ML041380169

Licensee Post Exam Written Comments (Initial Comments)

ML041380169
Person / Time
Site:	Oyster Creek
Issue date:	04/19/2004
From:	Hackenberg J AmerGen Energy Co
To:	Conte R NRC/RGN-I/DRS/OSB
Conte R
References
-RFPFR, 50-219/04-301 50-219/04-301
Download: ML041380169 (127)

Text

Grading summary spreadsheet u

Summary of finalized corrections Question 23 Question 25 Question 37 Question 71 Question SRO 3 Question SRO 7 Question SRO 12 Question SRO 22 Question SRO 23 1

1 1

1 1

1 Question SRO 25

t I

Summary of finalized corrections:

0 Question 19:

accept two answers, c and d 0

Question 23:

accept two answers, b and c 0

Question 25:

accept two answers, b and c 0

Question 37:

accept two answers, c and d 0

Question 47:

accept two answers, b and d 0

Quesfion 71 :

accept two answers, a and d 0

Question SRO 3:

accept two answers, a and b 0

Question SRO 7:

accept two answers, a and b 0

Question SRO 12: no correct answers, delete the question 0

Question SRO 22: correct answer is b 0

I

, c 0

Question SRO 23: all 4 answers are correct, delete the question 0

Question SRO 25: accept two answers, c and d

Question 19 This question has some mis-leading information within the stem, which caused some of the candidates to arrive at a different answer than was expected. This was due to wording within the stem that was in quotation marks. Orle of the bullets states:

L---

0 You are operating all available DW cooling Since the candidates had a copy of the Primary Containment Control EOP, and given the wording contained within the quotation marks, it is NOT unreasonable for them to go to the step in the Drywell Temperature leg containing the wording Operate all available drywell cooling IAW S.P. 27. Support Procedure 27 directs the operator to bypass the RBCCW isolation signals and start all available drywell recirc fans.

The stem wording all available DW cooling is operating implies that Support Procedure 27 has already been performed. In this case, RBCCW would have been bypassed and the correct answer to the question would be d, rated capacity of DW recirc fans is inadequate. This would be true if Primaiy Containment Control had been entered and Support Procedure 27 had already been performed, and a subsequent re-entry condition exists causing a re-entry to Primary Containment Control.

If this is the first time the question of being able to maintain bulk drywell temperature below 150 deg. F is asked, the stem of the question should have referenced the previous step in Drywell Temperature Control (Maintain bulk drywell temperature below 150 deg. F usina available drvwell coolers.) If available drvwell coolers is in quotation marks, there is no way the candidate can become confused with the wording in the quotation mdrks, given its location in the flowchart.

L-The wording available drywell coolers is different from all available drywell cooling.

Available drywell coolers implies the drywell cooling system is being operated within normal operating procedures, which specifies only 4 of 5 drywell recirc fans running, with RBCCW supplied to the coolers. The wording all available drywell cooling directs RBCCW isolations to be bypassed and all 5 recirc fans to be operated.

Based upon interpretation of the all available drywell cooling, coupled with the other plant conditions, the candidate could reach the conclusion that RBCCW has indeed isolated, which would make c the correct answer.

Therefore, since there is no time line given for the LOCA event, and given the all available DW cooling in quotation marks, answers c and d are correct.

References:

EMG-3200.02, Primary Containment Control EOP Users Guide, pp. 2-14 through 2-1 6

QUESTION #I9

.I I

W Given the following conditions:

A Loss of Offsite Power has occurred Reactor is at rated temperature and pressure The drywell pressure entry condition for EMG-3200-02, Primary Containment Control Reactor water level is 0 TAFand decreasing.

You are operating all available DW cooling.

The CRS asks: Can bulk drywell temperature be maintained below 150 degrees F?

has been satisfied.

0 0

0 Your response is NO.

What is the basis for this response?

K

6.

A LOCA signal has caused Chilled Water to isolate.

A High Drywell Pressure signal has caused Drywell Recirc fans to trip.

/

C.

A LOCA signal has caused RBCCW isolation valves to isolate.

D.

The rated capacity of 5 Drywell Recirc fans is inadequate.

ANSWER:

C EXPLANATION:

RBCCW isolation occurs with Lo-Lo water level and High Drywell Pressure. Without RBCCW there is no heat sink for drywell cooling and temperature cannot be reduced. The RBCCW isolation must be cleared or bypassed (Support Procedure 27) this is done if/when the answer is NO.

I TECHNICAL REFERENCE(S):

Primarv Containment Lesson Plan DCI 13: EOP-2 (Attach I

L if not previously provided)

Proposed references to be provided to applicants during examination:

EOPs Learning Objective:

(04) 07346 (As available)

Examination Outline Cross-reference:

Level RO SRO Tier #

1 -

Group #

KIA #

295028/EA1.02 Importance Rating 3.9 I

KIA Topic

Description:

Ability to operate and/or monitor the drywell ventilation system as it applies to high drywell temperature Question Source:

Bank #

Modified Bank #

New X

(Note changes or attached parent)

Question Cognitive Level:

Memory or Fundamental Knowledge X

Le Comprehensive or Analysis I O CFR Part 55 Content:

55.41 X

Comments:

55.43

P L - L P NOfSIA38 A

I S 83 10 0 3 11 3 M Atl a 318 V 11 VAV 3NISn d,OSL Mol39 38nlV83dW31 113MAtlO Mln8 NlVlNlVW t

PRIMARY CONTAINMENT CONTROL EOP USERS GUIDE t

This question is asked if normal means of temperature control were adequate to maintain Drywell bulk temperature below 150F. If normal methods were unsuccessful, then further actions are required.

Following the DECISION step is an Unusual Event flag. EPIP-OC-.O 1 recommends an Unusual Event Classification if Drywell bulk temperature is greater than or equal to 150F, but less than or equal to 281°F for 5 minutes or longer.

REVISION 4 2 - 15

91 - l P NOIS[AgItL

I

.I Question 23,

Answers b and c are both correct.

I Answer b is consistent with ABN-26 gudance, to reduce reactor power an6 thereby reduce steam line activity. Since iodine production is proportional to reactor power, reducing power will have a direct impact on iodine production. Also, RAP 1 OF-2-d for Stack Effluent HI, directs actions IAW ABN-26. Therefore, answer b is procedurally driven from ABN-26, which dictates a power reduction to clear the alarms. Nowhere in the procedures does it have the operator removing normal reactor building ventilation and starting standby gas treatment system.

Answer c is also correct, because starting Standby Gas Treatment will remave radioactive iodine that is present under all conditions.

Therefore, answers b and c are correct.

References:

RAP 1 OF-2-d, STACK EFFLUENT HI ABN-26, High Main Steam Line or Off-Gas Activity I

I I

QUESTION #23 Given the following plant conditions:

AOG is in service Stack Effluent HI alarm v

Reactor is at 100% power Main Steam Line Radiation Monitors all at approximhtely 550 mr/hr Reactor Bldg Vent Radiation at 8 mr/hr RCS activity at 90% of TS limit --

Significant/visible packing leak from "A". IC outboard steam isolation valve B IC isolated for maintenance NO leaks in the "A" IC tube. bundle --

e What action(s) would result in having the greatest reduction in the thyroid damage for the public?

A.

B.

Close "A" IC outboard steam isolation valve Reduce reactor power until stack effluent HI alarm clears C.

'Start SGTS and shutdown Reactor Building HVAC x D!

Close "A" IC vent valve ANSWER:

C EXPLAN AT1 0 N:

Starting SGTS is the only action that will remove radioactive iodine being released from the steam leak. The AOG will remove all iodine from the off gas regardless of reactor power so reducing power will not result in a reduction in iodine.

L' TECHNICAL REFERENCE(S):

(Attach if not previously provided)

Proposed references to be provided to applicants during examination:

None Learning Objective:

(As available)

Examination Outline Cross-reference:

Level RO SRO Tier #

1 -

Group #

I WA #

-' 295038/EK1

.Ol Importance Rating 2.5 WA Topic

Description:

Knowledge of the operational implications of the biological effects of radioactive ingestion as it applies to Off Gas Release rate.

Question Source:

Bank #

b Modified Bank #

(Note changes or attached parent)

New X

Question Cognitive Level:

Memory or Fundamental Knowledge Comprehensive or Analysis x

Group Heading R A D I A T I O N M O N I T O R S Notify Chemistry of condition.

(ODCM 2000-ADM-4532.04, Section 4.6.1.1.5.c) may apply.

The Offsite Dose Calculation Manual P R O C E S S S T A C K E F F L U E N T subject Procedure No.

Page 1 of 1 N S S S 2000-RAP-3024.01 10F d Alarm Response Procedures Revision No: 131 I

1 0 F d I

C S T A C K E F F L U E N T H

I USES :

(1) HI concentration of noble gas radioactivity in the main stack effluent.

I ZONFIRMATORY ACTIONS :

R E F L A S H SETPOINTS:

1,000 cps ACTUATING DEVICES:

Ch. #1 RE-661-1621 VIA RIT-661-1615 VIA RYS-661-1615 Ch. #2 RE-661-1622 VIA RIT-661-1624 VIA RYS-661-1624 Reflash unit:

PNL-661-1RAR3 Reference Drawings:

GU 33-611-17-003 GU 3D-661-42-001 Jerify the high radiation level at the Stack RAGEMS noble gas effluent monitors on

?anel 1R or Stack RAGEMS effluent recorders on Panel 10F. If the alarm is from a iigh concentration of noble gas in main stack effluent as verified from the Panel LOF Recorders, follow the mmlual corrective actions. If desired, contact Plant lhemistry to take a stack effluent noble gas sample.

cf the primary containment was being vented, the source of the high stack activity nay be from the primary containment.

>e from the primary containment, the GSS shall insure the containment is vented

hrough the Standby Gas Treatment System.

UJTOMATIC ACTIONS:

JONE lANuAL CORRECTIVE ACTIONS :

!heck for high radiation in the offgas stream, Reactor Building, Turbine Building,

)Id Radwaste, and New Radwaste, or trip of the Reactor Building Ventilation System md perform actions defined in Procedure 2000-ABN-3200.26, Increase in Offgas

~c t ivi t y.

If the source of the activity is confirmed to (Panel 10F/14)

Title Usage Level I

OYSTER CREEK GENERATING STATION PROCEDURE Revision No.

0 HIGH MAIN STEAM LINE OR OFF-GAS ACTIVITY Prior Revision _O incorporated the following Temporary Changes:

Number ABN-26 This Revision _O incorporates the following Temporary Changes:

List of Paqes 1.O to 7.0 1.o

OYSTER CREEK GENERATING STATION PROCEDURE AmWGen*

An Exekm#Rit%h fneiyy Corn pany Number ABN-26 Title HIGH MAIN STEAM LINE OR OFF-GAS ACTIVITY Revision No.

0

~~

1 OF-I -d RAD HI J-5-b a

HIGH MAIN STEAM 'LINE OR OFF GAS ACTIVITY 1.o APPLICABILITY This procedure provides directions for abnormally high Main Steam line or Off Gas radioactivity release rates.

Section 3.1 Section 3.2 Section 3.3

' Main Steam Radiation Levels 550 to 800 mr/hr Main Steam Radiation Levels greater than 800 mr/hr Rise in Off Gas Activity I

2.0 INDICATIONS 2.1 Annunciators Location Encraving Setpoint 1,000 mrlhr OFF GAS Hi-HI I

OF-1 -C I

OF-2-c OFF GAS HI 700 mr/hr 2,000 cps STACK EFFLUENT HI-HI STACK EFFLUENT HI 1 OF-2-d 1,000 cps 550 mr/hr 2.2 Change Parameter Location Air ejector off gas radiation Panel IOF, 1R Rising Stack effluent radiation Panel I OF, 1 R

~

Rising Rising Main steamline radiation Panel IOF, IR, 2R Other indications - None 2.3 2.o

OYSTER CREEK GENERATING STATION PROCEDURE HIGH MAIN STEAM LINE OR OFF-GAS ACTIVITY

-Gen, nn ~ ~ r l o n m r l t i ~ ~

C n e i g Company Title

\\,

I Number ABN-26 Revision No.

0 3.0 OPERATOR ACTIONS If while executing this procedure, an entry condition for any EOP occurs, then EXECUTE this procedure concurrently with the appropriate EOP.

3. I Main Steam Radiation Levels 550 to 800 mr/hr I.

If two or more Main Steam Line Radiation Monitors, on Panel 1 R and 2R are verified greater than 550 mr/hr, but less than 800 mr/hr, then PERFORM the following:

A.

DIRECT Chemistry to sample the Reactor coolant.

[ 1, B.

MONITOR off gas and stack effluent activity.

[

I C.

If Hydrogen Injection is in operation, then PERFORM the following:

[

I

1.

REDUCE Hydrogen Injection flow rate to between 5 and 6scfm.

[

I

2.

ALLOW 10 minutes for the Main Steam RAD HI alarm (J-5-b) to clear.

3.

If Main Steam RAD HI alarm (J-5-b) clears within 10 minutes, then PERFORM the following:

[

I

a.

MONITOR off gas and stack effluent activity.

[

I

b.

NOTIFY Reactor Engineering of plant conditions.

3.O

OYSTER CREEK GENERATING STATION PROCEDURE

.jW~erGen.~

Air fxetonlsrltlsh Energy Compny Number ABN-26

4.

If Main Steam RAD HI alarm (J-5-b) does not clear within 10 minutes, and fuel damage is confirmed by chemistry sample analysis and/or rising off gas activity,

[

I I

'y Title HIGH MAIN STEAM LINE OR OFF-GAS ACTIVITY I

Revision No.

0 then COMMENCE plant shutdown in accordance with Prbcedure 203, Plant shutdown.

5.

If Hydrogen Injection is not in operation, and fuel damage is confirmed by chemistry sample analysis and/or rising off gas activity, then COMMENCE plant shutdown in accordance with Procedure 203, Plant r

1 1

a I Shutdown.

L I

3.2 Main Steam Radiation Levels greater than 800 mr/hr L---

A.

If two or more Main Steam Line Radiation Monitors, on Panel I

R and 2R are verified greater than 800 mrlhr, and off gas activity is rising, then SCRAM the Reactor in accordance with ABN-1,

Reactor Scram.

[

I

2.

If the Reactor has successfully scrammed, then CLOSE the following valves:

0 MSlVs

[

I Isolation Condenser vents

[

I Reactor Water sample valves V-24-29 and V-24-30

[ ]

Drywell Air Supply valve V-6-395

[

I

3.

MONITOR off gas and stack effluent activity.

[

I

[

I

4.

EVACUATE the Turbine Building and/or the Reactor Building as directed by the US.

4.0

OYSTER CREEK GENERATING STATION PROCEDURE

____AmerGenw An fxelonihtlth? Z n q y Cornyny L.

Title HIGH MAIN STEAM LINE OR OFF-GAS ACTIVITY I

Number ABN-26 Revision No.

0

[

I

5.

REFER to EPIP-OC-01, Classification of Emergency Conditions, for EAL evaluation.

6.

NOTIFY Reactor Engineering of plant conditions.

[

I 3.3 Rise in Off Gas Activity

1.

If Reactor power is greater than 40%, and off gas activity rises by more than 50% after factoring out any rise'due to changes in thermal power, then PERFORM the following:

[

I A.

B.

REFER to Technical Specifications 3.6.E and 4.6.E. [ 1 DIRECT Chemistry to sample off gas and the Reactor coolant.

C.

REQUEST guidance from Reactor Engineering.

[

I

2.

If any of the following alarms are received, 0

OFF GAS HI (IOF-2-C)

STACK EFFLUENT HI (IOF-2-d)

STACK EFFLUENT HI-HI (IOF-I-d) then PERFORM the following:

NOTE: A change in any of the listed parameters may cause a fluctuation in the off gas release rate.

A.

REVIEW recent changes in any of the following parameters.

Off Gas line flow Condenser vacuum

[

I

[

I

[

I

[

I Steam seal header pressure 5.O

I OYSTER CREEK GENERATING STATION PROCEDURE AmerGen..

AR E~danlPrlt~sh Energy Company Number ABN-26 I

Title HIGH MAIN STEAM LINE OR OFF-GAS ACTIVI'TY B.

Revision No.

0 NOTIFY Chemistry of the condition.

[

I L-.

1 1

C.

REDUCE Reactor power until all three radiation alarms listed in Step 2 have cleared.

D.

If all three radiation alarms listed in Step 2 cannot be cleared, then DIRECT Chemistry to sample the Reactor coolant and off gas.

r. I

3.

If the OFF GAS HI-HI alarm (IOF-I-c) is received, then PERFORM the following:

1 1

A.

VERIFY off gas conditions.

I

[

I B.

REDUCE Reactor power until the OFF GAS HI-HI alarm clears. '

[

I C.

COMMENCE plant shutdown in accordance with Procedure 203, Plant Shutdown.

D.

If the OFF GAS HI-HI alarm does E t clear within 15 minutes of actuation, then PERFORM the following:

[

I

1.

SCRAM the Reactor in accordance with ABN-I, Reactor Scram.

2.

CONFIRM the following valves closed:

[

I Off Gas Exhaust Isolation Valve, V-7-31, on Panel 1 OXF

[

I AOG Inlet Valve, AOV-0001N-OOOIB, on Panel IOXF

3.

PLACE Drain Valves, V-7-29/SOV-O16 control switch in the CLOSE position on Panel IOXF.

[

I 6.0

OYSTER CREEK GENERATING STATION PROCEDURE HIGH MAIN STEAM LINE OR OFF-GAS ACTIVITY

,,,,,,,,,&nerGep*

Ai: :eielonimltKh rnergy Company L-Title I

Number ABN-26 Revision No.

0

4.

If the Reactor has successfully scrammed, then CLOSE the following valves

4.

0 MSIVS Isolation Condenser vents Reactor Water sample valves V-24-29 and V-24-30 Drywell Air Supply valve V-6-395

5.

EVACUATE the Turbine Building and/or the Reactor Building as directed by the,

us.

REFER to EPIP-OC-01, Classification of Emergency Conditions, for EAL evaluation.

[

I

[

I

[

I

[

I I.

[

I

5.

MONITOR off gas and stack effluent activity.

[

I

6.

NOTIFY Reactor Engineering of plant conditions.

[

I

4.0 REFERENCES

4. I Technical Specifications 4.2 ABN-1, Reactor Scram 4.3 Procedure 203, Plant Shutdown 5.0 ATTACHMENTS - None 7.O

I I

Question 25 Regarding core spray system availability per the Level Restoration procedure, all the EOPs are concerned with is main pump availability per each core spray system. The booster pumps are started with the US concurrence.

As it pertainst0 the core spray system, if the core spray sparger hi dp alarm is present, it only indicates the core spray system may not perform its design function of establishing a uniform spray pattern. RAP B-5-e and B-5-f (sparger dp hi alarms), list the cause of the alarm as high differential pressure across the sparger nozzles due to Core Spray line break in the vessel annulus. With the alarm in, it is assumed all core spray flow is diverted to the annulus. Even with this annulus flow, the core spray systems can be considered available as an injection source, and other mitigating actions will be based upon RPV water level at or above -30 inches. While it is absolutely true that the core spray system will not operate at design basis flows for spray cooling, this decision is not addressed until all actions have been taken to emergency depressurize and RPV water level cannot be restored and maintained above -30 inches. This condition is NOT what the question is asking.

Based upon the above argument, all four answers were assessed without any regard to sparger dp alarms.

For the remaining inforhation in the question, the key to determining which set of conditions will result in core spray flow is the Flow Permissive signal. Per RAP B-2-e and B-2-f (SYSTEM 1/2 FLOW PERMISSIVE), the following conditions must be met:

0 Booster pump dp signal for the respective core spray system, AND 0

Core spray main pump discharge pressure, AND 0

RPV pressure less than 305 psig Based upon these criteria, answers a and d CANNOT be correct, as the booster pump overload trip affects its system, and the booster pump dp signal will NOT be generated, thereby eliminating the flow permissive signal for that system. However, both answers b and c are correct, as the booster pump trip affects the other system, allowing the flow permissive alarm to be received.

Therefore, answers b and c are correct.

References:

RAP B-2-e, SYSTEM 1 FLOW PERMISSIVE RAP B-3-e, BSTR PUMP A/C OL RAP B-5-e, SPARGER 1 DP HI RAP B-2-f, SYSTEM 2 FLOW PERMISSIVE RAP B-3-f, BSTR PUMP B/D OL RAP B-5-f, SPARGER 2 DP HI EMG-3200.01 A, RPV Control - No ATWS, Level Restoration EOP Users Guide, pp. IA-25 and 1A-39

QUESTION #z5 t-Following a loss of offsite power, the crew has initiated EMG-3200.01A "RPV Control-No ATWS" and is at the step that specifies "Confirm the following sub-systems fined up for injection with pumps running".

Which of the following configurations of Core Spray annunciators LIT would confirm either Core Spray System 1 or Core Spray System 2 is lined up with pumps running?

A.

SPARGER 1 DP HI, SYSTEM 1 FLOW PERMISSIVE, BSTR PUMP A/C OL B.

SPARGER I DP HI, SYSTEM 2 FLOW PERMISSIVE, BSTR PUMP A/C OL C.

D.

ANSWER:

B SPARGER 2 DP HI, SYSTEM 2 FLOW PERMISSIVE, BSTR PUMP A/C OL SPARGER 2 DP HI, SYSTEM 2 FLOW PERMISSIVE, BSTR PUMP B/D OL EXPLANATION:

For A, C and D the sparger dp alarm indicates the sub-system that has the flow permissive (pumps actually running) is faulted and the flow may NOT be "lined up for injection" that is it may not be going into the RPV.

TECHNICAL REFERENCE(S):

(Attach if not previously provided) a Proposed references to be provided to applicants during examination:

Learning Objective:

(As available)

Examination Outline Cross-reference:

Level RO SRO Tier #

2 -

Group #

1 -

WA #

209001/A2.05 Importance Rating 3.3 KIA Topic

Description:

Ability to predict the impacts of Core Spray Line Break on the Low Pressure Core Spray System and based on those predictions use procedures to correct, control or mitigate the consequences of those abnormal conditions or operations.

