text

LER-1989-014, on 890413,unit Reactor Experienced Reactor Scram Which Was Result of Turbine Trip Due to Actuation of Generator Protection Circuitry.Turbine Trip Caused by Disconnected Wire.Wire Relanded
Event date:
Report date:
Reporting criterion:	10 CFR 50.73(a)(2)(iv), System Actuation
	4101989014R00 - NRC Website
	v • d • e

:on 890413,unit Reactor Experienced Reactor Scram Which Was Result of Turbine Trip Due to Actuation of Generator Protection Circuitry.Turbine Trip Caused by Disconnected Wire.Wire Relanded
	ML18038A470
Person / Time
Site:	Nine Mile Point
Issue date:	05/15/1989
From:	Burkhardt L, Rich Smith; NIAGARA MOHAWK POWER CORP.
To:	; NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
	CON-IIT07-664-91, CON-IIT07-773-91, CON-IIT7-664-91, CON-IIT7-773-91 LER-89-014, LER-89-14, NMP49057, NUREG-1455, NUDOCS 8905300041
	Download: ML18038A470 (177)
	v • d • e

ACCELEPATED D1F+IBUTJON DEMONSTRQON SYSTEM I

REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:8905300041 DOC.DATE: 89/05/15 NOTARIZED: NO DOCKET FACIL:50-410 Nine Mile Point Nuclear Station, Unit 2, Niagara Moha 05000410 AUTH.NAME AUTHOR AFFILIATION SMITH,R.G.

Niagara Mohawk Power Corp.

BURKHARDT,L.

Niagara Mohawk Power Corp.

RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

LER 89-014-00:on 890413,Unit 2 reactor scram due to turbine trip caused by loose wire connections.

W/8 ltr.

DISTRIBUTION CODE:

IE22D COPIES RECEIVED:LTRj ENCL I

SIZE:

7 TITLE: 50.73/50.9 Licensee Event Report (LER), Incident Rpt, etc.

NOTES RECIPIENT ID CODE/NAME PD1-'1 LA SLOSSON,M INTERNAL: ACRS MICHELSON ACRS WYLIE AEOD/DSP/TPAB DEDRO NRR/DEST/ADE 8H NRR/DEST/CEB 8H NRR/DEST/ICSB 7

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TOTAL NUMBER OF COPIES REQUIRED:

LTTR 44 ENCL 43

N T NIAGARA V MOHAWK NMP49057 NINE MILE POINT NUCLEAR STATION/P.O. BOX 32 LYCOMING,NEWYORK 13093/TELEPHONE (315) 343-2110 May 15, 1989 United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555 RE: Docket No. 50-410 LER 89-14 Gentlemen:

In accordance with 10CFR50.73, we hereby submit the following Licensee Event Report:

LER 89-14 Is being submitted in accordance with 10CFR50.73(a)(2)(iv),

"Any event or condition'hat results in manual or automatic actuation of an Engineered Safety Feature (ESF), including the Reactor Protection System (RPS)."

A 10CFR50.72(b)(2)(ii) report was made at 1150 hours0.0133 days 0.319 hours 0.0019 weeks 4.37575e-4 months on April 13, 1989.

This report was completed in the format designed in NUREG-1022, Supplement 2, dated September 1988.

Very truly yours, L. Burkhardt III Executive Vice President Nuclear Operations LB/GB/mjv (0492V)

Attachment cc: Regional Administrator, Region 1

Sr. Resident Inspector, W. A. Cook P~ Pu>~

=:90 30004l 890 1=-

PDR ADCICK C>.OOC14iO 8

PDC

NRC Form 356 (94)3) x LICENSEE EVENT REPORT ILERI U.S. NUCLEAR REOULATOAYCOMMIS6ION APPROVED OMB NO, 3)500104 EXPIRES; 5/31/Sd FACILI'TYNAME (I)

Nine IIile Point. Unit 2 DOCKET NUMBER (2)

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Nine Mile Point Unit 2 Reactor Scram Due to Turbi.ne Tri Caused b

Loose Wire Connections EVEN'7 DATE (5)

LEA NUMBER (6)

REPORT DATE (7I OTHER FACILITIES INVOLVED(BI MONTH DAY YEAR YEAR sdovENT>AL sp?:

NUMBER REV>SION NVMBER MONTH DAY YEAR FACILITYNAMES N/A DOCKET NUMBERIS) 0 5

0 0

0 04 13 89 9

1 4

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THIS AEPORT IS SUBMITTED PURSUANT T 60.73(e) (2)liv) 50,73(el(2) lvl 50.73(e l(2)(vii) 50 73( ~ l(2)(villi(A) 60,73( ~ I(2)(viii)(BI 60,73I ~ ) I2)lxl 20.402 (Bl 20.405 (e) l1 l(I) 20.405( ~ )III(iO 20.405(cl 60.36(cl (1) 50.3d (c) (2) 50.73( ~ ) (2)(O 60.73( ~ I(2)(iil 50.7 3(v)(2)(in) 20.405( ~ l(1)(iiil 20.405(e)(1)(Iv) 20.405( ~ )

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LICENSEE CONTACT FOR THIS LER (12I 0 THE REOUIREMENTS OF 10 CFR (i: /C>>reit onr or more o/ t>>r to/row'np/ (11) 73.710>I 73.71 (cl OTHER /Spenry in Aortrrct Below en>pin Text, IVI)C Form 36'SAl Special Report NAME AREA CODE TELEPHONE NUMBER Robert G. Smith, Operations Superintendent'Unit 2

3 1

5 3

4 9 -

2 3

8 8

COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBEO IN THIS REPORT (13)

CAUSE

SYSTEM COMPONENT MANUFAC TVRER REPORTABLE

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MONTH OAY EXPECTED SUBMISSION.

DATE (15)

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Iv0 ABSTRACT /Limit to /400 tpecer, Ir., rpprovimetriy /i/teen tinpre.epece typewrrttrn linn/ 116)

On April 13, 1989 at 1101 hours0.0127 days 0.306 hours 0.00182 weeks 4.189305e-4 months with the reactor mode switch in RUN, and the reactor at 100K rated thermal power, Nine Mile Point Unit 2 experienced a

reactor scram.

This event was a result of a turbine trip due to the actuation of the generator protection circuitry.

The generator protection circuitry initiated a fast transfer of house service loads to the station reserve transformers.

One of the 13.8kv electrical buses failed to transfer which caused a loss of feedwater.

Reactor water level decreased as the turbine control bypass valves modulated to control reactor pressure, which caused the automatic actuation of the High Pressure Core Spray (CSH) and Reactor Core Isolation Cooling (ICS) systems.

The cause for the turbine trip was determined to be a disconnected wire located in the main generator potential transformer cubical.

This created a

signal to the tripping and alarm relays causing a turbine trip.

The cause for the 13.8kv bus fast transfer failure was determined to be the positive interlocking 'roller for the breaker not fully engaged.

Corrective actions include:

(1) Relanded the disconnected wire and tightened other potential transformer connections; (2) Revising the electrical maintenance procedure (N2-EPM-GMS-R693) to check connection integrity in high vi.bration areas; (3) Issuing a lessons learned transmittal outlining the problems encountered during this event.

NRC Form Sdd (9 63)

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NRC Form 3SSA I~)

LICENSEE EV REPORT (LER) TEXT CONTINUATION U.S. NUCLEAR REOULATORY COMMISSION APPROVED OM8 NO. 3180&104 EXPIRES: 8/31/88 FACILITYNAMEill DOCKET NUMSER t3l LER NUMBER Iel YEAR P?I'EOUENTIAL gL<'EVISION

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.On April 13, 1989 at approximately 1101 hours0.0127 days 0.306 hours 0.00182 weeks 4.189305e-4 months , Nine Mile Point Unit 2 (NMP2) experienced a reactor scram due to a turbine trip.

At the time of the event the reactor mode switch was in "RUN" (Operational Condition 1) with the reactor at 100X rated thermal power, and the reactor pressure and temperature

't 1003.5 pounds per square inch gauge and 546 degrees Fahrenheit respectively.

The turbine trip resulted from a generator protective circuit relay actuation.

The turbine trip initiated a fast transfer of house*service loads from the station normal service transformer to the station reserve transformers.

Switchgear 2NPS-SWG003 failed to transfer.

This caused a loss of feedwater since the operating feedwater pumps (FWS-PlB and FWS-PlC) were being powered from 2NPS-SWG003.

The complete loss of feedwater coupled with the normal operation of the turbine bypass valves (TBV's) to control reactor pressure caused reactor water level to decrease to the Level 2 (108.8 inches) setpoint.

The lowest the reactor water level reached during the transient was approximately 98 inches.

The level 2 setpoint caused the automatic initiation

~ of the High Pressure Core Spray (CSH) and Reactor Core Isolation Cooling (ICS)

systems, which injected water from the Condensate Storage Tanks (CST) to the reactor vessel to restore water level.

NMP2 entered into an Unusual Event and its Emergency Plan based on Emergency Core Cooling System (ECCS) injection on a valid initiation signal.

When reactor water level was increased to normal, CSH injection was secured.

ICS injection was automatically secured at Level 8 (202.3").

Operators continued to monitor reactor water level and believed that all vessel injection was secured.

However, feedwater was 'continuing to be injected.

Power was lost to motor operated feedwater regulation valve 2FWS-LVlOB, causing the valve to fail as is.

This condition was not recognized by the operator since the indication of the valve position and the position demand failed downscale.

The operator believed 2FWS-LV10B had closed as had 2FWS-LV10C, the complementary hydraulically operated regulation valve.

