCTIONAL state within a reasonably short period of time consistent with its intended need. The SSC must be capable of meeting all of its most limiting requirements for the plant mode under consideration. Using a manual means for placing an SSC in service requires a dedicated operator assigned to be cognizant of the SSC along with a written procedure tor its restoration. A "dedicated" operator for the purpose of this definition is one who is specifically assigned the task and available, as necessary, to perform the required actions.

3.1 Backbone Schedule A preliminary schedule consisting of work items that are either required to be performed or have been deSignated by management as high priority items.

The following items would nom1ally comprise the backbone schedule:

Implementing Supervisor recommendations Key/(a)(1) Equipment priority action items Required Surveillances/PMs System Outages Committed Items - Priority 1 & 2 C.4.PR's, CORR's, and regulatory committed items Modification EC's determined a priority by Engineering repre.sentative or Scheduler (must be ready to work with work orders in ready or approved status)

Engineering recommendations Reactivity Management flagged Work Orders 3.3 Compensatory Actions Measures that are used to mitigate the impact and minimize the duration of an ELEVATED RISK activity. These measures may include CONTINGENCY PLANS or procedural controls.

3.4 Contingency Planning IOAP-025 A look ahead process whereby potential problems are systematically identified, assessed, and addressed by adding plans or mitigating actions.

The necessity for a contingency plan is based on the potential consequences as well as the probabllity of a problem occurring.

Rev. 39 Page 9 of 121 I

ATTACHMENT 3 Page 15 of 19 480V Substation E5?MCCIPaneI Load Summary Load: 480V Motor Control Center 22XA-2 Locadc9: Ur t Reaotor 3T. ldin ZY NE Draw ng

Reference:

-2 3c-9 Upstream Power Source: dBOV Substation E5 COMPT LOAD DESCRIPTION EFFECTS ON LOSS OF POWER DF5 F?lR Cuibaard lniection Valve Loss of load 2-El1-F3l7ATS 3.5.1, 36.1.3, 3.5.2, 3.3.2.1:

D3 RHR Inboard lnection Valve 2-El -FO15A Loss of load ITS 3.51, 3.8.1.3, 3.5.2,3.3.3.1)

DGO HR Tor,s Spray Valve 2-El i-F028A Loss of load tTS3.8.1,3.8.1.3.3.&2.3. 3.3.3.1) 0D7 Rx ecrculation Pump 2A Discharge Valve Losa of load 2-B22-FO31ATS 3.4.1, 3.5.1) 008 Rx Recrculation Pump 2A Discharge Loss of load Sypass Valve 2-232-F032A (TS 3.4.1 3.5.11 001-50.1 Rev. 42 Page 24 of 55 ATTACHMENT 3 Page 15 of 19 4BOV Substation E5/MCC/Panei Load Summary Load: 480V Motor Control Center 2-2XA-2 Location: Unit 2 Reactor Building 20' NE Drawing

Reference:

F-03D49 Upstream Power Source: 4S0V SUbstation E5 COMPT LOAD DESCRIPTION EFfECTS ON LOSS OF POWER DFS RHR Outboard Injection Valve Less of load 2-E11-F017A(TS 3.5.1. 3.6.1.3, 3.5.2, 3.3.3.1}

DF3 RHR Inboard Injecticn Val'.e 2-E11-FOt5A Loss of load

{IS 3.5.1. 3.8.1.3, 3.5.2, 3.3.3.1}

DGO R HR Torus Spray Valve 2-E 11-1"028.11, Loss of load (IS 3.5.1. 3.8.1.3, 3.6.2.3, 3.3.3. t) 007 Rx Recirculation Pump 2A Discharge Valve Loss of load 2-B;?2-F031A iTS 3.4.1. 3.S.1}

008 Rx Recirculation Pump 2A Discharge Loss of load Bypass Valve 2-B32-F032A (is 3.4.1, 3.5.1)

\\ 001-50.1 Rev. 42 Page 24 of 55\\

ATTACHMENT 2A Page 2 of 3 Residual Hear Removal System Loop A Panel Lineup Number Description Positicn Checked Venfied Indication Loop A Control Room Panel H12 P801 El lFcOeC Pump C Shuown Cooling CLOSED Suction V El l-FCOeA Pump A Shutdovn Cooling CLOSED Suction V El l-V32 Check Vae Bypass VIv CLOSED El l-FO17A Ouoard lrec:ion Vlv OPEN El l-F0le4 Drywell Spray Otbd Isol Vlv CLOSED Ell-F1O4A HX 2A Inboard Vent Vlv CLOSED Ell-FOI5A Inboard InjeciionVlv CLOSED El l-FO2IA Orywell Spray Inbd led Vlv LOSEO Ell-FIO3A HX 2A Outboard Vent /1v CLOSES El 1-F024A Torus Cooling Isol Vhi CLOSED Ell-FC4A HX24Bypass1v OPEN El l-F027A Torus Spray led Vi CLOSES El 1-FOl IA HX 2 Drain To Torus Vl CLOSES El 1-FcO4C Pump C Torus Suction Viv OPEN Eil-F028A Torus Discharge IsolVlv CLOSED El I-F026A

-IX 2A Drain To RCIC VIv CLOSES El I-FcO4A Pump A Torus Sucbon VIv OPEN E1l-FcO2A HX 2A Cutlev OPEN El I-FC7A Mn Flow Sypass V CLOSED El 1-FO2GA Pump A&C Torus Suction Vlv CPEN El i-Fc47A HX Z InletV OPEN El l-FE8OA Manual lnection ilv OPEN El l-PDV-Ffl38A HX Z SW Disch VIv CLOSED CS-517A Containment Spray Valve Control OFF Think Swilch 20P-17 Rev. 155 Page 244 of 297 Categories K/A:

S600000G2.02.37 Tier/Group:

T1G1 RO Rating:

3.6 SRO Rating:

4.6 LP Obj:

Source:

NEW Cog Level:

HIGH Category 8:

Numb:r El1-FOOeC Ell-FOOM Ell-V32 Ell-F017.4 El1-F01M Ell-Fl04A Ell-FOl5A El1-F021A El1-Fl03A El1-F024A Ell-F048A Ell-F027A Ell-FOllA Ell-FOO4C Ell-F028A E11-F02M El1-FOO4A E1l-FOO3.4 E11-FOO7A Ell-F020A E11-F047A E11-FOOOA E11-PDV-F068A CS-S17A ATTACHMENT 2.4-Page 2 of 3 Residual Heat Removal System Loop A Panel Lineup Description Positionl Checked Indication Loop A Control Room - Panel H12-P801 Pump C Shulx:lc'IIn Cooling CLOSED SuctionV'N Pump A Shutdown Cooling CLOSED SuclionV'N Check Va'Ne 8}'Jlass VIII CLOSED Outboard Injection VIII OPEN Drywell Spray Otbd Isol VIII CLOSED

!-IX 2A Inboard Vent V'N CLOSED Inboard Injection V'N CLOSED Drywell Spray lnbd (501 Iflv CLOSED

!-IX 2.4 Outboard Vent Vlv CLOSED Torus Cooling 1501 VIII CLOSED

!-IX 2A Bypass 'v1v OPEN Torus Spray lsol V'N CLOSED

!-IX 2A Drain To Torus Vlv CLOSED Pump C Torus Suction V'N OPEN Torus Discharge lsol V'N CLOSED

!-IX 2A Drain To RCIC VI" CLOSED Pump A Torus Suction VIII OPEN

!-IX 2A Outlet Vlv OPEN Min Flow Bypass IJI~'

CLOSED Pump A&C Torus Suction Ifl...

OPEN HX 2A Inlet V'N OPEN M.anuallnieciion Vlv OPEN

!-IX 24 SW Disch VI" CLOSED Containment Spray Va'Ne Control OFF Think Switch Verified 1 20P-17 Rev. 155 Page 244 of 2971 Categories KIA:

RORating:

LP Obj:

Cog Level:

S600000G 2.02.37 3.6 HIGH Tier / Group: T1 G 1 SRO Rating:

4.6 Source

NEW Category 8:

94. What action is required to be taken if Alternate Safe Shutdown (ASSD) Staffing drops below minimum complement due to an emergent on-shift AC illness and what procedure provides the guidance for this action?

The guidance for establishing an (1) if ASSD staffing composition is less than the minimum required is provided by (2)

A (1) ASSD Impairment (2) OASSD-00, User Guide B.

(1) Active LCO for T.S. 5.2.2, Facility Staff Organization, (2) OASSD-00, User Guide C. (1) ASSD Impairment (2) 001-01.01, BNP Conduct of Operations Supplement D. (1) Active LCO forT.S. 5.2.2, Facility Staff Organization, (2) 001-01.01, BNP Conduct of Operations Supplement

94. What action is required to be taken if Alternate Safe Shutdown (ASSD) Staffing drops below minimum complement due to an emergent on-shift AO illness and what procedure provides the guidance for this action?

The guidance for establishing an (1) if ASSD staffing composition is less than the minimum required is provided by (2)

A'I (1) ASSD Impairment (2) OASSD-OO, User Guide B. (1) Active LCO for T.S. 5.2.2, Facility Staff Organization, (2) OASSD-OO, User Guide C. (1) ASSD Impairment (2) 001-01.01, BNP Conduct of Operations Supplement D. (1) Active LCO for T.S. 5.2.2, Facility Staff Organization, (2) 001-01.01, BNP Conduct of Operations Supplement

Feedback K/A: SG2.O1.05 Conduct of Operations Ability to use procedures related to shift staffing, such as minimum crew complement, overtime limitations, etc.

(CFR: 41.10 / 43.5/45.12)

ROISRO Rating: 2.9/3.9 Objective: CLSLP304M*1 3m

13. Given ASSD procedures and plant conditions that require use of ASSD procedures, determine the following:

m. The manpower required to support the ASSD actions.

Reference:

OASSD-00, Revision 37, Page 30, Section 5.3.3 Cog Level: High Explanation:

The ASSD staffing composition may be less than the minimum requirements for a period of time not to exceed two hours in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore requirements to within the minimum requirements of the shift ASSD staffing.

If the ASSD staffing composition is less than the minimum required, establish an Alternative Safe Shutdown Impairment in accordance with OPLP-1.5, Alternative Shutdown Capability Controls, and OFPP-020, Impairment Notification.

Distractor Analysis:

Choice A: Correct Answer Choice B: Plausible because an impairment is the same as LCO (001-01.01) but impairments are not established against TS 5.2.2 and ASSD User Guide is correct.

Choice C: Plausible because ASSD impairment is correct and 001-01.01 provides staffing requirements for TS 5.2.2 but directs use of OASSD-00 procedure use for required staffing.

Choice D: Plausible because Plausible because an impairment is the same as LCO (001-01.01) but impairments are not established against TS 5.2.2 and 001-01.01 provides staffing requirements for TS 5.2.2 but directs use of OASSD-00 procedure use for required staffing.

SRO Only Basis: Requires knowledge of TS 5.2.2 Facility Staff Organization

- and prescribes the procedure required for guidance during periods of ASSD minimum complement not maintained.

Notes Feedback KIA: SG2.01.05 Conduct of Operations Ability to use procedures related to shift staffing, such as minimum crew complement, overtime limitations, etc.

(CFR: 41.10/43.5/45.12)

RO/SRO Rating: 2.9/3.9 Objective: CLS-LP-304-M*13m

13. Given ASSD procedures and plant conditions that require use of ASSD procedures, determine the following:

m. The manpower required to support the ASSD actions.

Reference:

OASSD-OO, Revision 37, Page 30, Section 5.3.3 Cog Level: High Explanation:

The ASSD staffing composition may be less than the minimum requirements for a period of time not to exceed two hours in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore requirements to within the minimum requirements of the shift ASSD staffing. If the ASSD staffing composition is less than the minimum required, establish an Alternative Safe Shutdown Impairment in accordance with OPLP-1.5, Alternative Shutdown Capability Controls, and OFPP-020, Impairment Notification.

Distractor Analysis:

Choice A: Correct Answer Choice B: Plausible because an impairment is the same as LCO (001-01.01) but impairments are not established against TS 5.2.2 and ASSD User Guide is correct.

Choice C: Plausible because ASSD impairment is correct and 001-01.01 provides staffing requirements for TS 5.2.2 but directs use of OASSD-OO procedure use for required staffing.

Choice D: Plausible because Plausible because an impairment is the same as LCO (001-01.01) but impairments are not established against TS 5.2.2 and 001-01.01 provides staffing requirements for TS 5.2.2 but directs use of OASSD-OO procedure use for required staffing.

SRO Only Basis: Requires knowledge of TS 5.2.2 Facility Staff Organization - and prescribes the procedure required for guidance during periods of ASSD minimum complement not maintained.

Notes

5.0 INSTRUCTIONS 5.3 General Guidelines for ASSD Staff 6.31 All ASSD Staffing Roster members must be capable of prompt response when events are in progress that may require entry into ASSO procedures.

5.12 All ASSD members shall obtain a designated radio at the beginning of shift and ensure that it is charged.

rNol-E:

Planned reduction of ASSD personnel below the minimum number required is NOT permitted.

5.3.3 The ASSD staffing composition may be less than the minimum requirements for a period of time not to exceed two hours in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore requirements to within the minimum requirements of the shift ASSD staffing.

5.3.4 If the ASSD staffing composition is less than the minimum required.

establish an Alternative Safe Shutdown Impairment in accordance with OPLP-1.5, Alternative Shutdown Capability Controls, and OFPP-020, Impairment Notification.

5.3.5 If an impairment exceeds two hours, initiate a Condition Report.

5.3.6 With both units in Mode 4 or 5, ASSD staffing is not required.

DASSO-QO Rev. 37 Page 30 of 53 5.0 INSTRUCTIONS 5.3 General GUidelines for ASSD Staff 5.3.1 All ASSD Staffing Roster members must be capable of prompt response when events are in progress that may require entrl into ASSD procedures.

5.3.2 All ASSD members shall obtain a deSignated radio at the beginning of shift and ensure that it is charged.

NOTE:

Planned reduction of ASSn personnel below the minimum number required is NOT permitted.

5.3.3 The ASSD staffing composition may be less than the minimum requirements for a period of time not to exceed two hours in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore requirements to within the minimum requirements of the shift ASSn staffing.

5.3.4 If the ASSn staffing composition is less than the minimum required, establish an Alternative Safe Shutdown Impairment in accordance '.'1ith OPLP-1.5, Alternative Shutdown Capability Controls, and OFPP-020, Impairment Notification.