Question Source:

Bank #

Modified Bank #

New X

(Note changes or attached parent)

Question Cognitive Level:

10 CFR Part 55 Content:

55.41 X

Comments:

Memory or Fundamental Knowledge Comprehensive or Analysis X

55.43

I Sub] ect Group Heading C 0 R E S P,,R A Y S Y S T E M 1 F L O W P E R M I S S I V E S Y S T E M 1 F L O W P E R M I S S I V E I I L

7SES :

Booster pump differential pressure greater than 3 0. 5 / 2 8. 5 psid (RV40A/RV40C)

- A N D -

core Spray pump dischakge pressure 3reater than 100 psig

- A N D -

ieactor pressure less than 3 0 5 psig JOTE: This alarm will activate only if all three conditions are met indicating that core spray should be injecting into the depressurized Rx-core.

I B e 1

SETPOINTS:

3 0. 5 psid 2 8. 5 psid 105.psig 3 0 5 psig

!ONFIRMATORY ACTIONS :

!heck pump discharge pressures on Panel 1F/2F.

'heck reactor pressure on Panel 4F.

ACTUATING DEVICES:

DPS RV40A or DPS RV4OC

- A N D -

PS RV29A or RV29C

- m -

RE17A or RE17B Reference Drawings:

NU 506036003 Sh. 1'& 3 GU 33-611-17-004 Sh. 1

.UTOMATIC ACTIONS :

ore Spray pumps discharge pressure greater than 105 psig allows start of booster ump. Failure of booster pump to develop a differential pressure greater than 0.5/28.5 psid (RV40A/RV40C) within 5 seconds, trips booster pump and starts lternate pump. Reactor pressure less than 305 psi9 permits opening of Core Spray solation valves with system initiation. NOTE:

tart automatically unless failure of both primary booster pumps occur.

The alternate booster pump will not LNUAL CORRECTIVE ACTIONS:

f alarm sounds and all three conditions are not met, repair switches if defective.

N S S S Alarm Response Procedures Procedure No.

Page 1 of 2 2000-RAP-3024.01 B

2 e

Revision No: 1 3 0

Group Heading 1

ubject Procedure No.

Page 2 of 2 N S S S 2000-RAP-3024.01 B

2 e

Alarm Response Procedures Revision No:

130 C O R E S P R A Y

/

/

1 B

2 e

1

/

ANNUNC COMMON

/

/

/

/

/

/

/

!ore Spray 1)

System 1 Flow Permissive

/

/

Determine which pump is affected. Start alternate pump as required and trip affected pump. Refer to 2000-OPS-3024.07 ICore Spray System Diagnostic and Restoration Actions.

I Subject Procedure No.

Page 1 of 2 N S S S 2000-RAP-3024. 01 C O R E S P,, R A Y

-1 Group Heading Alarm Response Procedures B S T R P U M P A

/

C O L Revision No: 130 SES :

Core Spray booster, pump, NZ03A or NZ03C, drive motor overload.

I B

3 e

1 SETPOINTS:

430 amps 2ONFIRMATORY ACTIONS:

ACTUATING DEVICES:

49 or 49 NZ 0 3A NZ03C Reference Drawings:

GE 116B8328 Sh. 15A, 15E GU 33-611-17-004 Sh. 1 LUTOMATIC ACTIONS:

lONE W A L CORRECTIVE ACTIONS:

B 3

e

Heading 1

C O R E S P R A Y B e B S T R P U M P A

/

C O L ZOMMON 74

/

49-1

/

49-1 4NNuNc I /

/

ect

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/

N S S S

/

Alarm Response Procedures

/

6 9 /NZO 1B

/

49-3

/

49-3

/

Procedure No.

Page 2 of 2 2000-RAP-3024.01 B e Revision No: 130

/

/

/

/

C O R E S P R A Y I

I S P A R G E R 1

D P H I i

High pressure differential across Core Spray System 1 sparger nozzles due to core Spray line break in the vessel I

I CONFIRMATORY ACTIONS :

SETPOINTS:

0.3 & 0.3 psid ACTUATING DEVICES:

____i I

DPIS RV30A Reference Drawings:

GE 148F712 GE 885D781 GE 112C2845 Sh. 3 GU 33-611-17-004 Sh. 2 If instrument reading is greater than or equal to 1 psid, consider Core Spray System 1 inoperable.

Notify Licensed Operations Supervisor.

limit within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Daily Instructions for guidance on rod movement and power changes.

Verify operability of System 2.

Core MAPLHGR must be brought within 90% of Contact Core Engineering by referencing the Core Maneuvering

( Fane 1 B/ 2 9 )

Group Heading lbject N S S S Alarm Response Procedures C O R E S P R A Y Procedure No.

Page 1 of 2 2000-RAP-3024.01 B

2 f

Revision No: 130 B

2 f

I 2

S Y S T E M 2 F L O W P E R M I S S I V E Booster pump differential pressure greater than 47.0/25.0 psid (RV4 OB/RV4 OD)

- AND -

ore Spray pump discharge pressure greater than 100 psig

- AND -

teactor pressure less than 305 psig JOTE: This alarm will activate only if all three conditions are met indicating that core spray should be injecting into the depressurized Rx core.

!ONFIRMATORY ACTIONS:

SETPOINTS:

47.0 psid 25.0 psid 140 psig 305 psig ACTUATING DEVICES:

DPS 'RV4OB or DPS RV4OD

- AND -

PS RV29B or RV29D

- A N D -

RE17C or RE17D Reference Drawings:

Nu 506036003 Sh. 2 & 4 GU 33-611-17-004 Sh. 1

!heck pump discharge pressures on Panel 1F/2F

'heck reactor pressure on Panel 4F.

UTOMATIC ACTIONS:

ore Spray pumps discharge pressure greater than 140 psig allows start of booster ump. Failure of booster pump to develop a differential pressure greater than 7.0/25.0 psid (RV40B/RV40D) within 5 seconds trips booster pump and starts lternate pump. Reactor pressure less than 305 psig permits opening of Core Spray solation valves with system initiation. NOTE: The alternate booster pump will not tart automatically unless failure of both primary booster pumps occur.

ANTJAL CORRECTIVE ACTIONS:

f alarm sounds and all three conditions are not met, repair switches if defective.

'up Heading

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C O R E S P S A Y

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S Y S T E M 2

F L O W P E R M I S S I V E

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B 2

f ect N S S S Alarm Response Procedures I

Procedure No.

Page 2 of 2 2000-RAP-3024.01 Revision No:

130 0

B f

ore Spray 2)

System 2 Flow Permissive B f I

I

\\-

2 Group Heading B f C O R E S P R A Y bject N S S S Alarm Response Procedures B S T R P U M P B / D O L Procedure No.

Page 1 of 2 2000-RAP-3024.01 B f Revision No: 130 lore Spray booster pump, NZ03B or IZ03D, drive motor overload.

SETPOINTS :

430 amps ACTUATING DEVICES:

49 or 49

-. NZ03B NZ03D Reference Drawings:

GE 116B8328 Sh. 15C, 15L GU 33-611-1'7-004 Sh. 1 ONFIRMATORY ACTIONS:

JTOMATIC ACTIONS:

)NE WAL CORRECTIVE ACTIONS:

tennine which pump is affected. Start alternate pump as required and trip ifected pump. Refer to 2000-OPS-3024.07 '#Core Spray System Diagnostic and

storation Actions".

t I

Zubject Procedure No.

Page 2 of 2 N S S S 2000-RAP-3024.01 B f A l a r m Response Procedures Revision No:

130 2

Group Heading B

3 f

C O R E S P R A Y 1'

B S T R P U M P B I D O L

/

ANNUNC COMMON 7 74 NZ 0 1A 6 9 /NZOlA I /

NAT -

74 7 NZOlC 69/NZ01C I /

NAT -

t 0

B-4-e SPR PMP A/C OL/BRKR PERM 74 NZOlB 0

B-4-f SPR PMP B/D

+

NZ03A t

/ I 0

B-3-e BSTR PUMP OL/BRKR PERM A/C OL 0

B-3-f BSTR PUMP B/D OL I

MANUAL CORRECTIVE ACTIONS :

30NFIRMATORY ACTIONS :

If instrument reading is greater than or equal to 1 psid, consider Core Spray S y s t e m 2 inoperable. Verify operability of System 1.

Notify Licensed Operations Supervisor.

limit within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

laily Instructions for guidance on rod movement and power changes.

Core MAPLHGR must be brought within 90% of Contact Core Engineering by referencing the Core Maneuvering ACTUATING DEVICES:

Spray System 2 sparqer nozzles due to Core Spray line break in the vessel annulus.

rerify pressure differential at instrument rack RK04.

Subject N S S S Alarm Response Procedures DPIS RV3OB Procedure No.

Page 1 of 1 2000-RAP-3024.01 B

5 f

Revision No: 131 Reference Drawings:

GE 148F712 GE 885D781 GE 112C2845 Sh. 3 GU 33-611-17-004 Sh. 2 LUTOMATIC ACTIONS:

None

( Pane 1 B/ 4 0 )

$2 - VI P NOISIA3tl t

. 6 30Ud lUOddnS t13d Z W31SAS A V t l d S 3UO3 -

6 - 30dd LUOddnS 8 - 30dd LldOddnS t13d 1 W3LSAS A V t l d S 3MO3.

M 3 d 31VSN30N03.

DNINNIItl S d W l l d HllM Nd1133rNI tlO3 dfl 0 3 N I l SW3lSAS-BflS S N I M O l l O J 3HL W t l l j N 0 3

6" - VI b NOISl/\\3ltl c

garno s;mn d 0 3 SMLV ON - TOXIN03 AdX

I 1

Question #37 Per RAP H-6-A, ROD DRIFT, the cause is any controlrod drifting more than 3 through an odd rod position, when the control rod is not selected. The RAP directs a scram if more than one rod is moving in or out abnormally. If only one rod is moving, it directs actions in accordance with ABN-6.

i I

\\.--

Per Technical Manual VM-RW-1316, Detailed Design Manual, Control Rod Monitor and Scan Routine, when a rod drift is detected, a IO-second timer starts. If the rod drifts for a period >IO seconds without the rod drift alarm clearing, RMCS will latch to the highest completed step having less than three insert errors and at least one rod withdrawn past the insert limit, making answer c correct. If the rod drift clears before the IO-second timer times out, then RMCS assumes it as a slow settlinq rod and the drift is determined to have cleared satisfactorily. In this case, the RWM Will relatch with no insert errors and,

no withdraw errors, making answer d correct.

The operator actions of ABN-6 direct the operator to select the rod and applv a continuous insert siqnal to Dosition 00. If the operator selects the drifting rod before the IO-second timer times out, the rod drift alarm will clear. While the actions for a drifting in control rod are not expected operator actions, it expectations for the URO to identify and select the drifting rod for two reasons. First, it is easier to monitor the drifting rod once it has been selected. Second, if the drifting rod has been selected, and the rod drift ala& does NOT clear, this is indicative of more than one rod drifting, which requires a manual reactor scram. If the rod drift alarm clears when it is selected, then only one rod (the selected rod) can be drifting. At that point, the operator will break out ABN-6, go to the section for a drifting in control rod, and carry out the actions specified.

operations management The students were taught to immediately select the identified rod that is drifting, for the above reasons. They were subjected to numerous drifting control rods during their training. Since Oyster Creek utilizes a full core display that shows all 137 control rod positions on the vertical section of Panel 4F, a drifting control rod is usually spotted within a few seconds, and it is not at all unlikely the rod will be selected before the 10-second timer has timed out.

Based upon when the drifting rod is selected, answers c and d are correct.

References:

Rod Worth Minimizer lesson plan VM-RW-1316, RWM DETAILED DESIGN MANUAL, sections 3.5.2.3, 3.11.1, and 3.11.3.3 ABN-6, Control Rod Drive System RAP H-6-a, ROD DRIFT

I QUESTION #37 Following a rod drifting in, the RWM will "relatch".

RMCS will locate the highest completed step that meets which one of the following criteria?

\\--

A.

LESS THAN three insert errors and MORE THAN two rods are withdrawn past the insert limit.

B.

NO insert errors and AT LEAST one rod is withdrawn past the insert limit C.

D.

LESS THAN three insert errors and AT LEAST one rod withdrawn past the insert limit.

NO insert errors and NO withdraw errors ANSWER:

EXPLANAT1 ON:

Obtained from OC Training as a bank question used previously.

TECHNICAL REFERENCE(S):

RWM Lesson Plan (Attach if not previously provided)

Proposed references to be provided to applicants during examination:

None L-Learning Objective:

(01) 10446 (As available)

Examination Outline Cross-reference:

Level RO SRO 2

Tier #

2 Group #

WA #

201 006/K4.06 -

Importance Rating 3.2 WA Topic

Description:

Knowledge of Rod Worth Minimizer design feature(s) that permit correction of out of sequence rod positions Question Source:

Bank #

X Modified Bank #

New Question Cognitive Level:

Memory or Fundamental Knowledge X

(Note changes or attached parent)

Comprehensive or Analysis 55.43 I O CFR Part 55 Content:

55.41 X

c Comments:

flpR 22 2004 9 : O S f l M OYSTER CREEK SEB 2 609-971-4739 P - 2 c

ROD WORTH MINIMIZER DETAILED DESIGN MANUAL, VOL. I 1'

VM-RW-13 16

, REVISION:

7 DATE:

10-29-93 PAGE:

11 OF 39 2.5.1.8 Task Names These, parameters define the names of a l l tasks sending or receiving messages i n the RWM System. These are the names used by the Task Builder (TKB) when the tasks are b u i l t and used by the

.system message facility t o pass messages between RWM tasks.

These parameters are RAD50 f o r actual use with system service calls.

RAD50 i s a method used by the Digital Equipment Corporation for storing three bytes o f selected character data i n two bytes instead o f the normal three.

Task names as currently defined i n the system are as follows:

PZDAS

' DAEXLZ' Data Acquisition Subsystem PZMMI

'HMEXEZ' Man/Machine Xnterface Subsystem-PZARS I DREXEZ' Data Archival/Retrieval Subsystem PZCRM

' CRMEXZ' Control Rod Monltor and Scan PZCM

' COMTKZ' PCS Communications Subsystem PZSQE

'SEQEDZ' Sequence Editor PZDBE

' DBEDTZ' Database Editor PZCSL I CONSLZ' Console terminal message receiver.

I a

2.5.1.9 Message Argument Offsets I

These parameters define the offsets into an array for building the intertask messages.

The arrays used f o r the messages must necessarily be local t o the routine sending the message.

PIMNO = 1 Message number PINUM = 2 PIARl 3

Argument 1 PIARZ = 4 Argument 2 PIARS = 5 Argument 3 PITM2 = 12 Number o f arguments PTlTMR = 600 PTZTMR = 600 PTSCRM = 600 10 Second Offset for rod drift t o clear 10 Second Offset for rod d r i f t t o remain clear 10 Second Offset after scram t o full core scan

A P R 22 2004 9 : O S A M O Y S T E R CREEK S E B 2 609-971-4739 VM-RW-1316 CHAPTER 3 REWSION: 8 DATE: 08/12/97 PAGE: 2 OF 42

,. 3.3.3 Digital Equipment Corporation, RSX-I 1 Mhl-Plus, Version 4.2. Volume 4C, Executive Reference Manual j.4 GENERAL DESCRIPTION OF CRMS 3.4.1 CRMS Overview CRMS performs an initialization routine at the t h e of RWM system initialization by a cold or warm boot of the RWM system computer. The CRMS initialization routine serves to test the operation of the RWM block/penissive finction and initialize local variables within CRMS.

In conjunction with CRMS initialization, the DAS subsystem is prompted to perform a full core scan to provide an update of the current control rod positions. Upon the completion of the full core scan as determined through the status of the full core scan request flag in the global CVT, CRMS obtains the updated rod positions from the CVT and anernpts to "latch" to the prescribed Low Power sequence. (The RWM boots in Lower Power Mode by default.), The latching operation consists of the determination of the sequence step corresponding to the current control rod pattern. Once the sequence has been latched, CRMS can compare present control rod positions to those required, identify existing errors and initiate control rod blocks as warranted.

During execution, CRMS monitors control rod position through either of two modes. The normal mode of operation is designated "Operator Follow Mode". In this mode of operation, CRMS tracks changes in RWM sysmm input data resulting from normal control rod positioning by the plant operator. However, a need for a full core scan update of rod positions may periodically become apparent based on niggering events ( e,&, rod drift alarm activation, reactor scram initiation,'etc.)

or through request by external sources. In such instances, the "Scan Mode" of operation is active and CRMS obtains b

updated position information for all control rods upon the completion Qf a full core scan by the DAS subsystem.

Within the realm of plant operation requiring activation of the sequence monitoring funcrion, latching logic is required for the determination of the1 proper latched sequence step. Under Low Power Mode, in-step latching is accomplished as p m of the operator follow mode. Each new sequence step is initiated through selection of control rods at rhe reactor manual control panel. Under certain conditions including the occurrence of a full core scan or the occurrence of specific changes in plant operation, relatching to the prescribed sequence is necessary. The CRMS module seeks co find the proper sequence step corresponding to current control rod positions by performing a search for the highest step completed without encountering an insert block condition. Instances during normal RWM system operation in which o relatch is required include the following:

I o RWM System Initialization o R W M System Unbypass 2

o Following Rod Drift Timer Expiration o Following Operator Rod Test Request o Following Correction of an Existing Insert or Withdraw Error o When Power Drops Below LPAP o When Power Drops Below LPSP o Following any Full Core Scan ( Power Less Than LPAP )

o On a timed interval during operation in the transition zone (Power between LPSP and LPAP setpoints) a Utilizing the rod position input data and sequence latching logic detailed above, CRc1S establishes a basis for the performance of the sequence monitoring function.. The sequence monitoring function generally serves to enforce the required sequencing constraints identified through the engineer-defined sequence and under Low Power Mode, BPWS rules. Esccptions to this condition exist concerning the loading of special shutdown margin or test sequences and during c

activation of the rod lest request. Under Low Power Mode, whenever a shutdown margin or test sequence is loaded in global. BPWS constraints are suppressed and rod sequencing is determined by the engineer-defined sequence alone.

BPWS consmints may also be suppressed via the VT-220 Man-machine function. as the engineer defined sequence

P - 4 FlPR 22 2004 9 : O S A M O Y S T E R CREEK S E B 2 609-971 -4739 I

L VM-R W-1 3 1 6 CHAPTER 3 REVISION: 8

. P.4GE: 2 OF 42 DATE: oa/izm longer enforce adherence to prescribed sequencing constraints. Under operating conditions above the LPAP or whenever the R W

system is placed in bypass by the plant operator, Low Power sequence monitoring shall cease to be active.

Sequence monitoring, however, is available above the LPAP, but requires manual activation by the Control Room Operator. Power Operations Mode may be activated to enforce a Power Operations Mode sequence at any power level while tbe RWM bypass switch is in the normal position, and Power Operations Mode @OM) has been started, and the POM sequence has been loaded.

Exceptions to this functional logic for sequence monitoring activation include conditions involving reactor scram initiation, bypass of the LPAP status within the RWM system programming and request of the rod test sequencing constraint by the plant operator.

I During the performance of the sequence monitorhg function, the CItMS subsystem controls rod block status data locared in the global CVT to enforce the prescribed sequence for rod movement as necessary. For normal Low Power plant operation below the LPSP, control rod movement shall be required to follow sequencing consmints established by an engineer-defmed sequence and Banked Position Withdrawal Sequence (BPWS) rules. Whenever any change is detected in control rod position which exceeds bounds established for the prescribed sequence (2 insert errors or 1 withdraw error),

comcsponding control rod motion is blocked except for the correction of existing emr5.

Under Power Operations Mode, control rod movement shall be required to follow sequencing constraints established by an engineer-defined POM sequence. The POM sequence and its enforcement differ from the Low Power Mode as Low power groups (Groups 1-1 through Groups 4-1) may not be defined and therefore may not be moved under Power Operations Mode.

l roiiows:

o o

o o

o Individual control rods may be defined and therefore moved under Power Operations Mode.

Only one insert error is allowed under Power Operations Mode.

Under Power Operations Mode, a select error generates both insert and withdraw blocks.

The Power Operations Mode sequence bas only 10 steps, and will only latch to Step 1, as the sequence is not reversible. Once Step 1 is complete, and a rod in Step 2 is selected, the sequence is updated deleting Step 1 and moving up all the remaining steps. A relatch is then performed sgaiast the new Step 1.

Lnder Power Operations Mode, rod movement is monitored against the current step only.

o Under either mode, CRMS provides appropriate messages for existing error and block conditions required by the MMI, CO\\ITASK and ARCHIVE subsystems.

3.3 REFERENCES

5.3. I GPUN Oyster Creek, Rod Worth Minimizer, Functional Specification, Document No. 100-8500001-06 o Sectjon 1.6.3, Control Rod Position and Scanning Program il Section 2.6.4, Sequence Monitoring Program o Section 26.9. R W M Performance Requirements 2.:.:

NEDO-2 123 1, Banked Position Withdrawal Sequence

P - 5 RPR 22 2004 9 : l O f l M OYSTER CREEK SEE 2 609-971-4739 VM-RW-1316 CHAPTER 3 REVISION: 8 DATE: 08/12/97 PAGE: 14OF12 3.5.2.2 Communications Communication between the various subsystems of the R W M shall be accomplished through the global tables and RSX message facilities.

The term timer has two connotations within the CILMS routhe.

T h e first connotation is associated with the timed future time through the system mark time service. (See referem-,

The second connotation occurs in the context of "checking" a timer. Timer as used here requires only a system service call to determine the current time. This type of timer is started by making a call to the TIME service and saving the time retufned in a local variable. Subsequent passes of CRMS "check" the timer by making another call to the TIME service and calculating the difference between the current system time and the saved system time. All of these type of timers have an associated time offset. '&e., TI and T2 a5 defined in Chapter 2, Section 2.5.1.10).

These tiqers are said to have expired when the difference between intervals mode of execution. Timer as used here refers to a system service call to "wake up" CRMS at a specified the current and saved system times is greater than the specified offset.

I I'

CRMS works with data at both the global and local levels to perfom the functions required of the CRh4S routine.

C-3.5.3.1 Global Data At the global level, CRMS is reading from and writing to the current value table (which contains the current value and qualip code} as well as the MMI communications tables. The complete list of global variables may be found in Chapter 3 and is not presented here. However, the global variables used by a COS module for input and output are identified within the sections provided below for each individual COS module.