Therefore, with the combination of cold water injection, steam line drains, and steam consumption by ICS, reactor pressure was lowered to the point where condensate booster pump discharge pressure exceeded reactor pressure.

These conditions permitted feedwater flow to the vessel through the open LVlOB valve.

The operator recognized that feedwater flow was increasing causing reactor water level to increase and informed the Station Shift Supervisor of these conditions.

The Station Shift Supervisor then ordered the remaining condensate booster pump secured.

The maximum reactor vessel water level recorded during the transient was approximately 258 inches.

Water level then decreased due to boil off'hen Level 8 had cleared its setpoint the ICS pump was used to maintain water level.

The CSH pump was tripped after it was verified to be no longer needed to maintain reactor vessel level.

/

The failure of the 13.8kv switchgear (2NPS-SWG003) to transfer was caused by a "positive interlocking roller" not being fully engaged.

This positions a

limit switch, which provides a breaker position interlock to the closing circuit.

NRC FORM SOS*

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NRC Form 3&&A 045)

LICENSEE EV T REPORT ILER) TEXT CONTINUATION U.S. NUCLEAR REOULATORY COMMISSION APPROVED OM8 NO. 3)50&104 EXPIR ES: 8/31/88 FACILITYNAME Ill DOCKET NUMBER (21 YEAR LER NUMSER 16) gjR SEOVENTIAL

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Nine Mile Point Unit 2 TmET

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Complications occurred during the event when a licensed operator inadvertently de-energized the remaining 13.8kv power board (N2-NPS-SWG001).

The licensed operator observed a "Red Flagged" condition with no position indicating light (due to a loose light bulb).

The operator attempted to check voltage on the affected board but observed the wrong meter (which indicated zero).

When the control switch for breaker l-l was placed in the reset (or lockout) position, power board N2-NPS-SWG001 was de-energized.

The operator immediately realized his mistake and re-energized N2-NPS-SWG001 in accordance with station procedures.

During the momentary loss of 13.8kv power to the house service loads, the remaining Circulating Water (CWS) pumps were de-energized.

The decrease in the Main Condenser wa'ter box level after the loss of power to the CWS pumps, prevented the immediate restart of the CWS pumps and the subsequent loss of the Main Condenser as the primary heat sink.

The SSS directed the use of the Steam Condensing mode of the Residual Heat Removal (RHS) system loop A.

The Main Steam Isolation Valves (MSIV's) were directed to be closed as the Main Condenser vacuum decreased to 10 inches of mercury.

As the inboard MSIV's were being closed, a Group I Isolation was received due to low condenser vacuum and a fast closure signal for the MSIV's was received (closing all the MSIV's).

The ICS system was used to maintain reactor vessel water level and the Steam Condensing mode of RHS was used to maintain reactor vessel pressure control.

A reactor cooldown to ambient conditions was then performed."

Uninterruptible Power Supply 1D (UPS-1D), tripped due to an overload condition.

This resulted in a loss of approximately one half of the Gai-tronics system in the plant, a total loss of Gai-tronics in the Control Room (affecting communications with plant operators outside the Control Room) and a partial loss of emergency lighting.

A root cause analysis was performed using Site Supervisory Procedure S-SUP-l, "Root Cause Evaluation Program".

The root cause for this event was determined to be loose wire connections in the Main Generator Potential Transformer

cubical, 2GMS-CUB01, for circuit 2SPGZ03.

This is attributed to poor installation compounded by vibration in the area of the connections.

NRC FORM &&&A 1883)

, o U.S OPO:1085 0 82& 538/&55(0631 LICENSEE EV T REPORT (LER) TEXT CONTINUATION U.S. NVCI.EAR REGULATORY COMMISSION APPROVEO OMB NO. 3150M(Cd EXPIRES: 6/31/BB FACILITYNAME (ll DOCKET NUMBER (El LER NUMBER (6)

SEOUENZIAL NUMSER REVISION NUMSER PAGE (3)

Nine Mile Point Unit 2 TEXT /4/Roro N>>oo EI /FEUPNf, IIFF //I/o/>>/ HRC Form 36SASI (1715 0

0 0 410 8

9 1

4 00 04 OF 0 6 This event is reportable under 10CFR50.73(a)(2)(iv):

"Any event or condition that results in manual or automatic actuation of any Engineered Safety Feature (ESF), including the Reactor Protection System (RPS).

However, actuation of an ESF, including RPS, that resulted from and was part of the preplanned sequence during testing or reactor operation need not be reported."

The reactor scram was due to a turbine trip, which was in response to the actuation of a generator protection relay.

The reactor scram is a protective function and therefore poses no adverse

safety consequences

The failure of the 13.8kv power board (N2-NPS-SWG003) to transfer and subsequent loss of the remaining 13.8kv power board (N2-NPS-SWG001) did not pose a threat to the health and safety of the General Public as the three (3) divisions of Emergency Core Cooling Systems (ECCS) were operable with power sources from off-site and Diesel Generators.

Only two of the three ECCS divisions are utilized to achieve safe shutdown.

CSH and ICS automatically initiated at Level 2 (108.8 inches),

to restore level as designed.

The problems that were encountered with the overload condition of UPS-1D (partial loss of communications outside the Control Room and partial loss of emergency lighting) did not compromise the safety of the general public as the safe shutdown of the plant can be achieved from the Control Room.

An evaluation of 10CFR50 Appendix R, Section III.J, "Emergency Lighting" requirements was conducted.

The evaluation concluded that there is no impact on the Appendix R safe shutdown analysis.

Engineering is, however, conducting a review of associated essential light circuits to reconfirm that cable routings do not traverse openly in postulated fire areas (i.e.,

UPS-1D circuit cables through the Control Room and Relay Room areas).

If unanalyzed conditions are found, a supplement to this report will be issued.

Transient recording indicated that water level was slightly above the lowest elevation of the Main Steam Line (MSL) nozzle.

However, the level trends indicate that water level did not reach the Main Steam Line (MSL).

A firm conclusion that water did not flow down the Main Steam Lines could not be made.

However, if water flowed down the Main Steam Lines, it was for a very short duration.

Based on prior Engineering analyses performed on previous vessel overfill, the effects of potential transients created, if water had entered Main Steam Lines, were within plant design margins.

NRC FORM ESSA I963I o U.S.GPO:1965 0 62d 536/d55

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NRC Form SSSA IQB3)

LICENSEE EVENT REPORT (LER) TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION APPROVED OMB NO. 3)50&)OS EXPIRES: 0/31/BB FACILITYNAME 111 DOCKET NUMBER 12)

YEAR LER NUMBER (5)

SEQUENTIAL NUMBER 45 REVISION NUMIIEII PAGE IS)

Nine Mile Pofnt Unit 2 TEXTÃI/Koo <<Moo Hnqake4 Igloo oA/I/ono/HRC Form 305AS/ (17) 0 5

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E (Cont'd)

In accordance with the requirements of Technical Specification Sections 3.5.1(f) and 6.9.2, Emergency Core Cooling System (ECCS) Injections, the following data is provided:

For the HPCS nozzle, Total accumulated initiation cycles to date

= 4 Current usage factor value remains below 0.70 The duration of the event was approximately 8.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months from the time the event was initiated (1101 hours0.0127 days 0.306 hours 0.00182 weeks 4.189305e-4 months ) until the Shutdown Cooling Mode of RHS was controlling reactor temperature and pressure, (approximately 1930 hours0.0223 days 0.536 hours 0.00319 weeks 7.34365e-4 months ).

IV.

E I E A TI N Relanded the disconnected wire and tightened the other potential transformer connections.

2 ~

The Electrical Preventative Maintenance Procedure N2-EPM-GMS-R693 will be revised to ensure the integrity of the wire connections in the areas of high vibration is checked.

3 ~

The Electrical Preventative Maintenance Procedures will be revised to check interlock mechanism for proper operation.

4 ~

5.

A Lessons Learned Transmittal was generated by the Operations Department to discuss the problems associated with this event.

I The licensed, operator involved in de-energizing N2-NPS-SWG001 was counseled on self-verification and communication.

6.

Operation Procedures have been revised to ensure visual verification of the interlock roller positions on 13.8kv breakers.

7.

Operation Procedures have been revised to ensure that Feedwater,

,Condensate Booster and Condensate pump power supply lineups are separate for running pumps.

8.

Operation Procedure was revised to provide improved direction for water level control following a reactor scram.

9.

The electrical loads on UPS-1D have been reduced to prevent a trip on overload.

Additional modifications are being considered to further reduce UPS-1D loads.

NRC FORM SOSA (0431 o U.S.GPO'.1055 0 52O'535<<55

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NRC Form 388A (IL83)

LICENSEE EVENT REPORT (LERI TEXT CONTINUATION U.S. NUCLEAR REGULATORY COMMISSION APPROVED OMB NO, 3150M)OS EXPIRES: 8/31/88 FACILITYNAME 11)

OOCKET NUMBER (2)

LER NUMBER 18)

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Nine Mile Point Unit 2 TEXT/F/RoroNMOP/rnqvtorf, voo~///IC Forrrr 38543/)17) 0 5

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DDI I N L A.

Failed Components:

1. Failed Component Identification:

Component Description:

Component Vendor:

2VBB-UPS1D Uninterruptible Power Supply 'for Station Iighting/Communication Exide Power Systems Division

2. Failed Component Identification:

2NPS-SWP-003-1 Component Description:

3000 Amp Breaker Component Vendor:

General Eleqtric Company B.