5.3.5 If an impairment exceeds two hours, initiate a Condition Report.

5.3.6 With both units in Mode 4 or 5, ASSD staffing is not required.

10ASSD-OO Rev. 37 Page 30 of 531

5.0 INSTRUCTIONS 5.4 Minimum ASSD Nuclear Shift Staffing/Assignments 5.4.1 Senior Reactor Operators:

1 Unit 1 SCO: Unit 1 Remote Shutdown Panel 1

Unit 2 SCO:

Unit 2 Remote Shutdown Panel 5.4.2 Auxiliary Operators:

1 Unit 1 Reactor BuildinglMCC Operator or as directed by the Unit SCO 1

Unit 2 Reactor BuildinglMCC Operator or as directed by the Unit SCO 1

Diesel Generator Operator or as directed by the Unit SCO 1

Emergency Switchgear Operator or as directed by the Unit SCO 1

Service Water Building Operator or as directed by the Unit SCO QASSD-00 Rev. 37 Page 31 ofj 5.0 INSTRUCTIONS 5.4 Minimum ASSD Nuclear Shift Staffing/Assignments 5.4.*1 Senior Reactor Operators:

Unit 1 seo: Unit 1 Remote Shutdown Panel 1

Unit 2 seo: Unit 2 Remote Shutdown Panel 5.4.2 Auxiliary Operators:

\\ OASSD-OO Unit 1 Reactor Building/MCe Operator or as directed by the Unit seo 1

Unit 2 Reactor BuildingJMCe Operator or as directed by the Unit seo 1

Diesel Generator Operator or as directed by the Unit seo 1

Emergency Switchgear Operator or as directed by the Unit seo 1

Service Water Building Operator or as directed by the UnitSeO Rev. 37 Page 31 of 53\\

9.4 Operations Leadership Role in Station Activities (continued) 5.

Operators work closely with station support personnel to establish appropriate priorities for resoMng plant equipment and station program deficiencies. Being aware of the integrated effect of equipment out of service and establishing priorities for equipment return-to-service consistent with plant impact are key components of this philosophy.

6.

Operations pursues the root cause(s) of problems; provides direction to implement corrective actions and hold department and station personnel accountable for achieving expected levels of perfomance.

9.5.

Operations Shift StaflinO Standards Operations ensures that the Control Room is adequately staffed for plant operations with appropriately qualified individuals. Additionally, Operations ensures staffing is adequate to meet regulatory and programmatic requirements.

Expectations 1.

General a.

The CRS and Shift Manager are responsible for ensuring that only qualified watchstanders hold required positions. Personnel should verify they are qualified for the position to be held prior to assuming the watch.

b.

Individual qualifications for specifc positions can be found in REG-NGGC-0012, Confirmation of Personnel Qualifications Associated with Commitments to Regulatory Guide 1.8.

c.

The shift complement may be one less than the minimum requirement for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence of onduty shift members provided immediate action is taken to restore the shift complement to within the minimum requirements. This provision does not permit any shift member position to be unmanned upon shift change due to an oncoming shift member being late or absent.

d.

Shift staffing shall meet the requirements of the indMdual plant license/Tech Specs and other regulatory and programmatic required positions at all times. Required staff numbers and positions can be found in Attachment I Shift Staffing.

OPS-NGGC-1000 Rev.2 I

Page46of 1491 9.4 Operations Leadership Role in Station Activities (continued)

5.

Operators work closely with station support personnel to establish appropriate priorities for resolving plant equipment and station program deficiencies. Being aware of the integrated effect of equipment out of service and establishing priorities for equipment return-to-service consistent with plant impact are key components of this philosophy.

6.

OperatiOns pursues the root cause(s} of problems; provides direction to implement corrective actions and hold department and station personnel accountable for achieving expected levels of perfornlance.

9.5.

Operations Shift Slaffing Standards Operations ensures that the Control Room is adequately staffed for plant operations with appropriately qualified individuals. Additionally, Operations ensures staffing is adequate to meet regulatory and programmatic requirements.

Expectations

1.

General

a.

The CRS and Shift Manager are responsible for ensuring that only qualified watchstanders hold required positions. Personnel should verify they are qualified for the position to be held prior to assuming the watch.

b.

Individual qualifications for specific positions can be found in REG-NGGC-0012, Confirmation of Personnel Qualifications Associated with Commitments to Regulatory Guide 1.8.

c.

The shift complement may be one less than the minimum requirement for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence of on-duty shift meml)ers provided immediate action is taken to restore the shift complement to within the minimum requirements. This provision does not permit any shift member position to be unmanned upon shift change due to an oncoming shift meml)er I)eing late or absent.

d.

Shift staffing shall meet the requirements of the individual plant licenseffech Specs and other regulatory and programmatic required positions at all times. Required staff numbers and positions can be found in Attachment 1 "Shift Staffing".

I OPS-NGGC-1000 Rev. 2 Page 46 of 1491

Attachment I

- Shift Staffing Shift Manning BNP Position Minimum Note staffing SM I

CRS 2

SRO/STA 1

RO 3

AO 9

9.5 Operations Shift Staffing In addition to the requirements of OPS-NGGC-1000. the following requirements apply:

9.5.1 General The following table outlines the administrative guideline for the normal Operations shift complement Any deviation from the normal shift complement must remain in accordance with Section 5.2.2 of Technical Specifications, and apphcable sections of IJASSD-OO.

OFPP-031. and Attachment 13. (Attachment 13 contains a listing of required ERO Watch Stations and qualifications for each and ASSD position& This attachment may be used as a tool to support determining shift staffing requirements.)

BNP Watchstations BNP Shift Complement License Shift Manager (SM) 1 Shift Manager SRO Control Room Supervisor (CRS) 2 CRSs (1 for each unit)

SRO Reactor Operator (RO) 4 Reactor Operators rtypically. 2 ROISRO for each unit)

Auxiliarj Operator (AO) 9 (includes 2 in Radwaste)

N/A Operations Center/Field SRO 1 Operations Center/Field SRO SRO STA 1 STA STA Qualified

The STA may stand watch as a CRS or Reactor Operator provided the following requirements are met:

At least 4 SROs are available on shift (this includes the STA hut does NOT include the Fire Brigade Advisor which may be filled by an RO licensed individual).

Another Licensed Operator is designated to relieve the STA as Unit CRS or RO.

(Relief as Reactor Operator is required if only one operator is assigned to a unit Relief as CR5 shall he filled from the CR5 position on the shift staffing roster.)

The designated relief must NOT be assigned as the Fire Brigade Advisor.

The designated relief has taken turnover on the affected unit.

The designated relief must he able to relieve the STA within 10 minutes.

001-Ui.131 Rev.

Page 14 of 177 Sheet 1 of 2 Shift Manning BNP Position SM CRS SRO/STA RO AO - Shift Staffing Sheet 1 of2 Minimum Note staffing 1

2 1

3 9

9.5 Operations Shift Staffing In addition to the requirements of OPS-NGGC-1000, the following requirements apply:

9.5.1 General The following table outlines the administrative guideline for the normal Operations shift complement A.flY deviation from the normal shift complement must remain in accordance with Section 5.2.2 of Technical Specifications, and applicable sections of OASSO-OO, OFPP-031, and Attachment 13. (Attachment 13 contains a listing of required ERO Watch Stations and qualifications for each and ASSD positions. This attachment may be used as a tool to support determining shift staffing requirements.)

BNP Watchstations BNP Shift Com~lement License Shift Manager (SM) 1 Shift Manager SRO Control Room Supervisor (CRS) 2 CRSs (1 for each unit)

SRO Reactor Operator (RO) 4 Reactor Operators (typically, 2 RO/SRO for each unit)

Auxiliary Operator (AO) 9 (includes 2 in Radwaste)

N/A Operations Center/Field SRO 1 Operations Center/Freid SRO SRO STA' 1 STA ST A Qualified

'The STA may stand watch as a CRS or Reactor Operator provided the following requirements are met:

At least 4 SROs are available on shift (thiS includes the STA but does.NOT include the Fire Brigade Advisor which may be filled by an RO licensed individual).

Another Licensed Operator is designated to relieve the STA as Unit CRS or RO.

(Relief as Reactor Operator is required if only one operator is assigned to a unit Relief as CRS shall be filled from the CRS position on the shift staffing roster.)

The deSignated relief must NOT be assigned as the Fire Brigade Advisor.

The deSignated relief has taken turnover on the affected unit.

The deSignated relief must be able to relieve the STA within 10 minutes.

1001-01.01 Rev. 29 Page 14 of 1771

ATTACHMENT 13 Page 1 of 2 Operations Staffing Roster Date:__________________

Shift:________________

STA P613 STA SRO PB11 Unit 1 CRS/U-1 RSD Panel SRO PB1I Unit 2 CRS1U-2 RSD Panel ARO PB12 Unit 1 RB MCC Operator ARC P812 Unit 2 RB MCC Operator ARC PB12

FB Advisor CREC PBI7 CREC AC PB14 SW Operator AC P614 DC Operator AC P814 Emergency Switchgear Operator FB (SIC) FBO2FBD3 FB (SIC)

FB FBO2 F8 F8 FBO2 FB FB FGO2 FB FB F802 FB Security Contact E&RC Contact Maintenance Contact A

May hold an RO OR SRO license.

Security Key Accountability iiiui; ii*;

Unit I RB AC Unit2 RBAO Outside AC Unit 1 CRS Un1t2CRS Shift Manager 001-01.01 Rev 29 Page 97 of 177 Date: ______

ATTACHMENT 13 Page 1 of 2 Operations Staffing Roster Shift ______ _

May hold an RO OR SRO license.

Security Key Accountability 1001-01.01 Rev. 29 Page 97 of 1771

5.2.2 Facility Staff The facility staff organization shall include the following:

a.

A total of three non-licensed operators shall be assigned for Brunswick Units I and 2 at all times.

Organization 5.2 5.2 Organization 5.2.2 Facility Staff continued) b.

At east one licensed Reactor Operator (RO) shall be present in the control room when fuel is in the reactor. In addition, when either unit is in MODE 1, 2, or 3. at least one licensed Senior Reactor Operator (SRO) shall be present in the control room. With one unit in MODE 1, 2, or 3 and the other unit defueled, the minimum shift crew shall include a total of two SROs and two ROs.

c Shift crew composition may be less than the minimum requirement of 10 CFR 50.54(m)(2)(i) and Specifications 5.2.2.a and 5.2.2.g for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements.

d.

An individual qualified in radiation protection procedures shall be on site when fuel is in the reactor. The position may be vacant for not more than 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , in order to provide for unexpected absence, provided immediate action is taken to fill the required position.

e.

Deleted.

f.

The operations manager or assistant operations manager shall hold an.

SRO license.

g.

The shift technical advisor shall serve in an advisory capacity to the shift superintendent on matters pertaining to the engineering aspects assuring safe operation of the unit when either unit is in MODE 1.2, or 3.

Eiunswick Unit 1 5.0-3 Amendment No. 253 I

5.2.2 Facility Staff The facility staff organization shall include the fol[owing:

a.

A total of three non-licensed operators shall be assigned for Brunswick Units 1 and 2 at all times.

5.2 Organization 5.2.2 Facility Staff (continued)

( continued)

Organization 5.2

b.

At least one licensed Reactor Operator (RO) shall be present in the control room when fuel is in the reactor. In addition, when either unit is in MODEl, 2, or 3. at least one licensed Senior Reactor Operator (SRO) shall be present in the control room. V'I'ith one unit in MODEl, 2, or 3 and the other unit defueled, the minimum shift crew shall include a total of two SROs and two ROs.

c.

Shift crew composition may be lee.s than the minimum requirement of 10 CFR SO.54(m){2)(i) and Specifications 5.2.2.a and 5.2.2.g for a peliod of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements.

d.

An individual qualified in radiation protection procedures shall be on site when fuel is in the reactor. The position may be vacant for not more than 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , in order to provide for unexpected absence: provided immediate action is taken to fill the required pOSition.

e.

Deleted.

f.

The operations manager or assistant operations manager shall hold an SRO license.

g.

The shift technical advisor shall serve in an advisory capacity to the shift superintendent on matters pertaining to the engineering aspects assuring safe operation of the unit when either unit is in MODE 1, 2, or 3.

Brunswick Unit '1 5.0-3 Amendment No. 253 I

Categories K/A:

SG2.0L05 Tier/Group:

T3 RO Rating:

2.9 SRO Rating:

3.9 LP Obj:

CLSLP3O4M*13M Source:

NEW Cog Level:

HIGH Category 8:

Y Categories KIA:

SG2.01.05 Tier / Group: T3 RORating:

2.9 SRORating

3.9 LP Obj:

CLS-LP-304-M* 13M Source:

NEW Cog Level:

HIGH Category 8:

Y

95. OFH-1 1, Refueling, prohibits control rod withdrawal during the core load sequence until a neutronic bridge is established.

Which one of the following core loading sequences establishes a neutronic bridge as described in OFH-1 1?

Four fuel bundles are loaded around (1)

,then fuel is loaded in all fuel cells in a line between SRMs (2)

A. (1) SRMsAand Donly (2) AandD B.

(1) SRMs B and D only (2) B and D C. (1) each of the four SRMs (2) A and D D (1) each of the four SRMs (2) B and D

95. OFH-11, Refueling, prohibits control rod withdrawal during the core load sequence until a neutronic bridge is established.

Which one of the following core loading sequences establishes a neutronic bridge as described in OFH-11?

Four fuel bundles are loaded around (1)

,then fuel is loaded in all fuel cells in a line between SRMs (2)

A. (1) SRMs A and D only (2) A and D B. (1) SRMs Band D only (2) Band D

c. (1) each of the four SRMs (2) A and D D~ (1) each of the four SRMs (2) Band D

Feedback K/A: SG2.01.42 Conduct of Operations Knowledge of new and spent fuel movement procedures.

(CFR: 41.10/43.7/45.13)

RO/SRO Rating: 2.5/3.4 Objective: CLSLP305C*

Reference:

OFH-1, Revision 93, Page 9, Section 4.37 Cog Level: High Explanation:

Provide ENP-24-12, Figure 1 as a reference From FH-11, 4.37 To help ensure that an unmonitored criticality will not occur, control rod withdrawal is not allowed during the core reload sequence until a neutronic bridge is established. The neutronic bridge ensures that two SRMs are neutronically coupled, thus monitoring the loaded area of the core. The reload sequence has three basic steps. Four fuel bundles are loaded around each of the four SRMs, the neutronic bridge is established and a spiral reload of the other fuel bundles completes the sequence. The neutronic bridge is established by loading fuel in all fuel cells in a line between two SRMs. These SRMs must be on opposite sides of the core and the line of loaded fuel cells must intersect the center of the core (A to D would not intersect the center, B to D would).

Distractor Analysis:

Choice A: Plausible because loading fuel around 2 SRMs and a line between them would establish a neutron bridge (between those 2 SRM5) but not PAW OFH-1 1 and A&D are adjacent.

Choice B: Plausible because loading fuel around 2 SRMs and a line between them would establish a neutron bridge (between those 2 SRM5) but not JAW OFH-1 I and A&D are adjacent.

Choice C: Plausible because loading fuel around all SRMs is correct but A&D are adjacent.

Choice D: Correct Answer SRO Only Basis: IOCFR55.43.6 Procedures and limitations involved in initial core loading, alterations in core configuration, control rod programming, and determination of various internal and external effects on core reactivity.

IOCFR55.43.7 Fuel handling facilities and procedures.

Notes Feedback KIA: SG2.01.42 Conduct of Operations Knowledge of new and spent fuel movement procedures.