3.5.3.2 Local Data At the local level. C W S requires at a minimum one variable per COS module. These variables will be used in one of two ways. For the modules associated with the on-demand type of wecurion, one pass is needed to process,*e module completely. In these cases the local variable is set qual to the state of the mgger variable. the conditions are processed, and the module is skipped in subsequent passes until another COS occurs. For the modules associated with the timed intervals execution. multiple passes are required to process the module completely. In these cases, the local variable is set equal to the state of the global variable at the first COS, and the initial pass processing is done. Subsequent passes will perform the timed sequence steps as needed, and the local variable will set equal to the trigger variable only when The trigger variable has returned to it's original value and all requirements of the COS have been met.

33.4 Special Interfaces CRVS shall use distinct modules for checking and enforcement of the Banked Position Withdrawal Sequence (BPWS).

Refer to Section 3 2 and Appendix A for a more thorough treatment of BPWS.

c...

P. 6 flPR 22 2004 9 : l O f l M OYSTER CREEK SEE 2 609-971-4739 VM-RW-13 16 CHAPTER 3 REVISION: 8 a'

t DATE 08/12/97 PAGE: 20 OF 42 3.10.3 Detailed Description 3.10.3.1 GlobaI Inputs GLOBAL COMMON VARIABLE VARIABLE NAME LDEUG (PSCRM)

Scram signal LDEUG (PDRM3 Rod drift signal The scram timer parameter will be used or the ten second timer as described in Chapter 2, Section 2.5.1.10.

3.10.3.2 Global Outputs I

I None 3.10.3.3 Method The scram COS module is entered on the first 5 c m COS and on each subsequent pass by CRMS until both the scram and rod drift signals have cleared. Each pass of CRMS perfoms one of the following submodufes. This is a timed interval module.

3.10.3.3.1 ' Jnitial COS On the first detection of the scram signal being set, CRMS retain5 the set state, startS a ten second timer, and notifies the appropriate tasks through the message facility of the scram.

I 3.10.2.3.2 Timer On subsequent passes, CRMS checks the timer until it has expired. At that point, the first of two full core scans is requesttd.

I

'6-3.10.3.5.; Verification After the initial full core scan. CRMS checks the state of both the scram signal and the rod drift alarm. When both are clear. a second full core scan is requested, a scram reset message is sent through the message facility, and the reset Sfate of the scram signal is retained so that subsequent passes of CkVS will ignore this module until the next scram COS. A check on the local rod drift variable is also performed a& this point, and that variable is reset as needed to avoid a third full cor? scan request from the rod drift COS module.

3.1 I ROD DRJFT COS (CRDRFT) 3.11.1 Purpose The rod drift signal is a field input point convened by the DAS subsystem to a logical variable in global common. The rod drift signal explicitly defines to CRMS that a full core scan and rod block requests are to be made if the rod drift has not clexed within a TI time period. Additionally, a second full core scan request is to be made after tfie drift has been clear for a l-2 period of time and the first full core scan has been completed. Should the scram and rod drift signals both be presenr. the scram signal takes precedence.

P. 7 R P R 22 2004 9:lOAM OYSTER CREEK SEB 2 609-971-4739 VM-RW-13 16 CHAPTER 3 REVISION: 8 DATE: OW1 2/97 PAGE: 21 OF 42 i

3. I I.2 Requirements The rod drift status COS module fulfills the following requirements:

o detects a COS on the rod drift status o A message indicative of the rod drift is sent through the message facility o employs two time offsets, TI and 72, to avoid unneeded or excessive fill core scans o initiates a full core scan at time TI after the rod drift COS is detected o initiates 8 second full core scan after the rod drift status has been clear for a time T2 1

3.1 1.3 Detailed Description 3.1 1.3.1 Global Inputs GLOBAL COMMON VARIABLE VARJABLE NAME LDEUG (PDWT)

Rod dn-fl signal LDEUG (PSCRM)

Scram signal Note: The TI and T2 time offsets are incorporated as parameters as defined in Chapter 2, Section 2.5.1.lo.

(,

3.1 1.3.2 Global Outputs.

None 3.1 1-32 Method The rod drift alarm,COS will be entered when the rod drift alarm change of state is first detected and on each subsequent pass until the rod drift has cleared satisfactoril:..

Each pass of CRMS performs one of the following submodules. This is a timed interval module.

3. I I.3.3. I Initial COS On the first detection of a rod dr.&LJ&

a T1 timer is started ?he state of the rod drift alarm is retained by CRNlS, and

-ate tasks are notified of the &Through the message facility.

3.11.332 Drift Determination On subsequent passes, CRMS checks to see if the TI timer is expired or the rod drift alarm is cleared. Should the Tl timer expire prior to clearing the rod drifi signal. the T2 Limer is stated and two requests are made. The fust request is to the rod blocks request COS to remove the insrn and withdra\\\\ perrnissives.

The second request is to the full core scan request COS module to initiate a full core scan.

Should the rod drift clear before the T1 timer expires, a d o h sealing control rod is assumed and the drift is determined to have cleared satisfactorily.

3.1 I.3.3.3 Verification of Position Following Rod Drift This lasr submodule is entered on all subsequent passes of CRVS after the TI timer expiration processing is completed as detailed above.

The T2 timer is restarted each pass in which the rod drifi alarm is not clear. A second full core scan request is made when the first full core scan has completed and the R timer has expired. and a request co the rod block COS module i s senerated for the application of the insert and withdraw permissives.

i 6

Each pass causes CRVS to check the rod drift status and the T2 timer.

Nuclear a

OBJECTIVES From memory unless otherwise indicated and in accordsuice with the lesson plan, the trainee shall be able to:

' -- A. (01)10435 B. (01)10446 C. (01)10453 D. (01)10444 E. (01)10447 F. (01)10451 Given plant operating conditions, describe ordex&in the purpose(s)/fimction(s) of the system and its components.

Identify and explain system operating controls/indications under all plant operating conditions.

Explain or describe how this system is interrelated with other plant systems.

Describe the interlock signals and setpoints for the affected system components and expected system response including power loss of failed components.

Given normal operating procedures and documents for the system, describe or interpret the procedural steps.

Given Technical Specifications, identify and explain associated actions for each section of the Technical Specifications relating to this system including personnel allocation and equipment operation.

Pg. #

2,6,7,14 3-9,11 3,7,17 4,14 8,18,20 20 Copyright 2002 by Exelon Nuclear, All Rights Reserved. Permission for reproduction and use is reserved for Exelon Nuclear.

.+-my other use or reproduction is expressly prohibited without the express permission of Exelon Nuclear.)

i k:\\trainingbdmin\\word\\262 1\\8280004 1.doc

Nuclear

References:

A.

Procedures:

i,

1.

2,

3.

4.

so #2

5.

so ##4

6.

20 1, Plant Startup 2 18, Operation Below 10% Rated Power with the Rod Worth Minimizer Bypassed or Inoperable 409, Operation of the Rod Worth Minimizer 106.1 1, Reactivity Management B.

Technical Specifications:

1.

Section 3.2.B.2 C.

Drawings:

1.

2.

3.

4.

5.

BR EO 15, RWM Patch Panel ER-653-089 Assy & Conn., Rev. 6,

GE 237E912, RMCS Elementary Diagram, Sheets 1, 4,5, & 8 GE 729E838, RWM System, Sheets. 1,2,3 GE 706E212, Rod Block Display GU 3E-653-18-1000, RWM Conn. Diagram 1.-

D.

Other:

1.

2.

3.

SOER 84-2

4.

LER 9O.O_O_3-CO-~~TS~-9005~9)

5.

OCNGS Updated FSAR, Section 7.7.1.3 NEDO-2333 1 Banked Position Withdrawal Sequence VM-RW-13 12, RWM Operators Man-,

I_ -//

Lesson

Description:

(

Approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of classroom lecture/discussion.

k:\\training\\admin\\wordL262 1 \\8280004 1.doc ii

ContentlS kills

9. CRMS System Status Flags 1'

I

a. Initialization Request - initiates CRMS activities required to properly initialize the RWM System.

b. Full Core Scan Request - used by CRMS to detect performance of core scan by DAS.

c. Relatch Request - C W S evaluates the proper sequence step corresponding to present rod positions.

L-

d. Rod Test Request - CRMS attempts to enter Rod Test mode.

1) All rods must be fully in.

2) allows operator to select and withdraw any singie I

control rod regardless of sequence loaded.

3) allows full utilization of one-rod-out permissive function without bypassing RWM.

e. Inoperable Rod Request - allows inoperable,rods to be removed from normal sequencing requirements. CRMS manages the status of control and operability.

I I

2.

Control Rod Sequencing I

1. Six separate sequences available - test, shutdown margin, and four standard operating sequences (A 1,A2,B 1,B2)

2. Sequences are detailed through an engineer defined sequence (EDS) using sequence editor.

3. When any A or B sequence is loaded, CRMS checks for conformance to Banked Position Withdrawal Sequence (BPWS) rules.

4. Engineer Defined Sequence

a. Stepwise listing of rod withdrawals.

b. Each step identifies:

1) a rod or group of rods to be withdrawn (or inserted),

and

2) insert and withdraw limits for rod motion.

c. EDS always begins from all-rods-in.

v Activi tieslNotes Relatches to currently loaded rod sequence.

LO B,E k:\\training\\admin\\word\\2621\\82800041

.doc Page 8 of 27

I ContentISkills b

d. Test and shutdown margin sequences - stepwise withdrawal of individual rods.

e. Standard operating sequences - stepwise withdrawal for groups of rods.

5. Banked Position Withdrawal Sequence (BPWS)

a. Set of rules for banked motion of rods in the core, which reduces rod worths to levels consistent wjth analyzed reactor safety limits.

b. Rules establish constraints for a defined set of ten rod groups.

1) One set of rules for groups 1 through 4, below 50%

rod density,

2) another set of rules for groups 5 through 10, above 50% rod density.

c. EDS is checked for conformance to BPWS when:

1) EDS is edited, and

2) when EDS is loaded into RWM.

v

6. Sequence Monitoring Operations

a. Performed by CRMS.

b. CRMS must "latch" to proper sequence step; done by comparing present rod positions to desired rod sequence.

c. When proper sequence step is established, CRMS uses rod block to enforce sequence.

d. Sequence latching performed in-step during normal operations: latched step is increased or decreased based on selection andor movement of rods by operator.

e. Relatch occurs when proper step is unknown or requires re-evaluation due to changing plant conditions.

1) RWM System initialization

2) RWM System unbypass

3) Following a core scan

4) Following correction of insert or withdrawal errors L

ActivitiedNotes "Black and white" pattern; rods are alternately full-in and full-out.

Done by CRMS continuously.

LO B Power must be below LPSP.

Page 9 of 27 k:\\training\\admin\\word\\262 1\\8280004 1.doc

C o n te n t/S k i I Is I

5) Following rod drift timer expiration I'

I

'?,'

I

6) Following operator request

7) When power drops below LPAP q,

8) When power drops below LPSP

f. During relatch, CRMS attempts to determine step by comparing number of rod notches withdrawn to notch withdrawals required by the sequence.

1) If step can be determined without identifying insert or withdrawal errors, relatch is complete.

2) If not possible, step is determined by more detailed search of rod sequence.

g. When insert or withdrawal errors exist, CRMS finds the highest completed sequence step such that:

1) less than three insert errors exist, and

2) at least one rod in the step is withdrawn past the step insert limit.

3) Results in a relatch to highest sequence step allowable without R W M insert block.

8

h. Once relatch completed, in-step latching is performed.

ActivitiedNotes Rod drift reset.

During relatch.

Conduct Interim Summary.

k:\\training\\admin\\word\\262 1 \\8280004 1.doc Page 10 of 27

1 ContentlSkiIls IV. Controls, Interlocks, and Alarms

. U' A.

Control Room Touch-screen CRT Display

1. Sequence Display Information

a. Upper left comer of screen provides:

1) Current sequence step

2) Group and subgroup identification

3) Selected rod identification and position

4) Insert and withdraw limits

5) Separate block shows loaded sequence.

b. Upper-center blocks provide:

1) Rod having insert errors (total of two) or withdraw error (total of one) 2)' Next rod for insert or withdrawal.

c. Selected rod and position always updated.

d. Other information only updated during sequence u

monitoring operations.

2. System Status Indications

a.

b.

C.

d.

e.

f.

g.

L-Low Power Setpoint (LPSP) - Green when below the LPSP; red when at or above the LPSP.

Rod Scan - Green when no core scan is in progress; red during performance of 111 core scan.

R W M Bypass - Green when keylock switch is in "NORMAL;" red when the switch is in "BYPASS."

Communication Link - Green when link between RWM and plant computer in functional; red when the link fails.

Select Error - Green with no select error; red when a select error exists.

Insert Block - Green when no insert block exists; red when an inset block develops.

Withdraw Block - Green when no withdraw block exists; red when a withdraw block develops.

ActivitieslNotes LO B Slide of Figure 41-4 Slide of 41-4 Q: How would the operator know a rod scan was in progress?

A: Rod scan button turns red.

k:\\training\\admin\\word\\262 1\\8280004 1.doc Page 11 of 27

ROD WORTH MINIMIZER OPERATORS MANUAL 3.2 SYSTEM INPUT AND SEQUENCE MONITORING FUNCTION 3.2.1 CRMS Subsystem Functional Overview The Control Rod Monitor and Scan (CRMS) subsystem provides 'the means to monitor the change of state of key RWM system'inputs and direct performance of the sequence monitoring function. CRMS also serves as 'a source of RWM system status information required by other RWM software subsystems.

1' 1

CRMS polls the datA maintained, in computer, memory upon the activation of computer system event flags triggered by DAS. These event flags are used to notify the CRMS subsystem whenever a change of state is detected in RWM system inputs by DAS. In this manner, CRMS determines changes in control rod selection, position, and selected system inputs as the changes occur.

System input data monitored by CRMS 'is generally required to determine the activation of sequence monitoring requirements and identification of necessary sequencb monitoring input. However CRMS also pe'rforms input monitoring functions of importance for other RWM softwkre subsystems. The CRMS subsystem generates RWM system messages following the change of state of key RUM system inputs which are accessed by both the ARCHIVE and PCS subsystems. As a result, monitoring of RWM system inputs is always maintained by CRMS regardless of the need for sequence monitoring activites.

The CRMS subsystem also performs numerous system input and sequence monitoring functions on demand from other RWM software subsystems. These activities are keyed to changes in RWM system sratus flags maintained in computer memory.

3.2.2 Input Monitoring Operations 4

The CRMS subsystem monitors the statds of several key system inputs on a continuous basis during RWM system operation. These system inputs include the following:

L-o Bypass Switch Position o

Low Power Setpoint (LPSP) Status o

Low Power Alarm Point (LPAP) Status o

SCRAM Signal Status o

Rod Drift Signal Status o

Rod Selection Input o

Rod Position Input The bypass switch position and LPSP/L,PAP status inputs are used by CXMS to determine whether sequence monitoring functions are required active. Whenever the system bypass switch is in the "normal" position and power remains below the LPSP, RWM system sequence monitoring activities are required. The CRMS subsystem monitors the sequence of control rod movement by the operator under these conditions and enforces the prescribed rod sequence. As reactor power is increased to a level between the LPSP and LPAP (transition zone), CRMS continues to monitor rod movement but ceases to enforce the sequence. Under operating conditions above the LPAP or whenever the RWM system is placed in bypass, all sequence monitoring functions cease to be active.

i--

Revision 1: 05/16/88 100-8600004-02 Page 3 - 4

ROD WORTH MINIMIZER OPERATORS MANUAL The reactor SCRAM and rod drift inputs are used by CRMS to trigger requests for full core scans of control rod position. This ensures that actual control rod positions are reflected in computer memory.

A full core scan of control rod positions is requested by CRMS following a ten second delay after the detection of a rod drift condition. At that point the CRMS subsystem also sets the rod blocks to prohibit control rod motion. A second full core scan is requested following a 'ten second delay after reset of the control rod drift.

During reactor SCRAM conditions, a subsequent rod drift condition is generally obtained due to control rod overtravel. The CRMS logic processes the reactor SCRAM signal in preference to the rod drift input resulting in a full core scan request from CRMS following a ten second delay after the detection of the reactor SCRAM. A second full core scan is requested following reset of both the SCRAM and rod drift inputs.

Monitoring of control rod selection and position inputs is always maintained by CRMS when the RWM system is in operation. These inputs are monitored in two seperate modes by CRMS. The normal mode of operation is designated as the "operator follow mode". In the operator follow mode, CRMS tracks changes in rod selection and position inputs as they occur during control rod selection and positioning by the operator.. The second mode of operation is designated as the "scan mode". In the scan mode, CRMS obtains updated position information for' all the control rods in the core following the coqpletion of a full core scan by DAS.

3.2.3 System Status Flag Monitoring As detailed above, CRMS subsystem operation is also keyed to numerous RWM system status flags. These system status flags include the following:

o Initialization Request Status o

Full Core Scan Request Status o

Relatch Request Status o

Rod Test Request Status o

Inoperable Rod Request Status An initialization request status flag initiates CRMS program activities required to properly initialize the RWM system. The CRMS subsystem must evaluate initial operating conditions whenever the RWM system is placed on-line (initialized). This initialization request is set by the DAS subsystem when the DAS first begins operation and is used t o trigger initial CRMS subsystem operation.

The full core scan request status flag is used by CRMS to detect the performance of scanning activity by the DAS subsystem. This status flag allows CRMS to determine the occurrence of a full core scan regardless of the source of the scan request. CRMS rod position monitoring in the scan mode is triggered by this status flag.

Revision 1 : 05/16/88 100-8600004-02 Page 3-5

ROD WORTH MINIMIZER OPERATORS MANUAL The relatch request status flag is used to request a "relatch" by CRMS to the control rod sequence. A relatcp is simply an evaluation of the proper sequence step corresponding to present rod positions. This function is necessary for CRMS to 'establish the present sequence,step during sequence monitoring activities. The relatch request status flag may be set by numerous CRMS subsystem modules or by other RUM software subsystems.

The remaining system status flags are used to request special sequence monitoring activities by CRMS. These request flags are only of importance to CRMs subsystem operation during the performance of sequence monitoring activities.

Upon receipt of a rod test request, CRMS attempts to initiate the RWM system "rod test" mode. This mode of RWM system operation may only be entered if all control rods are fully inserted within the reactor core. Once entered, CRMS will allow the operator to select and withdraw any single control rod regardless of the sequence loaded on the RWM. This allows the operator to fully utilize the one-rod-out permissive function *during reactor shutdown conditions without'requiring bypass of the RWM system.

Upon receipt of an inoperable rod request by CRMS, the operable status of control rods can be changed for sequence monitoring logic. Inoperable control rods must be removed from the normal sequencing requirements for power operation (ie, Banked Position Withdrawal Sequence). This status flag triggers changes in the status of control rod operability as managed by the CRMS subsystem.

3.2.4 Control Rod Sequencing Constraints I

I 3.2.4.1 General Any of six seperate sequences may be loaded on the RWM system including special test and shutdown margin sequences as well as the standard operating sequences for power operation (Al,AP,Bl or B2). The control rod sequence is detailed through an engineer defined sequence (EDS) developed using the off-line sequence editor subsystem. Whenever the A or B sequences are loaded at the RUM system, CRMS additionally checks for conformance to Banked Position Withdrawal Sequence (BPWS) rules.

3.2.4.2 Engineer Defined Sequence (EDS)

The engineer defined sequence consists of a stepwise listing of control rod withdrawals. Each step identifies a control rod or group of rods to be withdrawn and the applicable limits for control rod motion. These limits for rod motion are the defined step insert and withdraw limits which establish bounds for rod motion during a sequence step.

The control rod sequence identified through the engineer defined sequence always begins from an all-rods-in condition. The series of steps in the engineer defined sequence establishes a contiguous sequence for the movement of control rods to a target control rod pattern.

Revision 1: 05/16/88 100-8600004-02 Page 3-6

ROD WORTH MINIMIZER OPERATORS MANUAL Normal power operating sequences identified in the engineer defined sequences are checked for BPWS consistency through a user specified sequence step'by the sequence editor subsystem. However, the CRMS subsystem also checks to ensure Test or shutdown margin sequences are always provided as a stepwise withdrawal sequence of individual control rods. This ensures that the exact sequence for rod movement is maintained under test or shutdown margin conditions.

In contrast, the standard control rod sequences developed for normal power operation are generally provided as a stepwise withdrawal sequence for groups of control rods. The rod grouping utilized in these sequences is generally based on BPWS rod group definitions since these sequences are required to be consistent with BPWS requirements. Each step identifies appropriate insert and withdrawal limits for a defined BPWS group or engineer defined BPWS subgroup.

-.-/

3.2.5.1

.General Under proper system input conditions described above, the CRMS subsystem directs the sequence monitoring function of the RWM system. The CRMS subsystem monitors the motion of control rods against the desired sequence loaded on the RWM system. Error conditions involving the insertion or withdrawal of control rods are identified by CRMS as they occur and the status of control rod blocks is controlled in computer memory.

During active sequence monitoring operation, the CRMS subsystem must "latch" to the proper sequence step. This process requires the evaluation of present rod positions in comparison to the desired rod sequence. The CRMS subsystem determines the current location within the sequence and existing sequence errors through this process.

Revision 1: 05/16/88 100-8600004-02 Page 3 - 7.

ROD WORTH MINIMIZER OPERATORS MANUAL Once the proper sequence step is established, the CRMS subsystem controls the status of rod blocks maintained in computer memory to direct the enforcement of the desired rod sequence. Whenever any change is detected in control rod I

positions which exceeds the bounds established for the sequence (2 insert errors or 1 withdraw error), corresponding control rod motion is blocked except for the correction of existing error conditions. As a result, an insert block condition will occur if more than two rod insert errors are determined to exist and a withdraw block condition will occur with a single withdraw error.

The CRMS subsystem provides appropriate messages concerning all existing error and block conditions for the other RWM subsystems.

3. 2. 5. 2 Sequence Latching Logic m-Sequence latching activity is performed by the CRMS subsystem in conjunction with the update of control rod position data during both the scan mode and operator follow mode. Following the performance of a full core scan by the RWM system, a relatch to the sequence is performed taking into account the current positions of all rods in the core. During updates of rod position in the operator follow mode, the CRMS subsystem performs in-step latching activity.

In-step latching involves the increase or decrease of the latched sequence step based on the selection and/or movement of control rods by the operator.