Nine Mile Point Unit 2 has not experienced a reactor scram caused by a similar event.

NRC EORM ESSA 1943) o U.S.GPO,'1988 0 824 538/455

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6 gSSmPXX0XAZ 33K ERAT On April 13, 1989 at approximately 1101 hours0.0127 days 0.306 hours 0.00182 weeks 4.189305e-4 months , Nine Mile Point Unit 2 (NMP2) experienced a reactor scram due to a turbine trip.

At the time of the event the reactor mode switch was in "RUN" (Operational Condition

1) with the reactor at 100K rated thermal power, and the reactor pressure and temperature at 1003.5 pounds per square inch gauge and 546 degrees Fahrenheit respectively.

The turbine trip resulted from a generator protective circuit relay actuation.

The turbine trip initiated a fast transfer of house service loads from the station normal service transformer to the station reserve transformers.

Switchgear 2NPS-SWG003 failed to transfer.

This caused a loss of feedwater since the operating feedwater pumps (FWS-P1B and FWS-PIC) were being powered from 2NPS-SWG003.

The complete loss of feedwater coupled with the normal operation of the turbine bypass valves (TBV's) to control reactor pressure caused reactor water level to decrease to the Level 2 (108.8 inches) setpoint.

The lowest the reactor water level reached during the transient was approximately 98 inches.

The level 2 setpoint caused the automatic initiation of the High Pressure Core Spray (CSH) and Reactor Core Isolation Cooling (ICS)

systems, which injected water from the Condensate Storage Tanks (CST) to the reactor vessel to restore water level.

NMP2 entered into an Unusual Event and its Emergency Plan based on Emergency Core Cooling System (ECCS) injection on a valid initiation signal.

When reactor water level was increased to normal, CSH injection was secured.

ICS injection was automatically secured at Level 8 (202.3").

Operators continued to monitor reactor water level and believed that all vessel injection was secured.

However, feedwater was continuing to be injected.

Power was lost to motor operated feedwater regulation valve 2FWS-LV10B, causing the valve to fail as is.

This condition was not recognized by the operator since the indication of the valve position and the position demand failed downscale.

The operator believed 2FWS-LV10B had closed as had 2FWS-LV10CI the complementary hydraulically operated regulation valve.

Therefore, with the combination of A

cold water injection, steam line drains, and steam consumption by ICS, react.oi.

pressure was lowered to the point where condensate booster pump discharge pressure exceeded reactor pressure.

These conditions permitted feedwater flow i.o the vessel through the open LV10B valve.

The operator recognized

that, feedwater flow was increasing causing reactor water level to inrrease and informed the Station Shift Supervisor of these conditions.

'I'he Stat. itin Sliift Supervisor then ordered the remaining condensate booster pump secured.

Tile maximum reactor vessel water level recorded during the transient.

was approximately 258 inches.

Water level then decreased due to boil off.

When +

Level 8 had cleared its setpoint the ICS pump was used to maintaiII watei.

level.

The CSH pump was tripped after it was verified to be iio loiiger needed to maintain reactor vessel level.

RIIC 50ItM 566A I9dLTI The failure of the 13.8kv switchgear (2NPS-SWG003) t.o t.ransfer was caused by "positive interlocking roller" not being fully engaged.

This posit.ioiis a

limit switcli, which provides a breaker position interlock to the closiiig Clrculte

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Complications occurred during the event when a licensed operator inadvertently de-energized the remaining 13.8kv power board (N2-NPS-SWG001).

The licensed operator observed a "Red Flagged" condi.tion with no position indicating light (due to a loose light bulb).

The operator attempted to check voltage on the affected board but observed the wrong meter (which indicated zero).

When the control switch for breaker 1-1 was placed in the reset (or lockout) position, power board N2-NPS-SWG001 was de-energized.

The operator immediately realized his mistake and re-energized N2-NPS<<SWG001 in accordance with station procedures.

During the momentary loss of 13.8kv power to the house service

loads, the remaining Circulating Water (CWS) pumps were de-energi.zed.

The decrease in the Main Condenser water box level after the loss of power to the CWS pumps, prevented the immediate restart of the CWS pumps and the subsequent loss of the Main Condenser as the primary heat sink.

The SSS directed the use of the Steam Condensing mode of the Residual Heat Removal (RHS) system loop A.

The Main Steam Isolation Valves (MSIV's) were directed to be closed as the Main Condenser vacuum decreased to 10 inches of mercury.

As the inboard MSIV's were being closed, a Group I Isolation was received due to low condenser vacuum and a fast closure signal for the MSIV's was received (closing all the MSIV's).

The ICS system was used to maintain reactor vessel water level and the Steam Condensing mode of RHS was used to maintain reactor vessel pressure control.

A reactor cooldown to ambi,ent condi.tions was then performed.

Uninterruptible Power Supply 1D (UPS-1D), tripped due to an overload condition.

This resulted in a loss of approximately one half of the Gai-tronics system in the plant, a total loss of Gai-tronics in the Control Room (affecting communications wi.th plant operators outside the Control Room) and a partial loss of emergency lighting.

I I.

GA.USE. QE..XHK~T A root cause

~nalysis was performed using Site Supervisory Procedure S-SUP-1, "Root Cause Evaluation Program".

The root cause for this event was determined to be loose wire connections'n the Main Generator Potential Transformer

cubical, 2GMS-CUB01I for circuit 2SPGZ03.

This is attributed to poor installation compounded by vibration in the area of the connections.

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IIIIC FWAI 888A 15881 LICENSEE EVENT REPORT (LER) TEXT CONTINUATION U.E IIUCLEAIIAEOULATOIlyCOMMIEEIOII AttllOVEDOME IIO SI SOWIO4 LXtIIIIS 8/Sling FACILITYNAMElll DOCyt I HI MEEA IEI LE1 NUMEEII III yEAA +; EIOVIHTIAL '

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V IA EAOE III Nine Mile Point Unit 2 TDP IP'awe HM8IIIIy4MEME~ eaMNanAI HJIC AyIII~'Q 1111 0

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This event is reportable under 10CFR50.73(a)(2)(iv):

"Any event or condition that results in manual or automatic actuation of any Engineered Safety Feature (ESF), including the Reactor Protection System (RPS).

However, actuation of an ESF, including RPS, that resulted from and was part of the preplanned sequence during testing or reactor operation need not be reported."

The reactor scram was due to a turbine trip, whi.ch was in response to the actuation of a generator protecti.on relay.

The reactor scram is a protective function and therefore poses no adverse

safety consequences

The failure of the 13.8kv power board (N2-NPS-SWG003) to transfer and subsequent loss of the remaining 13.8kv power board (N2-NPS-SWG001) did not pose a threat to the health and safety of the General Public as the three (3) divisions of Emergency Core Cooling Systems (ECCS) were operable with po~er sources from off-site and Diesel Generators.

Only two of the three ECCS divisions are utilized to achieve safe shutdown.

CSH and ICS automatically initiated at L'evel 2 (108.8 inches),

to restore level as designed.

The problems that were encountered with the overload condition of UPS-1D (partial loss of communications outside the Control Room and partial loss of emergency lighting) did not compromise the safety of the general public as the safe shutdown of the plant can be achieved from the Control Room.

An evaluation of 10CFR50 Appendix R, Section III.J, "Emergency Lighting" requirements was conducted.

The evaluation concluded that there is no impact on the Appendix R safe shutdown analysis.

Engineering is, however, conducting a review of associated essential 1ight circuits to reconfirm that cable routings do not traverse openly in postulated fire areas (i.e.,

UPS-1D circuit cables through the Control Room and Relay Room areas).

If unanalyzed conditions are found, a supplement to this report wi11 be issued.

Transient recording xndicated that water level was slightly above the lowest elevation of the Main Steam Line (MSL) nozzle.

However, the level trends indicate that water level did not reach the Main Steam Line (HSL).

A firm conclusion that water did not flow down the Main Steam Lines could not be made.

However, if water flowed down the Main Steam Lines, it was for a very short duration.

Based on prior Engineering analyses performed on previous vessel overfill, the effects of potential transients created, if water had entered Hain Steam Lines, were within plant design margins.

MAC BOAV SAAA I888 I

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4 LICENSEE EVENT REPORT (LER) TEXT CONTINUATION U.t NUCLLAh h<<OULATOAY COMMISSION AtrhOYTD OMS NO SISO.OIO4 Q<<tIASS, tISIIOI TACILITYNAMt lu DOCI<<tT NVMtth Qr YTAII Lth NUMtth I~I SI OVC NYIAL NUM A

4<<VISION VVV IA

~Aot ISI NIne Mile 1'oint Unit 2

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m~xszs.azw~zxm In accordance with the requirements of Technical Specification Sections 3.5.1(f) and 6.9.2, Emergency Core Cooling System (ECCS) Injections, the following data is provided; For the HPCS nozzle, Total accumulated initiation cycles to date

= 4 Current usage factor value remains below 0.70 The duration of the event was approximately 8.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months from the time the event was initiated (1101 hours0.0127 days 0.306 hours 0.00182 weeks 4.189305e-4 months ) until the Shutdown Cooling Mode of RHS was controlling reactor temperature and pressure (approximately 1930 hours0.0223 days 0.536 hours 0.00319 weeks 7.34365e-4 months ).

CQBRKXLVXMCXIQHS Relanded the disconnected wire and tightened the other potentiai transformer connections.

The Electrical Preventative Maintenance Procedure N2-EPM-GMS-8693 will be revised to ensure the integrity of the wire connections in the areas of high vibration is checked.