(CFR: 41.10/43.7/45.13)

RO/SRO Rating: 2.5/3.4 Objective: CLS-LP-305-C*

Reference:

OFH-1, Revision 93, Page 9, Section 4.37 Cog Level: High Explanation:

Provide ENP-24-12, Figure 1 as a reference From FH-11, 4.37 To help ensure that an unmonitored criticality will not occur, control rod withdrawal is not allowed during the core reload sequence until a neutronic bridge is established. The neutronic bridge ensures that two SRMs are neutronically coupled, thus monitoring the loaded area of the core. The reload sequence has three basic steps. Four fuel bundles are loaded around each of the four SRMs, the neutronic bridge is established and a spiral reload of the other fuel bundles completes the sequence. The neutronic bridge is established by loading fuel in all fuel cells in a line between two SRMs. These SRMs must be on opposite sides of the core and the line of loaded fuel cells must intersect the center of the core (A to D would not intersect the center, B to D would).

Distractor Analysis:

Choice A: Plausible because loading fuel around 2 SRMs and a line between them would establish a neutron bridge (between those 2 SRMs) but not lAW OFH-11 and A&D are adjacent.

Choice B: Plausible because loading fuel around 2 SRMs and a line between them would establish a neutron bridge (between those 2 SRMs) but not lAW OFH-11 and A&D are adjacent.

Choice C: Plausible because loading fuel around all SRMs is correct but A&D are adjacent.

Choice D: Correct Answer SRO Only Basis: 10CFR55.43.6 Procedures and limitations involved in initial core loading, alterations in core configuration, control rod programming, and determination of various internal and external effects on core reactivity.

10CFR55.43.7 Fuel handling facilities and procedures.

Notes

4.0 PRECAUTIONS AND LIMITATIONS 4.34 RPS shorting links SHALL be removed for control rod withdrawal (except for control rods removed in accordance with Technical Specifications) in the refuel mode when core verification AND subsequent strongest rod out verification have NOT been performed. Control rods may be withdrawn with the shorting links installed, provided core verification (QENP-24.13),

subsequent strongest rod out verification (single control rod suhcriticality test in accordance with OFH-1 1) have been performed, and the one-rod-out refuel interlocks have been demonstrated to be operable.

4.35 An SRO with no other concurrent duties shall directly supervise all core alterations.

4.36 Members of fuel handling crew, scheduled for consecutive daily duty, should NOT normally work more than 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months out of each 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

4.37 To help ensure that an unmonitored criticality will NOT occur, control rod withdrawal is NOT allowed during the core reload sequence until a neutronic bridge is established. The neutronic bridge ensures that two SRM5 are neutronically coupled, thus monitoring the loaded area of the core. The reload sequence has three basic steps. Four fuel bundles are loaded around each of the four SRMs, the neutronic bridge is established and a spiral reload of the other fuel bundles completes the sequence. The neutronic bridge is established by loading fuel in all fuel cells in a line between two SRM& These SRMs must be on opposite sides of the core and the line of loaded fuel cells must intersect the center of the core.

4.38 With fuel removed, if a control rod is withdrawn without blade guides installed, the insertion capability shall be removed for the control rod.

4.39 The Bridge Operator should immediately push the STOP button if the bridge fails to respond to Operator commands, such as speed changes or jogs. The STOP button will prevent all bridge movement 4.40 If attaching tools, such as ajet pump grapple or control blade latching tool, to either the monorail or frame mounted hoist, verify proper thread engagement/size by ensuring there is no play in the connection prior to thread engagement of three (3) full tum& The correct tool and coupling thread size is 7116-14 UNC. Additionally, a 112-13 UNC bolt will not fit into a proper size tool (7/16-14 U NC); thus, this check may be performed if practical. Failure to detect mis-matched thread sizes will significantly reduce the load capacity of the tool/hoist.

4.41 Indication of criticality observed on the SRM indicators during functional, subcritical, or shutdown margin rod checks shall be reason to teminate fuel loading until a complete evaluation of the cause of the criticality indication is determined.

OFH-1 1 Rev. 93 Page 9 of 55 4.0 PRECAUTIONS AND LIMITATIONS 4.34 RPS shorting links SHALL be removed for control rod withdrawal (except for control rods removed in accordance with Technical Specifications) in the refuel mode when core verification AND subsequent strongest rod out verification have NOT been performed. Control rods may be withdrawn with the shorting links installed, provided core verification (OENP-24.13),

subsequent strongest rod out verification (single control rod sub criticality test in accordance with OFH-11) have IJeen performed, and the one-rod-out refuel interlocks have been demonstrated to IJe operable.

4.35 An SRO with no other concurrent duties shall directly super"ise all core alterations.

4.36 Members of fuel handling crew, scheduled for consecutive dail~' duty, should NOT nom13l1y work more than 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months out of each 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

4.37 To help ensure that an unmonitored criticality will NOT occur, control rod withdrawal is NOT allowed during the core reload sequence until a neutronic bridge is established. The neutronic bridge ensures that two SRMs are neutronically coupled, thus monitoring the loaded area of the core. The reload seQuence has three basic steps. Four fuel bundles are loaded around each ofthe four SRMs, the neutronic bridge is established and a spiral reload of the other fuel bundles completes the sequence. The neutronic bridge is established by loading fuel in all fuel cells in a line between two SRMs. These SRMs must be on OPPOsite sides of the core and the line of loaded fuel cells must intersect the center of the core.

4.38 With fuel removed, if a control rod is withdrawn without blade guides installed, the insertion capabiliPf shall be removed for the control rod.

4.39 The Bridge Operator should immediately push the STOP button if the bridge failS to respond to Operator commands, such as speed changes or jogs. The STOP button will prevent an bridge movement.

4.40 If attaching tools, such as a jet pump grapple or controll)lade latching tOOl, to either the monorail or frame mounted hoist, verify proper thread engagement/size by ensuring there is no play in the connection prior to thread engagement of three (3) full turns. The correct tool and coupling thread size is 7116-14 UNC. Additionally, a 112-13 UNC IlOlt wiI[ not fit into a proper size tool {7/16-14 UNC); thus, this check may be performed if practical. Failure to detect mis-matched thread sizes will significantly reduce the load callacity of the tOOl/hoist.

4.41 Indication of criticality observed on the SRM indicators during functional, subcritical, or shutdown margin rod checks shall be reason to temlinate fuel loading until a complete evaluation of the cause oftM criticality indication is determined.

IOFH-11 Rev. 93 Page90f55 I

FIGURE 09.1-2 IN-Core Instrurnenation Location Diagram 00 LI IRM DETECTOR LOCATION DETECTOR LOCATION PLANT NORTH CORE RM LOCATION A

12.41 B

36-41 C

20-33 0

283.3 CORE IRM LOCATION E

28.25 F

20-26 G

36-09 H

12-09 SD-091 Rev. 6 Page 49 of 61 Categories K/A:

SG2.O1.42 RORating:

2.5 LP Obj:

Tier/Group:

T3 SRO Rating:

3.4 Source

BANK CORE SRM LOCATION A

12.33 B

2641 C

36-26 0

20.17 Cog Level:

HIGH Category 8:

Y FIGURE 09.1-2 IN-Core Instrumentation Location Diagram r

r r!,

LA..J r

(, ~

~ ~

L L

rHl I I

L 12 CORE SRM LOCATION A

12.33 a

28-41 C

36-25 0

20*11 I SD-09.1 Categories KIA:

SG2.01.42 RO Rating:

2.5 LPObj

Cog Level:

HIGH PLANT ~

NORTH,..".-

n h

/'" ~

l/

B,-l

--41

~

ffr

-33 4:f. ~

t:l.f; ~

'( -:;

-25

~ ~

~ :J w

-11 L.~

w

--09 W

20 28 D IRM DETECTOR LOCATION ZSIO SRM DETECTOR LOCATION CORE CORE IRM LOCATION IRM LOCATION A

12*41 E

28*25 B

36-41 F

20*25 C

20*33 G

36*09 0

28.33 H

12*09 Rev. 6 Page490f61 I Tier / Group: T3 SRORating:

3.4 Source

BANK Category 8:

Y

96. With Unit Two operating at power, Annunciator RCIC TURBINE STM LINE DRN POT LEVEL HI alarms and the RO observes the E51-F054, F025, & F026 indicate closed on Panel P601.

Which one of the following identifies the cause of the above indications and the operability status of RCIC?

(Reference provided)

These valves are closed due to loss of (1) and after taking the appropriate actions in the annunciator procedure the system would be declared Inoperable and(but)

(2)

A.

(1) pneumatics (2) Unavailable B (1) pneumatics (2) Available C. (1) DC Power (2) Unavailable D. (1) DC Power (2) Available

96. With Unit Two operating at power, Annunciator RCIC TURBINE STM LINE DRN POT LEVEL HI alarms and the RO observes the E51-F054, F025, & F026 indicate closed on Panel P601.

Which one of the following identifies the cause of the above indications and the operability status of RCIC?

(Reference provided)

These valves are closed due to loss of (1) and after taking the appropriate actions in the annunciator procedure the system would be declared Inoperable and (but)

(2)

A. (1) pneumatics (2) Unavailable B:-" (1) pneumatics (2) Available C. (1) DC Power (2) Unavailable D. (1) DC Power (2) Available

Feedback K/A: SG2.02.15 EQUIPMENT CONTROL Ability to determine the expected plant configuration using design and configuration control documentation, such as drawings, line-ups, tag-outs, etc.

(CFR: 41.10 143.3/45.13)

ROISRO Rating: 3.9/4.3 Objective: CLSLP016*15e

15. Given plant conditions, predict the RCIC System response to the following conditions:

s. Loss of instrument air.

e. DC power failure.

Reference:

2APP A-03 3-5, Revision 49, Page 44 Cog Level: High Explanation:

Valves fail closed on loss of DC power or Pneumatics, however with a loss of power, position indication on P601 will also be lost. Per APP A-03, 3-5

- If either E51-F025 or E51-F026 has been failed closed for more than 5 minutes, perform the following:

a. Close Turbine Trip and Throttle Valve, E51 -V8, to prevent water hammer damage from a RCIC auto start.

b. If RCIC must be started, proceed to OP-16.

this would still make RCIC available for use per the procedure but it is inoperable because it will not auto start as required.

This will make the RCIC system inoperable but available to be restarted per the procedure.

Distractor Analysis:

Choice A: Plausible because loss of pneumatics only is correct and the system will not start in auto when required, but could be manually started.

Choice B: Correct Answer Choice C: Plausible because a loss of power will cause valves to fail closed, but with loss of power position indication will be lost and the system will not start in auto when required.

Choice D: Plausible because pneumatics and power will cause valves to fail closed, but with loss of power position indication will be lost and it is available to start per the procedure which makes it available.

SRO Only Basis: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, emergency conditions.

Notes Feedback KIA: SG2.02.15 EQUIPMENT CONTROL Ability to determine the expected plant configuration using design and configuration control documentation, such as drawings, line-ups, tag-outs, etc.

(CFR: 41.10/43.3/45.13)

RO/SRO Rating: 3.9/4.3 Objective: CLS-LP-016*15e

15. Given plant conditions, predict the RCIC System response to the following conditions:

s. Loss of instrument air.

e. DC power failure.

Reference:

2APP A-03 3-5, Revision 49, Page 44 Cog Level: High Explanation:

Valves fail closed on loss of DC power or Pneumatics, however with a loss of power, position indication on P601 will also be lost. Per APP A-03, 3-5 -If either E51-F025 or E51-F026 has been failed closed for more than 5 minutes, perform the following:

a. Close Turbine Trip and Throttle Valve, E51-V8, to prevent water hammer damage from a RCIC auto start.

b. If RCIC must be started, proceed to OP-16.

this would still make RCIC available for use per the procedure but it is inoperable because it will not auto start as required.

This will make the RCIC system inoperable but available to be restarted per the procedure.

Distractor Analysis:

Choice A: Plausible because loss of pneumatics only is correct and the system will not start in auto when required, but could be manually started.

Choice B: Correct Answer Choice C: Plausible because a loss of power will cause valves to fail closed, but with loss of power position indication will be lost and the system will not start in auto when required.

Choice D: Plausible because pneumatics and power will cause valves to fail closed, but with loss of power position indication will be lost and it is available to start per the procedure which makes it available.

SRO Only Basis: Assessment of facility conditions and selection of appropriate procedures during normal, abnormal, emergency conditions.

Notes

RCIC STEAM POT Partial P&ID RCIC STEAM POT Partial P&ID

~

QRAIN!

I

.f.£lI.

F04S

Unit 2

APP A-03 3-S Page 2 of 2

ACTIONS (Cont a)

CAUTION If Main Steam Line Drain Vlv, NVD-F021, fails to close, then the Main Steam Line Drain Inboard and Outboard Isolation valves must be closed.

6. If reguii-ed, then close Main Steam Line Drain Inbd lad

Vlv, B21-F0l6, and Main Steam Line Drain Otbd Isol Vlv, B2l-FOl.

7. If alarm fails to clear within five minutes after completion of actions 1 2,3, 5, or 6, then dispatch an Auxiliary Operator to the Drwell access roof to determine if the HPCI/RCIC Condensate Drain Line Back Pressure Orifice is plugged or the drain line isolated.

NOTE Greater than 500 psig on HPCI/RCIC Back Pressure Orifice Inlet Pressure Gauge, 2-MVD-PI-7146 would be an indication of a plugged orifice.

8.

IF back pressure orifice is plugged, a,

Open HPCI/RCIC (ond Drn Line Back Press Orifice Bypass Valve, 2-MVD-VSOO2.

b.

Close BPCI/RCIC Cond Drn Line Back Press Orifice Inlet Isol

Valve, 2-MVD-VS000.

c.

Close HPCI/RCIC Cond Drn Line Back Press Orifice Outlet Isol

Valve, 2-MVD-VSOOl.

d.

Place valves under proper administrative control.

9.

If NPCI/RCIC Cond Drain Line is isolateth a.

Open HPCI/RIC (ond Drn Line Back Press Orifice Inlet Isol

Valve, 2-MVD-VS000.

b.

Open HPCI/RCIC Cond Drn Line Back Press Orifice Outlet Isol

Valve, 2-MVD-VSOOl.

10.

IF a circuit malfunction is suspected, ensure that a WE/JO is prepared.

DEVICE/SETPOINTS Level Switch ES1-LSH-NO1O-l Instrument failure in the Switch Point tl dry condition/1980 my.

Level Switch ESl-LSH-NOl0-l Also detects instrument failure in the Switch Point #2/0 +/- 2 wet condition.

Incox-porates water.

100 sec time delay in annunciator circuitry.

POSSIBLE PLANT EFFECTS Damage to the RCIC turbine due to high moisture carryover on the steam.

REFERENCES 1.

LL-9364 50 2.

OP-iS, RCIC System Operating Procedure 2APP-A-03 Rev. 49 Page 45 of 102 Unit 2 APP A-03 3-5 Page 2 of 2 ACTIONS (Cont'd)

CAUTION If r~in Steam Line Drain v~v, MVD-F021, fails to close, then the Main Steam Line Drain Inboard and Outboard Isolation valves must be closed.