A relatch to the sequence is generally performed whenever the proper sequence step is unknown or requires reevaluation due to changing plant conditions. Instances in which a relatch is performed by CRMS include the following circumstances:

o RWM system initialization o

RWM system unbypass o

o o

o Following operator request o

o o

Following any full core scan (power below LPSP)

Following correction of an exisfing insert or withdraw error condition Following rod drift timer expiration (rod drift reset)

When power drops below LPAP When power drops below LPSP On a timed interval during operation in the Transition Zone (Power between LPSP and LPAP)

During a relatch, the CRMS subsystem first attempts to determine the sequence step by a comparison of the number of control rod notches withdrawn to the notch withdrawals required by the sequence. If the sequence step can be determined in this manner without the identification of rod insert or withdrawal errors, the relatching process is complete. Otherwise, the proper sequence step is determined through a more detailed search of the rod sequence.

When rod insert or withdrawal errors are determined to exist, the CRMS subsystem searches to establish the highest completed sequence step such that less than three insert errors exist and at least one rod in step is withdrawn past the step insert limit. This effectively results in a relatch to the highest sequence step allowable without the occurrence of RWM insert block conditions.

Revision 1: 05/16/88 100-8600004-02 Page 3-8

ROD WORTH MINIMIZER OPERATORS MANUAL

, Once a relatch to the sequence is completed, in-step latching is performed by

'the CRMS subsystem to maintain the proper sequence step during rod motion by the operator.

An increase in the latched sequence step is possible if attempted rod movement by the operator will result in less than three existing insert errors. This effectively allows a step increase by the RWM system only if it can be achieved without the occurrence of an insert block condition.

'L A decrease in the latched sequence step is possible only if all control rods in the present step have been moved to the associated step insert limit. This effectively allows a step decrease by the RWM system only if it can be achieved without the occurrence of a rod withdraw block condition.

3.2.5.3 Sequence Error and Rod Block Logic Sequence error and rod block conditions are determined by the CRMS subsystem using a defined set of sequence monitoring logic. The logic used by the CBMS subsystem establishes absolute definitions, of sequence error and block conditions as detailed below.

i--

The three error conditions identified through sequence monitoring activity consist of control rod selection, insert and withdrawal errors. Precise definitions for each of these error conditions are provided in Appendix 1 of this manual but are repeated here for further clarification.

A select error exists whenever the control rod selected by the operator is determined to be outside of the currently loaded sequence (allowable latched step). The CRMS subsystem evalutes rod selection by the operator to 'ensure '

that the rod selected for motion meets either of two conditions. The control rod must either be within the current latched step or be within the next highest or next lowest step allowable through in-step latching requirements.

Otherwise a rod selection error exists.

Rod insertion errors exist whenever a control rod is inserted to a position less than the insert limit for the last sequence step in which the control rod was defined. Insert errors can therefore be produced for rods positioned in the present sequence step or any previously completed sequence step.

Rod withdrawal errors exist whenever a control rod is withdrawn to a position beyond the last step in which the control rod was defined. If the control rod was not defined within the sequence up through the latched step, the rod must remain fully inserted or be defined as a withdraw error. A rod withdrawal error can therefore be produced for any control rod in the core with the exception of any fully withdrawn in-sequence rods.

The rod block logic employed by the CRMS subsystem is based upon the number of insert and/or withdraw errors which exist as defined above. As described earlier, when error conditions exist which exceed the bounds established for the sequence (2 insert errors or 1 withdrawal error), rod blocks are initiated by CRMS. Only corrective motion of control rods is allowed to clear existing errors under these circumstances.

Revision 1: 05/16/88 100-8600004-02 Page 3-9

'e-

\\,. -

ROD WORTH MINIMIZER OPERATORS MANUAL Specific rod sequence conditions which cause a rod insert block during conditions requiring sequence 6nforcement may be summarized as follows:

There is an existing rod withdrawal error resulting in a rod withdrawal block condition qnd the operator.is not attempting its correction (operator has selected a rod differing from the withdraw error rod).

' 0 I

I o

Three,insert errors have been produced by the operator during control rodamotion.

Specific rod sequence conditions which cause a rod withdraw block during conditions requiring sequence enforcement may be summarized as follows:

o There are three existing rod insert errors resulting in a rod insert block condition and the operator is not attempting their correction (operator has selected a rod differing from any,of the three insert error rods).

o A withdraw error has been produced by the operator during control rod motion.

o One or more rod withdrawal errors are determined to exist upon system initialization, system unbypass or power reduction below the LPSP.

Revision 1: 05/16/88 100-8600004-02 Page 3-10

OYSTER CREEK GENERATING I AmerGen,.

STATION PROCEDURE An Exelon/Bntish Energy Company Number ABN-6

3.

Other Indications I

L-Title Control Rod Drive System Red scram light lit on the full core display for the affected rod.

Revision 0

Control rod position indicates blank with green backlighting on full core display.

One divisional group of scram solenoid lights not lit on Panels 4F and 6R or 7R.

Accumulator LOW PRESS/HI LEVEL alarm on 5W6F.

then PERFORM the following:

I 1

2.

ISOLATE the associated HCU in accordance with Procedure 302.1, Control Rod Drive Hydraulic System.

[

I

3.

MONITOR the following parameters for indications of fuel failure:

Off-gas activity

[

I Reactor coolant activity 1

1 Main steam line radiation

[

I

4.

NOTIFY Reactor Engineering of the abnormal rod motion.

[. I

5.

CONSULT Technical Specifications, Section 3.2

[

I 5.0

Group Heading

.I C O N T R O L R O D S / D R I V E S R O D C N T R L

/I///

H a DRIFT CAUSES:

SETPOINTS:

Actuation of odd DRIFT CAUSES:

ACTUATING DEVICES:

AR2-1, AR2-2, AR2-3, AR2-4 Any of the Control Rods drifting more than 3" through an odd rod position, when the Control Rod is not selected.

I I

I I

SONFIRMATORY ACTIONS:

Subject N S S S Alarm Response Procedures

heck Control Rod position indication on Panel 4F.

Procedure No.

Page 1 of 1 2000-RAP-3024.01 H a Revision No: 131 GE 148F481, GU 3E-611-17-01Q rUTOMATlC ACTIONS:

IONE IANUAL CORRECTIVE ACTIONS:

more than one Control Rod is moving in or out abnormally, scram the reactor in accordance with 2000-ABN-3200.01, Reactor Scram. if single rod unintended motion is indicated (insert or withdrawal), perform the actions defined in 2000-ABN-3200.06, Abnormal Control Rod Motion, as appropriate.

(Pane 1H/ 6 )

t 1'

Question 47,

Regarding the IRM/APRM circuitry and indications, the following sources of power exist:

+24 VDC, which powers the detector circuitry. This power is via batteries.

0 CIP-3, which provides recorder power on Panel 4F.

0 RPS bus 1 and 2, which powers kip circuitry and RPS trip units associated with the respective drawers.

For t-24 VDC, this power is provided by batteries, which will NOT be affected by the stated transient.

For CIP-3, its normal pqwer source is via the rotary inverter powered from VMCC 1 B2.

On a loss of VMCC 1 B2 (from the LOOP), the rotary'inverter will automatically swap to I

the DC motor, powered from DC Distribution Center B, with no loss of AC output voltage from the rotary inverter, and no loss of power to CIP-3.

For RPS buses 1 and 2, the RPS MG set flywheels maintain power long enough for the EDGs to start and re-power 1 C and 1 D buses. The basis for this is presented below.

In a memo dated January 11, 1996 regarding loss of RPS power during LOOP, the RPS engineer provided the following informatiqn. (Copy of memo is enclosed) 0 Upon a loss of offsite power with a succdssful anticipatory scram, the RPS MG set output breaker and Electrical Protection Assemblies will trip on under-frequency or under-voltage in approximately 15 seconds.

Upon a loss of offsite power with no anticipatory scram, the RPS MG set output breaker and EPAs will trip on under-frequency or under-voltage in approximately 4 seconds.

0 The difference in the response of the RPS MG set output upon a loss of supply voltage described above depends on whether the anticipatory scram signal (turbine trip on LOOP) is received or not. This is the result of the difference in RPS load pre-scram versus post-scram. After a scram, the RPS load is greatly reduced due to the de-energization of the scram pilot solenoid valves, the scram contactors, and the condenser low vacuum or turbine trip control relays.

Since no power is lost to the IRM and APRM circuits, Panels 4F, 3R, and 5R throughout the transient.

indications will be available at During the initial license class simulator training, the students were exposed to numerous losses of offsite power scenarios. During all scenarios where the EDGs were available, RPS power was NOT lost because the EDGs re-power the 1 C and 1 D buses within approximately 10 seconds from the loss of power signal. Since the RPS MG sets are designed to maintain voltage and frequency for approximately 15 seconds, this results in NO loss of RPS power during the transient.

Based upon this information, answers b and d are correct.

References:

RAP 9XF-5-c, CIP-3 INV AC INP LOST GPUN Memo 2252-96-001, dated Januaw 1 1, I996

I QUESTION #47 1'

u Given the following conditions:

e Immediately following a loss of all offsite power you are the reactor operator and observe Ten seconds later b d h emergency buses are energized from Diesel Generators (EDGs).

one control rod at position 48 with the remaining control rods at 00.

I Which of the following describes the affect on IRM/APRM indications?

A.

Lose IRM/APRM indications due to loss of.PSP-1&2.

I B.

C.

Maintain IRM/APRM indications due to DC power supply available.

Lose IRM/APRM indication due to loss of vital'buses and RPS MG set voltage.

D.

Maintain IRM/APRM indications due to re-powered busses and RPS MG set flywheels.

Answer: 6

0.

EXPLANATION: DC will maintain power via an inverter. AII remining power sources will (at least momentarily) lose power or do not power up the 'IRM/APRM indicators.

I TECHNICAL REFERENCE(S):

Neutron Monitorincl Lesson Plan (Attach if not previously provided) u I

Proposed references to be provided to applicants during examination:

Learning Objective:

(As available)

Examination Outline Cross-reference:

Level Tier #

Group #

KIA ##

RO SRO 2 -

1 21 5005/K6.01 Importance Rating 3.7 K/A Topic

Description:

Knowledge of the effect that a loss or malfunction of the RPS will have on the APRM/LPRM Question Source:

Bank #

Modified Bank #

New X

(Note changes or attached parent)

Question Cognitive Level:

I O CFR Part 55 Content:

55.41 X

Comments: Information on recorder power obtained from OC training.

Memory or Fundamental Knowledge Comprehensive or Analysis X

55.43

Group Heading V I T A L P O W. E R A C X F E R S 9 X F c C I P - 3 I N V A C I N P L O S T

ub j ect Procedure No.

E L E C T R I C A L 2000-RAP-3024

.02 Page 1 of 1 9 X F c Alarm Response Procedures Revision No: 81

)C drive motor for continuous mstrument panel supply generator unning. This indicates loss of power br trip of the AC power.

ONFIRMATORY ACTIONS:

SETPOINTS:

DC Drive motor running ACTUATING DEVICES:

2MS Reference Drawings:

BR 3013,, Sh. 1 GE 3300C15A3164 GU 33-611-17-022 C Drive light is ON" at CIP-3 Rotary Inverter Control Panel.

UTOMATIC ACTIONS:

nverter switches to DC drive.

ice in DC-RUN, the rotary Inverter will transfer back to AC DRIVE, after a 2 inute time delay, when the start selector switch is placed in the AUTO RUN

>sit ion.

W A L CORRECTIVE ACTIONS :

xrect cause as necessary and return AC motor to service.

2ference Procedure 339, "Vital Power System1'.

I I

I I

I O

I Nucl e ar

~ o s i of RPS Power During LOOP J. P. Munley RPS Engineer Memorandum Date:

January 11, 1996 Location:

Oyster Creek 225 2-96-00 1

J. Vaccaro Instructor Nuclear IV Per our discussions, the following provides a description of RPS MG Set flywheel design and operation and will serve as input in modeling the Simulator for a loss of offsite power, The RPS Motor Generator Set flywheel is designed t o mitigate a 2 second supply voltage interruption with a drop of output voltage and frequency of less than 5% and recovery to steady state regulation after restoration of rated supply voltage within 2 seconds.

Experience has shown that the output voltage and frequency drop following a loss of MG Set supply power is load dependant. For higher loads, the output voltage and frequency degrade more quickly than for lower loads, when the output voltage and frequency degrade more slowly.

I The RPS will, therefore, trip at different times upon a loss of supply power depending upon the load on the MG Set.

7.

I Upon a loss of offsite power with a successful anticipatory scram, the RPS MG Set output breaker and Electrical Protection Assemblies will trip on under-frequency or under-voltage in approximately 1 5 seconds.

2.

Upon a loss of offsite power with no anticipatory scram, the RPS MG Set output breaker and electrical protection assemblies will trip on under-frequency or under-voltage in approximately 4 seconds.

The difference in the response of the RPS MG Set output upon a loss of supply voltage described above depends on whether the anticipatory scram signal is received or not. This is the result of the difference in RPS load pre-scram versus post-scram. After a scram, the RPS load is greatly reduced due to the de-energization of the scram pilot solenoid valves, the scram contactors, and the Condenser Low Vacuum or Turbine Trip control relays.

This description provides the necessary details of RPS MG Set output design and operation during a loss of offsite power t o allow approximate modeling of the OC Simulator. Please contact me with any further questions or comments.

Extension 4252

/bl cc:

C. Desai, System Engineer P. Cervenka, Plant Engineering Supervisor

Question 71 The turbine bypass valves do NOT pass approximately 10% steam flow. Each bypass valve passes approximately 5% steam flow, while the FLOW MISMATCH alarm is set at 7%. Based upon this, there are two possible answers tothis question, based upon two failure mechanisms which affect the bypass valves.

The first failure mechanism deals with a failure of the Bypass relay in the turbine front standard, calling for turbine bypass valves to open. The Bypass relay in the Front Standard translates relay (servo) motion into a mechanical motion which exits the Front Standard, goes through the floor to the Heater Bay and across the Heater Bay ceiling to the individual bypass valves contained in two valve blocks. The mechanical motion at the bypass valve blocks is transmitted to each of the nine bypass valves through a cam and cam follower arrangement. As the cam rotates, the lobe on the first bypass valve will progressively open #1 bypass valve throughout its range of travel from full shut to full open. When the first bypass valve reaches approximately 70% open, the cam for the second bypass valve will progressively open #2 bypass valve. When the second bypass valve is approximately 70% open, the cam for the third bypass valve will progressively open #3 bypass valve. Since all nine bypass valves are controlled by this cam arrangement, each successive bypass valve will start to open before the previous valve is fully open. In the case of the Bypass relay fault, a second bypass valve will be partially open when the first bypass valve is fully open. This steam flow will more than likely exceed 7%, resulting in the Flow Mismatch alarm. Additionally, the flow being diverted from the HP turbine through the now-open bypass valves will cause turbine third stage extraction pressure to drop. Since the RPS system uses third stage extraction pressure to bypass the anticipatory scrams, any reduction below the equivalent 40% pressure will cause the anticipatory scrams to in fact be bypassed, even though actual reactor power can be above 40%. In this case, answer d is a correct answer.

-VI The second failure mechanism that can affect turbine bypass valves is a failure of an individual bypass valve. Each of the nine bypass valve mechanisms at the two bypass valve blocks in the heater bay have a fast-acting accumulator to ensure the bypass valve will respond quickly when needed. These accumulators are 12 inches in diameter and use turbine operating oil pressure (at approximately 250 psig) as their hydraulic motive force. If an individual bypass valve accumulator were to fail in the open direction, ONLY that bypass valve will be affected. Therefore, it will result in an approximate 5%

steam flow diversion from the main turbine through the open bypass valve. This 5%

steam flow will NOT be sufficient to activate the Flow Mismatch alarm. In this case, if the alarm were to come in, it can only be caused by additional steam flow to reach the 7% alarm setpoint, and it can be deduced there is a steam leak somewhere in the Turbine Building. Therefore, answer a is correct for this failure mechanism.

Based upon the given information and these possible failure mechanisms, answers a and d are correct.

I

References:

RAP J-7-a, FLOW MISMATCH GE 233R309, Turbine Controls OCNGS UFSAR, Section 10.2.1, Turbine Generator, pg. 10.2-1 e

I QUESTION #71 u

The following plant conditions exist:

0 The reactor power has just been increased to 40% power Turbine-Generator is on the line at approximately 200. MWE A malfunction causes a bypass valve to fully open FLOW MISMATCH alarm (J-7-a) annunciates shokly after the bypass valve (BPV) opens 0

0 Answer the following:

a) Is FLOW MISMATCH an,expected alarm for the stated conditions?

b) What is the operational significance of this alarm at 40% power?

A.

NO this is NOT expected. The significance is that a steam line break has occurred in the I

Turbine Building.

B.

NO this is NOT expected. The significance is that extraction steam has isolated from feedwater heaters.

C.

Yes this is expected. The significance is that extraction steam has isolated from feedwater heaters.

D.

Yes this is expected. The significance is that Turbine Anticipatory Scrams have been bypassed.

t 6

I ANSWER:

D v

EXPLANATION :

This is an expected alarm since BPVs will pass approximately 10% steam flow. The alarm is set at 7%. The steam going through the BPVs bypass first stage turbine and will not be counted as power for the 40% trip setpoint. With no other alarms in it should not be assumed that there may be a steam line break. Although the BPVs will have some impact on extraction steam flow it is not the reason the alarm is actuated.

TECHNICAL REFERENCE( S) :

Alarm ResDonse J-7-a FLOW MISMATCH (Attach if not previously provided)

Proposed references to be provided to applicants during examination: None Learning Objective:

(As available)

Examination Outline Cross-reference:

Level RO SRO 2

Tier #

Group #

2 -

WA #

239001/A1.09 Importance Rating 3.5 L,

KIA Topic

Description:

Ability to predict and/or monitor changes in parameters associated with the Main and Reheat Steam System controls including the Main Steam Flow.

Quest ion Cognitive Level:

10 CFR Part 55 Content:

55.41 X

Comments: Licensee should confirm the stated conditions would prompt an RO to 'initiate a shutdown without specific direction from the Shift Manager.

Memory or Fundamental Knowledge Comprehensive or Analysis X

L 55.43

I Grow Headina M A I N S T E A M Greater than 7% difference in the total main steam flow and the sum of steam flow through the turbine 1 st stage and, extraction steam flow to the 2nd stage reheater.

I 30NFlRMATORY ACTIONS:

J-7-23 SETPOINTS: ',

7% with 10 second time delay ACTUATING DEVICES:

DRFCS Software DO-5505 Tag: STM-LEAK-ALM DO#8 Reference Drawings:

GU 3E-625-41-001, Sht. 3 GU 3E-611-17-011 I.

?.

Check turbine bypass valve status.

Check Condenser Bay and Trunnion Room radiation level and temperatures for indications of a possible steam line break.

I UJTOMATIC ACTIONS:

Jone AAN UAL COR R ECTlVE ACT1 ONS:

' the Plant is operated with Bypass valves open and the Main Turbine is on-line, then inappropriate ypassing of the Turbine Anticipatory Scrams may occur.

a steam line break is confirmed,

'HEN scram the reactor in accordance with 2000-ABN-3200.01, Reactor Scram.

his alarm indicates that a parameter has exceeded or has the potential to exceed an Emergency ction Level (EAL). Enter Procedure EPIP-OC-.O1, Classification of Emergency Conditions. EAL - RCS Itegrity.

ubject I Procedure No.

I I

B O P I

Page Of 1

2000-RAP-3024.03 J - 7. - a Alarm Response Procedures Revision No: 121 Panel J

Oyster Creek Nuclear Generating Station FSAR Update TURBINE GENERATOR 10.2.1 Design Bases The Turbine Generator has been designed to produce electrical power from the steam generated in the reactor, and to discharge exhaust steam into the condenser.

The turbine nameplate rating is 640,700 kW, 1800 rpm, 15 stage, tandem compound, six flow, two stage (513°F) reheat steam turbine with 38 inch last stage buckets, designed for steam conditions of 950 psig saturated with 0.28 percent moisture, 1 inch mercury absolute exhaust pressure and 0 percent makeup while extracting for three stages of feedwater heating. The six flow design and speed of 1800 rpm were dictated by the pressure and temperature of the steam available from the reactor.

The generator is a direct driven, 60 cycle, 24,000 volt, 1800 rpm conductor cooled, synchronous generator rated at 687,500 kVA at 0.8 power factor, 45 psi hydrogen pressure and 0.58 Short Circuit Ratio (SCR). The turbine includes one double flow (high pressure) and three double flow (low pressure) elements. Exhaust steam from the high pressure element' passes through moisture separators and reheaters before entering the three low pressure units. The separators are designed to reduce the moisture content of the steam to less than 1 percent by weight.

L-.

The turbine controls include speed governor, overspeed governor, steam control valves, main stop and bypass valves, combined intercept and reheat stop valves, and two initial pressure regulators: one electro hydraulic and the other mechanical.

The ability of the plant to follow system load is accomplished by adjusting the reactor power level, either by regulating the reactor recirculation flow or by moving the control rods. The turbine speed governor can override the initial pressure regulation, and close the steam admission valves when an increase in system frequency or a loss of generator load causes the speed of the turbine to increase. In the event that the reactor is delivering more steam than the admission valves will pass, the excess steam is bypassed directly to the Main Condenser by automatic pressure controlled bypass valves. Other standard protective devices are included.

during startup to control reactor pressure until the turbine can use all of the reactor steam. The system also limits transient pressure changes and resultant reactor flux 10.2-1 Update 10 04/97

t L/

L 1

Question SRO 3 In the Containment Pressure leg of Primary Containment Control, if primary containment isolation is NOT required (Le., pressure is less than13 psig), direction is given to vent the containment in order to maintain containment pressure below 3 psig.

There is absolutely NO direction implicit or explicit to secure the venting if it will result in dropping below the CSIL.

8 Answers c and Id CANNOT be correct, as it states venting is NOT allowed. This would be in direct conflict with the directions to vent the containment and maintain pressure below 3 psig.

Answers aland b are both correct.

In answer a, directions to vent the containment per the steps in the Pressure Control leg &I take precedence over any directions to spray in the Drywell Temperature leg. By procedure, we are required to vent the containment to keep it less than 3 psig.

In answer b, venting the containment &I result in a reduction of temperature. This is a classic Ideal Gas Law concept. Since the containment volume is constant, any reduction in pressure will result in a corresponding reduction in. temperature. This is expressed below.

a I

This concept is part of the Generic Fundamentals course the candidates went through While the drywell temperature reduction may not be significant, it will occur.