3.

The Electrical Preventative Maintenance Procedures will be revised to check interlock mechanism for proper operation.

A Lessons Learned Transmittal was generated by the Operations Department to discuss the problems associ.ated with this event.

The licensed operator involved in de-energizing N2-NPS-SWG001 was counseled on self-verification and communication.

Operation Procedures have been revised to ensure visual verification of the interlock roller positions on 13.8kv breakers.

Operation Procedures have been revised to ensure that Feedwat<.l, Condensate Booster and Condensate pump power supply 1iur lrps I<<~ slp'll'Ilail for running pumps.

Operation Procedure was revised to provide improved <<lie<<.ct.io>>

f<<rr wlrter level control following a reactor scram.

The electrical loads on UPS-1D have been reduced to preve>>t a trip ou over loa<<l.

Additional modifications are being cons idel'ed t<<r 1 ur'tlrr I reduce UPS-1D loads.

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'gC APE 000A LICENSEE EVENT REPORT (LER) TEXT CONTINUATION U.S NUCLSAR RfOULATORYCOMMISSION APPROVSO OMS NO S150W104 fXPIASS, I/SlI80 PAC1LITY NAMKIll OOCRSS NUMSSR Ql VCAR LSR NUMSSR 10) 4I0 VIIITIAL

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Nine Nile Point Unit 2

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Failed Components:

1. Failed Component Identification:

Component Description:

Component Vendor:

2VBB-UPS1D Uninterruptible Power Supply for Station Lighting/Communication Exide Power Systems Division

2. Failed Component Identification: 2NPS-SMP-003-1 Component Description:

3000 Amp Breaker Component Vendor:

General Electric Company Nine Nile Point Unit 2 has not experienced a reactor scram caused by a

similar event.

NWC PQIIM 0444 (04Lll 4 U 5 GPO 1000 0 0P ~ 030 400

(, Nf)NtAGARA EOP EVALUATIONREQUEST tern e nit Qt H2 C

/tip-eo/ - c'5 Ravimn Solon 8te p No.

P age Nc.

Panty Qt K<2 I

Oue Date Disc"vered during:

Q Ccntrol Rocm Use QPericdic Review CICcntrcl Ream W/T QTraining

@Simulator

+~Other Discrepency / Suggested Change K&Wik-,

commitment

Quality Assurance could find no controlled document that satisfied this commitment as the Appendix A to the Page 4 of 29

PSTG indicates that BWROG steps are not applicable. It appears that Appendix A would be the proper place to address deviations in unit 2 EOP-MSL from the BWROG recommendations contained in NEDO 30324.

AI-1.0, Rev.00 "Site Writer's Guide" section 7.0b "Unit 2

Emergency Operating Procedures" needs to be updated to reflect the current organization with respect to the approval block.

N2-ODI-5.10 Rev.0 "EOP ongoing evaluation program" states in section 2.2.d "S-SUP-4, Procedure Evaluation Request" provide a method for the procedure user to request corrections,

changes, or improvements to existing procedures".

This suggest that the S-SUP-4 process is to be used to address concerns with Unit-2 EOP's.

Later in the procedure, a

new process for addressing concerns with the Unit 2

EOP's is described including a

new form. why is a new process necessary to evaluate concerns with the Unit 2 EOP's7 It is not clear which of the processes is the preferred one to use.

The S-SUP-4 procedure needs to be modified to address the changes described in this procedure.

N2-MSL PSTG step MSL-3 is not contingent on step which states "operate available SJAE's through Off-Gas". This should be a

separate step IAW AI-1.0 "Site Writer's Guide" section 7.0b.

Plexiglas in the unit 2 control room for RPV Control EOP is broken and should be replaced.

EOP-6 Attachment 26 first note should include two PA 2235 keys as required by step 26.2.1, these keys are required to be removed in step 26.2.7.c.

Page 5 of 29

The following is a list of the items assessed and their responses:

Review was performed by comparing the Generic Technical Guidelines (EPG) to the Plant Specific Technical Guidelines (PSTG) and ensuring the EOP's were in compliance.

The following EOP's were reviewed during this portion of the assessment:

Primary Containment Hydrogen Control MSIV Leakage Control Reactor Pressure Vessel Control Contingencies C2, C3, C5, C6 Item Assessed:

Compare the generic Technical Guidelines (EPG) index to the index of Plant Specific Technical Guidelines (PSTG's) and evaluate the differences.

Response

Made comparison and discovered that MSIV Leakage Control was in the PSTG but not in the EPG.

This is a new procedure that wasn' included in the BWR Owners Group Revision 4 guidelines.

This procedure, came from NEDO 30324 and was committed to in a letter from C'. Mangan to the US NRC (NMP2L 1020).

Item Assessed:

Review documentation.

addressing development of Plant Specific Technical Guidelines,PSTG.

Response

The above listed documentation was reviewed for any variations, deviations and adequate justifications.

Item Assessed:

Review questions on incorporation of EPG's into EOP's with operations.

Response

Reviewed all concerns and questions with Unit 2 EOP Coordinator.

Page 6 of 29

Item Assessed:

Verify appropriate prioritization of accidents mitigation strategies in the procedures.

Response

Satisfactory prioritization was evaluated based on compliance with the EPG's.

Deviation and verifications were evaluated to ensure that prioritization of accident mitigation strategies did not deviate from those in the EPG's.

Item Assessed:

Verify recommended vendor sequence is followed.

Response

Compared the EPG's with the PSTG's and EOP's and found that the recommended vendor sequence was followed in most cases and in those cases when it wasn t, adequate justification was provided.

Item Assessed:

Verify entry points are correct.

Response

All entry points checked were in agreement with the EPG's the only differences noted were necessary changes made to make the entry points plant specific.

Item Assessed:

Verify entry points are easily followed.

Response

Entry points were easily followed.

Item Assessed:

Verify exit points are correct.

Response

When exit points were

provided, they appeared appropriate and consistent with the EPG's.

Page 7 of 29

Item Assessed:

Verify exit points are easily followed.

Response

When exit points were

provided, they appeared appropriate and consistent with the EPG's.

Item Assessed:

Verify transition points are correct.

Response

Transition points were in agreement with the EPG's with exceptions justified.

Item Assessed:

Verify transition points are easily followed.

Response

Transition points were easily followed within the same EOP and from EOP to EOP.

Item Assessed:

Verify transition points are well defined.

Response

Transition points are well defined.

Items Assessed:

Verify that major identified deviations have adequate justification.

Response

All major identified deviations have adequate justification.

Some of the minor deviations did not have any justification.

Example:

a.

Wording in purpose for PSTG is different from EPG with no justification.

Page 8 of 29

b.

Condensate Transfer was added to PSTG step RC/2-3, this deviates from EPG and no justification has been provided.

c.

Step C6-3 of the EOP contains a caution step and instruction to use Fuel Zone Instrumentation, these items are not in the PSTG.

d.

PSTG adds defeating of interlocks, which deviates from EPG.

This deviation is explained,

however, the interlock defeat is not in PCH steps of the EOP and this is not explained in the EOP variance.

e.

MSIV Leakage Control EOP contains a variance (unisolated mode/normal mode) between the EOP and PSTG on page 182 of attachment 182 of the safety evaluation.

A statement is made on page 182 that there is no variance.

f.

'EOP RC/P-2 requires 2IAS*SOV164,

165, 166 184 to be reopened if necessary, this is not mentioned. in the PSTG or EOP variance in attachment 8 of the safety evaluation.

Item Assessed:

Determine if safety significant deviations were reported to the NRC.

Response

No safety significant deviations were identified in the reviewed procedures.

Item Assessed:

Ensure that safety significant deviations had safety evaluations performed per 10 CFR50.59.

Response

Reviewed safety evaluation for Revision 4 of the EPG's.

There was no identification or question. of an unreviewed safety question.

Item Assessed:

Determine if any deviations, warranted by the plant specific

design, are not incorporated into the EOP's.

Response

During this review no deviations, warranted by plant design, were found not to be incorporated.

Page 9 of 29

Item Assessed:

Select 5 plant specific values from the procedure reviewed and determine by review of the setpoint documentation that the values are correct.

Response

Reviewed the setpoints of PC/H against setpoint documentation for correctness.

A conflict was discovered in steps PC/H 2.1, 2.2, 3.1, 3.2 and N2-OP-62 step D.5.0 which defines the maximum 0,

concentratioq as 2.5% with greater than 5% H,.

The PC/H steps allow up to 5% 0, with H, greater than 5%.

Item Assessed:

Determine if adverse containment values are provided.

Response

Adverse containment values are present throughout primary containment control EOP's.

Item Assessed:

Verify that setpoint changes are supported by setpoint documentation.

Response

Reviewed the setpoints of PC/H against the EPG's.

Justification was contained in the PSTG for adequacy and identification.

Item Assessed:

Determine that the use of notes and cautions are correct.

Response

In RPV control, some cautions were incorporated into the steps this goes against the philosophy of Revision 4 of the BWROG EPG which is to have the cautions stand out.

Item Assessed:

Confirm that cautions identify potential hazards.

Page 10 of 29

P4

Response

Cautions used were the same found in the EPG's and were used in the locations specified in the EPG's, any deviations were justified.

Item Assessed:

Determine that no actions are found in either notes or cautions.

Response

No actions were found in the cautions and notes reviewed in the above listed procedures.

Item Assessed:

Evaluate the descriminability of decision points.

Response

There were no problems noted with the descriminability of decision points.

Item Assessed:

Evaluate the clarity of decision points.