6. If required, then close [*lain Stearn Line Drain Inbd Iso1 V1v, B21-F016, and Main Steam Line Drain Otbd Iso1 V1v, B21-F019.

7. If alarm fails to clear within five minutes after completion of actions 1 2,3, 5, or 6, then dispatch an Auxiliary Operator to the Drywe11 access roof to determine if the HPCI/RCIC Condensate Drain Line Back Pressure Orifice is plugged or the drain line isolated.

NOTB:

Greater than 500 psig on HPCI/RCIC Back Pressure Orifice Inlet Pressure Gauge, 2-1*lYD-PI-7146 would be an indication of a plugged orifice.

8.

IF back pressure orifice is plugged,

a.

Open HPCI/RCIC Cond Drn Line Back Press Orifice Bx~ss Valve, 2-['lVD-V5002.

b.

Close HPCI/RCIC Cond Drn Line Back Press Orifice Inlet Iso1 Valve, 2-t-1VD-V5000.

c.

Close HPCI/RCIC Cond Drn Line Back Press Orifice Outlet Isol Valve, 2-t-r.rD-V5001.

d.

Place val,,'es under proper adrninistrat ive control.

9.

If HPCI/RCIC Cond Drain Line is isolated:

a.

Open HPCI/RCIC Cond Drn Line Back Press Orifice Inlet Isol

Valve, 2-M'~~-V5000.

b.

Open HPCI/RCIC Cond Drn Line Back Press Orifice Outlet Isol Valve, 2-M'.rD-V5001.

10. IF a circuit malfm1ction is suspected, ensure that a WR/JO is prepared.

D~vlCE/SETPOINTS Level Switch E51-LSH-NOIO-l Switch Pc,int #1 Level Switch E51-LSH-NOIO-l the Switch Point #2/0" +/- 2" water.

POSSIBLE PLANT EFFECTS Instrument failure in the dry condition/1980 mV.

.~lso detects instrument fa.ilure ill wet condition.

Inc01~orates 100 sec time delay in ~1nunciator circuitry.

Damage to the RCIC turbine due to high moisture carryover on the steam.

REFERENCES

1.

LL-9364 - 50

2.

OP-16, RCIC System Opera.t ing Procedure I2APP-A-03 Rev. 49 Page 45 of '1021

Unit 2

APP A-03 3-S Page 1 of 2

RCIC TIJREINE STh LINE DRN POT LEVEL HI RCIC Turbine Steam Line Water Drain Pot High Level)

AUTO ACTIONS 1.

Supply Drain Pot Drain Bypass Valve, ES1-F054, opens.

CATJSE 1.

Heavy condensate load dul-ing steam line warmup.

2.

Normal orifice clogged.

3, HPCIJRCIC ond.

Drain Line Back Pressure Orifice is plugged.

4.

Drain line isolation valves to main condenser closed.

5.

Drain pot level instrument failure or loss of instrument, power.

6.

Circuit malfunction.

OBSERVATIONS 1.

RCIC Supply Drain Pot Drain Byp Valve, ESl-F054, opened.

NOTE:

If alarm occurs and the ES1-F054 valve does not automatically open, the most probable cause is instrument failure or loss of instrument power (Panel 2B-Rx PH1O1T CKT 14),

NOTE:

Additional LED indications are available inside the level element control box device HSE (RB 20 elevation) as follows:

Normal status No annunciator No LEDs illuminated High Water level Green LED on Instrument failure Red LED on ACTIONS 1.

Ensure Supply Drain Pot Drain Byp Vlv, ESl-F054, is open.

2.

Ensure RCIC Supp Pot Inbd Isolation Valve, ESi-F025, is open.

3.

Ensure RCIC Supp Pot Outbd Isolation Valve, ES1-F026, is open.

NOTE:

Valves E51-F025 and E51-F026 will close on loss of instrument air and will also close if E5l-F045 is not fully closed.

Valves ES1-F025 and E51-F026 cannot be opened in either of these conditions.

4.

If either ESl-Ft25 or ESl-F026 ha been failed closed for more than 5 minutes, perform the following:

a.

Close Turbine Trip and Throttle Valve, ESl-V8, to prevent water hammer damage frcm a RCIC auto start.

b.

If RCIC must he started, proceed to OP-16.

S.

Ensure Main Steam Drain Lme Vlv, MVD-F02l, is cload.

2APP-A-03 Rev. 49 Page 44 of 102 Unit 2 APP "~.-03 3-S Page 1 of 2 RCIC TURBINE STI-l LINE DRN POT LEVEL HI iRCIC Turbine Steam Line Water Drain Pot High L=vel)

"~UTO ACTIONS C.... USE

1.

Supply Drain Pot Drain Bypass Valve, ESI-F054, opens.

1.

Heavy condensate load during steam line warmup.

2.

Normal orifioe clogged.

3.

HPCI!RCIC Cond. Drain Line Baok Pressure Orifioe is plugged.

4.

Drain line isolation valves to main oondenser olosed.

S.

Drain pot level instrument failure or loss of instrument po;;er.

6.

Cirouit malfunction.

OBSERVATIONS

1.

RCIC Supply Drain Pot Drain Byp Valve, ES1-F054, opened.

NOTE:

If alarm ooours and the E51-FOS4 valve does not automatioally open, the most probable oause is instrument failure or loss of instrument power (Panel 2B-Rx "HIO" CKT 14/.

NOTE:

Additional LED indioations are available inside the level element control box device H5E (P£ 20' elevation) as follo;;s:

Normal status No annunciator No LEDs illuminated Green LED on Red LED 011.

ACTIONS High Water level Instrument failure

1.

Ensure Supply Drain Pot Drain Byp "lIlv, ESI-FOS4, is open.

2.

Ensure RCIC Supp Pot IOOd Isolation Valve, ESI-F025, is open.

3.

Thlsure RCIC Supp Pot Outbd Isolation Valve, ESI-F026, is open.

NOTE:

Valves E51-F025 and ESI-F026 will close on loss of instrument air and will also close if ESI-F045 is not fully olosed.

Valves ESI-F025 and E51-F026 oannot be opened in either of these conditions.

4.

If either ESI-F025 or ES1-F026 has been failed olosed for more than 5 minutes, perform the following:

a.

Close Turbine Trip and Throttle Valve, ESI-V8, to prevent water hammer damage from a RCIC auto start.

b.

If RCIC must be started, proceed to OP-16.

S.

Ensure Main Steam Drain Line Vlv, MVD-F02l, is olosed.

I2APp-A-03 Rev. 49 Page 44 of '1021

I IF rapid isolation is NOT desired, THEN PERFORM the following to isolate and de-pressurize the RCIC steam supply line:

a.

CLOSE STEAM SUPPLY INBOARD 1SOL VLV, E51-F007.

b.

OPEN HPCLRCIC COND DRN LINE SACK PRESS ORiFiCE BYPASS VALVE MVD-V5002.

c.

OPEN TURBiNE STEAM SUPPLY VL E1-FO45, AND MONITOR turbine response.

d.

CLOSE SUPPLYDRAIN POT1N8D DRAIN VLV, E1-FO25.

e.

CLOSE SUPPLY DRAiN POT OTBD DRAIN VLV, E51-FO26.

20P-16 Rev. 107 Page 34 oi1 R

R3r9rr Uae 8.4 Isolating the RCIC System Steam Supply 8.4.1 Initial Conditions 1.

All applicable prerequisites listed in Section 4.0 are met.

8.4.2 Procedural Steps 1.

IF rapid isolation of RCIC steam line is desired, THEN PERFORM the following:

a.

CLOSE STEAM SUPPLYIWBOARD ISOL VLV, E1-FOO7.

b.

CLOSE STEAMSUPPLYOUTBOARDISOL VLV, E1-FOO8.

8.4 Isolating the RCIC System Stearn Supply 8.4.1 Initial Conditions

1.

All applicable prerequisites listed in Section 4.0 are met.

8.4.2 Procedural Steps

1.

IF rapid isolation of RCIC steam line is desired, THEN PERFORM the following:

a.

b.

CLOSE STEAM SUPPL Y INBOARD /SOL VL V.

E51-F007.

CLOSE STEAM SUPPL Y OUTBOARD ISOL VL 11, E5'1-FOOB.

CAUTION o

o o

Opening the TURBINE STEAM SUPPL Y VL V. E51-F045, to de-pressurize the RCIC steam line will roU the RCIC turbrne,

2.

IF rapid isolation is NOT desired, THEN PERFORM the following to isolate and de-pressurize the RCIC steam supply line:

a.

CLOSE STEAM SUPPL Y INBOARD ISOL VL V.

0 E51-FOO7,

b.

OPEN HPCllf?CIC COND DRN LINE BACK 0

PRESS ORIFICE BYPASS VALVE, MVD-V5002.

c.

OPEN TURBINE STEAM SUPPL Y VL V, 0

E51-F045, AND MONITOR turbine response.

d.

CLOSE SUPPLY DRAIN POT lNBD DRAIN VLV; 0

E51-F025.

e.

CLOSE SUPPLY DRAIN POT OTaD DRAIN VL1I, 0

E51-F026.

R Rijlefijr Use 12oP-16 Rev. 107 Page 34 of 891

8.12 Controlled Manual Start of the RCIC System With Turbine Steam Line R

Drain Pot High Level or RCIC Pump Low Discharge Pressure Refrence Indicated 8.12.1 Initial Conditions 1.

IF RCIC is being operated for a planned evolution (non emergency operation), THEN Health Physics (HPs) shall be notified to attend the pre-job briefing AND a log entry made to identify the individual contacted.

2.

One of the following conditions exist:

a.

The RCIC turbine has been shutdown or tripped and annunciator RC!C TURBINE STM LINE DRN POT LEVEL HI (A-03 3-5) sealed in.

b.

The RCIC turbine has been shutdown or tripped and the RCIC PUMP DISH PRESS LOW annunciator (A-02, 1-6) is sealed in.

3.

A controlled manual start of RCIC is desired.

8.12.2 Procedural Steps CAUTION The RCIC turbine has the potential for failures that could cause personnel injuries. The potential is most significant when the system is initially started after control system maintenance, or after an extended period of being idle. Announcing turbine starts and clearing of all personnel from the RCIC area are required during this period of risk.

Permission to access this area during initial RCIC roll requires the approval of the Unit sco.

1.

EVACUATE all personnel f 0111 he RCIC turbine area.

20P-16 Rev. 107 Page 52 of 89 8.12 Controlled Manual Start of the RCIC System With Turbine Steam Line Drain Pot High Level or RCIC Pump Low Discharge Pressure Indicated 8.12.1 Initial Conditions IF RCIC is being operated for a planned evolution (non-emergency operation), THEN Health Physics (HPs) shall be notified to attend the pre~ob briefing AND a log entry made to identify the individual contacted.

o

2.

One of the follol;1,1ng conditions exist

3.

8.12.2

a.

b.

The RCIC turbine has been shutdown or tripped and annunciator RCIC TURBINE STM LINE DRN POT LEVEL HI (A-03 3-5) sealed in.

The RCIC turbine has been shutdown or tripped and the RCIC PUMP DISCH PRESS LOW annunciator (A-02, 1-6) is sealed in.

A controlled manual start of RCIC is desired.

Procedural Steps CAUTION o

o o

The RCIC turbine has the potential for failures that could cause personnel injuries. The potential is most significant when the system is initially started after control system maintenance, or after an extended period of being idle. Announcing turbine starts and clearing of all personnel from the RCIC area are required during this period of risk.

Permission to access this area during initial RCIC roll requires the approval of the Unit SCO.

EVACUATE all personnel from the RCIC turbine area.

0 R

Reference Use 120p--.16 Rev. '107 Page 52 of 891

ATTACHMENT 2A Page5of 30 PANEL 4A LOCATION NORMAL SUPPLY Reference Drawing LL-3024-6 Control Building 49 ft East Switchboard 2A CIRCUIT LOAD EFFECT Rx.Annunciator Logic, 2-H12-P630 1.

Auto transfers to alternatesource, PaneI4B circuit 1.

Panels 80t/503 2.

Receive annunciator A5-&.

2 HPCI Flow controler 1.

Controller fails downscale.

E41-FIC-K800 (24 VDC;.

2.

Loss of f;ow ndicatcn.

3.

Receive annunciator A 1-2-5.

4.

Loss of HPCI 5.

Loss of ASSD function.

HPC1 Supervisory Lights 1.

Loss of E41-VS and E4l-V indicaticn 2.

Loss HPCI oil tank level HilLO alarm.

HPCI Vertical Board meters 1.

Loss of pressure transmitters/meters R6OI R32, R503, R80(

(52.5 VDC)

HPCI Turbine Speed Control 1.

Loss of speed control, 2GM and soeed sensor.

2.

Loss of speed indicaon on veitcal board.

E41-F053, E41-FOE4, E41-F026 1.

Fail closed.

2.

E41-F054 and 241-F026 loss of indication.

251-F006,E51-F025 1.

Failclosed.

2.

Loss of indication, 001-50 Rev. 45 I

Reference Drawin CIRCUIT lOAD 1

R>:. Annunciator logic, 2-H12-P630

i.

Panels 60 !fe03

2.

2 HPCI Flow controller

[1 E41-FIC-K600 (24 \\lDC)

2.

3.

4.

5.

HPCI Super~'isory Lights

1.

2.

HPCI Vertical Board meters

[1.

(52.5 VDC)

HPCl Turbine Speed Control

i.

2.

E41-F053, E41-F054. E41-F026

1.

2.

E51-F005, E51-F025

1.

2.

1001-50 ATTACHMENT 2A Page 5 of 30 NORMAL SUPPLY Switchboard 21\\

EFFECT Auto transiers to alternate source, Panel4B circuit 1 Receive annunciator Ae-5-S.

Controller fails downsca.ie.

loss of flo'l/ indication.

Reoeive annunciator A 1-2-5.

loss of HPCr loss of ASSD function.

loss of E41-1/S and E41-V9 indication loss HPCI oil lank le... el HillO alam *.

loss of pressure transmitters/meters Re01, R602. Re~3, R60!

loss of speed control, EGM and speed sensor.

loss of speed indication on vertioal board.

Faif closed.

E41-F054 and E41-F026 loss ofindication.

Fail clcsed.

loss of indication.

Rev. 45

ATTACHMENT 25 Page 90132 PANEL: 4B LOCATION:

NORMAL SUPPLY:

Reference Drawing: LL-3024-7 Control Building 49 ft South Switchboard 2B Cku:,

LOAD EFFECT E

Recrc Pump 3 Auxiliary EqtLpment 1.

Loss of aJternate control power to:

Aternate Control Power Recirc B Gen. Fielo Breaker, control, frp and indicaior.

Recirc B Scoop Thbe Power Failure Look & Reset Recirc Lube Oil Pumps S-i ano 8-2, control and ndication.

Reciro B Lock out lTrp Logic ATWS Trip Logic S 2.