Additionally, the class has been taught that a total loss of drywell cooling will take approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> for drywell temperature to reach 281 OF. This is based upon engineering calculations performed in the 1 980s that confirms this. The annunciator response for drywell temperature above 150 OF and not able to be reduced, is to perform a normal reactor shutdown. The reactor can be shutdown and cooled down to a cold shutdown condition within this time frame. Therefore, spraying the containment for a total loss of drywell cooling is not needed, nor desired.

While the basis for answer a is directly related to the EOPs, the basis for answer b is a fundamental concept, which is reinforced during all phases of training. The question did NOT distinguish between a procedurally driven concept or a fundamental concept.

Therefore, answers a and b are correct.

References:

EMG-3200.02, Primary Containment Control EOP Users Guide, pp. 2-28 and 2-29 BW R Generic Fundamentals, Thermodynamics, Chapter 3, Steam DOE Fundamentals Handbook, Thermodynamics, Heat Transfer, and Fluid Flow

QUESTION # SRO-3

\\-/

A loss of all drywell cooling has occurred and you have entered Primary Containment Control, EMG-3200.02 when the drywell temperature entry conditions are exceeded.

The following conditions exist:

0 All attempts to restore drywell cooling have failed.

Drywell pressure is at 2.75 psig and steady.

When you direct the RO to "vent the containment per support procedure 31" the STA NO other entry conditions for Primary Containment Control or RPV control exist at this 0.

notifies you that the drywell temperature is approaching 200 degrees F.

point.

0 Answer the following:

Are you allowed to vent the containment? Also, provide'a basis for this action.

A.

B.

Yes, reduction of drywell pressure is the most important strategy at this point.

,Yes, venting the drywell will also result in reduction in drywell temperature.

C.

No, venting the drywell will result in exceeding the Containment Spray Initiation Limit.

D.

No, venting the drywell may cause a inadequate NPSH for the Containment Spray Pumps.

b ANSWER:

C EXPLANATION:

With drywell temperature above 200 degrees F any reduction in drywell pressure (below 2.75 psig) will result in exceeding CSIL. Once CSlL is exceeded the plant will, ultimately require EMERGENCY DEPRESSURIZATION since sprays cannot be initiated. The order should be changed to "spray the containment" before CSlL is exceeded. With no other entry conditions present, NPSH should not be a problem for Containment Spray Pumps.

TECHNICAL REFERENCE( S) :

EOPs (Attach if not previously provided)

Proposed references to be provided to applicants during examination: EOPs Learning Objective:

(As available)

Examination Outline Cross-reference:

Level RO SRO I

1 -

Tier #

Group #

WA #

295024lEA2.02 Importance Rating -

4.0 -

WA Topic

Description:

Ability to determine and/or interpret drywell temperature as it applies to High Drywell Pressure, Question Source:

Bank #

L Modified Bank #

New X

(Note changes or attached parent)

Question Cognitive Level:

Memory or Fundamental Knowledge X

t b o Comprehensive or Analysis 55.43 55.43(bM5) I 10 CFR Part 55 Content:

55.41 X

Comments: Applicant must select the appropriate flow path in,Containment Control.

With a LOCA, drywell pressure will increase with temperature, however in the loss of drywell cooling with no LOCA temperature increase will $e greater than pressure increase, hense venting the containmenf is NOT the right thing to do.

EOP USER'S GUIDE PRIMARY CONTAINMENT CONTROL c-I' This question is asked to determine if a Reactor Lo-Lo water level (86 in.) OR high Drywell pressure (3.0 pig) signal is present. If neither signal is present, the operator is permitted to use SBGT or Reactor Building Ventilation to vent the Primary Containment via the 2 in. vent lines as necessary to maintain Drywell pressure below 3 psig. If an isolation signal is present, the operator is directed to abandon containment venting in accordance with Support Procedure -31 and confirm Primary Containment isolations in accordance with Support Procedure - 1.

L' REVISION 4 2 - 2 8

EOP USER'S GUIDE PRIMARY CONTAINMENT CONTROL TO MAINTAIN LOWING PER The initial action taken to control Primary Containment pressure employs the same methods used during normal Plant operations: using 2 in. containment vent lines to SGTS or Reactor Building Ventilation as required to maintain containment pressure below the high Drywell pressure scram setpoint. Thus the Primary Containment Pressure Control leg provides a smooth transition from normal system operating procedures to emergency operating procedures, and assures that normal methods of Primary Containment pressure control are attempted in advance of initiating more complex actions to terminate increasing Primary Containment pressure.

Support Procedure -3 1 provides instructions for venting the Primary Containment via the 2 in. vents to either the SGTS train or the Reactor Building Ventilation system.

The choice of systems is left to LOS discretion. The 2 in. Torus vents are the preferred vent path because they take advantage of the Torus scrubbing which will help remove Drywell airborne radionuclides as they flow down the downcomers and bubble through the Torus water volume before exiting the 2 in. Torus vent line.

If the Torus cannot be vented because of high Torus level or mechanical failure of the 2 in. Torus vent valves, Support Procedure -3 1 provides contingency actions for venting the Drywell through the Drywell 2 in. vent lines.

No direction is given to the operator at this time to override isolation interlocks or to exceed normal offsite release rates. If Primary Containment pressure cannot be controlled below 3.0 psig or if RPV level drops below 86 in., a containment isolation will occur and venting will be terminated. If higher than normal offsite release rates are experienced while venting, the operator should secure the vent path.

It should be noted that use of Support Procedure -31 is only required as necessary to maintain Primary Containment pressure below 3.0 psig. If upon entry to the PRIMARY CONTAINMENT CONTROL procedure, Primary Containment pressures are at their normal values and not increasing, venting per Support Procedure -3 I is not required.

REVISION 4 2 - 29

CHAPTER 3

STEAM P c P

Ti UQUID L

?3 TI TZ TZ Tc Tc T3 y

CRITICAL POINT SATURATED LIQUID LINE SATURATED VAPOR LINE STUDENT TEXT REV 3 02000 General Physics Corporation, Columbia, Maryland All nghts lesewed No pan of this book may be reproduced In any form or by any means, wlthout permission in wntlng from General Physlcs Corporation

I Using the elements atomic weight improves the accuracy of the calculation. However, the added accuracy is insibificant and is not usually required. Hence, the following relationship can be made:

hi2 Mass (grams)

Number of moles =

Equation 3-2 This is true for all substances whether they be solids or fluids (liquids, vapors, or gases).

I Calculate the number of moles of U-238 that are present in a fuel rod containing 3 kg of U-238.

Exantple 3-1 IDEAL GASES Most familiar gases are colorless and odorless, such as the oxygen and nitrogen of the atmosphere, the bubbles of carbon dioxide that rise in a glass of soda pop, and the hydrogen or helium gas that is used to fill balloons. A few gases are colored; for example, nitrogen dioxide is red-brown and iodine vapor is violet.

Anything that we can smell exists in the gaseous state, because our sense of smell reacts only to gases.

The word gas refers to a substance that at ordinary temperatures and pressures is present in the gaseous state only. The word vapor is used for gas that has evaporated from a material that is usually solid or liquid at ordinary temperatures.

Gases have observable physical properties. They fill available space, but can be compressed into a smaller volume by applying pressure. They are affected by temperature, can expand and contract, or exert different pressures.

It is obvious from the force of the wind on a stormy day that gases can flow readily from place to place and that they have mass.,However, gases are not very dense. An air-filled vessel floats on the surface of a pond because the air is less dense than the water.

Because of their interrelated effects, temperature, pressure, and volume must be specified when discussing gases. The quantitative relationships among the temperature, pressure, and volume of a gas are expressed in the gas laws, which were first explored in the eighteenth and nineteenth Fenturies. Any gas that perfectly obeys the gas laws is called an ideal gas.

The properties of an ideal gas are constant throughout its mass.

Chemical reactions, external forces, or molecular forces do not effect ideal gas molecules.

The Ideal Gas Law is useful because at low pressures, all real gases behave like an ideal gas.

Monatomic gas behavior is similar to perfect gases. It can be described very accurately using the Ideal Gas Law, such as helium (He) and argon (Ar).

Accuracy will decrease with diatomic and polyatomic gases, such as oxygen

( 0 2 ) and carbon dioxide (CO2).

Also, as gas pressure increases, the accuracy decreases.

Experimentally derived corrections allow the Ideal Gas Law to be applied to the behavior of these gases with desired accuracy.

BWR /THERMODYNAMICS / CHAPTER 3 2 of 38 0

2000 GENERAL PHYSICS CORPORATION

/ STEAM REV 3

CHARLES LAW Figure 3-1 shows a piston and cylinder assembly filled with a gas at absolute temperature (TI) and volume (VI). The piston is free to move against a constant external pressure (PI). A burner is provided to allow heat to be added to the gas.

e MOVABLE 9 PISTON Vi, T i, Pi V2, T2, P2 Figure 3-1 Charles Law Adding heat causes the temperature of the gas to increase. As the gas temperature increases, the volume increases and applies pressure against the piston causing the piston to move outward.

Once the pressure on the internal piston face equalizes to the external pressure (PI), the piston stops moving.

The system is again in equilibrium.

The initial pressure (PI) is the same, but the absolute temperature (T2) is higher and the volume (V,) is greater.

Repeating the process of adding heat, causing the piston to move outward, and remeasuring the process variables of gas volume and temperature leads to the following conclusion:

At low pressures, the volume of a gas at constant pressure is directly proportional to the absolute temperature of the gas.

This statement is Charles Law, written mathematically as:

l=2-v v

v

= k (constant)

-4 T2 T

At a constant pressure (P)

Equation 3-3 Equation 3-3 is valid only for absolute temperature measurements of low-pressure gases; the constant (k) is different for each gas.

BOYLES LAW The piston and cylinder assembly is reconfigured by removing the burner. The cylinder is filled with a gas at volume (VI), temperature (TI), and at an absolute pressure (PI). Heat will not be added to the gas through the cylinder, so the temperature of the gas will remain constant.

MOVABLE PISTON V2, T2, P2 Figure 3-2 Boyle 3 Law The piston is physically moved to a new position, creating a new volume ( V 2 ) and absolute pressure (P2).

After V2 and P2 are measured, the procedure is repeated, recording the data. Examining the measured variables, the following conclusion about the gas may be derived:

At low pressures, the volume of a gas at constant temperature is inversely proportional to the absolute pressure of the gas.

BWR /THERMODYNAMICS / CHAPTER 3 3 of 38 0

2000 GENERAL PHYSICS CORPORATION I STEAM REV 3

t This statement is Boyles

Law, Written mathematically as:

k v

PIVl = P2V2 = PV = k (constant)

At a constant temperature (T)

Equation 3-4 8

Equation 3-4 is valid only for absolute pressure measurements; the constant (k) is different for each gas.

Since temperature is constant, the units of measure have no effect on the equation.

I COMBINED GAS LAW Charles Law and Boyles Law are valid for ideal gases and real gases in the pressure range where a real gas behaves like an ideal gas. Therefore, any real gas at low pressure will obey these laws and may be combined to derive the following law:

For a given mass of any gas, the product of the absolute pressure and volume occupied by the gas, divided by its absolute temperature, is a constant.

I,

This statement is the Combined Gas Law, written mathematically as:

Equation 3-5 Example 3-2 A compressor discharges into an air receiver and cycles off when the pressure in the receiver reaches 160 psia. During the

, compression, hGat is added to the air. The temperature in the receiver is 140°F.

Assuming no air loads are in service, at what temperature

( O F )

should the compressor restart to maintain the receiver above 150 psia?

BWR J THERMODYNAMICS / CHAPTER 3 4 of 38 0

2000 GENERAL PHYSICS CORPORATION J STEAM REV 3

c IDEAL GAS LAW By applying the gas laws already presented in this chapter, we can derive the Ideal Gas Law.

Remember, Boyle worked with constant temperature; Charles worked with constant pressure. Their laws will be further expanded to form the Ideal Gas Law.

An ideal gas is defined as one in which PV/T = K (a constant) under all circumstances.

PV/T = K is a specific application of the General Energy Equation. Though no such gas exists, the fact that a real gas behaves approximately like an ideal gas provides a basis for theories for the gaseous state.

Experimenters discovered the constant (K), in terms of the number of moles (n) of gas in a sample, by understanding that the molar volume of a gas at 273K (OOC) and standard pressure

[ 1 atmosphere (atm) or 14.7 psia] is 22.4 liters.

Where:

P

= Pressure (1 atmosphere or 14.7 psia)

V

= Volume (22.4 liters)

T

= Temperature (273 K or OOC)

K

= Constant (in terms of number of moles Substituting and rearranging:

PV

-=nR T

PV R=-

nT (1 atm122.4 L)

(n1273 K)

R =

Where:

, n

= number of moles ofgas (a conversion factor)

R

= universal gas constant Empirical data has shown that the value of the universal gas constant (R) is:

atm liters J

R = 0.0821 or 8.314 mole K mole K Equation 3-6 The universal gas constant (R) is an energy equivalent for PV energy. To convert the units of the universal gas constant from atm liters (atm P ) to Joules (0:

(897.1 in lb,) -

= 74.8 Rlb, (1; Yn)

Since:

1 ftlb, = 1.35582 J Then:

(74.8 ft lb,) (;;', J)=101.4 J Thus:

latmP=101.4J Equation 3-7 BWR /THERMODYNAMICS / CHAPTER 3 5 of 38 0

2000 GENERAL PHYSICS CORPORATION

/ STEAM REV 3

I DOE-HDBK~1012/1-92 JUNE 1992 I

DOE FUNDAMENTALS HANDBOOK THERMODYNAMICS, HEAT TRANSFER, AND 'FLUID FLOW Volume I of 3 U.S. Department of Energy Washington, D.C. 20585 FSC-6910 Distribution Statement A. Approved for public release; distribution is unlimited.

Th er-m odvn am ics CUMP R ESSION PROCESSES

~~

COMPRESSION PROCESSES Compression and pressurization processes are very common in many types of industrial plants. These processes vary from being the primary ftlnction of a piece of equipment, such as an air compressor, to an incidental restilt of another process, such as filling a tank with water without first opening the valve.

EO 1.32 Apply the ideal gas laws to SOLVE for the unknown pressure, temperature, or volume.

EO 1.33 DESCRIBE when a fluid may be, considered to be incompressible.

EO 1.34 CALCULATE the work done in constant pressure and constant volume prqcesses.

EO 1.35 DESCRIBE the effects of pressure changes on confined fluids.