Response

There were no problems noted with decision points.

Item Assessed:

Determine the extent of deviations of the procedures from the current plant writers guide.

Response

Reviewed PC/H and MSL against the requirements of AI-1.0 Rev.

0 "Site Writer's Guide" section 7.0.B "Unit 2 Emergency Operating Procedures".

The review revealed that the Site Writers Guide needs to be updated to reflect the current organization with respect to the approval block.

Page 11 of 29

Item Assessed:

Evaluate the procedures and the plant writer's guide in light of any other significant Human Factors Issues with structure and format.

Response

A review of the EOP's and Site Writers Guide did not reveal any significant Human Factors Issues.

USE OF EOP~S IN THE PLANT CONTROL ROOM Item Assessed:

a. Physical condition of the EOP's good.

Response

The EOP's are under Plexiglas or laminated with cardboard backing.

The EOP covers are clear with no confusing marks.

The RPV Control EOP has a tom corner and frayed edge this did not cause the EOP to be unreadable.

The Plexiglas in the area of the RPV Control EOP is broken and should be replaced.

Item Assessed:

b. Pencils and pens available.

Response

Color makers are used by the SSS and ASSS to keep their places in the EOP's.

Each person uses a different color marker.

Item Assessed:

c. Table space adequate and appropriate.

Response

Not sufficient space to lay out all EOP's at the same time, but space is sufficient for working with the EOP's and'ocation is good for using the EOP's.

Page 12 of 29

Item Assessed:

d. Control room environmental factors do not adversely effect the implementation of procedures (temperature, lighting, noise levels, etc.)

Response

Lighting excellent, temperature good noise level,a little high (due to outage in progress).

Item Assessed:

Do the units of measure in the EOP's match those used on the control boards?

Response

Searched all EOP's for parameters that were required to be measured.

All units matched those used on the control boards..

Item Assessed:

Are the needed controls/displays available and usable (scale selection, range and units consistent with procedure requirements)?

Response

All controls/displays were available and usable.

Scale selection and units were consistent with procedure requirements.

The ranges in some instruments were less than was indicated by the EOP figures.

In those cases the graphs stopped at the point where the instrumentation range stopped.

Item Assessed:

Are control positions easily recognized?

'Response:

No problem was noted in control position recognition.

Item Assessed:

Is location information adequate?

Page 13 of 29

Response

EOP-6 di'rects operation in the plant.

EOP"6 appears to rely on operators knowledge of the plant instead of spelling out any locations.

Item Assessed."

Are staffing. levels adequate to perform procedures?

Response

The normal control room manning was sufficient to perform all actions required by the EOP's.

Item Assessed:

Are roles and responsibilities clearly defined?

Response

N2-0DI-1.08 Rev.

4 "Operating Policy For Emergency.

Procedures",

and N2-ODI-1.09 Rev.

4 "EOP Users Guide" provide explicit guidance on roles and responsibilities.

Item Assessed:

Are there any difficulties in interfacing with departments outside the control room?

Response

No concerns were identified.

Item Assessed:

For the procedure being executed, accident'onditions could create a situation where the operator cannot carry out his actions at the local control station, due to risks to personnel and/or equipment.

Response

I EOP-6 does not identify potential situations where operators could be impeded in the performance of their duties due to risks to personnel and/or equipment.

Page 14 of 29

Item Assessed:

Does the procedure identify safety issues related to performing local actions?

Response

EOP-6 does not identify potential situations where operators could be impeded in the performance of their duties due to risks to personnel and/or equipment.

Item Assessed:

Is a procedure available to the operator performing local actions?

Response

The applicable OP was available to the operator at the local stations

however, EOP-6 was not available at the local stations for performance of RWCU Boron Injection and Defeating HVR LOCA Isolation Signals.

Item Assessed:

What is the location of local control station procedures?

Response

The procedures are in the vicinity of the local control panels.

Item Assessed:

Are additional procedures/operator aids (diagrams) needed at local control stations?

Response

Yes, EOP-6 is needed at the RWCU control panel and the local HVR control panel.

Item Assessed:

Are personnel available and appropriate?

Response

i Yes, personnel are available, an E operator should be present on any EOP operations in the plant.

Page 15 of 29

Item Assessed:

Are controls and displays at local site accessible?

Response

Controls and displays were accessible.

Item Assessed:

Are local controls and equipment operable?

Response

All equipment simulated in this assessment was operable.

Item Assessed:

Is vital equipment operable?

Response

All simulated equipment was operable.

Item Assessed:

A failure in. the "local environment prevents operator from taking action, if so what are the potential consequences?

Response

In defeating the HVR interlocks, the HVR ventilation could not be restarted and the STGTS would have to left on the line to maintain a negative pressure in the reactor building.

Response

In the RWCU boron injection, this is a multiple failure situation.

Both SLS pumps would have had to fail, the hydro pump injection method would be unavailable and an environmental condition would have to be present to prevent the use of RWCU. If this happens there is no other method of injecting boron into the vessel identified in the EOP's.

Item Assessed:

Are adequate tools available?

Page 16 of 29

Response

Procedure (EOP-6 attachment

19) requires exact weights for boric acid and borax however, there is no method provided to weigh it out.

The Borax and Boric Acid should be located on station instead of picking it up from stores..

Step 19.9.f directs the operator to step F.5.4 of.OP-37.

The note prior to 5.4 requires the key lock switch to be positioned to System A or B.

This requires a

PA 2235 key, attachment 19 does not point out that this key is needed.

Response

Attachment 26 first note should also include 2

PA 2235 keys as required by step 26.2.1, these keys are required to be removed in step 26.2.7.c.

Item Assessed:

Is protective clothing accessible?

Response

RWCU boron injection (EOP-6 attachment

19) required gloves, long sleeve shirts and eye protection, none of these items are available at the local operating station.

Item Assessed; Can local actions be performed when dressed out?

Response

Local actions could be performed when dressed out however, a dress out was not performed during the simulations.

Item Assessed:

Is means of communications usable under existing conditions?

Response

The means of 'communications would be a radio, communications with the control room by radio was not observed.

Item Assessed:

Is means of. communication convenient to the user?

Page 17 of 29

Response

The operator stated he would not have any problem with using the radio for communications.

PERFORMANCE OF EOP'S IN THE SIMULATOR The following scenarios were observed:

02-REQ-009-TRA-2-06 REV.1 "HIGH POWER ATWS WITH MSIV CLOSURE" 02-REQ-009-TRA-2-10 REV.1 "SMALL STEAM LEAK IN DRYWELL (WHICH WORSENS)/NOT ALL RODS IN" 02-REQ-009-TRA-2-24 REV.1 "OFF-SITE RADIOACTIVITYRELEASE" 02-REQ-009-TRA-2-16 REV.1 "LOSS OF ALL HIGH PRESSURE INJECTION SYSTEMS" Items Assessed:

Are operators able to quickly and accurately access specific EOP's?

Response

EOP access was quick and accurate.

Item Assessed:

Is the table space adequate and appropriate?

Response

Adequate space is available for EOP's Item Assessed:

Are logic statements clearly understood?

Response

No problems noted with logic statements.

Item Assessment:

Are step and section numbering clear?

Page 18 of 29

Response

Sections are clearly marked, but there is no step numbering as EOP's are in flow chart'ormat.

Reference points for moving around within the EOP and from EOP to EOP are clearly marked and easily followed.

Item Assessed:

Do operators have difficulty in making transitions within and between procedures?

Response

The SSS was able to make transitions'ithin and between procedures with no difficulties noted.

Item Assessed:

Is concurrent use vs. independent use of procedures clear?

Response

Steps that are to be performed concurrently are clearly marked.

Items Assessed:

Are place keeping aids used between and with in procedures?

Response

Colored markers are used to keep place with in EOP's.

Items Assessed:

When place keeping is provided for high-level steps

only, do operators have difficulty in keeping their places in= low-level steps?

Response

ID There was no difficultynoted of operators keeping their places in any EOP step irreguardless of the steps importance.

Items Assessed:

Does physical interference exist between operators?

Page 19 of 29

Response

The operators all had stations they went to, there was no physical interference noted between operators.

At one point, the CSO was using the phone from the P603 panel and had the cord stretched out to the back of the computer console.

This created a trip hazard for the operator that was moving from the 851 panel to the back panels.

Items Assessed:

Are there any unnecessary duplication of operator actions?

Response

At one point, the SSS was having the same parameter reported by two different people.

This was not the fault of the EOP's and was brought to the attention of the SSS by the training instructor.

He suggested that the SSS designate one individual to keep him of any particular parameter he wanted monitored.

Item Assessed:

Are operators able to move easily about the control room?

Response

Movement about the control room was easy and was minimized.

Item Assessed:

Are non sequential steps performed correctly?

Response

not observed Item Assessed:

Are recurrent steps performed at correct intervals?

Response

not observed Page 20 of 29

Pg, Item Assessed:

Are time-dependent steps performed when necessary?

Response

not observed Item Assessed:

Are continuously monitored steps adequately addressed?

Response

Operators monitored parameters continuously that were required by EOP's.

Item Assessed:

Are critical safety functions monitored?

Response

Yes, power, level,

pressure, radiation levels, Suppression pool temperature/level, and Dry Well pressure.

Item Assessed:

Were there any deviations from written procedures? If so, what and why?

Response

'EOP MSL does not adequately address/prevent de-pressurization of the RPV to the Main Condenser.

As a result, a current operating crew was observed to have erroneously de-pressurized to the main Condenser with indication of Gross Fuel Element Failure.