Normal power is from Panel 1OA, ckt 2.

Backup Scram valve. 2-C12-1 lflS 1.

Backup Scram valve fails closed; Div I Backup Scram valve can still fun Div II Backup Scram Logic 1.

Sc-ram Discharge Volume Vent and 2ran Vaves wil no receive a close valves will sti I function with Div I.

2.

DFWLCS wD rot receive auto set down from Div II. Digital eedwater w 2.

Ten-second tme delay por to scram reset, will not function for B RPS 7

Spare Spare RCIC Flow controller 1.

Controller sails cownecale.

E51 -FlC-KDO (24 VOC) 2.

Loss of flow indication.

3.

Receive annunciator A3-6-5.

RCIC Supervisory Lights 1.

Loss of E51-V8 and 251-VQ ndic-ation.

RCIC Vertical Board meters 1.

Loss of pressure :ransmittersmeters ROOl, RO2, RD3, RCIJ4 on the P i2.5 VDC1 E51-F02& E51-FCD4. E51-F054 1.

Fail closed.

2.

Loss of indicaon.

HPCI E41-FC25 1.

Fail closed.

2.

Loss of indicaon.

RCIC 2GM 1.

Loss of speed control.

2.

Loss of speed indication on RIGS RCIC Initiation and Control Logic 1.

RCIC will not auto initiate. Cannot be manually operated.

2.

Receive annunciator A3-1-4.

2.

Mm flow valve will not auto open.

4.

Barometric condenser vacuum tank auto level control nop.

001-50 I

Rev. 45 r

PIPING HY QLlo PUi tC 1i4 13 tLJRB.VNDQR h1 REv)SL PLR C 6t164 55 R-Vt5fD PIR rc 64l2 A

PROGRESS ENERGY li-(MQRMATIOtI ON HS oNAw:1o CDMPI IFS WllI Ctk %l

tJtT 2 5i S/A 2-FP46 (l PO 729E48B SH 2)

REACIOR BL.i1DING RLACJOR CORE ISOLATION NOTE RLVISONS TO THIS ORAWING MUST ALSO 1E COOLiNG SYSII M P4CORPORATO ON lE CORRESPONDING ORAW14S:

PIPING I)IAG AM C) 1476, C) 0427, 0 04219, I) 04220 &

1) 04221 Dø229 PANEl:4B Reference Drawing: lL..,3024-7 Ckt#

LOAD 5

Recirc Pump 8 AuxillaI'I Equipment Alternate Control PeweI t)

Backup Scram valve, 2-C12-i=11 08 Div II Backup Scram Logic 7

Spare 8

RCIC Flo'll contrcller E5l-FIC-K800 (24 VDq RCtC Supervisory lights RCIC Vertical Board meters (52.5VDCi E51-F026. E51-F004. E51-F054 HPCr E41-F025 It RC1CEGM RCIC Initiation and Contrel Logic 1001-50 ATTACHMENT 29 Page 9 of 32 LOCATION:

J Contra! Building 49 ftSouth NOBMAt SUt>,P:L Y:

.. Switchboard 2B EFFECT

1. Loss of alternate control power to:

Recilc B Gen. Field Breaker, oontre!, trip and indication.

Recilc B Scoop Tube Power Failure Lock & Reset Recife Lube Oil Pumps 8-1 and B-2. control and indicatien.

Recifc B lock out ITrip logic A TWS Trip logic 8

2. Normal power is irom Panel lOA, ckt 3.

1. Backup Scram val'Je fails dosed; Div I Backup Scram valve can still fun,

1. Sc*ram Discharge Volume Vent and Drain Va.lves will nOl receive a close lIallies wilf still function wilh Dill I.

2. DFWLCS w~1 not receive auto, set down from Dill rI. Digital Feedwater w

3. Ten-second time delav prior to scram reset, will not function for B RPS !

Spare

1. Conlroller fails downscale.

2. Loss of flow indication.

3. Receive annunciatcr />'3-6-5.

1. Loss of E51-V8 and E51-V9 indicatien.

1. Loss of pressure transmitters/meters ReOl, R602, R60S. R804 on the R

1. Fai.!closed.

2. Loss of indication.

1. Fail closed.

2. Loss of indication.

1. Loss of speed control.

2. Loss of speed indication on RTG8

1. RCIC 'liill noi auto iniliate. Cannot be manuati'l operated.

2. Receive annunciator />'3-14.

2,_

Min flc'II valve will not auto open.