EO 1.36 DESCRIBE the effects of temperature changes on confined fluids.

~~~

~

Bovle's and Charles' Laws The results of certain experiments with gases at relatively low pressure led Robert Boyle to formulate a well-known law. It states that:

the pressure of a gas expanding at constant temperature varies inversely to the volume, or (Pl)(Vl) = (P,)(V,) = (P3)(V3) = constant.

Charles, also as the result of experimentation, concluded that:

the pressure of a gas varies directly with temperature when the volume is held constant, and the volume varies directly with temperature when the pressure is held constant, or (1 -40)

(1-41)

L-Rev. 0 Page 97 HT-O 1

I CO2 H2 0 2 H 2 0 N2 COMPRESSlON PROCESSES Thermodvnamics M

28.95 44.00 2.01 6 28.02 32.0 18.016 Ideal Gas Law By combining the results of Charles' and Boyle's experiments, the relationship

= constant

( 1-42)

Pv T -

may be obtained. The constant in the above equation is called the ideal gas constant and is designated by R; thus' the ideal gas equation becomes Pv A RT (1 -43) where the pressure and temperature are absolute values. The values of the ideal gas constant (R) for several of the more commoh gases are given in Figure 39.

Gas Air Corbon dioxide Hydrogen N it r og en Steam Oxygen rr E

c -

m a

3 1 v) c-i-0 0 c30E

• R 53.35 35.13 766.80 55.16 48.31 85.81

'CP 0.1 72 0.1 60 2.44 0.1 76 0.155 0.36 Steam ot pressures less thon 1 psi0 behoves neorly os o perfect 90s.

C V 0.240 0.205 3.42 0.247 0.21 7 0.46 er Y 2

5 u.s D 0 -

l a, c q 1 w k

1.40 1.28 1.40 1.40 1.40 1.28 Figure 39 Ideal Gas Constant VaIues The individual gas constant (R) may be obtained by dividing the universal gas constant (Ro) by Ro the molecular weight (MW) of the gas, R = -.

The units of R must always be consistent MW with the units of pressure, temperature, and volume used in the gas equation. No real gases follow the ideal gas law or equation completely. At temperatures near a gases boiling point, increases in pressure will cause condensation to take place and drastic decreases in volume. At very high pressures, the intermolecular forces of a gas are significant. However, most gases are in approximate agreement at pressures and temperatures above their boiling point.

HT-01 Page 98 Rev. 0

E Thermodynamics COMPR ESSiQN PROCESSES The ideal gas law is utilized by engineers working with gases because it is simple to use and approximates real gas behavior. Most physical conditions of gases used by man fit the above description. Perhaps the most common use of gas behavior'studied by engineers is that of the compression process using ideal gas approximations. Such a compression process may occur at constant temperature (pV = constant), constant volume, or adiabatic (no heat transfer).

Whatever the process, the amount of work that results from it depends upon the process, as brought out in the discussion on the First Law of Thermodynamics. The compression process using ideal gas considerations results in work performed on the system and is essentially the area under a P-V curve. As can be seen in Figure 40, different amounts of work result from different ideal gas processes such as constant temperature and constant pressure.

I I

I I

I I

e v

d Figure 40 Pressure-Volume Diagram Fluid A fluid is any substance that conforms to the shape of its container. It may be either a liquid or a gas.

Compressibilitv of Fluids Usually a fluid may be considered incompressible when the velocity of the fluid is greater than one-third of the speed of sound for the fluid, or if the fluid is a liquid. The treatment of a fluid that is considered incompressible is easy because the density is assumed to be constant, giving a simple relationship for the state of the substance. The variation of density of the fluid with changes in pressure is the primary factor considered in deciding whether a fluid is incompressible.

'L Rev. 0 Page 99 HT-0 1

I 1

Question SRO 7 Answer d is NOT correct. The C Battery is declared inoperable whenever battery temperature drops below 50 O F. This is determined by battery electrolyte temperature, not battery room temperature.

The question states that 41 60V switchgear room temperature is reading about 40 O F due to an unusually cold night. It does NOT address actual battery temperature.

Furthermore, there*is no information given that would lead one to believe that all equipment in the area has, reached a thermal equilibrium with the room temperature.

However, both a and b are correct statements. Procedural actions to install temporary heating in the room in accordance with CC-MA-103-1001, requires a TCCP Request, if one has not already been written. This direction is given on page 7 of CC-L I

be initiated. Within the TCCP initiation procedure,.the first step is to initiate an Action MA-1 03-1 001.

Both actions would be required to mitigate the room temperature problems and prevent the loss of the C battery.

Therefore, both a and b are correct.

References:

Procedure 340.3, 125 Volt dC Distribution System C, pp. 2.0 and 16.0

-L, CC-MA-103-1001, Implementation of Configuration Changes, pp. 1-8

QUESTION # SRO-7 It is a particularly cold January night. The Turbine Building Operator calls you up to let you know that the 4160 V switchgear room temperature is abnormally cool with a local room thermometer reading only about 40 degrees F.

-1 What immediate action(s) are required?

A.

Initiate a Temporary Configuration Change Package (TCCP) and install a portable heater in the room.

B.

Initiate an Action Request to have install a portable heater in the room.

C.

Conservatively, declare the 41 60 Switchgear Room Fire Suppression System inoperable and assign a continuous Fire Watch in the room.

D.

Determine the reactor must be placed in the COLD SHUTDOWN CONDITION while attempting to resolve any HVAC problems.

ANSWER:

D EXPLANATION:

With a 4160 V room temperature below 50 degrees F the C battery must be declared inoperable. With the C battery inoperable, TS 3.7.B requires The reactor shall be placed in the COLD SHUTDOWN CONDITION.... Although the US may take other actions, the TS requirements must be initiated immediately and take precedence over other actions.

TECHNICAL REFERENCE(S):

i/

DC Distribution Lesson Plan cJacle 4: TS Daaes 3.7-1 and 4.7-1 (Attach if not previously provided)

Proposed references to be provided to applicants during examination: None Learning Objective:

(01 1 10445 (As available)

Exam i nation Outline Cross-reference:

Level RO SRO Tier #

Group #

KIA #

295004/2.1.33 Importance Rating -

4.0 1

1 -

KIA Topic

Description:

Ability to recognize indications of DC system operating parameters which are entry level conditions for Technical Specifications.

Question Source:

Bank #

Modified Bank #

New X

(Note changes or attached parent)

Quest ion Cog n i the Leve I:

10 CFR Part 55 Content:

Comments: The applicant must combine at least three facts to obtain the right answer.

Other equipment may be affected but that is not germane to the question.

Memory or Fundamental Knowledge 55.41 Comprehensive or Analysis X

1 55.43 55.43(b)(2) and (3)

-w

OYSTER CREEK GENERATING 1

STATION PROCEDURE

AmerGen, An ExelonlBntish Energy Company I

Number 340.3 I

Title 125 Volt DC Distribution System C Revision No.

26 0

I PROCEDURE HISTORY 1

OR I G i NATO R T. cdrcoran, M. Heck J. Freeman M. Heck M. Heck VI. Heck I. Lorentzen I. Ruark

4. Heck

SUMMARY

OF CHANGE Add requirement to enter Technical Specification 3.7.A.4 LCO when transferring static chargers.

Added TABLE OF CONTENTS. Added REFERENCES section. Added GL 89-1 0 DC valve requirement steps.

Added NORMAL OPERATION and ATTACHMENT 8

sections. Made administrative changes to bring the procedure in line with the writers standard. Added steps to address the tripping of Reactor Feed Pump A and Cleanup Recirc Pump A. Added steps to declare the C Battery inoperable if temperature limits are exceeded.

Provide alternate guidance on static charger voltage adjustments and delete requirement for elect. mai,nt.

support, Changed to add Tech Spec LCO numbers associated with MOV inoperability. Updated references. Added installation of jumpers when removing C Battery or C Distribution Center from service per CAPS 1998-1 202 and 1998-1 428.

Chahged PM 251010 reference to PM 735010. The rotation of the C Chargers has been moved from PM 251 01 0 to PM 73501 0.

Deleted all steps associated with 41 60V Swgr jumpers.

Revised C Battery Room operating temperatures to agree with Procedure 328.1. Added step for declaring C Battery inoperable below 124.2 VDC.

Procedure Upgrade Project - format changes only.

4djust charger voltage to equalize charger voltage with 3us voltage prior to closing charger output breaker lattery temperature, not room temperature (CAP 02003-1046).

4dded clarification on where to read voltage values for several steps.

I 2.0

OYSTER CREEK GENERATING STATION PROCEDURE AmerGem An ExelonlB~itish Energy Company Number 340.3 9.2.5 9.2.6 9.2.7 9.2.8 9.2.9 9.2.1 0 I

ritle

.U' 125 Volt DC Distribution System C 9.2.4 Battery capacity diminishes below 77°F. 'However, capacity at 2 50°F is acceptable due to available reserve. If any C Battery cell temperature drops below 50°F, C Battery shall be considered inoperable.

Accelerated loss of battery life occurs above 104°F. Battery damage may occur at 120°F. If Battery Room temperature increases to 120°F for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, C Battery shall be considered inoperable.

Revision No.

26 Do not place the static chargers C1 and C2 in parallel operation on Distribution Center C.

The battery is E t to be disconnected from the C Distribution Center while the plant is > 212°F or operating at power.

Alarms for the 125 VDC System for C Battery are as follows:

1.

Degraded Voltage Set Point 130.8 2 0.2 Volts via BUS C I

UV (9XF-2-d)

2.

Low Voltage Set Point 11 5 V TROUBLE (U-4-f) or BAT CHG C2 TROUBLE (U-5-f) 1 Volts via BAT CHG C1 In order to maintain the seismic qualifications of the following switchgear/motor control centers, any breakers required to be racked out, shall be removed from their switchgear/motor control center cubicle and stored properly. During an outage, if the switchgear/motor control center is @ required to be available, this precaution does not apply. Switchgear affected are 4160V 1C and 1 D, Motor Control Centers 1A21, 1A21A, IAZIB, 1A23, 1A24, 1821, 1B21A, IBZIB, 1B23, 1B24.

DC-1, DC-2, and Vital Motor Control Centers 1 A2, 182, and 1AB2.

With the DC Distribution Center C inoperable per Technical Specification 3.7.A.4, the following Technical Specifications also apply for the following reasons:

0 3.8.C, because V-14-35, Emergency Condenser NE01 B Condensate Return Valve, is inoperable.

0 3.8.E, because V-14-33, Steam Inlet Valve to 'B' Emergency Condenser, is inoperable.

16.0

t

.d Exeb nSM Nuclear CC-MA-I 03-1 001.

Revision 4 Page 1 of 117 IMPLEMENTATION OF CONFIGURATION CHANGES SECTION PAGE NUMBER 1. 0 PURPOSE.............................................................................................................................

4 2.0 ENGINEERING EVALS........................................................................................................

4 3.0 DETEREMINATION OF CONFIGURATION CHANGE TYPE.........................................

4 3.1APPLICATION OF SUB-PROCESS NOT COVERED BY CC-AA-103.....................

5 3.2APPLICATlON OF SUB-PROCESS COVERED BY CC-AA-103..................................

6 4.0CONFlGURATlON CHANGE PACKAGE...............................................................

7 4.1 PREPARATION OF CONFIGURATION CHANGE PACKAGE..............................

7 4.1.1 PACKAGE CREATION............. 1.................................................................

7 4.1.2 DESIGN CONSIDERATIONS AND IMPACTS...........................................

I O 4.1 2.1 PROBLEM bEFINITION........:.....................................................

10 4.1.2.2 SCOPE....................................................................................

10 4.1.3 SAFEGUARDS INFORMATION.............................................................

11 4.1.4 DESIGN CLASSIFICATION..................................................................

11 4.1.5 DISCUSSIONS WITH DESIGN ENGINEERING MANAGER........................

11 4.1.5.1 ENGINEERING CONTENT AND ACTIVITIES..................................

12 4.1.5.2 ENGINEERING REVIEWS...........................................................

12 4.1.5.3 WALKDOWN CONSIDERATIONS.................................................

12 4.1.5.4 CONFIGURATION CHANGE SCOPE MEETING..............................

13 4.1.5.5 OPERATIONS BRIEFING............................................................

13 I

4.2 PREPARATION OF DCP FOR REVIEW.......................................................

13 4.2.1 DESIGN TEAM....................................................................................

13 4.2.2 WALKDOWN......................................................................................

15 4.2.3 PREPARE / UPDATE / PERFORM ENGINEERING DELIVERABLES.......... 15 4.2.3.1 DESIGN ATTRIBUTES.................................................................

15 4.2.3.2 ANALYSES, CALCULATIONS, COMPUTATIONS. AND ENGINEERING EVALUATIONS....................................................

15 4.2.3.3 COMPONENT RECORD LIST......................................................

15 4.2.3.4 ITEMS TO BE COMPLETED AFTER CONFIGURATION CHANGE PACKAGECLOSURE.................................................................

18 4.2.4 ADVANCE WORK AUTHORIZATION......................................................

18 4.2.5 PREPARE MATERIALS LIST.................................................................

19 4.2.6 TESTING CRITERIA AND REQUIREMENTS............................................

22 4.2.7 CONFIGURATION SCOPE MEETING.....................................................

22

CC-MA-I 03-1 001 Revision 4 Page 2 of 117 4.2.8 NEW/ REVISED DOCUMENTS. DRAWINGS. AND SKETCHES.................. 22 4.2.10 AFFECTED DOCUMENTS LIST............................................................. 23 4.2.11 INTERACTION WITH PENDING CHANGES............................................

24 4.2.12 ASME CODE ANI I ANI1 APPLICABILITY..............................................

25 4.2.13 CHECKLIST OF CONFIGURATION ACTIVITIES....................................

25 4.2.14 EQUIPMENT DATA...........................................................................

25 4.2.15 IDENTIFY AFFECTED PROGRAMS.......................................................

25 4.2.16 IDENTIFY AFFECTED PROCEDURES...................................................

25 4.2.17 IDENTIFY TRAINING CHANGES...........................................................

25 4.2.18 SPECIAL INSTRUCTIONS...................................................................

25 4.2.19 TRACKING OF AFFECTED CONFIGURATION AND PROGRAM CHANGES 26 4.2.20 10CFR50.59 REVIEWS.......................................................................

26 4.2.21 ASSEMBLE THE CONFIGURATION PACKAGE.......................................

27 4.2.21.1 DOCUMENTATION OF INTERDISCIPLINARY INPUT.......................

27 4.2.21.2 ADMINISTRATIVE TASKS.........................................................

27 4.2.21.3 CONFIGURATION CHANGE PACKAGE ATTACHMENTS............... 29 4.2.21.4 DOCUMENTATION OF INSTALLER AND USER WALKDOWNS......... 30 I 4.2.22 REVIEW OF PACKAGE BY AFFECTED DEPARTMENTS..........................

30 4.2.9 SINGLE POINT VULNERABILITY AND LATENT FAILURE REVIEWS 23 I 4.3 CONFIGURATION CHANGE PACKAGE ISSUANCE......................................

31 4.3.1 SIGN CONFIGURATION CHANGE PACKAGE..........................................

31 4.3.2 DESIGN REVIEW................................................................................

31 PERFORMING A DESIGN VERIFICATION......................................

31 4.3.2.1.I ADDITIONAL DESIGN VERIFICATION METHODS.......................

33 413.2.1.2 EXPECTATIONS OF THE VERIFIER.......................................

34 4.3.2.2 DOCUMENTATION OF DESIGN VERIFICATION...........................

35 4.3.3 ENGINEERING CONTRACT DESIGN ENGINEER.....................................

35 4.3.4 CONFIGURATION CHANGE PACKAGE REVIEW AND APPROVAL............. 35 4.3.5 EQAB REVIEW...................................................................................

36 4.3.6 RESOLUTION OF EQAB FINDINGS.......................................................

38 4.3.8 PORC / PRG REVIEW.........................................................................

38 4.3.9 PLANT MANAGER APPROVAL.............................................................

38 4.3.10 REGULATORY ASSURANCE APPROVAL..............................................

38 4.3.11 CONFIGURATION CHANGE PACKAGE APPROVAL................................

39 V

I 4.3.2.1 4.3.7 SITE ENGINEERING DIRECTOR APPROVAL 38 I 4.4 CONFIGURATION CHANGE INSTALLATION...............................................

39 4.4.1 PLANNING CONFIGURATION CHANGE PACKAGE IMPLEMENTATION.... 39 4.4.2 CONFIGURATION CHANGE IMPLEMENTATION.....................................

40 4.5 TESTING...............................................................................................

40 4.6 OPERATIONS ACCEPTANCE...................................................................

40 4.7 COMPLETION OF CONFIGURATION CHANGE ACTIVITIES...........................

41

\\/

CC-MA-103-1001.

Revision 4 Page3of117 4.8 CONFIGURATION CHANGE PACKAGE RnEVISION AND CANCELLATION 42 4.8.1 CONFIGURATION CHANGE PACKAG'E REVISION..................................

42 I

'c 4.8.2 CANCELLED CONFIGURATION CHANGE PACKAGES............................

42 5 PIMS PROCESSING OF ECR'S..........................................................................

43 5.1 CREATING AN ECR...........................................................................

43 5.2 CREATING AN.. ECR REVISION............................................................

44 ATTACHMENT 1 ATTACHMENT 2 ATTACHMENT 3 ATTACHMENT 4 ATTACHMENT 5 ATTACHMENT 6 ATTACHMENT 7 ATTACHMENT 8 ATACHMENT 9 ATTACHMENT I O ATTACHMENT 11 ATTACHMENT 12 ATTACHMENT 13 I

i/

PROPER USE OF PlMS EVALS....................................................

45 SETPOINT CHANGES...................................................................

47 COMMERCIAL CHANGE SCREENING CRITERIA............................

49 EQUIVALENT CHANGE SCREENING CRITERIA.................................

54 DESIGN MARGIN..................................................................................

55 CHANGES ANALYSIS...........................................................................

67 MODELS / BOUNDARY CONDITIONS....................................................

75 OPERATING EXPERIENCE..................................................................

94 CRITICAL CHARACTERISTICS.........................................................

97 SPECIAL INSTALLATION INSTRUCTIONS..........................................

104 SUPPLEMENTAL DESIGN REVIEW QUESTIONS...............................

107 SECONDARY INFORMATION.....................................................

110 RISK AND BARRIER REVIEW.....................................................

114 I

CC-MA-103-1001 Revision 4 Page 4 of 117 1.0 PURPOSE

J I

The purpose of this manual is to provide management expectations, suggested methods, and commonly accepted engineering and business practices foi accurately and efficiently performing configuration changes. This manual is designed to complement the requirements contained in CC-AA-I 03, Configuration Change Control, and CC-AA-104, Document Change Requests. Where the requirements of CC-AA-103 and CC-AA-104 are self-explanatory, no additional guidance is provided in this manual.

NOTE: In general, this manual is organized to provide guidance based on the steps of the Design Change sub-process, as specified in CC-AA-103. It is understood that not all of the steps in the Design Change sub-process apply to the other sub-processes (e.g., the Commercial Change process or the Document Change Request process).

2.0 ENGINEERING EVALUATIONS Requests to Engineering may not always require a configuration change as described in this manual.,Technical evaluations or consulting may be provided outside of the configuration change process. Examples of this are:

0 Technical evaluations dispositioned in accordance with CC-AA-309-101.

Other requests for engineering support made via a,PIMS A/R Evaluation c-Attachment 1 of this manual provides additional guidance for proper use of PlMS Evaluations.

I 3.0 DETERMINATION OF APPLICABLE CONFIGURATION CHANGE TYPE (CC-AA-103 Step 4.2) (CC-AA-104, Step 4.2)

CC-AA-103 contains direction for performing Commercial Changes, Equivalent Changes, and Design Changes.

CC-AA-I 04 contains direction for processing Administrative Change Document Change Requests (DCRs), Commercial Change DCRs, Equivalent Change DCRs, and Design Change DCRs.

If field work is required, then use CC-AA-103. If no field work is required, then use CC-AA-104.

In addition, there are types of configuration changes, such as the Pre-Engineered Change, that are not governed by either CC-AA-103 or CC-AA-104. The information provided in CC-AA-103 and its associated attachments direct the user to the sub-process and associated procedure or procedure section that is appropriate for the configuration change.

Nonconformances are processed per process description CC-AA-I 1. A nonconformance is entered into the corrective action process per LS-AA-125 and an operability evaluation is made using LS-AA-105. The operability evaluation includes identification of corrective actions and the time frame for completing the corrective actions. If a configuration change is required as L

0 CC-MA-I 03-1 001 Revision 4 Page 5 of 117 t

\\-

one of the corrective actions, the change is made per; the established configuration change procedures. A nonconformance does not impose any unique considerations related to development of the configuration change package. Since a repair disposition requires field work, use CC-AA-103 for the permanent disposition and use CC-AA-112 for an interim (temporary) disposition. Since a use-as-is disposition does not require field work, use CC-AA-104.

For information related to the applicability of setpoint changes to the configuration change process, refer to Attachment.2.of this manual.

3.1 APPLICABILITY OF CONFIGURATION CHANGE SUB-PROCESSES (not covered by CC-AA-1031 (CC-AA-103, Step 4.2.1)

DOCUMENT CHANGE REQUEST (refer to CC-AA-104)

I A label change is not considered field work since it does not require a clearance, work'order, or testing. Therefore, a label change can be handled as a document change request. Issue a PlMS evaluation to have the label changed in the field.

TEMPORARY CONFIGURATION CHANGE (refer to CC-AA-112)

Temporary configuration changes include what used to be,interim dispositions of nonconforming conditions at Peach Bottom and Limerick.

8 I

DESIGN ANALYSES No additional guidance.

PRE-ENGINEERED CHANGE Pre-Engineered Changes are alternatives to existing physical configurations in the facility that have been previously evaluated by Engineering and determined to meet or exceed installation and functional requirements of the System, Structure, or Component (SSC).

An example of a Pre-Engineered Solution would be the removal of a tubing support that was interfering with maintenance activities. The engineer would authorize support removal provided minimum support requirements were met as documented in an approved specification (e.g., spec NE-007 at PBAPS, SP 9000-44-001 at OC).

Another example of a Pre-Engineered Solution is the use of 125-1 evaluations at Oyster Creek and TMI. These evaluations historically prepared in accordance with OC/TMI Conduct of Engineering Principles provide alternate parts evaluations and resolution of installation issues.

Since the technical evaluation required to support a Pre-Engineered Change is contained in an approved specification or procedure, there is no need to generate a configuration change package (i,e., ECR) prior to performing the field work. Knowledgeable craft can refer to the associated work order for direction. Engineering may be required to provide a technical interpretation of the specification or procedure. Interpretations and clarifications are L-

CC-MA-103-1001 Revision 4 Page6of 117 I

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documented as an Engineering Technical Evaluation (refer to CC-AA-309-101) in an AIR evaluation.

Although a Pre-Engineered Change may provide a bounding technical evaluation, a Document Change Request may be required to assure configuration control. For example, removal of a piping support, while performed in accordance with a Maintenance procedure or specification, may require update of a controlled drawing, processed by a Document Change Request.

Another use of a Document Change Request is to ensure that any required procedure or program updates are performed. If the revised document is required to support plant operation, the Document Change Request needs to be approved prior to installation.

Pre-Engineered Changes are implemented using the appropriate work control process (e.g.,

work orders, NRs).

ITEM EQUIVALENCY CHANGE (refer to SM-AA-300)

An Item Equivalency Change is a hardware change that does not change the performance of the design bases functions of the associated component or system, and does not change the items or its applicable interfaces compliance with the plant licensing #bases. Item equivalency evaluations are performed in accordance with Procurement Engineering procedures through evaluation of form, fit, and function of replacement components or their piece parts. Refer to the applicable governing procedure for additional details.