When questioned, the training instructor indicated that numerous current licensed operating crews have made the same error.

Item Assessed:

Communication between procedure reader and operator understood?

Problem Sources

.Inadequacy of content of oral communication

.Interference from noise (HVAC, alarms, other conversation)

Page 21 of 29

4

Response

I Repeat backs were made by the operators.

The operators ensured that the SSS acknowledged their communications and repeated if necessary to get an acknowledgment.

Response

Oral communication was good, with only one discrepancy noted.

The CSO asked for water level and the parameter value was given by the 601 panel operator without identifying which parameter he was giving the value for.

This only occurred once all other times both the parameter and value were given.

Response

Alarms were the main source of noise, the ASSS informed every one and then went to master silence to keep the noise level down.

Item Assessed:

Action or consequence of communications between procedure reader and operators acknowledged.

f Response:

Yes, at a point early in EOP all operators were giving input to the SSS.

The SSS acknowledged what he could and operators repeated what he apparently had missed.

Item Assessed:

What are the user attitudes toward procedures (e.g.

operators perform steps before being instructed or abandon procedures before finished)

Response

Operators had a

good attitude towards the EOP's.

They had a

discussion on EOP-6 after their first scenario where the instructor asked for any better solutions or ways that could improve EOP-6 to be inputted to the EOP procedure writer.

Item Assessed:

a Are cooperation and team work apparent?

Page 22 of 29

Q,

Response

Yes, good communications.

ASSS kept SSS well informed.

Operators worked well together.

Item Assessed:

Verify mindsets do not exist which jeopardizes plant safety (e.g.,

reluctance or refusal to borate when required by procedure)

Response

There was no reluctance to perform any steps in the procedure.

Ask control room staff about their training on the procedures being used (issues 'ddressed,

,recency, frequency),

especially when problems are encountered.

Response

Regarding EOP-6, the operator questioned stated he had read the procedure but received no formal training on that procedure.

3 VERIFICATION AND VALIDATION The following scenarios were observed:

02-REQ-009-TRA-2-06 REV.1 nHIGH POWER ATWS WITH MSIV CLOSUREn 02-REQ-009-TRA-2-10 REV.1 "SMALL STEAM LEAK IN DRYWELL (WHICH WORSENS)/NOT ALL RODS IN" 02-REQ-009-TRA-2-24 REV 1 irOFF SITE RADIOACTIVITYRELEASEn 02-REQ-009-TRA-2-16 REV.1 "LOSS OF ALL HIGH PRESSURE INJECTION SYSTEMS" Observe EOP exercises on the simulator using an actual operating crew (not technical staff personnel)

Item Assessed:

Determine that the procedures provide operators with sufficient guidance such that their responsibilities and required actions during the emergencies, both individually and as a team are clearly outlined.

Page 23 of 29

Response

Sufficient guidance exists to provide operators with their responsibilities and required actions during the emergencies.

Item Assessed:

Focus on identified areas of concern about usability (examples excessive transitions)

Response

N2-EOP-6 attachment 14 had to be 'changed as a do loop existed in the flowchart if the scram solenoids could not be deenergized.

Response

EOP MSL does not adequately address/prevent depressurization of the RPV to the main condenser with MSIV's stuck open and a fuel element failures demonstrated during this observation period.

When the training instructor, when questioned, indicated that numerous current licensed operating crew made the same error.'tem Assessed:

Verify that when a transition from one EOP to another EOP or other procedures is required, precautions are taken to ensure that all necessary

steps, prerequisites, initial conditions, etc.,

are met or completed and that operators are knowledgeable about where to enter and exit the procedures.

Response

No concerns were identified during this assessment.

Item Assessed:

Note any activities that would occur outside the control room based on the scenario as presented and follow up as appropriate.

Response

Activities occurring outside the control room were performed by training personnel.

Item Assessed:

Audit the EOP Lesson Plans for technical adequacy.

Page 24-of 29

Response

Review of referenced lesson plans revealed no concerns.

Item Assessed:

Ensure training covers technical basis.

Response

Not observed.

Item Assessed:

Ensure training covers structure and format.

Response

Not observed (covered during classroom training).

Item Assessed:

Ensure that simulator scenarios used during training sufficiently covered all EOP's and that multiple malfunctions are included.

Response

No concerns were identified during this assessment.

Ensure that operator's received training on revised EOP's prior to implementation.

EOP-6 Attachment 19 did not receive sufficient training issuance.

One operator informed the assessor that he required to read the attachment prior to issuance

but, received any training.

prior to had been had not LONG TERM EVALUATION PROGRAM FOR THE EOPiS Determine if the program provides as adequate system to ensuring technical adequacy by factoring the following factors:

Item Assessed:

Operating Experience Page 25 of 29

Response

No concerns were identified during this assessment.

Item Assessed:

Training Experience

Response

No concerns were identified during this'ssessment.

Item Assessed:

Simulator Exercised

Response

No concerns were identified during this assessment.

Item Assessed:

Control Room Walk Through

Response

No concerns were identified during this assessment.

Item Assessed:

In Plant Design

Response

The EOP coordinator identified a weakness in that modifications, changes in plant design and changes in unit operating license are not presently being appropriately evaluated for impact on the EOP's.

Currently changes are being made to the process to provide adequate controls in the process.

Item Assessed:

Changes In Technical Specifications

Response

No concerns were identified during this assessment.

Page 26 of 29

Item Assessed:

Changes In Technical Guidelines

Response

No concerns were identified during this assessment.

Item Assessed:

The Site Writer's Guide

Response

No concerns were identified during this assessment.

Item Assessed:

Other Plant Procedures

Response

No concerns were identified during this assessment.

Determine if the program provides as adequate system to ensuring structure quality by factoring the following factors:

Item Assessed:

Operating Experience

Response

No concerns were identified during this assessment.

Item Assessed:

Training Experience

Response

No concerns were identified during this assessment.

Item Assessed:

Simulator Exercised I

Page 27 of 29

Response

No concerns were identified during this assessment.

Item Assessed:

Control Room Walk Through

Response

No concerns were identified during this assessment.

Item Assessed:

Changes in plant design

Response

No concerns were identified during this assessment.

V Item Assessed:

Changes In Technical Specifications

Response

No concerns were identified during this assessment.

Item Assessed:

Changes In Technical Guidelines

Response

No concerns were identified during this assessment.

Item Assessed:

The Site Wr'iter's Guide

Response

No concerns were identified during this assessment.

Item Assessed:

Other Plant Procedures Page 28 of 29

Response

No concerns were identified during this assessment.

Page 29 of 29

C

TO J.G. Burton INTERNALCORRESPONDENCE FOAM 112 2 A 0240 66 01 013 FROM J.B. Helker N

Y NIASARA U MOHAWK DISTRICT Nine Mile Point DATE February 5

Z9 9I Fl!.E CODE UNIT 2 EOP PROGRAM ASSESSMENT Attached are Operations Department responses to weaknesses and concerns identified during the QA Assessment of NMP2 EOP program.

All items have either been corrected or if further evaluation or long term fixes are required added to our ongoing evaluation program.

Thank you for a comprehensive evaluation and congratulations on a positive response from the NRC during their EOP inspection.

If you have any questions or comments, please contact me at extension 7523.

J..

elker Operations Supervisor JBH/da Attachment xc:

M.J.

Colomb

4

~"

1l

QA Assessment of NMP2 EOPs (Rev.

4)

NOTED WEAKNESSES Training for EOP-6 Attachment 19 was not adequate prior to the.procedure being issued.

2.

~Res onse N2-EOP-6 was covered in cycles 8 and 9 as part of procedure changes.

Since the majority of the procedure is taken directly from Operating Procedure (OP) off-normal sections in depth training was not provided.

Several operators over the past couple of weeks have

=requested additional training specifically on EOP-6 attachments.

A TMR has been submitted to training.

Additional training will be conducted.

EOP-6 Attachment 19 has several technical inadequacies.

3.

~Res onse This comment will be addressed in the concerns section for specific items.

Justification not provided in all cases for deviations between the EPG's and PSTG's.

R~es o se This will be addressed in the concerns section for specific items.

4.

EOP MSL does not adequately address/prevent de-pressurization of the RPV to the main condenser with a gross fuel element failure.

~Res onse See response to item B.28.

NOTED CONCERNS In RPV Control some cautions wexe incorporated into the steps.

This goes against the philosophy of revision 4 of the BWROG EPG's which is that the cautions stand out.

~Res onse No cautions in RPV Control have been incorporated into the steps as notes (with hand pointers).

Cautions however are incorporated directly into the steps to which they apply as specified by N2-EOP-5 (Rev.

1) Appendix A.

Placing cautions directly in the flowpaths is also sanctioned by NUREG/CR 5228 Section 13.4.

The confusion probably comes to play because the HPCS NPSH caution is formatted like a caution where the NPSH limits for other ECCS pumps is not.

This is consistent with the EPG (Rev. 4).

Also previously we had some cautions formatted as notes or supplementary information with hand pointers.

It was identified during verification that this was wrong and all were fixed.

There was one case however that we did go back to formatting a caution into a step.

That was the case of EPG caution g6 (exceeding RPV cooldown rate).

For that caution because of the nature of the caution and the problems exhibited during validation (due to being formatted as a caution) it was decided to incorporate it directly into the applicable, steps.

2 ~

N2-EOP-6 Attachment 14 had to be changed due to technical inadequacies.

A do loop currently exists in the flowchart if the scram solenoids can not be de-energized.