4. Barometric condenser lIacuum tank auto level oontrol inop.

Rev. 45 56 55

~~~'-L-------------~---~~~----------------;A C3 PROGRESS ENERGY

Q 1 R NIT S:

I QUPPJ

NS RUM1S &

PIPING AR REIXII IY JNII &

SSIM LMiS 2 th NLSS OTHWS N0ED UEFNCE LRWIIN(S SEC D Ø1q.

. I 511 IMEiAT lfl\\

- N RA1 ICNS Af*

MJI I; L,IHFS IR)JH QN S Iy

4. A...L INSRUAENT R.CKS AFE PREIXED 2H2l.

S. Ki *FR O OG1C [NrR1QC<,

&A.L ANUNCLA0 ALAQS R[ PRE-IXED 2 W2 Pfl XX, 7.

-. OENDTS VALVE LEAKOFT WHICH WILL E NORM&L OPEN WILL 3E PIPED TO CRW, UNDER CASS 6e.

8. VENDOR FURNIS ED.

9 < )oio f,S MASIR EQUIPMN LISt NUAt*R

. SC-CS24 IS USt) fl Sl Ci filHfR IC RkI O FtC 3S? AI[)

FO NSR OWR JIY SOUCf 10 1

NiL.

U, x=:s: CLASS

=Qc)..LTY Cj.,S EE 0- ø2i9 FQF ADDI IIQNA NOTES t2 HIGH POThT UTNT CAE S NORMALY MQVEO AND ORAIN tOSF NSTAI D FOR iS1FM VENTING ii SE ECHNICAL

PoRr PI52 FOR APPUCADLE ASPE SCrION XI RFQUIRMN7S.

LF Categories KJA:

SG2.02.15 Tier! Group:

T3 RO Rating:

3.9 SRO Rating:

4.3 LP Obj:

CLSLPO16*15E Source:

NEW Cog Level:

HIGH Category 8:

YF UNlf &:

.), I NSmUI,lENtAl ION PENElRt'\\nONS ARE MULTI-LINES THROUGH ONl:

4. ALL INSTRUMENT RACKS M~E PREnXED H21"

5.

REFER INTERLOCK.

6. ALL ANNUNCIATOR ALARMS N~E PI~EFlXED HI2**P60,**xX".

7.

DENOTES W"LVE LEAKOFF 'NHICl-I VaLL BE NORMAllY OPEN WIll BE PIPED TO C.R.W. UNDER CLASS 160",

B. VENDOR fURN1StIED.

MA$rEI~ EQU!PMENI LIsr NUMBER, (1,2.3.M.-)

AOantONAl NOTES.

12. HtGH POiNT VENT CAP !S NORMAlt,Y R(MOVEO ANO DRAIN INSTALLED r.OR VENrtNG.

R(PORf F"OR APPLICABLE XI Categories KIA:

SG2.02.15 Tier / Group:

RORating:

3.9 SRORating

LPObj:

CLS-LP-016*15E Source:

Cog Level:

HIGH Category 8:

T3 4.3 NEW YF

97. The following conditions exist on Unit One after a transient:

Jet Pump Flow Loop A 22 Mlbs/hr Jet Pump Flow Loop B 33 Mlbs/hr Recirc Pump A Percent Speed 47%

Recirc Pump B Percent Speed 66%

Total Core Flow (UICPWTCF) 55 MIbs/hr Which one of the following identifies the Required Action lAW T.S. 3.4.1, Recirculation Loops Operating, and the bases for this action?

Recirculation (1) mismatch is exceeded requiring Recirculation Loop A to be considered out of service (2)

A (1) Loop Flow (2) to ensure that assumptions of the LOCA analysis are satisfied B. (1) Loop Flow (2) due to the inability to detect significant degradation in jet pump performance C. (1) Pump Speed (2) to ensure that assumptions of the LOCA analysis are satisfied D. (1) Pump Speed (2) due to the inability to detect significant degradation in jet pump performance

97. The following conditions exist on Unit One after a transient:

Jet Pump Flow Loop A Jet Pump Flow Loop B Recirc Pump A Percent Speed Recirc Pump B Percent Speed Total Core Flow (U1CPWTCF) 22 Mlbs/hr 33 Mlbs/hr 47%

66%

55 Mlbs/hr Which one of the following identifies the Required Action lAW T.S. 3.4.1, Recirculation Loops Operating, and the bases for this action?

Recirculation (1) mismatch is exceeded requiring Recirculation Loop A to be considered out of service (2)

A'! (1) Loop Flow (2) to ensure that assumptions of the LOCA analysis are satisfied B. (1) Loop Flow (2) due to the inability to detect significant degradation in jet pump performance C. (1) Pump Speed (2) to ensure that assumptions of the LOCA analysis are satisfied D. (1) Pump Speed (2) due to the inability to detect significant degradation in jet pump performance

Feedback K/A: SG2.02.22 Equipment Control Knowledge of limiting conditions for operations and safety limits.

(CFR: 41.5 / 43.2 I 45.2)

RO/SRO Rating: 4.0/4.7 Objective: CLSLP002*34

27. Explain why there is a limit for mismatch between total Jet Pump Loop flows

34. Given plant conditions and Technical Specifications, including the Bases, TRM, ODCM, and COLR determine the required action(s) to be taken in accordance with Technical Specifications associated with the Reactor Recirculation System. (SROISTA only)

Reference:

Unit 1 Technical Specification 3.4.1 and BASES Cog Level: High Explanation:

Two recirculation loops are normally required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied.

Jet pump loop flow mismatch should be maintained within the following limits:

- jet pump loop flows within 10% (maximum indicated difference 7.5 xl 0 lbslhr) with total core flow less than 58 x10 lbs/hr

- jet pump loop flows within 5% (maximum indicated difference 3.5 xl 06 lbslhr) with total core flow greater than or equal to 58 xl 06 lbs/hr Distractor Analysis:

Choice A: Correct Answer Choice B: Plausible because Loop flow mismatch is correct and vibrations would be a result of low or reverse flow.

Choice C: Plausible because Pump Speed used to be the indication utilized and LOCA analysis is correct.

Choice D: Plausible because Pump Speed used to be the indication utilized and vibrations would be a result of low or reverse flow.

SRO Only Basis: Application of Required Actions and Knowledge of TS Bases.

Notes Feedback KIA: SG2.02.22 Equipment Control Knowledge of limiting conditions for operations and safety limits.

(CFR: 41.5 143.2 1 45.2)

RO/SRO Rating: 4.0/4.7 Objective: CLS-LP-002*34

27. Explain why there is a limit for mismatch between total Jet Pump Loop flows

34. Given plant conditions and Technical Specifications, including the Bases, TRM, ODCM, and COLR determine the required action(s) to be taken in accordance with Technical Specifications associated with the Reactor Recirculation System. (SRO/STA only)

Reference:

Unit 1 Technical Specification 3.4.1 and BASES Cog Level: High Explanation:

Two recirculation loops are normally required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied.

Jet pump loop flow mismatch should be maintained within the following limits:

- jet pump loop flows within 10% (maximum indicated difference 7.5 x1 06 Ibs/hr) with total core flow less than 58 X102 Ibs/hr

- jet pump loop flows within 5% (maximum indicated difference 3.5 x106 Ibs/hr) with total core flow greater than or equal to 58 x106 Ibs/hr Distractor Analysis:

Choice A: Correct Answer Choice B: Plausible because Loop flow mismatch is correct and vibrations would be a result of low or reverse flow.

Choice C: Plausible because Pump Speed used to be the indication utilized and LOCA analysis is correct.

Choice D: Plausible because Pump Speed used to be the indication utilized and vibrations would be a result of low or reverse flow.

SRO Only Basis: Application of Required Actions and Knowledge of TS Bases.

Notes

Recirculation Loops Operating 3.4.1 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1 Recirculation Loops Operating LCD 3.4.1 Two recirculation loops with matched flows shall be in operaon, OR One recirculalion oop may be in operation provided the following limits are applied when the associated LCD is applicable:

a.

LCO 3.2.1.

AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR), single loop operation limits specified in the COLR; b.

LCO 3.2.2, MINIMUM CRITICAL POWER RATIO (MCPR), single loop operation limits specified in the COLR; c.

LCO 3.2.3. LINEAR HEAT GENERATION RATE (LHGR) single loop operation limits specified in the COLR: and d.

LCO 3.3.1.1, Reactor Protection System RPS) Insfrumentation, Function 2.b (Average Power Range Monitors Simulated Thermal PowerHigh), Allowable Value of Tabe 3.3.1.1-1 is reset for single loop operation.

APPLICABILITY:

MODES I and 2.

ACTIONS COMPLETION CONDITION REQUIRED ACTION TIME A.

Requirements of the LCD A.1 Satist the requirements of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months not met, the LCD.

(continued)

Siunswick Unit 1 3.4-1 Amendment No. 246 Recirculation Loops Operating 3.4."1 3.4 RE.A.CTOR COOL.A.NT SYSTEM (RCS) 3.4.. 1 Recirculation Loops Operating LCO 3.4.1 Two recirculation loops with matched lIows shall be in operation.

One recirculation loop may be in operation provided the following limits are applied when the associated LCO is applicable:

a.

LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR), single loop operation limits specified in the COLR;

b.

LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO {MCPR}, single loop operation limits specified in the COLR;

c.

LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," single loop operation limits specified in the COLR; and

d.

LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation, Function 2.b (Average Power Range Monitors Simulated Thermal Power-High), Allowable Value of Table 3.3. '1.1-1 is resetror single loop operation.

APPLICABILITY:

MODES 1 and 2.

ACTIONS CONDITION A.

Requirements of the LCO nolmet Brunswick Unit 1 A.1 REQUIRED ACTION COMPLETION TIME SatisPj the requirements of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months the LCO.

( continued) 3.4-1 Amendment No. 246 I

Recirculation Loops Operating ACTIONS continuedi 3.4.1 COMPLETION CONDITION REQUIRED ACTION TIME 5.

Required Action and 8.1 Se n MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not met.

OR No recirculation loops in operation.

SURVEILLANCE_REQUIREMENTS SURVEILLANCE FREQUENCY SR 34.i.1

NOTE----

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both recrcuation toops are in operation.

Verify recirculation loop jet pump flow mismatch with 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months both recirculation loops in operation:

10% of rated core flow when operating at

< 75% of rated core flow; and b.

5% of rated core flow when operating at 75% of rated core flow.

Snjnswjck Unit 1 3.4-2 Amendment No. 244 Recirculation Loops Operating 3A:l ACTIONS (continued)

CONDITION REQUIRED.A.CTlON B.

Required Action and B.1 Be in MODE 3.

associated Completion Time of Condition.A. not met.

No recirculation loops in operation.

SURVEILLANCE REQUIREMENTS SR 3.4:1.1 Brunswick Unit 1 SUR\\lEILLANCE

NOTE--------------------------

Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both recirculation lOops are in operation.

Verify recirculation loop jet pump flow mismatch with both recirculation loops in operation:

a.

5: -t 0% of rated core flow when operating at

<: 75% of rated core flow; and

b.

5: 5% of rated core flO'A' when operating at

75% of rated core flow.

3.4-2 COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Amendment No. 244

Recirculation Loops Operating B 3.4.1 BASES APPLICABLE For AREVA ftiel, the COLR presents single loop operation APLHGR limits SAFETY ANALYSES in the form of a multiplier that is applied to the two loop operation (continued)

APLHGR limits.

The transient analyses of Chapter 15 of the UFSAR have also been evaluated for single recirculation loop operation. The evaluation concludes that results of the transient analyses are not significantly affected by the single recirculation loop operation. There is, however, an impact on the fuel cladding integritj SL since some of the uncertainties for the parameters used in the critical power determination are higher in single loop operation. The net result is an increase in the MCPR operating limit.

During single recircutation loop operation, modification to the Reactor Pratection System (RPS) average power range monitor APRM)

Simulated Themial PowerHigh Allowable Value is required to account for the different analyzed limits between two-recirculation drive now loop operation and operation with only one loop. The APRM channel subtracts the W value from the measured recirculation drive flow to effectivej shift the limits and uses the adjusted recirculation drive flow value to determine the APRM Simulated Themial PowerHigh Function trip setpoint.

Recirculation loops operating satisfies Criterion 2 of 10 CFR S0.36(cX2)(ii) (Ref. 4).

LCO Two recirculation loops are normally required to be in operation with their flows matched within the limits specified in SR 3.4.1,1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied. Alternately, with only one recirculation loop in operation, modifications to the required APLHGR limits LCO 3.2.1, AVERAGE PLANAR L1NEAR HEAT GENERATION RATE (APLHGRy), MCPR limits (LCO 3.2.2.

MINIMUM CRITICAL POWER RATIO MCPRfl, LHGR limits (LCO 3.2.3, LINEAR HEAT GENERATION RATE (LHGR)), and APRM Simulated Thermal Power High Allowable Value (LCO 3.3.1.1), as applicable, must be applied to allow continued operation. The COLR defines adjustments or modifications required for the APLHGR, MCPR, and LHGR limits for the current operating cycle.

continued)

Brunswick Unit 1 6 3.4.1-3 Revision No.58 B.A.SES Recirculation Loops Operating B 3.4.1 APPLICABLE For AREVA fuel, the COLR presents single loop operation APLHGR limits SAFETY AN.A.L YSES in the form of a multiplier that is applied to the two loop operation (continued}

APLHGR limits.

lCO Brunswick Unit 1 The transient analyses of Chapter 15 of the UFSAR have also been evaluated for single recirculation loop operation. The evaluation concludes that results of the transient analyses are not significantly affected by the single recirculation loop operation. There is, however, an impact on the fuel cladding integrity SL since some of the uncertainties for the parameters used in the critical power determination are higher in single loop operation. The net result is an increase in the MCPR operating limit.

During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor (APRM)

Simulated Themlal Power-High Allowable 'Value is required to account for the different analyzed limits bet'A'een two-recirculation drive tlow loop operation and operation with only one loop. The APRM channel subtracts the l!.W value from the measured recirculation drive flow to effective~1 shift the limits and uses the adjusted recirculation drive flow value to determine the APRM Simulated Themlal Power-High Function trip setpoint.

Recirculation loops operating satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 4}.

Two recirculation loops are normally required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure !hat dunng a LOCA caused by a break of the piping of one recirculation loop

!he assumptions of the LOCA analysis are satisfied. Alternately, with only one recirculation loop in operation, modifications to the required APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), MCPR limits (LeO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), and APRM Simulated Thermal Power-High Allowable Value (LCO 3.3.1.1), as applicable, must be applied to allo\\'/ continued operation. The COLR defines adjustments or modifications required for the APLHGR, MCPR, and LHGR limits for the current operating cycle.

( continued)

B 3.4.1-3 Revision No. 58

Recirculation Loops Operating 3.4.1 APPLICABILITY In MODES I and 2, requirements for operation of the Reactor Coolant Recirculation System are necessary since there is considerable energy in the reactor core and the liniiting design basis transients and accidents are assumed to occur.

In MODES 3,4, and 5, the consequences of an accident are reduced and the coastdown characteristics of the recircuation loops are not important.

ACTIONS Al With the requirements of the LCO not met, the recirculation loops must be restored to operation with matched flows within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than the required limits. The loop with the lower flow must be considered not in operation. Should a LOCA occur with one recirculation loop not in operation, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed to restore the inoperable loop to operating status.

Alternatively, if the single loop requirements of the LCO are applied to operating limits and RPS setpoints, as applicable, operation with only one recirculation loop would satisfy the requirements of the LCO and the initial conditions of the accident sequence.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Completion Time is based on the low probability of an accident occurring during this time period, on a reasonable time to complete the Required Action (i.e.. reset the applicable limits or setpoints for single recirculation loop operation), and on frequent care monitoring by operators allowing abrupt changes in core flow conditions to be quickly detected.

This Required Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between the total jet pump flaws of the two loops is greater than the required limits. However, in cases where large flow mismatches occur, low flow or reverse flow can occur in the low flaw loop jet pumps. causing vibration of the jet pumps.

If zero or reverse flaw is detected, the condition should be alleviated by changing pump speeds to re-establish forward flow.

I continued)

BASES Brunswick Unit 1 B 3.4.1-4 Revision No. SB BASES APPLICABILITY ACTIONS Brunswick Unit 1 Recirculation Loops Operating B 3.4.1 In MODES 1 and 2, requirements ior operation ofthe Reactor Coolant Recirculation System are necessary' since there is considerable energy in the reactor core and the limiting design basis transients and accidents are assumed to occur.

In MODES 3, 4, and 5, the consequences of an accident are reduced and the coastdown characteristics of the recirculation loops are not important.

With the requirements of the LCO not met, the recirculation loops must be restored to operation with matched flows within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than the required limits. The loop with the lower flow must be considered not in operation. Should a LOCA occur with one recirculation loop no! in operation, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed to restore the inoperable loop to operating status.

Altematively, if the single loop requirements of the lCO are applied to operating limits and RPS setpoints, as applicable, operation with only one recirculation loop would satisfl/ the requirements of the LCO and the initial conditions of the accident sequence.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Completion Time is bae.ed on the low probability of an accident occurring during this time period, on a reae.onable time to complete the Required Action (I.e., reset the applicable limits or setpoints for single recirculation loop operation), and on frequent core monitoring by operators allowing abrupt changes in core flow conditions to be quickiy detected.

This Required Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between the total jet pump flows of the two loops is greater than the required limits. However, in cases where large flow mismatches occur, low flow or reverse flow can occur in the low flow loop jet pumps, causingllibralion of the jet pumps. If zero or reverse flow is detected, the condition should be alleviated by changing pump speeds to re-establish forward flow.

(continued)

B 3.4.1-4 Revision No. 58

Recirculation Loops Operating B 3.4.1 ACTIONS (continued)

With no recirculation loops in operation or the Required Action and associated Completion Time oi Condition A not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the pant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In this condition, the recirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.1.1 REQUIREMENTS This SR ensures the recirculation loops are within the allowable limits for mismatch. At low core flow (i.e.. < 76% of rated core flow), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can, therefore, be allowed when core flow is < 75% of rated core flow. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop.

The mismatch is measured in terms of the percent of rated core flow.