3.2 APPLICABILITY OF CONFIGURATION CHANGE SUB-PROCESSES (that are covered by CC-AA-103) (CC-AA-103, Steps 4.2.2,4.2.3, and 4.2.4)

COMMERCIAL CHANGE (refer to CC-AA-103, Section 4.3)

A Commercial Change implements a configuration change with fewer controls than a Design Change.

Commercial Changes are developed and implemented using codes, standards, and good engineering practices typically applied during the design of systems, structures, and components outside of nuclear jurisdiction. This includes use of national standards such as fire code, Uniform Building Code, National Electric Code, local and state standards, and other utility design standards.

An example of a Commercial Change would be alterations of the water treatment building lighting configuration (e.g., addition of fixtures).

Since the scope of a commercial change may vary from a simple change, such as the installation of a water fountain in the main control room, to a complex change, such as constructing a new warehouse building outside the protected area, the level of documentation and design team involvement will vary.

EQUIVALENT CHANGE (refer to CC-AA-103, Section 4.4)

No additional guidance.

1 I

I CC-MA-103-1001,

Revision 4 Page 7 of 117 DESIGN CHANGE (refer to CC-AA-103, Section 415)

A Design Change is any other type of configuration change that cannot be processed as a pre-engineered change, a temporary configuration change, a design analysis, an item equivalency, a document change request, a commercial change, or an equivalent change.

An example of a Design Change is the installation of a blank flange downstream of an inoperable Primary Containment Isolation Valve (PCIV). Since the blank flange provides the design bases isolation function differently than the PCIV, this type of configuration change is considered a Design Change.

It is intended that configuration changes with several portions be processed using cafeteria style execution, whereby the depth of documentation and review would be commensurate with the portion of the design change being considered. The following examples illustrate this concept:

I Example 1, adding a water cooler to a safety related block wall. The portions of the configuration change related to changes to the block wall would be treated as a design change, whereas the portions related to the water cooler could be treated as a commercial change.

Example 2, adding non-safety related vibration monitors to, a safety-related system. The portions of the configuration change related to seismic impact on the piping and components would be treated as a design change, whereas the portions related to the function of the vibration monitoring system could be treated as a commercial change.

4 I

ii Example 3, adding a non-safety related indicator to a safety-related control room panel. The portions of the configuration change related to the seismic analysis of the panel and human factors would be treated as a design change, whereas the portions related to the function of the indicator could be treated as a commercial change.

4.0 CONFIGURATION CHANGE PACKAGE 4.1 PREPARATION OF CONFIGURATION CHANGE PACKAGES (CC-AA-103, Step 4.5) 4.1.I.

PACKAGE CREATION (CC-AA-104, Step 4.1.I)

- Use a CM-ECR type A/R for all configuration changes that involve field work.

I

- Use an EC-ECR type A/R for all other configuration changes. This includes engineering work involved with developing pre-engineered changes that will be implemented by other AIRS.

An Engineering Change Request (ECR) needs to be created in PIMS. If not already created by the Responsible Engineers supervisor or the Initiators supervisor, the Responsible

\\.

~

CC-MA-103-1001 Revision 4 Page 8 of 117 Engineer creates the ECR in PIMS. See Section 5.1 of this manual for guidance on creating an ECR. If all affected documents associated with an Administrative Change type of Document Change Request are issued in final form (i.e., no as-building required), it is acceptable to use an EVAL in lieu of an ECR.

The types of ECRs to choose from are as follows:

CONFIGURATION CHANGE ECR TYPE CONTROLLING SUB-PROCESS PROCEDURE Item Equivalency IEC SM-AA-300 Administrative Change ACP CC-AA-1 04 Commercial Change CCP CC-AA-103, CC-AA-I 04 Equivalent Change ECP CC-AA-103, CC-AA-104 Design Change DCP CC-AA-I 03, CC-AA-104 Temporary Change TCP cc-AA-112 Note: Since a nonconformance does not receive any special treatment per the configuration change procedures, the NCR type of ECR is obsolete and is no longer used. If the AIR is a CM NCR type, create a child CM ECR or EC ECR type A/R to allow creating the proper type of ECR.

A configuration change may contain portions that meet the screening criteria for a less rigorous type of change package. In this case, it is acceptable to either use one ECR for the whole change or use multiple ECRs, one for each portion of the change. For example, some portions of a configuration change may be covered under a Design Change, while other portions meet the Commercial Change screening criteria. Either create a DCP type ECR and a CCP type to support the different portions of the configuration change, or create one DCP type ECR that contains limited attributes for the commercial change portion.

L Use additional ECRs as necessary to divide the design work to support design, installation, and testing. Examples include:

0 Unit specific changes to common documents, such as the UFSAR, Technical Specifications, and DBDs.

0 Partial installation, acceptance testing, and as-building.

0 Use by different installing organizations, such as contractors, Maintenance, and NMD.

There is basic information included in a configuration change package to assure that the users of the package understand what is being done and why it is being done. Although the procedure requires several items to be addressed in different contexts at different times, there is no need to repeat the same information in several places in the package. Therefore, a suggested general format for disposition of a configuration change is as follows:

L

4 I

Question SRO 12 The stated initial plant conditions cannot be met at Oyster Creek. With only three recirc pumps in operation, the pump speeds are limited to <33 HZ, which translates into a maximum power of no more than 55%. Therefore, we cannot and would not operate at 80% with three recirc pumps.

Considering the question with the given plant conditions, the stated transient will result in a reactor scram, #either due to a loss of sufficient feedwater flow causing an automatic scram at 138 in., or a manual scram due to expected operator actions of ABN-17.

These expected operator actions require a manual scram if a multiple feed or condensate pump trip occurs. Stated conditions are reactor power initially at 80%

power, with a subsequent loss of bus 1 B. This results in a loss of two condensate and two feedwater pumps.

SJ I

I For multiple feedwater or condensate pump trips, ABN-17 REQUIRES a reactor scram be inserted.

While the first part of suggested answer a is a correct statement (saying the plant would have scrammed from the transient), the second part of the statement is NOT true.

The plant must be cooled down to a cold shutdown condition if the loss of the startup transformer lasts for longer than 7 days by Tech Spec section 3.7 dealing with AC power sources.

Therefore, there is no correct answer for this question, and the question should be deleted.

I sl, I

References:

ABN-17, Feedwater System Abnormal Conditions, section 3.3 pg. 12 Technical Specificat ions, section 3.7

QUESTION # SRO-I 2 At noon on April 1, 2004 the plant is at 80% power with three reactor recirc pumps operating (NGOI-A, C and E). NO LCOs are in effect at this time. At 12:05 PM the following conditions occur on the AC distribution system:

b The following alarms annunciate:

f

/

I d

BUS I B UV b

SIB BRKR TRIP 41 60V BUS 1 B voltmeter is reading downscale 41 60V BUS 1A voltmeter is reading 41 60 volts Security reports that Startup Transformer SB deluge system is discharging on the All other switchyard equipment is available for use.

./

p i,,! I I

MN BRKR I B TRIP MN BRKR 1B 86 LKOUT TRIP SIB BRKR OL TRIPIBRKR PERM OPN EDG No. 2 has started and has energized 4160V Bus 1 D e

transformer.

0 The operators quickly respond to the 1 B Bus alarms and indications (ping OPS-3024.1 Oa) and stabilize the plant within the design capability of the remaining energized systems and components. All applicable Technical Specification ACTION statements are satisfied.

Answer the following:

a.

b.

L What is the maximum power level sustainable with the AC distribution configuration as it exists at 1205 PM?

How long can the conditions existing at 12:05 PM be allowed to continue?

A.

The plant would have scrammed from the transient. The existing conditions can be maintained indefinitely.

B.

The plant could be run at approximately 33% power. The existing conditions can be maintained for 7 days.

C.

The plant could be run at approximately 50% power. The existing conditions can be maintained for 7 days.

D.

The plant could be run at approximately 33% power. The reactor must be placed in the COLD SHUTDOWN CONDITiON.

ANSWER:

B EXPLANATION: The limiting configuration with Bus 1 B deenergized is the condensate/feedwater system which will have only one condensate and one feedwater pump running. The remaining 4160V equipment (fed from Bus IA) will sustain over 50% power. A half SCRAM will occur, but it can be reset after the #2 EDG loaded onto Bus 1 D. It is expected that Bus 1 B would be energized from the Station Blackout Transformer within about one hour. TS allows operation in this configuration for 7 days.

TECHNICAL REFERENCE(S):

OPS-3024.10a: TS 3.7 (Attach if not previously provided)

8 I 1 Proposed references to be provided to applicants during examination:

None

-u' Learning Objective:

(As available)

Examination Outline Cross-reference:

Level RO SRO 2

1 Tier #

Group #

WA ##

26200 112.1.7 Importance Rating -

4.4 4

WA Topic

Description:

Ability to evaluate plant performance and make operational judgements related to AC Electrical Distribution based on operating characteristics/reactor behavior/ and instrument interpretation.

I Question Source:

Bank ##

Modified Bank #

New X

(Note changes or attached parent)

Question Cognitive Level:

10 CFR Part 55 Content:

Comments: Sustainable power level must be'validated by licensee.

Memory or Fundamental Knowledge 55.41 55.43 55.43(b)(5)and (2)

Comprehensive or Analysis x

Number OYSTER CREEK GENERATING STATION PROCEDURE ABN-17 I lAmerGenw An ExelonlBritish Energy Company I

Title FEEDWATER SYSTEM ABNORMAL CONDITION$

Revision No.

0 D.

RESTORE and MAINTAIN RPV level 155-165.

1 E.

DIAGNOSE the cause of the failure in accordance with section 3.3 of this procedure.

[

I 3.3 Loss of Feed/Feed Flow Abnormalities A.

Feed Pump Trip B.

Condensate Pump Trip C.

Multiple Feed Pumps Trip D.

Multiple Condensate Pumps Trip E.

Feed Flow Abnormalities CHECK feed pump and associated valves lined up correctly.

[

I

1)

2)

If the block valve(s) are misaligned as indicated by:

e Individual feedwater flow in the A or C string unbalanced.

e BLOCK VLV TROUBLE annunciators in alarm (J-6-d (f)).

12.0

I 3.7 AUXILIARY ELECTRICAL POWER Applicability: Applies to the OPERATING status of the auxiliary electrical power supply.

Obiective:

To assure the OPERABILITY of the auxiliary electrical power supply.

---.a-Specifications:

A. The reactor shall not be made critical unless all of the following requirements are satisfied:

I.

The following buses or panels energized.

I I

a.

b.

4160 volt buses IC and ID in the turbine building switchgear room.

460 volt bu.ses 1A2, 1B2, IA21, 1B21 viral MCC LA2 and IB2 in the reactor building switchgear room: 1.43 and 1B3 at the intake structure; 1A21A, 1B21A, 1A21B, and

,1B21B and vital MCC 1AB2 on 23'6" elevation in the reactor building; 1A24 and 1B24 at the stack.

1

c.

208/120 volt panels 3,4, 4A, 4B, 3C and VACP-I in the reactor building switchgear room.

d.

120 volt protection panel I and 2 in the cable room.

e.

125 volt DC distribution centers C and,B, and panel D, Panel DC-F, isolation valve motor control center DC-1 and 125V DC motor control center DC-2.

f.

One 230 KV line is fully operational and switch gear and both startup transformers are energized to carry power to the station 4 160 volt AC buses and carry power to or away from the plant.

24 volt D.C. power panels A and B,in the cable room.

2.

c

3.

An additional source of power consisting of one of the following is in service connected to feed the appropriate plant 4 160 V bus or buses:

a.

b.

A 69 KV line fully operational.

A 34.5 KV line fulJy operational.

4.

Station batteries B and C and an associated battery charger are OPERABLE. Switchgear I

control power for 4160 volt bus ID and 460 volt buses 1B2 and 1B3 are provided by battery B.

Switchgear control power for 4160 volt bus 1C and 460 volt buses 1A2 and 1A3 are provided by battery C.

5.

Bus tie breakers ED and EC are in the open position.

B.

The reactor shall be PLACED IN the COLD SHUTDOWN CONDITION if the availability of I

power falls below that required by Specification A above, except that 1.

The reactor may remain in operation for a period OYSTER CREEK 3.7-1 Amendment No.: 44,55,80, 119, 136, 211, 222

I not to exceed 7 days if a startup transformer is out of service. None of the engineered safety feature equipment fed by the remaining transformer may be out of service.

2.

The reactor may remain in operation for a period not to exceed 7 days if 125 VDC Motor Control Center DC-2 is out of service, provided the requirements of Specification 3.8 are met.

C.

Standby Diesel Generators

1.

The reactor shall not be made critical unless both diesel generators are operable and capable of feeding their designated 4160 volt buses.

2.

If one diesel generator becomes inoperable during power operation, repairs shall be initiated immediately and the other diesel shall be operated at least one hour every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at greater than 80% rated load until repairs are completed. The generator is out of service. During the repair period none of the engineered safety features normally fed by the operational diesel generator may be out of

'service or the reactor shall be placed in the cold shutdown condition. If a diesel is made inoperable for'6hnnid hSpection, the testing and engineered safety feature requirements described above must be met.

reactor may remain in operation for a period not to exceed 7 days if a diesel I

3. '

If both diesel generators become inoperable during power operation, the reactor shall be placed in the cold shutdown condition.

L

4.

For the diesel generators to be considered operable:

A)

There shall be a minimum of 14,000 gallons of diesel fuel in the standby dibsel generator fuel tank, O R

6)

To facilitate inspection, repair, or replacement of equipment which would require full or partial draining of the standby diesel generator fuel tank, the following conditions must be met:

1)

There shall be a minimum of 14,000 gallons of fuel oil contained in temporary tanker trucks, connected and aligned to the diesel generator fill station.

OYSTER CREEK 3.7-2 Amendment No.: 44, 55, 92, 1 19+!4+?.,

239

0

..J Question SRO 22 Per Category J, Radiological Releases:

0 Iodine release greater than 40 pCi/sec is an ALERT classification 0

Valid integrated dose at or beyond the site boundary of 25 mREM but ~ 1 0 0 0 mREM TEDE is a SITE AREA EPhERGENCY classification Based upon the HP call of 700 mREM[/hr] TEDE at the route 9 bridge, this constitutes a SITE AREA EMERGENCY,not a GENERAL EMERGENCY.

Therefore, answer b is the correct answer.

References:

EPIP-OC:.Ol, Classification of Emergency Events, Category J I

QUESTION # SRO-22 L/

One hour has elapsed since a steam line break occurred in the Turbine Building. The transient has caused fuel damage, a reactor scram, but manual closure of the MSlVs was NOT successful.

Following the transient the following conditions exist:

0 0

All rods reached 00 on the SCRAM Torus temperature is 96 degrees F There is indication of 50,000 Ibs/hr flow on the A main steam line flow instrument RPV level is 60 TAF and slowly increasing from a low point of 30 TAF RPV pressure is 760 psig and dropping slowly Security calls and informs you that steam can be seen issuing from, the Turbine Building Chemistry sampling results of reactor coolant are NOT in yet but the accompanying HP reported that the sample bottle was 5 WHR when the chemist left the sample station Iodine release is 50 uCl/sec An HP calls from Route 9 bridge and reports 700 mREM/hr TEDE at his location Classify the event.

A.

General Emergency B.

Site Area Emergency C.

Alert D.

Unusual Event ANSWER:

I,A EXPLANATION: The key factors are the MSlVs not closed and the last data from the HP which satisfies GE. The remaining indications all satisfy UE or ALERT.

TECHNICAL REFERENCE(S):

Procedure EPIP-OC-01. Classification of Emeraency Conditions, Appendix I (Attach if not previously provided)

Proposed references to be provided to applicants during examination: EPIP-OC-01 Appendix 1 Learning Objective:

(As available)

Examination Outline Cross-reference:

Level RO SRO 3

4 Tier #

Group #

K/A #

2.4.41 Importance Rating -

4.1 -

KIA Topic

Description:

Knowledge of the emergency action level thresholds and classifications L

Question Source:

Bank #

X Modified Bank #

New (Note changes or attached parent)

I '

Question Cognitive Level:

Memory or Fundamental Knowledge Comprehensive or Analysis X

I O CFR Part 55 Content:

55.41 Comments: INPO bank Susquehanna 9/30/99. Changed units and terminology to OC specific.

55.43 55.43(b)(5) and (4)

I

OYSTER CREEK EMERGENCY PREPAREDNESS IMPLEMENTING PROCEDURE

, AmerGen, An ExelonlBrihsh Energy Company Title Number EPIP-OC--01 Revision No.

(J)

Coizdition Applicability CLASSIFICATION OF EMERGENCY CONDITIONS

'V' APPENDIX 2 Category J "Radiological Re'leases

'I 14 AI1 Plant Conditions.

Basis This covers any event which leads to a rad release regardless of plant condition.

Classifications Unusual Event EAL ' s

1. Noble Gas: Stack Monitor greater than CPS,,

-or-

-or-

2. Iodine: Release rate greater than 4 uCi/sec

3. 10 CFR 20, Appendix B, Table 2, Column 2, limits exceeded in discharge canal at Rt. 9 Bridge

-or-Off-site Dose:

4. A valid integrated dose at or beyond the Site Boundary of greater than or equal to 0.1 mRem total whole body (TEDE) but less than 10 mRem total whole body dose (TEDE) exists as indicated by: dose projections or field team readings A valid integrated dose at or beyond the Site Boundaky of greater than or equal to 0.5 mRem (CDE) adult thyroid but less than 50 mRem (CDE) adult thyroid dose exists as indicated by: dose projections or field team readings.

-or-

5.

L-Basis Unplanned releases in excess of the site technical represent a potential degradation in the level of safety.

The final integrated dose is not the primary concern here, it is the degradation in plant control implied by the fact that the release was not isolated.

The term "Unplanned", as used in this context, includes any release for which a radioactive discharge permit was not prepared, or a release that exceeds the conditions (e.g.,

minimum dilution flow, maximum discharge flow, alarm setpoints, etc.) on the applicable permit.

Offsite Dose due to plant releases (readinqs above backsround) can be determined from field measurement readings or dose projections. Monitor indications are calculated on the basis of the methodology of the Offsite Dose Calculation Manual (ODCM), which demonstrates compliance with 10CFR20 and/or 10CFR50 Appendix I requirements.

In EAL 4, the 0.1 mR value is based on a proration of two times the 500 mR/yr for an individual member of the public stated in the Oyster Creek Off-Site Dose Calculation Manual, rounded down to 0.1 mRem per event.

specifications that continue for 5 minutes or longer 1--

(EPIPOl/S4)

E2-15

'ER CREEK Number

'AREDNESS EPIP-OC-.01 CLASSIFICATION OF EMERGENCY CONDITIONS t

14 APPENDIX 2 Category J "Radiological Releases" Classification EAL S I

Basis Classification EAL ' s Basis Alert

1. Noble Gas: Stack Monitor greater than CPS,

2. Iodine: 'Release rate greater than 40 uCi/sec

3. 10 CFR 20, Appendix B, Table 2, Column 2, Limits exceeded by a

-or-

-or-,

factor of 10 in discharge canal at Rt. 9 Bridge.

-or-I Offsite Ddse:

4. A valid integrated dose at or' beyond the Site Boundary of greater than or equal to 10 mRem but less than 50 mRem total whole body dose (TEDE) exists as indicated by: dose projections or field team readings.

-or-

5. A valid integrated dose at or beyond the Site Boundary of greater than or equal to 50 mRem but less than 250 &em (CDE) adult thyroid dose exists as indicated by: dose projections or field team readings.

This event escalates from the Unusual Event by escalating the magnitude *of the release by a factor of 10. In EAL 3, the 10.0 mR/hr value is based on a proration of 200 times the 500 mR/Yr limit for an individual member of the public stated in the Oyster Creek Off-Site Dose Calculation Manual, rounded down to 10.0 mR/hr. EALs' at this level or higher are entry conditions to Procedure EMG-3200.12.

Site Area Emergency Offsite Dose:

4.

5.

A valid integrated dose at or beyond the Site Boundary of greater than or equal to 50 mRem but less than 1000 mRem (1 Rem) total whole body dose (TEDE) exists as indicated by: dose projections or field team readings.

A valid integrated dose at or beyond the Site Boundary of greater than or equal to 250 -em but less 5000 mRem ( 5 Rem)

(CDE) adult thyroid exists as indicated by: dose projections or field team readings.

-or-The 50 mRem is based on the corporate philosophy for classification relative to the EPA's protective action guidelines, where 5% of the lower limit shall be the trigger value for a Site Area Emergency.

The 250 mRem child thyroid dose is in consideration of the 1:5 ratio established by the PAG's for total whole body dose (TEDE) to (CDE) adult thyroid relationship.

E2-16

OYSTER CREEK EMERGENCY PREPAREDNESS IMPLEMENTING PROCEDURE AmerGen-bn ExelonlBritish Energy Company Title i-- CLASSIFICATION OF EMERGENCY CONDITIONS APPENDIX 2 Number EPIP-OC- -01 Revision No.

14 Category J "Radiological Releases" Classification General Emergency EAL ' s Offsite Dose:

4. A valid integrated dose at or beyond the Site Boundary of greater than or equal to 1000 mRem (1 Rem) total whole body dose (TEDE) exists as indicated by: dose projections or field team readings.

A valid integrated dose at or beyond the Site Boundary of greater than or equal to 5000 mRem (5 Rem) (CDE) adult thyroid exists as indicated by: dose projections or field team readings.

-or-5.

Basis The 1000 mRem total whole body (TEDE) and the 5000 mRem (CDE) adult thyroid integrated dose are based on the proposed EPA protective action guidance which indicates that public pl;otective actions are warranted if the dose exceeds 1 rem total whole body (TEDE) or 5 rem (CDE) adult thyroid. This is consistent with the emergency class description for a General Emergency and the Nureg's initiating conditions. Actual meteorology (including forecascs) should be used.

E2-17

I 1

Question SRO 23 Based upon the given information, there are 30,500 gallons of diesel fuel available for diesel engine operation. At the 3-day fuel consumption rate per Amendment 18, it comes out to 7.37 days of available fuel oil. The question, as written, assumes the Diesel Fuel Oil tank must be maintained at 14,500 gallons. Technical Specifications bases for section 3.7 assumes the EDGS are available: to be run as long as the fuel supply holds out. The fuel supply takes into consideration the Diesel Fuel Oil tank, as well as the heating #boiler fuel supply. Therefore, taking into consideration 14,000 gallons in the fuel oil tank and 16,500 in the heating boiler tank, there is a total of 30,500 gallons, NOT just 16,500 as stated in the question explanation.

L-I The 3-day consumption rate is 12,410 gallons of fuel oil, which equates to 4,136.66 gallons per day. By dividing 30,500 gallons by 4136.66 gal/day, the total time is 7.37 days of operation.

The question asks: How long is the fuel supply adequate, considering the TS Basis consumption rate.

Since the question is not looking for the longest time the diesels will run with the available fuel supply, days, 7 days.) Under all cases, the supply is adequate to cover all four answers.

four answers can be considered correct (3 days, 4 days, 5 8

This question should be deleted.

I

References:

Technical Specifications, section 3.7 including bases

Q UESTlO N WRO-23 The plant is in normal full power operation with no LCOs on April 1, 2004 when massive grid instabilities result in the loss of offsite power for the foreseeable future. The plant responds as designed including both Standby Diesel Generators which have started and loaded to their respective buses. The following conditions exist as of noon on April 1, 2004:

l-.

Diesel fuel oil delivery is uncertain due to infrastructure problems The Standby Diesel Generator Fuel Tank is at 14,500 gallons The heating boiler tank has 16,500 gallons of available fuel NO other sources of diesel fuel are available on site The heating boilers are shutdown for maintenance How long is the fuel supply adequate considering the TS Basis consumption rate?

For your answer assume two diesels continue to run at the consumption rate specified in Amendment 18. Round off you answer to the nearest day.

A.

Threedays B.

Four days C.

Fivedays D.

Sevendays L-ANSWER:

, B EXPLANATION: Per TS Bases the rate is 12,410 gallons for three days. The 16, 500 gallons in the heating boiler tank will last three days and 23+ hours (16,546 gallons for four days) with the Standby Diesel Generator Fuel Tank maintained above its TS minimum level of 14,000 gallons.

TECHNICAL REFERENCE(S):

TS 3.7.C and TS Bases for TS 3.7 if not previously provided)

(Attach Proposed references to be provided to applicants during examination: None Learning Objective:

(As available)

Examination Outline Cross-reference:

Level RO SRO 3

1 Tier #

KIA #

2.1.33 Importance Rating -

4.0 K/A Topic

Description:

Ability to recognize indications for system operating parameters which are entry conditions for Technical Specifications Question Source:

Bank #

X Modified Bank #

New Group #

L (Note changes or attached parent)

t

\\.-

Question Cognitive Level:

I O CFR Part 55 Content:

M&nory or Fundamental Knowledge 55.41 I

Comprehensive 01; Analysis X

55.43 55.43(b)(2)

Comments: Used INPO bank question from Duane Arnold 5/25/99: Made values and terminology consistent with OC Tech Specs I

I

not to exceed 7 days if a startup transformer is out of service. None of the engineered safety feature equipment fed by the remaining transformer may be out of service.

2.

The reactor may remain in operation for a period not to exceed 7 days if 125 VDC Motor Control Center DC-2 is out of service, provided the requirements of Specification 3.8 are met.

C.

Standby Diesel Generators

1.

The reactor shall not be made critical unless both diesel generators are operable and capable of feeding their designated 4160 volt buses.

2.

If one diesel generator becomes inoperable during power operation, repairs shall be initiated immediately and the other diesel shall be operated at least one hour every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at greater than 80% rated load until repairs are completed. The reactor may remain in operation for a period not to exceed 7 days if a diesel generator is out of service. During the repair period none of the engineered safety features normally fed by the operational diesel generator may be out of

'service or the reactor shall be placed in the cold shutdown condition. If a diesel is made inoperable for bienniar tnspecfion, the testing and-engfiikGred safety feature requirements described above must be met.

I

=%-=Y*

-I-

3.

If both diesel generators become inoperable during power operation, the reactor shall be placed in the cold shutdown condition.

c-

4.

For the diesel generators to be considered operable:

A)

There shall be a minimum of 14,000 gallons of diesel fuel in the standby diesel generator fuel tank, OR B)

To facilitate inspection, repair, or replacement of equipment which would require full or partial draining of the standby diesel generator fuel tank, the following conditions must be met:

1)

There shall be a minimum of 14,000 gallons of fuel oil contained in temporary tanker trucks, connected and aligned to the diesel generator fill station.

OYSTER CREEK 3.7-2 Amendment No.: 44, 55,X?, 1 l&448,19?, 239

I I

-AND-

2)

The reactor cavity shall be flooded above elevation 1 I7 feet with the spent fuel pool gates rempved, or all reactor fuel shall be contained in the spent fuel pool with spent fuel pool gates installed.

6 AND

3) The plant shall be placed in a configuration in which the core spray system is not required to be OPERABLE.

I OYSTER CREEK 3.7-3 Amendment No.: 148, 222

Bases The general objective is to assure an adequate supply of power with at least one active and one standby source of power available for operation of equipment required f0r.a safe plant shutdown, to maintain the plant in a safe shutdown condition and to operate the required engineered safety feature equipment following an accident.

AC power for shutdown and operation of engineered safety feature equipment can be provided by any of three active (one or two 230 KV lines, one 69 KV line, and one 34.5 KV line) and either of two standby (two diesel generators) sources of power. (In applying the minimum requirement of one active and one standby source of AC power, since both 230 KV lines are on the same set of towers, either one or both 230 KV lines are considered as a single active source.) Normally all six sources are available.

However, to provide for maintenance and repair of equipment and still have redundancy of power sources the requirement of one activemand one standby source of power was established. The plant's main generator is not given credit as a source since it is not available during shutdown.

The plant 125V DC system consists of three batteries and associated distribution system. Batteries B and C are designated as the safety related subsystems while battery A is designated as a non-safety related subsystem. Safety related loads are supplied by batteries B and C, each with two associated full capacity chargers. One charger on each battery is in service at all times with the second charger available in the e<ent of charger failure. These chargers are active sources and supply the normal 125V DC requirements with the batteries and standby sources. ( I )

.The probability analysis in Appendix "L" of the FDSAR was based on one diesel and shows that even with only one diesel the probability of requiring engineered safety features at the same time as the second diesel fails is quite small. The analysis used information on peaking diesels when synchronization was required which is not the case for Oyster Creek. Also the daily test of the second diesel when one is temporarily out of service tends to improve the reliability as does the fact that synchronization is not required.

I As indicated in Amendment 18 to the Licensing Application, there are numerous sources of diesel fuel which can be obtained within 6 to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and the heating boiler fuel in a 75,000 gallon tank on the site could also be used. As indicated in Amendment 32 of the Licensing Application and including the Security System loads, the load requirement for the loss of offsite power would require 12,410 gallons for a three day supply. For the case of loss of offsite power plus loss-of-coolant plus bus failure 9790 gallons would be required for a three day supply.

OYSTER CREEK 3.7-4 Amendment No.: 55,60,99, 136, 148, 222

'c

t L'

In the case of loss of offsite phwer plus loss-of-coolant with both diesel generators starting the load requirements (all equipment operating) shown there wouldsnot be three days' supply. However, not all of this load is-required for three days and; after evaluation of the conditions, loads not required on the diesel will be curtailed. It is reasonable to expect that within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> conditions can be evaluated and the foIlowjng loads curtailed:

1.

I One Core Spray Pump

2.

One Core Spray Booster Pump

3.

One Control Rod Drive Pump

4. One Containment Spray Pump

5.

One Emergency Service Water Pump 1

With these pieces of equipment taken off at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the incident it would require a total consumptibn of 12,840 gallons for a three. day supply. Therefore, a minimum technical specification requirement of 14,000 gallons of diesel fuel in the standby diesel generator fuel tank will exceed the engineered safety features operational requirement after an accident by approximately 9%.

During plant cold shutdown or refueling, it may be necessary to inspect, repair and replace the 15,000 gallon standby diesel generator fuel storage tank. This would require tank partial or full drain down. An alternate fuel supply configuration may be established which consists of temporary tanker trucks capable of containing 14,000 gallons. This con figbration is capable'of supporting continuous operation of both diesels for at least 3 days.

The temporary configuration is acceptable since a minimal power load would be required during and following a design basis condition of a loss of offsite power while the plant is in cold shutdown or refueling. Analysis shows that in the event of a tornado or seismic event which may cause a loss of offsite power and a temporary loss of the temporary EDG fuel oil supply, power can be restored before the consequences of previously analyzed conditions are exceeded.

References:

(I) Letter, Ivan R. Finfrock, Jr. to the Director of Nuclear Reactor Regulation dated April 4, 1978.

OYSTER CREEK 3.7-5 Amendment No.: 99, 148,203, 222

Question SRO 25 Step 7.2.4 of procedure 312.9 (precautions and limitations) sa rs... If the primaq Containment requires venting and the potential exists for airborne activity to be higher than normal, consideration should be given to vent through the Standby Gas Treatment System.

c Step 7.3.2.6 (steps to depressurize the Torus) says IF stack gas activity exceeds 1000 cps, THEN immediately SECURE the purge.

a.

CLOSE Torus Vent V-28-17

b.

CLOSE Torus Vent V-28-18 C.

NOTIFY the OS The suggested answer to the question was c, to secure the primary containment purge by closing V-28-17 and V-28-18.

The candidates were onlv provided sections 7.1 and 7.2 of procedure 31 2.9, hence they all chose the answer dealing with the above-stated precaution to vent through Standby Gas Treatment System. It is not expected for the candidates to memorize a discrete action setpoint contained within an operating procedure, especially if it is a setpoint that is not readily recognized. The answer the students chose was based upon the supplied sections of the procedure. The suggested correct answer was derived from that section of the procedure that was not available to the students.

Therefore, answers c and d are correct based upon the provided references.

L References Procedure 31 2.9, Primary Containment

t 1

QU EST10 N #S RO-25 A drywell entry must be made in order to inspect for increased unidentified leakage. A plant shutdown is in progress. The following conditions exist:

0 Reactor Power is 90% and decreasing Purging of the drywell with air is in progress in accordance with Procedure 31 2.9, Primary The Chemistry Department indicated that the Stack Gas Activity should NOT exceed 900 DRYWELL VENT-PURGE INTERLOCK BYPASS switch is in the BYPASS position (Panel Venting is via the Reactor Building Ventilation System Stack gas activity is at I I00 CPS and slowly increasing Containment Control.

CPS, based on their sample 12XR) 0 Your direction to the operator(s) controlling the purge in accordance with Procedure 312.9 is that they are required to:

A.

B.

Decrease the purge flow until stack gas activity decreases below 900 CPM Confirm stack release rate with RAGEMSand then decrease purge flow rate.

c_c C.

D.

Secure the primary containment purge by closing V-28-17 and V-28-18.

Shift the purge to go through the Standby Gas Treatment System s

t I

I -.----

ANSWER:

C EXPLANATION: This is specified in Step 7.3.2.6 of Procedure 312.9. The other distractors, though possible mitigation strategies, are not specified actions.

TECHNICAL REFERENCE(S):

Section 7.0 of Procedure 312.9 (Attach if not previously provided)

Proposed references to be provided to applicants during examination: Section 7.1 and 7.2 of Procedure 312.9 Learning Objective:

(As available)

Examination Outline Cross-reference:

Level RO SRO Tier #

3 Group #

Importance Rating -

3.4 3

KIA #

2.3.9 KIA Topic

Description:

Knowledge of the process for performing a Containment Purge Question Source:

Bank #

L Modified Bank #

New X

(Note changes or attached parent)

Question Cognitive Level:

Memory or Fundamental Knowledge X

Comprehensive or Analysis

I O CFR Part Comments:

55 Content:

55.41 55.43 55.43(bM4)

DCC FILE #:20.1812.0010 OYSTCR CREEK GENERATING STATION PROCEDURE

AmerGen, k

AnExeh Company

• i I

Title Primary Containment Control Revision No.

30 7.0 PURGING PRIMARY CONTAINMENT WITH AIR 7.1 Prerequisites 7.1.I The Instrument and Service Air System is in operation in I

accordance with Procedure 334.

[

I 7.1.2 The Reactor Building Heating,.Cooling and Ventilation System is in operation in accordance with Procedure 329.

1 1

7.1.3 The Process Radiation Monitoring System is in operation in accordance with Procedures 406.1 and 406.2.

[

I 7.1.4 The Chemistry Department has evaluated Reactor Coolant activity in accordance with procedure 829.1 0 step 9.3 and taken an air sample if required. If a sample i.s required, it has been analyzed for radioactivity and the Primary Containment atmosphere has been found satisfactory for purging via the Reactor Building Ventilation System.

[

I 7.1.5 The Stack RAGEMS is in operation in accordance with Procedure 406.8.

[

I 7.1.6 Hydrogen concentration in the Drywell has been verified to be less than 2% prior to purging. If it is greater than or equal to 2%, the Drywell must be inerted to less than 2% H2 concentration in accordance with Procedure 312.1 I.

The preferred method of verification is the H2/02 monitor.

7.2 Precautions and Limitations 7.2.1 7.2.2 Drywell entries shall be controlled in accordance with Procedure 233.

When purging in the RUN mode, the DRYWELL VENT-PURGE INTERLOCK BYPASS switch must be in the BYPASS position (Panel 12XR).

Normal containment purging will be via the Reactor Building Ventilation System. Purging following the release of Reactor steamlwater to the containment and subsequent Containment Isolation shall be controlled by the Emergency Operating Procedures.

7.2.3

[

I 18.0

DCC FILE #:20.1812.0010 I

Title OYSTER CREEK GENERATING STAT1 0 N PROCEDURE 312.9 AmerGen%

An Exeh COmpatIy Revision No.

I 30 Primary Containment Control Stack and Reactor Building Radiation Monitors shall be monitored whenever the Primary Containment is being vented. If the Primary Containment requires venting and the potential exist for airborne activity to be higher than normal, consideration should be given to vent through the Standby Gas Treatment System.

7.2.5 Primary Containment de-inerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a scheduled shutdown in accordance with Tech.

Spec. 3.5.A.6.

When Primary Containment is required, simultaneous opening of Drywell and Torus valves listed together in Groups I or II or Ill in the table below is prohibited. Operating with both Drywell and Torus valves open creates a pathway to bypass the Torus to Drywell Vacuum Breakers (CM-2).

7.2.6 Group I

I1 I11 NP Purge (12XR)

N2 Makeup (12XR)

Ventilation Valves (Exhaust)

Drywell V-23-13 V-23-14 V-23-17 V-23-18 V-27-1 V-27-2 V-23-2 1 V-2 3 -22 V-23-15 V-23-16 I

V-23-19 V-23-20 V 1 7 V-28-18 V-2847 19.0

OYSTER CREEK GENERATING STATION PROCEDURE t

AmerGen-An Exeh Company Title Primary Containment Control I

Number 312.9,

Revision No.

30 7.3.1.1 PERFORM the following steps to isolate N2 to the

1. CONFIRM open 100 psig air supply valve V-6-166 (in Shutdown Cooling Pump I

Drywell and Torus:

Room west wall by the pumps).

[

I

2.

NOTE The following step will cause the N2 indicator, to extinguish, the AIR indicator to illuminate and the N2 COMPR FAIL (C-3-g) alarm to annunciate in the Control Room.

I

-v-SELECT AIF with the AIRIN2 selector switch

3. OPEN Nitrogen Compressor #I local at the nitrogen compressors.

[

I disconnect switch.

[

I

4. OPEN Nitrogen Compressor #2 local

5. CLOSE the following nitrogen valves:

Nitrogen Compressor # I Supply Nitrogen Compressor #2 Supply Nitrogen Compressor # I Discharge disconnect switch.

[

I Valve V-23-1002.

[

I Valve V-23-1001.

[

I Valve V-23-170.

[

I Nitrogen Compressor #2 Discharge Nitrogen Receiver Discharger

6.

OPEN the Nitrogen Receiver Drain Valve V-23-177 and completely VENT the Valve V-23-171.

[

I Valve V-23-169.

[

I receiver.

[

I 20.0

DCC FILE #:20.1812.0010 mmw 1

OYSTER CREEK GENERATING Number An Exdcn Company STATION PROCEDURE I

3,2.9 L-.

I I

Title I Revision No.

I 30 Primary Containment Control 7.3.1.2 TRANSFER purge gas to the TIP tubes from nitrogen to air as follows:

I. OPEN the instrument air supply to the TIP indexers V-6-1321. (Tip Drive Room)

2. CLOSE the nitrogen supply to the TIP indexers V-23-163. (Tip Drive Room)

3. ADJUST Pressure Regulating Valve V-23-69 to obtain 0.8 to 1.2 as read on DPI-23-278 (RB 23').

7.3.1.3 CONFIRM closed the following nitrogen makeup and purge valves (Panel 12XR):

0 DRYWELL N2 MAKEUP V-23-17

[

I

[

I

[

I

[

I DRYWELL N2 MAKEUP V-23-18

[

I e

DRYWELL N2 PURGE PRESSURE CONTROL V-23-13

[

I DRYWELL N2 PURGE SHUTOFF V-23-14

[

I TORUS N2 MAKEUP V-23-19

[

I 0

TORUS N2 MAKEUP V-23-20

[

I e

TORUS N2 PURGE PRESSURE CONTROL V-23-15

[

I TORUS N2 PURGE SHUTOFF V-23-16

[

I 7.3.1.4 PLACE the Drywell Oxygen Analyzer and Torus Oxygen Analyzer Sample Pump in service in accordance with Procedure 312.7.

[

I 21.o

DCC FILE #:20.1812.0010 I

Title Primary Containment Control I

-v Revision No.

30 OYSTER CREEK GENERATING STATION PROCEDURE AmerGen.

An ExebnCmpany

~

I 7.3.1.5 CONFIRM CNTMT VENT AND PURGE ISOLATION BYPASS switch (lower left side) in NORMAL position (Panel 11 F).

[

I 7.3.2 DEPRESSURIZE the Torus as follows:

I

1.

CONFIRM closed Drywell Vent and Bypass valves:

V-23-21

[ I' V-23-22

[

I V-27-1

[

I V-27-2

[

I

2. E the REACTOR MODE SELECTOR switch is in 0

0 the RUN position, THEN PLACE DRYWELL VNT-PURGE INTERLOCK BYPASS switch in BYPASS position (Panel 12XR).

[

I

3.

OPEN Torus Vent valves (Panel 11 F):

V-28-17

[

I v-28-18

[

I

4.

MONITOR the following:

Reactor Building ventilation exhaust activity (Panel IOF) stack gas activity (Panel IOF) stack gas activity (Panel 1R) 22.0

c I

Title

AmerGen, An Exebn Company Revision No.

OYSTER CREEK GENERATING STATION PROCEDURE Primary Containment Control DCC FILE #:20.1812.0010 31 2.9 30

5.

MARK the time the depressurization was started on the stack gas recorder (Panel 1 OF).

[

I

6. E stack gas activity exceeds 1000 cps, THEN immediatelv SECURE the purge:

a. CLOSE Torus Vent V-28-17

[

I

b.

CLOSE Torus Vent V-28-18

[

I

c.

NOTIFY the OS

[

I

[

I

7.

VERIFY Torus pressure is approximately zero as indicated on the pressure recorder (Panel 12XR).

8.

CLOSE Torus Vent valves (Panel 11 F):

V-28-17

[

I V-28-18

[

I 7.3.3 DEPRESSURIZE the Drywell as follows:

I. CONFIRM closed Torus Vent and Bypass valves (Panel 11 F):

V-28-17

[

I V-28-18

[

I V-2847

[

I

2.

the REACTOR MODE SELECTOR switch is in the RUN position, THEN PLACE the DRYWELL VENT-PURGE INTERLOCK BYPASS switch in BYPASS position (Panel 12XR).

[

I 23.0

I

.~

=__.-

Title DCC FILE #:20.1812.0010 Revision No.

OYSTER CREEK GENERATING STATION PROCEDURE

AmerGen, AnWnCompany I

30 Primary Containment Control n 3.

I I

CAUTIO N Torus and Drywell pressure must be monitored while purging the Drywell. This ensures a positive AP is maintained between Drywell and Torus to prevent opening the Torus,to Drywell vacuum breakers.

OPEN Drywell Vent valves (Panel I 1 F):

V-27-1 V-27-2

[

I 0

I

4. E while Drywell purging.is in progress, Torus pressure increases sufficiently to approach the opening of the Torus to Drywell vacuum breakers,

THEN PERFORM the following:

a. CLOSE Drywell Vent valves:

V-27-1

[

I v-27-2

[

I

b. RETURN to Step 7.3.2 to purge the Torus.

[ ]

5.

MONITOR the following:

a.

Reactor Building ventilation exhaust activity (Panel 1 OF)

b. Stack gas activity (Panel 1 R)

6.

MARK the time the depressurization was started on the stack gas recorder (Panel 1 OF).

[

I 24.0

DCC FILE #:20.1812.0010 v

Title

-my 1

OYSTER CREEK GENERATING Number An &ton Compny STATION PROCEDURE 1

312.9 Revision No.

Primary Containment Control I

30 7.3.4

7. E stack gas activity exceeds 1000 cps, THEN immediately SECURE the purge:

a.

CLOSE Drywell Vent V-27-1.

b. CLOSE Drywell Vent V-27-2.

c.

NOTIFY the OS.

8.

WHEN the drywell pressure is approximately 0 psi, THEN CLOSE Drywell Vent valves (Panel I 1 F):

V-27-1 V-27-2 E l

[

I

[

I

[

I

[

I NOTE Steps 7.3.4, 7.3.5, 7.3.6, and 7.3.7 can be performed in any order as determined by the OS.

PURGE the Drywell with air as follows:

1. WHEN Drywell pressure has been reduced to approximately zero as indicated on the pressure recorder on Panel 12XR, THEN PERFORM the following:

a. CONFIRM closed Torus Vent and Bypass valves (Panel I 1 F):

V-28-17

[

I V-28-18

[

I V-28-47

[

I 25.0

OYSTER CREEK GENERATING STATION PROCEDURE AmerGenw An Exelon Company I

Title Primary Containment Control

\\-

Revision No.

30 DCC FILE #:20.1812.0010 MAIN SUPPLY HEADER VALVES TO DW V-28-42 and V-28-43 (Panel I 1 R)

[ ]

s 1.

DW PURGE V-27-3

[ I 0

DW PURGE V-27-4 DW VENT V-27-1

' [ 1 DW VENT V-27-2

[

I 7.3.5 SECURE the Nitrogen Purge System as follows:

I.

S I

CLOSE Grove Reducer Pressure Regulator V-23-234 or V-23-235 by turning its stem fully counter clockwise.

[.]

2.

CLOSE Nitrogen Vaporizer Supply Valve V-23-268.

[

I I

3.

CLOSE Thermostatic Control Valve Inlet Valve V-23-186.

[

I

4.

CLOSE Thermostatic Control Valve Outlet Valve V-23-187.

[

I

5.

CLOSE Inlet to #I Grove Reducer Valve V-23-189.

[

I

6.

CLOSE Inlet to #2 Grove Reducer Valve V-23-190.

[

I

7.

CLOSE Outlet from #I Grove Reducer Valve V-23-191.

[ ]

8.

CLOSE Outlet from #2 Grove Reducer Valve V-23-192.

[ ]

9.

PLACE the Nitrogen Vaporizer Power Control Switch to the STOP position.

[

I OFF.

[

I I O. PLACE the selected heater power control switch to 26.0

An Exebn Company

-v-I Title Primary Containment Control DCC FILE #:20.1812.0010 I

OYSTER CREEK GENERATING I Number Revision No.

30 I

312.9 I

STATION PROCEDURE

11. PLACE the following power circuit breaker switches to the OFF position:

HTR-854-165

[

I HTR-854-166

[

I M-23-1

[

I

12. OPEN N2 Purge Line Drain Valve V-23-143.

(Outside Reactor Building NE corner).

13. OPEN Purge Header Drain Trap Inlet Valve V-23-263.

(Reactor Building NE Stairwell).

14. OPEN Purge Header Drain Trap Vent Valve V-23-362.

(Reactor Building NE Stairwell).

15. PERFORM the Nitrogen System Shutdown Valve Lineup, Attachment 312.1 1-3.

7.3.6 WHEN Primary Containment is no longer required, THEN PURGE the Torus as follows:

1. OPEN Torus Vent valves:

V-28-17 V-28-18

2. OPEN Reactor Bldg to Torus Vacuum Breaker valves (Panel 11 F):

[

I

[

I

[

I

[

I

[

I

[

I V-26-16 V-26-18 27.0

DCC FILE #:20.1812.0010 I-Title Primary Containment Control ma, 1 OYSTER CREEK GENERATING Number 1

312.9 An,ExdbnCompany STATION PROCEDURE Revision No.

30

3.

BLOCK OPEN Reactor Bldg to Torus Vacuum Breaker valves:

V-26-15.

[

I V-26-17

[ 1.

4. COMPLETE Attachment 31 2.9-6, Reactor Building to Torus Vacuum Breaker Control Sheet.

[

I 7.3.7 WHEN Primary Containment is required, THEN PURGE the Torus as follows:

I

1. VERIFY temporary modification is installed in accordance pith Attachment 31 2.9-8.

[

I

2. VERIFY Breathing Air System is in service in accordance with Procedure 334.1.

[

I

3.

CONFIRM closed Drywell Vent and Bypass valves:

V-27-1

[

I V-27-2

[

I V-23-21

[

I V-23-22

[

I

4. OPEN Torus Vent valves:

V-28-17 V-28-18

[

I

[

I 28.0

OYSTER CREEK GENERATING STATION PROCEDURE AmerGenl An ExebCOmp~ny v

Title Primary Containment Control

5.

Number 312.9 Revision No.

30

6.

7.

8.

9.

I O.

11.

12.

CONFIRM closed Drywell NP Purge valves (Panel 12XR):

V-23-13

[

I V-23-14

[

I OPEN Torus N2 Purge valves (Panel 12XR):

V-23-15

[

I V-23-16

[

I CLOSE valve V-23-357.

[

I CLOSE valve V-23-224.

[

I OPEN valve V-23-356.

[

I NOTE Torus and Drywell pressure must be monitored when breathing air is being supplied to the Torus. This ensures a positive DP is maintained between Drywell and Torus to prevent opening the Torus to Drywell vacuum breakers.

THROTTLE open valve V-44-284.

[

I IF Torus pressure increases to 0.5 psi greater than Drywell pressure, THEN THROTTLE closed valve V-44-284 until Torus pressure decreases below Drywell pressure.

[

I PURGE the Torus in this manner until desired oxygen level is reached.

[

I 29.0

h e r -,

1 OYSTER CREEK GENERATING AnlExebn company STATION PROCEDURE l.--

I Title Primary Containment Control

13. CLOSE valve V-44-284.

I 3

7.3.8 WHEN THEN 7.3.9 WHEN THEN

14. CLOSE valve V-23-356.

15. OPEN valve V-23-224.

16. OPEN valve VY23-357.

DCC FILE #:20.1812.0010 Number 312.9 I

Revision No.

30

17. CLOSE Torus N2 Purge valves (Pane V-23-15 V-23-16

18. CLOSE Torus Vent valves: '

I 0

V-28-17 I V-28-18 2XR):

the atmosphere is acceptable for Drywell entry as monitored by portable O2 sampling equipment, MAINTAIN an air purge at all times while the Drywell and Torus are open for entry by the following valves being OPEN (Panels 1 1 F and 11 R):

MAIN SUPPLY HEADER VALVES TO DW V-28-42 and V-28-43 DW PURGE V-27-3 DW PURGE V-27-4 DW VENT V-27-1 DW VENT V-27-2 the MODE switch is no longer in the RUN position, PLACE the DRYWELL VENT-PURGE INTERLOCK BYPASS switch in NORMAL position (Panel 12XR).

[

I

[

I

[

I

[

I

[

I 30.0

AmerGeny An Exebn Company OYSTER CREEK GENERATING STATION PROCEDURE Title Primary Containment Control Number 31 2.9 Revision No.

30 7.3.10 MAINTAIN Drywell and Torus ventilation in accordance with Procedure 233, Drywell Access and Control.

8.0 DRYWELL COOLER FAN OPERATION

8. I Prerequisites 8.1.I Reactor Building Closed Cooling Water System (RBCCW) is operating in accordance with Procedure 309.2.

[

I 8.1.2 480 Volt Electrical System is operating in accordance with Procedure 338.

[

I 8.1.3 MCC 1A23 and MCC I B23 are energized in accordance with 12.9-1.

. [ 1 I

8.2 Precautions and Limitations L

8.2.1 Four Drywell Recirculation Fans should be in operation at all times. If Drywell ventilation must be reduced during Reactor operation, closely monitor Drywell pressure (Panel 12XR) and adjust pressure in accordance with Procedure 31 2.1 1.

8.3 Instructions 8.3.1 PLACE the Drywell Recirculation Fans in operation as follows:

8.3.1.I OPEN the following valves (Panel 1 F/2F):

CCW INLET ISOLATION V-5-147

[

I CCW INLET ISOLATION V-5-167

[

I DRYWELL CLG SHUT-OFF V-5-148

[

I CCW OUTLET ISOLATION V-5-166

[

I 31.O