3 ~

~Res onse This item was previously identified by operations and'as being carried as N2-ODI-5-10 Open Item.g90-15.

N2-EOP-6, Att. 14 has been TCN'd to correct this item and open item g90-15 closed out.

EOP-6 appears to be deficient in location identification.

4 ~

R~es ense EOP-6 attachments have been validated and found to be workable.

Also ongoing training is continuing. It is expected that through training and installation of operator aids (pictures within the panel and the EOP tape) will eliminate any location problems.

As specific weaknesses are identified we will upgrade the procedure using the ongoing evaluation program.

EOP-6 does not identify or caution personnel of potential hazards and risks to themselves and/or equipment while executing specific tasks through use of'he various attachments.

B.R~es onse Where hazards specific only to a particular attachment exist these appear as cautions.

(Ex. Att. 17 Step 17.3).

For hazards of a general nature (elevated temperature, radiation levels, water levels) this information is included in the front part of N2-EOP-6 within the Purpose section.

Because the EOPs are symptomatic and it may be impossible to presuppose environmental conditions in the locations required for access and because including this general information in each attachment would tend to clutter the procedure, it was felt more appropriate to include it in the front of N2-EOP-6. It is expected that the discussions in EOP-6, the Basis Document and that training will adequately address this concern.

5.

EOP-6 was not available at local control stations for RNCU and HVR.

6.

~Res onse It is not our intent to stage EOP-6 at every place outside the control room at which actions age performed.

Currently there are five satellite master copies of EOP-6 stage outside the control room and six satellite master copies in the control room.

Should operations requiring the use of EOP-6 at the above locations be required.

The operator will obtain a copy of the procedure either from the control room or one of four staged copies in the reactor building.

EOP-6 Attachment 19 step 19.3 commas need to be replaced with dashes i.e.

1 325 container instead of 1,

325.

7 ~

geesonse This has been corrected by spelling out the word "one".

EOP-6 Attachment 19 step 19.3 the Borax and Boric Acid should be on station instead of having to pick it up from stores.

I

B.8.

R~es onse Chemistry, Operations and Warehouse personnel are coordinating an effort to stage borax and boric acid in premeasured containers locally on El 328 ft.

When this is done the need to transport and weigh material will be eliminated.

This is being carried as N2-0DI-5.10 Open Item f91-13.

EOP-6 Attachment 19 step 19.4 is confusing as the only combinations of Filter Demins are A&C, A&D, B&C, and B&D.

~Res o se This logic has been corrected.

9.

EOP-6 Attachment 19 step 19.6 should be started earlier in the procedure.

~Res onse This item needs further clarification and evaluation and will be added to N2-ODI-5.10 Open Issue f91-13.

10.

EOP-6 Attachment 19 requires gloves, long sleeve shirts and eye shields, these items are not readily available at the RWCU station.

~Res ense Gloves and eye glasses are staged in EOP tool boxes; 11.

EOP-6 Attachment 19 step 19.9:

a)

The tank is normally kept. half full, the tank will need to be drained to one quarter full.

Bees ouse This item needs further clarification and evaluation and will be added to N2-0DI-5.10 Open Issue f91-13.

b)

These steps require addition of 146 pounds and 150 pounds of chemicals.

There is no way provided to the operator for determining the weight of these chemicals.

I CA

~Res ense Chemistry, Operations and Warehouse personnel are coordinating an effort to stage borax and boric acid in premeasured containers locally on El 328 ft.,

When this is done the need to transport and weigh material will be eliminated.

This is being carried as N2-0DI-5.10 Open Item f91-13.

In the interim a scale has been staged in the room.

c)

With the level just above the drain standpipe there may not be sufficient level to keep the pump from tripping on low level.

R~es ense This item needs further clarification and evaluation and will be added to N2-0DI-5.10 Open Issue f91-13.

Preliminary discussions with the system engineer indicate that this will not be a problem.

d)

The part of the step in parenthesis should be a

note.

R~es one e The information in parenthesis provides direction and will be retained within the step.

e)

Directs operator to enter N2-OP-37 at step F5.4.

The note prior to that step requires key a lock switch to be repositioned to system A or B.

A PA 2235 key is needed to perform the operation.

There is nothing written that has the operator obtain that key.

~Res o se The requirement for a key is added to Attachment 19.

12.

EOP-6 step 19.10 requires draining of the tank after each addition, it would be quicker if the chemicals could be added with out draining.

~Res o se This item needs further evaluation and will be added to N2-0DI-5.10 Open Item f91-13.

f I

t~b 13.

EOP-6 step 19.8 will be hard to perform as N2-OP-37 states -flow can not be returned to Feed Water unless the plant is greater than 200 degrees and less than 204 power.

Also the section of the procedure referenced by 19.8 starts the pump from cold start-up conditions.

This could take up to half a shift to perform.

14..

R~es ense OP-37 is changed to provide for an exemption during use of this procedure.

Local actions specified by the procedure are not required since the system is already filled and vented.

Additionally this is not the cold system startup procedure.'ondensate Transfer was added to PSTG step RC/L-3 this is a deviation from the EPG s.

No justification was provided for this deviation.

15

'Res onse Appendix A to the PSTG has been revised to add a

justification.

See Attachment 1 to this write up.

Page 35 of Attachment 8 is missing from the safety evaluation for the EOP's.

~Res ense This page has been verified to present in the

PSTG, however is missing in the SER.

This item has been added to N2-0DI-5.10 to track for correction on next SER revision.

See Attachment 2.

16.

EOP RC/P-2 requires 2IAS*SOV164, 165,

166, 184 to be reopened if necessary, this is not mentioned in PSTG of EOP variance in Attachment 8 of the EOP safety evaluation.

If added the PSTG need to have a deviation justification.

~Res ense The words "defeat pneumatic system isolation interlocks if necessary" do already appear in the PSTG.

Also Appendix A to the PSTG does contain the deviation justification.

We have added an EOP variance however to identify that the specific valve numbers are added to the flowchart.

See Attachment 3 of this write up.

P r,

B..17 'here is a variance between the MSL EOP

& the PSTG on page 182 of Attachment 8 of the EOP safety evaluation.

One refers to The 'Normal Mode'nd the other refers to "Unisolated Mode'.

Under EOP variance it states that there is no variance.

18.

R~es onse An EOP variance is added to explain the wording change.

See Attachment 4 to this write up.

In the PCH section of Primary Containment Control the PSTG adds defeating of interlocks which deviates from the EPG.

This deviation is explained, however, the interlock defeat is not in the PCH steps of the EOP.

This is not covered in the EOP variance.

19.

~nes onse The direction to defeat interlocks is contained as part of the support procedure directing the purge operation (N2-EOP-6 Attachment 25).

The EOP variance has been strengthened to identify this (PC/H-4 and PC/H).

See Attachment 5 of this write up.

Wording in the Purpose section of the PSTG is different than the

EPG, no )ustification is provided.

~Res ense An Appendix A section has been added for the introduction section.

See Attachment 10.

20.

Typo page 286 of Attachment 8 of the EOP safety evaluation first bullet item.

es onse This has no impact on the SER or conclusions drawn in the SER therefore it will not be revised at this time.

This will however be added to N2-0DI-5.10 Issue g90-08.

The PSTG however has been corrected.

See Attachment 2.

21 ~

Tygo EOP-RR "Radioactivity Release Control" step to "isolate all primary systems..."

the all is spelled IIa 1 fl ~

J

s B.~Res ense

.This is believed to be due to the copy used for review and the reproduction process.

The correct spelling has been verified on the high quality flowcharts recently received.

22

~

Step C6-3 the EOP contains a caution step and instruction to use Fuel Zone Instrumentation.

These items are not in the PSTG.

23.

~Res onse The step instruction is justified as an EOP variance.

A reference to the caution has been added to this justification.

See Attachment 7 to this write up.

In step PC/H 4.2 it was decided to use 201 feet suppression pool level as the maximum level, this appears to be a deviation and as such should be reflected in-the PSTG step.

~Res ense Justification added to the EOP variance.

See Attachment 8 of this write up.

24.

BWROG step PC/H 4.3 is not reflected in the PSTG step, EOP-6 Attachment 25 or in the EOP's.

There is no deviation or variance to justify why it has been excluded.

25.

~Res o se Justification in EOP variance provided.

See Attachment 9 to this write up.

Step PC/H '4.4 adds an additional step to meet conditions to spray the DW with no justification in the deviation or variance sections.

~es orrse Justification in EOP variance provided.

See Attachment 9 of this write up.

S 26.

Step PC/H 2.1, 2.2, 3.1, and 3.2 conflict with the maximum Oz concentration allowed for hydrogen recombiner operation in N2-OP-62 D.5.0, which defines the maximum 0> concentration as 2.54 with greater than 54 H>.

This step allows up to 54 0> with H> greater than 54.

~Res ense This item requires further research and discussion to

'lose out. It will be carried as N2-ODI-5.10

. Open Issue f91-16.

27.

Step RC/L 2 no direction is provided for controlling pump flow to prevent damage due to NPSH.

~Res ense Direction is provided on the flowchart for all ECCS pumps except HPCS by reference to N2-EOP-6, Att. 3.

For HPCS it is intentionally not throttled due to the shape of the NPSH curve, rather this information is provided as a caution.

This is consistent with EPG (Rev.

4).

28.

EOP MSL does not adequately address/prevent de-pressurization of the RPV to the main condenser with a gross fuel element failure.

As a result a current operating crew was observed to have erroneously de-pressurized to the main condenser with indication of gross fuel element failure.