If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered not in operation. The SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is consistent with the Surveillance Frequency for jet pump OPERABILITY verification and has been shown by operating experience to be adequate to detect off normal jet pump loop flows in a timely manner.

REFERENCES 1.

UFSAR. Section 5.4.1.3.

2.

UFSAR, Chapter 15.

3.

NEDC-31776P, Brunswick Steam Electric Plant Units I and 2 Single Loop Operation, February 1990.

4.

10 CFR E0.36(c)t2)(ii).

Brunswick Unit 1 B 3.4.1-6 Revision No.58 Categories KJA:

SG2.02.22 Tier / Group:

T3 RO Rating:

4.0 SRO Rating:

4.7 LP Obj:

CLSLP0O2*34 Source:

NEW Cog Level:

HIGH Category 8:

Y BASES BASES Recirculation Loops Operating B 3.4:1 ACTIONS

.!U.

(continued)

With no recirculation loops in operation or the Required Action and associated Completion Time of Condition A not met, the plant must be brought to a MODE in which the LCO does not apply_ To achieve this status, th.e plant must be brought to MODE 3 within 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months s_ In this condition, the recirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and *... 'ithout challenging piant systems.

SURVEILLANCE SR 3.4.U REQUIREMENTS This SR ensures the recirculation loops are within the allowable limits for mismatch_ At low core t/ow (Le., -< 75% of rated core flow), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced_ A larger flow mismatch can, therefore, be aI/owed when core tlow is < 75% of rated core flow. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop_

The mismatch is measured in terms of the percent of rated core flow. If the flow mismatch exceeds the specified limits, the loop wiltl the lower flow is considered not in operation. The SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation_ The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months frequency is consistent with the Surveillance Frequency for jet pump OPERA.BILITY verification and has been shown by operating experience to be adequate to detect off normal jet pump loop flows in a timely manner.

REFERENCES

1.

2.

3.

UFSAR, Section SA 1.3.

UFSAR, Chapter 15.

4.

NEDC-31776P, Brunswick Steam Electric Plan! Units 1 and 2 Single Loop Operation, February 1990.

10 CFR SD_36(c)(2)(ii)_

Brunswick Unit 1 63A1-5 Revision No. 58 Categories KIA:

RORating:

LP Obj:

Cog Level:

SG2.02.22 4_0 CLS-LP-002*34 mGH Tier / Group: T3 SRORating: 4.7 Source:

NEW Category 8:

Y

98. Which oneQf the following identifies the procedure required to control drywell pressure within PCPL-A lAW PCCP and the release rate restrictions, if any, in effect during the venting?

A SEP-01 Section 1 Venting Primary Containment irrespective of Off Site Release rate B. SEP-01, Section 2 Venting Primary Containment via the Suppression Chamber within Site Release Rate Limit C. SEP-01, Section 3, Venting Primary Containment via the Drywell within Site Release Rate Limit D. OLDMG-003, Containment Venting Under Conditions of Extreme Damage irrespective of Off Site Release Rates

98. Which one,Qf the following identifies the procedure required to control drywell pressure withinPCPL-A:IAW PCCP and the release rate restrictions, if any, in effect during the venting?

A~ SEP-01 Section 1 'j Venting Primary Containment irrespective of Off Site Release rate B. SEP-01, Section 2.,. Venting Primary Containment via the Suppression Chamber within Site Release Rate Limit C. SEP-01, Section 3, Venting Primary Containment via the Drywell within Site Release Rate Limit D. OEDMG-003, Containment Venting Under Conditions of Extreme Damage irrespective of Off Site Release Rates

Feedback K/A: SG2.03.11 Radiation Control Ability to control radiation releases.

(CFR: 41.11 /43.4/45.10)

ROISRO Rating: 3.8/4.3 Objective: CLSLP300L*08d

8. Given the Primary Containment Control Procedure and plant conditions, determine if the following actions are required:

c. Venting the primary containment while staying within radioactivity release rate limits

d. Venting the primary containment IRRESPECTIVE of radioactivity release rate limits

Reference:

001-37.8, Revision 4, Page 33, Step PC/P-18 Cog Level: High Explanation:

Action to vent the primary containment is taken before drywell pressure rises to Primary Containment Pressure Limit A to assure that the integrity of the primary containment is maintained and to prevent core damage that might be caused by the inability to vent the reactor, as necessary, to permit injection of water to cool the core. Venting of the primary containment is performed irrespective of the off-site radioactivity release rate that will occur, and defeating isolation interlocks if necessary, because the consequences of not doing so may be either severe core damage or loss of primary containment integrity and uncontrolled radioactive release much greater than might otherwise occur. Note that primary containment venting is performed only, as necessary, to restore and then maintain pressure below the limit.

Distractor Analysis:

Choice A: Correct Answer.

Choice B: Plausible because within ODCM limits is utilized during SEP-01 section 1 when venting the torus due to containment Hydrogen/Oxygen concentration concerns and before exceeding PCPL-A Choice C: Plausible because within ODCM limits is utilized during SEP-01 section 1 when venting the drywell due to containment Hydrogen/Oxygen concentration concerns and before exceeding PCPL-A.

Choice D: Plausible because irrespective is correct and after exceeding PCPL-A is wrong SRO Only Basis: Detailed knowledge of diagnostic steps and decision points in the EOPs that involve transitions to emergency contingency procedures.

Notes PRIMARY CONTAINMENT PRESSURE LIMIT-A The lesser of the pressure capability of the primary containment, pressure at which containment vent valves sized to reject all decay heat from the containment can be opened and closed, or pressure at which SRVs can be opened and will remain open (Figure 2).

DE0P-01-UG Rev. 55 Page 71 of 151 Feedback KIA: SG2.03.11 Radiation Control Ability to control radiation releases.

(CFR: 41.11/43.4/45.10)

RO/SRO Rating: 3.8/4.3 Objective: CLS-LP-300-L *08d

8. Given the Primary Containment Control Procedure and plant conditions, determine if the following actions are required:

c. Venting the primary containment while staying within radioactivity release rate limits

d. Venting the primary containment IRRESPECTIVE of radioactivity release rate limits

Reference:

001-37.8, Revision 4, Page 33, Step PC/P-18 Cog Level: High Explanation:

Action to vent the primary containment is taken before drywell pressure rises to Primary Containment Pressure Limit A to assure that the integrity of the primary containment is maintained and to prevent core damage that might be caused by the inability to vent the reactor, as necessary, to permit injection of water to cool the core. Venting of the primary containment is performed irrespective of the off-site radioactivity release rate that will occur, and defeating isolation interlocks if necessary, because the consequences of not doing so may be either severe core damage or loss of primary containment integrity and uncontrolled radioactive release much greater than might otherwise occur. Note that primary containment venting is performed only, as necessary, to restore and then maintain pressure below the limit.

Distractor Analysis:

Choice A: Correct Answer.

Choice B: Plausible because within ODCM limits is utilized during SEP-01 section 1 when venting the torus due to containment Hydrogen/Oxygen concentration concerns and before exceeding PCPL-A Choice C: Plausible because within ODCM limits is utilized during SEP-01 section 1 when venting the drywell due to containment Hydrogen/Oxygen concentration concerns and before exceeding PCPL-A.

Choice D: Plausible because irrespective is correct and after exceeding PCPL-A is wrong SRO Only Basis: Detailed knowledge of diagnostic steps and decision points in the EOPs that involve transitions to emergency contingency procedures.

Notes PRIMARY CONTAINMENT PRESSURE LlMIT-A The lesser of the pressure capability of the primary containment, pressure at which containment vent valves sized to reject all decay heat from the containment can be opened and closed, or pressure at which SRVs can be opened and will remain open (Figure 2).

IOEOP-01-UG Rev. 55 Page 71 of 151 I

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100 1'10 80 70 60 50 40 30 20 10 0

ATTACHMENT 5 Page 17 of 27 FIGURE 2 Primary Containment Pressure Limit-A

10 0

10 20 30 40 50 GO 70 8Q PRIMARY CONTAINMENT WATER LEVEL (FEET)

IF USING THE FOLLOWING INSTRUMENT:

CAC-PI-1230 CAC-PI-4176 CAC-PR-1257-1 PCPl-A IS:

70 PSIG USE THE GRAPH USE THE GR.f\\PH IOEOP-01-UG Rev. 55 Page 77 of 151 I

PCPL-A j DRYWELL PHESS PCPL.A VENT ThE PRMARV CTT RRSPCTIV& OF OFcsIrE NZUASE RAXF

$ETtON I OF pcjp. i STEP BASES:

Action to vent the primary containment is taken before drywell pressure rises to Primary Containment Pressure Limit A, defined to be the lesser of either:

a.

The pressure capability of the containment, or b.

The maximum containment pressure at which vent valves sized to reject all decay heat from the containment can be opened and closed, or C.

The maximum containment pressure at which SRVs can be opened and will remain open, or d.

The maximum containment pressure at which reactor vent valves can be opened and closed.

This action is taken to assure that the integrity of the primary containment is maintained and to prevent core damage that might be caused by the inability to vent the reactor, as necessary, to permit injection of water to cool the core.

The directions Lo vent before drywell pressure reaches PCPL-A allows, but does not require, venting at significantly lower pressures Early or extended venting can permit primary containment pressure reductions before significant fuel damage occurs, thereby increasing the capacity of the containment to retain lission products and reducing the radioactivity released to the environment, If the primary containment has failed, venting may also reduce the offsite dose by directing fission products through an elevated release point.

001-37.8 Rev.

I Page 33 of 58 PCPL-A STEP BASES:

rmVWllll. PRESS R~AClfeS PCPL*A VENT THE PRIMARY elMT IRRESPECTIVE OF OFFSITE "IELEASe RAtE PER SECTION 1 OF 1001"*01* SEP. 01 "CiP*HI Action to vent the primary containment is taken before drywell pressure rises to Primary Containment Pressure Limit A,defined to be tile lesser of either:

a.

The pressure capability of the containment, or

b.

The maximum containment pressure at whicll vent valves sized to reject all decay heat from tile containment can be opened and closed, or

c.

The maximum containment pressure at which SRVs can be opened and will remain open, or

d.

The maximum containment pressure at which reactor vent valves can be opened and closed.

This action is taken to assure that the integrity of the primary containment is maintained and to prevent core damage that might be caused by tile inability to vent the reactor, as necessary, to permit injection of water to cool tile core.

The directions to vent "before drywell pressure reaches pePl-A" allows, but does not require, venting at significantly lower pressures. Early or extended venting can permit primary containment pressure reductions before significant fuel damage occllrs, thereby increasing the capacity of the containment to retain fission products and reducing the radioactivity released to the environment. If the primary containment has failed, venting may also reduce the offsile dose by directing fission prodllcts throllgh an elevated release point.

1001-37.8 Rev. 4 Page 33 of 581

STEP PCIP.18 (continued)

Venting of the primary containment is performed irrespective of the off-site radioactivity release rate that will occur, and defeating isolation interlocks if necessary, because the consequences of not doing so may be either severe core damage or loss of primary containment integrity and uncontrolled radioactive release much greater than might otherwise occur. Note that primary containment venting is performed only, as necessary, to restore and then maintain pressure below the limiL Primary containment venting is performed using Primary Containment Venting, EDP-O1 -SEP-01.

001-37.8 Rev. 4 Pane 34 of 58 STEP PC/P*18 (continued) venting of the primary containment is petiormed irrespective of the off-site radioactivity release rate that will occur, and defeating isolation interlocks if necessary, because the consequences of not doing so may be either severe core damage or loss of primary containment integrity and uncontrolled radioactive release much greater than might otherwise occur. Note that primary containment venting is petiormed only, as necessary, to restore and then maintain pressure below the limit Primary containment venting is performed using Primary Containment Venting, EOP-01-SEP-0'I.

1001-37.8 Rev. 4 Page 34 of 581

PRIMARY CONTAINMENT VENTING 1.0 ENTRY CONDITIONS As dhrected by the PC/P section of Primary Contaniment Control Procedure, EOP-O2-PCCP OR As directed by the PC/H section of Primary Containment Control Procedure, EOP-02-PCCP 2.0 OPERATOR ACTIONS CO:

2.1 IF while executing this procedure, it is recognized the actions can NOT be performed, OR will NOT be effective, THEN GO TO Containment Venting Under Conditions of Extreme Damage, OEDMG-003, if directed by the Unit SCO.

CO:

2.2 IF venting for pressure control, THEN PERFORM Section 1, on page 3.

CO:

2.3 IF venting for H2/02 control, THEN PERFORM section of procedure directed by SCO.

I OEOP-Oi-SEP-Oi Rev. 24 Page 2 of 22 Categories KJA:

SG2.03.I 1 Tier / Group:

T3 RU Rating:

3.8 SRU Rating:

4.3 LP Ubj:

CLSLP3OOL*O8D Source:

NEW Cog Level:

HIGH Category 8:

PRIMARY CONTAINMENT VENTING 1.0 ENTRY CONDITIONS As directed by the PC/P section of Primary Containment Control Procedure, EOP-02-PCCP OR As directed by the PC/H section of Primary Containment Control Procedure, EOP-02-PCCP 2.0 OPERA TOR ACTIONS CO:

2.1 IF while executing this procedure, it is recognized the actions can NOT be performed, OR will NOT be effective, THEN GO TO Containment Venting Under Conditions of Extreme Damage, OEDMG-003, if dlrected by the Unit SCO.

CO:

2.2 IF venting for pressure control, THEN PERFORM Section oJ, on page 3.

CO:

2.3 IF venting for H2/02 control.. THEN PERFORM section of procedure directed by SCO.

IOEOP-ool-SEP-O'l Rev. 24 Categories KIA:

SG2.03.11 RO Rating:

3.8 LP Obj:

CLS-LP-300-L*08D Cog Level:

HIGH Tier / Group: T3 SRO Rating:

4.3 Source

~vv Category 8:

0 0

0 Page 2 of 22 1

99. During non-ATWS emergency conditions on Unit Two, Emergency Depressurization is required with reactor pressure at 1100 psig.

Which one of the following identifies the bases for the Minimum Number of SRV5 Required for Emergency Depressurization and the required procedure utilized if this number of SRVs open cannot be achieved?

The Minimum Number of SRVs Required for Emergency Depressurization is based on the low pressure ECCS system with the lowest head being capable of making up the SRV steam flow at the Minimum (1)

(2)

Procedure is required if the minimum number of SRVs cannot be opened.

A.

(1) Reactor Flooding Pressure (2) Primary Containment Flooding B. (1) Reactor Flooding Pressure (2) Alternate Emergency Depressurization C. (1) Alternate Reactor Flooding Pressure (2) Primary Containment Flooding D (1) Alternate Reactor Flooding Pressure (2) Alternate Emergency Depressurization

99. During non-ATWS emergency conditions on Unit Two, Emergency Depressurization is required with reactor pressure at 1100 psig.

Which one of the following identifies the bases for the Minimum Number of SRVs Required for Emergency Depressurization and the required procedure utilized if this number of SRVs open cannot be achieved?

The Minimum Number of SRVs Required for Emergency Depressurization is based on the low pressure ECCS system with the lowest head being capable of making up the SRV steam flow at the Minimum (1)

(2)

Procedure is required if the minimum number of SRVs cannot be opened.

A. (1) Reactor Flooding Pressure (2) Primary Containment Flooding B. (1) Reactor Flooding Pressure (2) Alternate Emergency Depressurization C. (1) Alternate Reactor Flooding Pressure (2) Primary Containment Flooding D:' (1) Alternate Reactor Flooding Pressure (2) Alternate Emergency Depressurization

Feedback KJA: SG2.04.17 Emergency Procedures I Plan Knowledge of EOP terms and definitions.

(CFR: 41.10 /45.13)

ROISRO Rating: 3.9/4.3 Objective: CLSLP300H*002

2. Given plant conditions and the Emergency Operating Procedures, determine if execution of the Alternate Emergency Depressurization Procedure is required.

Reference:

OEOP-01-UG, Revision 55, Page 70, Attachment 5 (Definitions)

RVCP Cog Level: High Explanation:

The Minimum Number of SRVs Required for Emergency Depressurization (5) is defined to be the least number of SRVs which correspond to a Minimum Alternate Reactor Flooding Pressure sufficiently low that the ECCS with the lowest head will be capable of making up the SRV steam flow at the corresponding Minimum Alternate Reactor Flooding Pressure.

If the number of SRVs specified cannot be opened, the reactor must be depressurized by other means. A list of alternate systems that can be used for depressurizing the reactor is included in the Alternate Emergency Depressurization Procedure, EOP-01 -AEDP.

Distractor Analysis:

Choice A: Plausible because Minimum Reactor Flooding Pressure is easily confused with Minimum Alternate Reactor Flooding Pressure and Primary Containment Flooding requires exiting all EOPs which is wrong for the given conditions.

Choice B: Plausible because Minimum Reactor Flooding Pressure is easily confused with Minimum Alternate Reactor Flooding Pressure and AEDP is correct.

Choice C: Plausible because Minimum Alternate Reactor Flooding Pressure is correct and Primary Containment Flooding requires exiting all EOPs which is wrong for the given conditions.

Choice D: Correct Answer SRO Only Basis: Detailed knowledge of diagnostic steps and decision points in the EOPs that involve transitions to emergency contingency procedures.

Notes MINIMUM ALTERNATE FLOODING PRESSURE The lowest reactor pressure at which steam 110w through open SRVs is sufficient to preclude any clad temperature from exceeding 1500F even if the reactor core is not completely covered OEOP-Oi-UG Rev. 55 Page 69 of 151 Feedback KJA: SG2.04.17 Emergency Procedures I Plan Knowledge of EOP terms and definitions.

(CFR: 41.10/45.13)

RO/SRO Rating: 3.9/4.3 Objective: CLS-LP-300-H*002

2. Given plant conditions and the Emergency Operating Procedures, determine if execution of the Alternate Emergency Depressurization Procedure is required.

Reference:

OEOP-01-UG, Revision 55, Page 70, Attachment 5 (Definitions)

RVCP Cog Level: High Explanation:

The Minimum Number of SRVs Required for Emergency Depressurization (5) is defined to be the least number of SRVs which correspond to a Minimum Alternate Reactor Flooding Pressure sufficiently low that the ECCS with the lowest head will be capable of making up the SRV steam flow at the corresponding Minimum Alternate Reactor Flooding Pressure. If the number of SRVs specified cannot be opened, the reactor must be depressurized by other means. A list of alternate systems that can be used for depressurizing the reactor is included in the Alternate Emergency Depressurization Procedure, EOP-01-AEDP.

Distractor Analysis:

Choice A: Plausible because Minimum Reactor Flooding Pressure is easily confused with Minimum Alternate Reactor Flooding Pressure and Primary Containment Flooding requires exiting all EOPs which is wrong for the given conditions.

Choice B: Plausible because Minimum Reactor Flooding Pressure is easily confused with Minimum Alternate Reactor Flooding Pressure and AEDP is correct.

Choice C: Plausible because Minimum Alternate Reactor Flooding Pressure is correct and Primary Containment Flooding requires exiting all EOPs which is wrong for the given conditions.

Choice D: Correct Answer SRO Only Basis: Detailed knowledge of diagnostic steps and decision points in the EOPs that involve transitions to emergency contingency procedures.

Notes MINIMUM ALTERNATE FLOODING PRESSURE The lowest reactor pressure at which steam flow through open SRVs is sufficient to preclude any clad temperature from exceeding 1500°F even if the reactor core is not completely covered I

OEOP-O*!-UG Rev. 55 Page 69 of *15"1 I

ATTACHMENT 5 Page 10 of 27 Definitions MINI MUM CORE FLOODING INTERVAL The greatest amount of time required to flood the reactor to the top of the active Tuel with reactor pressure at the minimum reactor flooding pressure and at least the minimum number of SRVs required for emergency depressurization open.

MINIMUM INDICATED LEVEL The highest reactor water level instrument indication which results from off-calibration instrument run temperature conditions when reactor water level is actually at the elevation of the instrument variable leg tap.

M1NIMUM NUMBER OF SRVS REQUIRED FOR EMERGENCY DEPRESSURIZATION The least number of SRVs which correspond to a minimum alternate reactor flooding pressure sufficiently low that the ECCS with the lowest head will be capable of making up the SRV steam flow at the corresponding minimum alternate reactor flooding pressure.

MINIMUM REACTOR FLOODING PRESSURE The minimum SRV reopening pressure; 50 psid with 5 SRVs open. This pressure is utilized to assure sufficient liquid injection into the reactor to maintain SRVs open and to flood the reactor to the elevation of the main steam lines during the flooding evolution when the reactor is shutdown.

MINIMUM SRV REOPENING PRESSURE The lowest reactor pressure at which an SRV will lufly open and remain fully opened when its control switch is placed in the OPEN position.

MINIMUM STEAM COOLING REACTOR WATER LEVEL The lowest reactor water level at which the covered portion of the reactor core will generate sufficient steam to preclude any clad temperature in the uncovered portion of the core from exceeding 150DF. This limit is used during an ATWS event to prevent fuel damage when level is lowered below TAF (Unit 1 only:

Figure 18; Unit 2 only: Figure 18A).

OEOP-01-UG Rev. 55 Page 70 of 151 ATTACHMENT 5 Page 10 of 27 Definitions MINIMUM CORE FLOODING INTERVAL The greatest amount of time required to flood the reactor to the top of the active fuel with reactor pressure at the minimum reactor flooding pressure and at least the minimum number of SRVs required for emergency depressurization open.

MINIMUM INDICATED LEVEL The highest reactor water level instrument indication which results from off-calibration instrument run temperature conditions when reactor water level is actually at the elevation of the instrument variable leg tap.

MINIMUM NUMBER OF SRVS REQUIRED FOR EMERGENCY DEPRESSURIZATION The least number of SRVs which correspond to a minimum altemate reactor flooding pressure sufficiently low that tile ECCS witll the 101,vest head will be capable of making up the SRV steam flow at the corresponding minimum alternate reactor flooding pressure.

MINIMUM REACTOR FLOODING PRESSURE The minimum SRV reopening pressure; 50 psid witl) 5 SRVs open. This pressure is utilized to assure sufficient liquid injection into the reactor to maintain SRVs open and to flood the reactor to the elevation of the main steam lines during the flooding evolution when the reactor is shutdown.

MINIMUM SRV REOPENING PRESSURE The lowest reactor pressure at which an SRV will fully open and remain fully opened when its control switch is placed in the OPEN position.

MINIMUM STEAM COOLING REACTOR WATER LEVEL The lowest reactor water level at which the covered portion of the reactor core will generate sufficient steam to preclude any clad temperature in the uncovered portion of the core from exceeding 1500°F. This limit is used during an ATWS event to prevent fuel damage when level is lowered below T AF (Unit 'I only:

Figure 18; Unit 2 only: Figure'18A).

I OEOP-O'l-UG Rev. 55 Page 70 of '15'1 I

STEPS RCIP-23 through RC/P-25 The Minimum Number of SRVs Required for Emergency Depressurizatiori (5) is defined to be the least number of SRVs which correspond to a Minimum Alternate Reactor Flooding Pressure sufficiently low that the ECCS with the lowest head will be capable of making up the SRV steam flow at the corresponding Minimum Alternate Reactor Flooding Pressure.

The Minimum SRV Re-opening Pressure is the lowest reactor pressure at which an SRV will remain fully open with its control switch in the open position. The accuracy of the re-opening pressure and the indication available to determine reactor pressure result in conditions such that the SRVs are not always open when the pressure indicated is 50 psig. One hundred psig has been selected as a value which can be used to determine the SRV5 have failed to function. When reactor pressure is below this value, depressurization is considered complete and reactor pressure reduction need not be augmented by use of additional systems even if less than the minimum number of SRVs are open.

If the number of SRVs specified cannot be opened, the reactor must be depressurizeci by other means. A list of alternate systems that can be used for depressurizing the reactor is included in the Alternate Emergency Depressurization Procedure, EOP-O1-AEDP. However, since event independence must be maintained and specific plant conditions cannot be presumed, no priority regarding system use is indicated. This approach provides an operator the flexibility of being able to use whatever system(s) may be most appropriate under current plant conditions.

001-37.4 Rev. 8 Page 59 of 78 PERFORM ALTERNATE EFi.ERGE.NCY DEPRESSURI2.ATION PROCEDURE (EOP. 01. AEDP IRRSPECTNE OI OFFSITE RADIOACTIVITY RELEASE RATE 1

STEP BASES:

STEPS RC/P*23 through RC/P*25 PERFORM "ALTERNATE EMERGENCY DEPRESSURIZATION PROCEDURE" (EOP. 01. AEDPI IRRESPECTIVE OF OPPSIlE RADIOACTIVITY REll:.... SE RAT!:

RCIP-ZS STEP BASES:

The Minimum Number of SRVs Required for Emergency Depressurization (5) is defined to be the least number of SRVs which correspond to a Minimum Alternate Reactor Flooding Pressure sufficiently low that the ECCS with the lowest !lead will be capable of making up the SRV steam flow at the corresponding Minimum Alternate Reactor Flooding Pressure.

The Minimum SRV Re-opening Pressure is the lowest reactor pressure at which an SRV will remain fully open with its control switch in the open position. The accuracy of the re-opening pressure and the indication available to detelmine reactor pressure result in conditions such that the SRVs are not always open when the pressure indicated is 50 psig. One hundred psig has been selected as a value which can be used to determine the SRVs have failed to function. When reactor pressure is below this value, depressurization is considered complete and reactor pressure reduction need not be augmented by use of additional systems even if less than the minimum number of SRVs are open. If the number of SRVs specified cannot be opened, the reactor must be depressurized by other means. A list of alternate systems that can be used for depressurizing the reactor is included in the Alternate Emergency Depressurization Procedure, EOP-01-AEDP. However, since event independence must be maintained and specific plant conditions cannot be presumed, no priority regarding system use is indicated. This approach provides an operator the flexibility of being able to use whatever system(s) may be most appropriate under current plant conditions.

1001-37.4 Rev. 8 Page 59 of 781

ALTERNATE EMERGENCY DEPRESSURIZATION PROCEDURE 1.0 ENTRY CONDITIONS As directed by the RCIP section of Reactor Vessel Control Procedure, EOP-Ol-RVCP OR As directed by the RC/P section of Level/Power Control, EOP-O1-LPC OR As directed by SAMG Primary Containment Flooding, SAMG-Ol 2.0 OPERATOR ACTIONS NOTE:

Manpower:

I Control Operator I Auxiliary Operator I Independent Verifier Special equipment:

4 jumpers (32, 33, 34, and 35:

1 Ilathead screwdriver I locking screwdriver tape NOTE:

Performance of this procedure will affect any main steam line leakage control pathways established by EOP-Oi -SEP-i t 2.1 EVACUATE the Unit 1 and 2 Turbine Buildings using the following actions:

CO:

2.11 SOUND the Unit 1 and Unit 2 Turbine Building evacuation alarms AND ANNOUNCE the evacuation.

CO:

2.1.2 REQUEST the SCO to notify the TSC that the Turbine Building is being evacuated due to potential high radiation conditions during the alternate emergency clepressurization.

CO:

2.2 IF either Unit 1 or Unit 2 Turbine Building ventilation is in service in the once-through lineup, THEN SECURE that units turbine building ventilation (OP-37.3).

OEOP-Oi-AEDP Rev. 18 Page 2 of 16 Categories K/A:

SG2.04.17 Tier/Group:

T3 RO Rating:

3.9 SRO Rating:

4.3 LP Obj:

CLSLP3OOH*OO2 Source:

NEW Cog Level:

HIGH Category 8:

Y ALTERNATE EMERGENCY DEPRESSURIZATION PROCEDURE 1.0 ENTRY CONDITIONS As directed by the RC/P section of Reactor Vessel Control Procedure, EOP-01-RVCP OR As directed by the RC/P section of Level/Power Control, EOP-01-LPC OR As directed by SAMG Primary Containment Flooding, SAMG-O'l 2.0 OPERATOR ACTIONS NOTE:

Manpower:

Special eqUipment:

'1 Control Operator

'1 Auxiliary Operator

'I Independent Verifier 4 jumpers (32, 33, 34, and 35}

1 flathead screwdriver 1 locking screwdriver tape NOTE:

Performance of this procedure will affect any main steam line leakage control pathways established by EOP-O'l-SEP-'!'L 2,1 EVACUATE tile Unit 1 and 2 Turbine Buildings using the following actions:

CO:

2.2 2.1:1 2.1.2 SOUND the Unit 1 and Unit 2 Turbine Building evacuation alarms AND ANNOUNCE the evacuation.

REQUEST the SCO to notify the TSC that the Turbine Building is being evacuated due to potential high radiation conditions during the alternate emergency depressurization.

IF either Unit 1 or Unit 2 Turbine Building ventilation is in service in the once-througlliineup, THEN SECURE that units' turbine building ventilation (OP-37.3).

I OEOP-O'I-AEDP Rev. '18 Categories KIA:

SG2.04.17 RO Rating:

3.9 LP Obj:

CLS-LP-300-H*002 Cog Level:

mGH Tier / Group: T3 SRO Rating:

4.3 Source

~VV Category 8:

Y o

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Page 2 of 161

100. An ATWS has occurred on Unit Two:

ARI has been actuated.

No blue lights are lit on the Full Core Display.

Suppression Pool Temperature is 112° F.

The 2A SLC pump has a red light indication.

The 2B SLC pump has a green light indication The SLC A Squib Valve Continuity white light is lit The SLC B Squib Valve Continuity white light is extinguished.

Which one of the following identifies the procedure that an AC would be directed to perform based on the above conditions and the resultant effect of those actions?

A Perform LEP-02, Section 2 to insert control rods in order to shutdown the reactor by venting the Scram Air Header.

B. Perform LEP-02, Section 6 to insert control rods in order to shutdown the reactor by venting the overpiston area of the control rods.

C. Perform LEP-03, Section 2 to inject boron to shutdown the reactor using RCIC.

D. Perform LEP03, Section 3 to inject boron to shutdown the reactor using RWCU via the SLC tank.

100. An ATWS has occurred on Unit Two:

ARI has been actuated.

No blue lights are lit on the Full Core Display.

Suppression Pool Temperature is 112 0 F.

The 2A SLC pump has a red light indication.

The 2B SLC pump has a green light indication The SLC A Squib Valve Continuity white light is lit The SLC B Squib Valve Continuity white light is extinguished.

Which one of the following identifies the procedure that an AO would be directed to perform based on the above conditions and the resultant effect of those actions?

A'! Perform LEP-02, Section 2 to insert control rods in order to shutdown the reactor by venting the Scram Air Header.

B. Perform LEP-02, Section 6 to insert control rods in order to shutdown the reactor by venting the overpiston area of the control rods.

C. Perform LEP-03, Section 2 to inject boron to shutdown the reactor using RCIC.

D. Perform LEP~03, Section 3 to inject boron to shutdown the reactor using RWCU via the SLC tank.

Feedback K/A: SG2.04.35 Emergency Procedures I Plan Knowledge of local auxiliary operator tasks during an emergency and the resultant operational effects (CFR: 41.10 /43.5/45.13)

RO/SRO Rating: 3.8/4.0 Objective: CLSLP300J*005 5.

Given plant conditions and the Local Emergency Procedures, determine which sections of the Alternate Control Rod Insertion Procedure should be utilized for Control Rod Insertion (EOP-01 -LEP-02).

4. Given plant conditions and the Local Emergency Procedures, determine which method of the Alternate Boron Injection is appropriate (EOP-01-LEP-03)

Reference:

OEOP-01 -LEP-02 Cog Level: High Explanation:

Based on the conditions given, determines that scram valves have not opened (no blue lights on full core display) and that Boron is injecting with A pump running (red light on) and B squib valve opened (white light extinguished) so LEP-03 is not required. The pumps discharge into a c9rflmoIheader before going to the squib valves. Requires assessment of alternate control rod insertion seOtions anddetermines venting the scram air header is appropriate.

Distractor Analysis:

Choice A: Correct Answer Choice B: Plausible because venting of the over piston area will insert the control rods but would be the inappropriate decision for rod insertion given the conditins. The operational effect is reactor shutdown with control rod insertion.

Choice C: Plausible because suppression pool temperature is greater than 1100 F and boron injection is required. With A pump running but the A squib valve not open and no B pump a common misconception is that SLC flow will not occur to the Reactor. this would be correct under different conditions in the stem. The operational effect is reactor shutdown with boron injection.

Choice D: Plausible because suppression pool temperature is greater than 1100 F and boron injection is required. With A pump running but the A squib valve not open and no B pump a common misconception is that SLC flow will not occur to the Reactor. this would be correct under different conditions in the stem. The operational effect is reactor shutdown with boron injection.

SRO Only Basis: Assessing plant conditions and prescribing a section of a procedure with which to proceed.

Notes Feedback KIA: SG2.04.35 Emergency Procedures I Plan Knowledge of local auxiliary operator tasks during an emergency and the resultant operational effects.

(CFR: 41.10/43.5/45.13)

RO/SRO Rating: 3.8/4.0 Objective: CLS-LP-300-J*005

5. Given plant conditions and the Local Emergency Procedures, determine which sections of the Alternate Control Rod Insertion Procedure should be utilized for Control Rod Insertion (EOP-01-LEP-02).

4. Given plant conditions and the Local Emergency Procedures, determine which method of the Alternate Boron Injection is appropriate (EOP-01-LEP-03)

Reference:

OEOP-01-LEP-02 Cog Level: High Explanation:

Based on the conditions given, determines that scram valves have not opened (no blue lights on full core display) and that Boron is injecting with A pump running (red light on) and B squib valve opened (white light extinguished) so LEP-03 is not required. The pumps discharge into a c9ffi..rnQ!lJl~~der before going to the squib valves. Requires assessment of alternate control rod insertion seCtions and"determines venting the scram air header is appropriate.

Distractor Analysis:

Choice A: Correct Answer Choice B: Plausible because venting of the over piston area will insert the control rods but would be the inappropriate decision for rod insertion given the conditins. The operational effect is reactor shutdown with control rod insertion.

Choice C: Plausible because suppression pool temperature is greater than 110° F and boron injection is required. With A pump running but the A squib valve not open and no B pump a common misconception is that SLC flow will not occur to the Reactor. this would be correct under different conditions in the stem. The operational effect is reactor shutdown with boron injection.

Choice D: Plausible because suppression pool temperature is greater than 110° F and boron injection is required. With A pump running but the A squib valve not open and no B pump a common misconception is that SLC flow will not occur to the Reactor. this would be correct under different conditions in the stem. The operational effect is reactor shutdown with boron injection.

SRO Only Basis: Assessing plant conditions and prescribing a section of a procedure with which to proceed.

Notes

21 INSERT control rods by one or more of the following methods:

2.71 DE-ENERGIZE the scram pilot valve solenoids AND VENT the scram air header Section 2 on Page 9 2.7.2 RESET RPS AND INITIATE a manual scram. Section 3 on Page 14.

2.7.3 SCRAM indMdual rods with the scram test switches, Section 4 on Page 17.

2.7.4 INSERT control rods with the Reactor Manual Control LI System, Section 5 on Page 21.

2.7.5 VENT the over piston area of control rods, Section 6 on Page 22.

OEOP-O1-LEP-02 Rev. 26 Page 3 of 29 2.2 INJECT boron with one or more of the following systems:

ENOTE:

System(s) should be selected in order listed and based upon system II availability and accessibility.

CO:

CRD, Section 1 on page 3 LI NOTE:

HPCI/RCIC should be used only if suction is from the CST.

CO:

HPCl/RCICSection2onpage14 LI CO:

RWCU via SLC tank, Section 3 on page 21 LI CO:

RWCU with borax, Section 4 on page 31 LI OEOR-Di-LEP-03 Rev. 27 Page 2 of 41 2.7 INSERT control rods by one or more of the following methods:

2.7.1 2.7.2 2.7.3 2.7.4 2.7.5 DE-ENERGIZE the scram pilot valve solenoids AND VENT the scram air header, Section 2 on Page 9.

RESET RPS AND INITIATE a manual scram, Section 3 on Page '14.

SCRAM individual rods with the scram test switches, Section 4 on Page H.

INSERT control rods with the Reactor Manual Control System, Section 5 on Page 21.

VENT the over piston area of control rods, Section 6 on Page 22.

I OEOP-01-LEP-02 Rev. 26 2.2 INJECT boron with one or more of the following systems:

o o

o Page 3 of 29 I NOTE:

System(s) should be selected in order listed and based upon system availability and accessibility.

CO:

CRD, Section 1 on page 3 NOTE:

HPCIIRCIC should be used only jf suction is from the CST.

CO:

HPCIIRCIC, Section 2 on page 14 CO:

RWCU via SLC tank, Section 3 on page 21 CO:

RWCU with borax, Section 4 on page 31 I OEOP-01-LEP-03 Rev. 27 o

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o Page 2 of 4-1 I

K/A:

SG2.04.35 RORating:

3.8 LP Obj:

CLSLP3OOJ*OO5 Cog Level:

NIGH Tier / Group:

T3 SRO Rating:

4.0 Source

NEW Category 8:

4.0 Source

NEW Category 8:

f002A F002B PUMP COO1A PUMP C001B

ML101590078

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