When questioned, the training instructor indicating that numerous current licensed operating crews have made the same error.

~Res onse It is acceptable to depressurize to the condenser when specifically directed to do so by defeating interlocks.

In these cases (and there are only two, from C2 and C6) this is done irrespective of the, resulting release rate.

In the cases cited above the MSIVs had failed to close and the operators although were not to procedurally authorized used this flowpath did intentionally use the turbine bypass valves.

N2-EOP-MSL directs that the MSIVs be verified closed this means to check the action and if required make it happen.

This definition which means to manually initiate the action is consistent with NUREG/CR 5228 Section 13.2.1.

The procedure is technically correct, however the operator in this scenario made an error in judgement.-

Since this has been a recurring problem and there does not appear to be a simple good way to procedurally address this item a TMR has been issued to ensure operators are trained on this concept.

Unless specifically authorized to defeat radiation interlocks and release irrespective of the resulting release rate you should not utilize a flowpath which should have hut did not isolate

.This can apply to both MSIVs and CPS valves.

If you are specifically authorized, then you no longer meet the entry conditions for MSL and thus there is no conflict.

Additionally this item has previously been identified and is being carried as N2-ODI-5.10 Open Item f90-13.

29.

In letter from C.

Mangan to the U.S.

NRC it was committed that, "prior to initial criticality, that Unit 2 operating and/or Emergency Operating Procedures will be updated to address each recommendation of the BWROG as contained in NEDO 30324, except for those relating to a leakage control system".

Contrary to this commitment Quality Assurance could find no controlled document that satisfied this commitment as the Appendix A to the PSTG indicates that BWROG. steps are not applicable.

It appears that Appendix A would be the proper place to address deviations in Unit 2 EOP-MSL from the BWROG recommendations contained in NEDO 30324.

~Res ense This will be considered for next PSTG/EOP revision.

N2-0DI-5.10 Open Issue g91-2 issued to track.

30.

AI-1.0, Rev.

00 "Site Writer's Guide" section 7.0B "Unit 2 Emergency Operating Procedures" needs to be updated to reflect the current organization 'with respect to the approval block.

B.31 ~

RResRonse An S-SUP-4 has previously been issued to update AI-1.0 section 7B in its entirety.

See Attachment 11.

N2-0DI-5.10 Rev.

0 "EOP ongoing evaluation program" states in section 2.2D "S-SUP-4, Procedure Evaluation Request" provide a method for the procedure user to request corrections,

changes, or improvements to existing procedures".

This suggest that the S-SUP-4 process is to be used to address concerns with Unit-2 EOP's.

Later in the procedure, a new process for addressing concerns with the Unit 2 EOP's is described including a new form.'hy is a new process necessary to evaluate concerns with the Unit 2 EOP's? It is not clear which of the processes is the preferred one to use.

The S-SUP-4 procedure needs to be modified to address the changes described in this procedure.

~Res onse N2-0DI-5.10 is specifically geared toward EOP and EOP related items.

S-SUP-4 is generic in nature.

Either procedure (and others Problem Report, Mod

Request, Training Mod Request) can be used to initiate a concern.

N2-0DI-5.10 however is used to track EOP concerns.

It contains much more detailed guidance on disposition of items.

For operating department procedures the N2-ODI-5.10 form receives a higher level of review on initiation than that of S-SUP-4's.

I do not believe it would be practical to upgrade S-SUP-4 to address all of the specific information contained in N2-ODI-5.10 at this time.

32.

N2-MSL PSTG step MSL-3 is not contingent on step which states "operate available SJAE's through Off-Gas".

This should be a separate step IAW AI-1.0 "Site Writer's Guide" section 7.0B.

es onse The observation is technically correct.

However, since it will not impact procedure use it will not be changed right, away.

Rather N2-ODI-5.10 Open Item f91-3 is written to correct it next revision.

33.

Plexiglass in the Unit 2 control room for RPV Control EOP is broken and should be replaced.

B.~Res ense New nonglare plexiglass has been staged in both the control room and simulator.

34.

EOP-6 Attachment 26 first note should include two PIA 2235 keys as required by step 26.2.1, these keys are required to be removed in step 26.2.7.c.

~Res onse N2-EOP-6 has been TCN'd to address these concerns.

C.

EMERGENCY OPERATING PROCEDURE REVZEW 1 ~

Review was performed by comparing the Generic Technical Guidelines (EPG) to the Plant Specific Technical Guidelines (PSTG) and ensuring the EOP's were in compliance.

The following EOP's were reviewed during this portion of the assessment:

- Primary Containment Hydrogen Control

- MSIV Leakage Control

- Reactor Pressure Vessel Control

- Contingencies C2, C3, C5, C6 2 ~

~Res onse Not Required.

Compare the generic Technical Guidelines (EPG) index to the index of Plant Specific Technical Guidelines (PSTG's) and evaluate the differences.

- Made comparison and discovered that MS?V Leakage Control was in the PSTG but not in the EPG.

This a is new procedure that wasn't included in the BWR Owners Group Revision 4 guidelines.

This procedure came from NEDO 30324 and was committed to in a letter C. Mangan to the US NRC (NMP2L 1020).

es onse 3.

Not Required.

Review documentation addressing development of Plant Specific Technical Guidelines PSTG.

- The above listed documentation was reviewed for any variations, deviations and adequate justifications.

NI I

k n

4

C.

EMERGENCY OPERATING PROCEDURE4.

~Res ense Not'equired.

Review questions on incorporation of EPG's into EOP's with operations.

- Reviewed all concerns and questions with Unit 2 EOP Coordinator.

~Res ense 5.

Not Required.

Verify appropriate prioritization of accidents mitigation strategies in the procedures.

- Satisfactory prioritization was evaluated based on compliance with the EPG's.

Deviation and verifications were evaluated to ensure that prioritization of accident mitigation strategies did not deviate from those in the EPG's.

6.

R~es ense Not Required.

Verify recommended vendor sequence is followed.

- Compared the EPG.'s with the PSTG's and EOP's and found that the recommended vendor sequence was followed in most cases and in those cases when it wasn't adequate justification was provided.

7 ~

~Res o se Not Required.

Verify entry points are correct.

- All entry points checked were in agreement with the EPG's the only differences noted were necessary changes made to make the entry points plant specific.

~Res o se Not Required.

I

EMERG CY OPERATING PROCEDURE8.

Verify entry points are easily followed.

- Entry points were easily followed.

R~es onse Not Required.

9.

Verify exit points are correct.

- When exit points were provided they appeared appropriate and consistent with the EPG's.

~Res ense Not Required.

10.

Verify exit points are easily followed.

- When exit points were provided they appeared appropriate and consistent with the EPG's.

~Res ense Not Required.

11.

Verify transition points are correct.

- Transition points were in agreement with the EPG's with exceptions justified.

~Res onse Not Required.

12.

Verify transition points are easily followed.

- Transition points were easily followed within the same EOP and from HOP to EOP.

~Res ~os Not Required.

13.

Verify transition points are well defined.

- Transition points are well defined.

l I

4 A

EMERGENCY OPERATING PROCEDURE~Res e se Not Required.

14.

Verify that major identified deviations have adequate justification.

- All major identified deviations have adequate justification.

Some of the minor deviations did not have adequate or any justification.

ie.

a)

Wording in purpose for PSTG is different from EPG with no justification.

b)

Condensate Transfer was added to PSTG step RC/2-3 this deviates from EPG and no justification has been provided.

c)

Step C6-3 of the EOP contains a caution step and instruction to use Fuel Zone Instrumentation, these items are not in the PSTG.

d)

PSTG adds defeating of interlocks which deviates from EPG this deviation is explained.

However, the interlock defeat is not in PCH steps of the EOP and this is not explained in the EOP variance.

e)

MSIV Leakage Control there is a variance between the EOP and PSTG on page 182 of attachment 8 of the safety evaluation a statement is also made on this page there is no variance.

(The variance is unisolated mode one place normal mode the other.)

f)

EOP RC/P-2 requires 2IAS*SOV164, 165, 166

& 184 to be reopened, if necessary this is not mentioned in the PSTG or EOP variance in attachment 8 of the safety evaluation.'eeso~se Each of the above items in C.14 have been addressed by adding PSTG Appendix A discussions.

See attachments 1,

3, 4, 7, 8, 9 and 10.

15.

Determine if safety significant deviations were reported to the NRC.

- Identified no safety significant deviations in the reviewed procedures.

I J

CI'

EMERGENCY OPERATING PROCEDURE~Res onse Not Required.

16.

Ensure that safety significant deviations had safety evaluations performed per 10 CFR50.59.

- Reviewed safety evaluation for Revision 4 of the EPG's with no identification or question of an unreviewed safety question.

~Res ense Not Required.

17.

Determine if any deviations warranted by the plant specific design are not incorporated into the EOP's.

- During this review no deviations warranted by plant design were found not to be incorporated.

~Res onse Not Required.

18.

Select 5 plant specific values from the procedure reviewed and determine by review of the setpoint documentation that the values are correct.

- Reviewed the setpoints of PC/H against setpoint documentation for correctness.

A conflict was discovered in steps PC/H 2.1, 2.2, 3.1, 3.2 and N2-OP-62 step D.5.0 which defines the maximum 0~

concentration as 2.5% with greater than 5% Hz.

The PC/H steps allow up to 54 Oz with Hz greater that 54.

~Res o se See response to item B.26.

19.

Determine if adverse containment values are provided.

- Adverse containment values are present throughout primary containment control EOP's.

I

~Res onse Not Required.

20.

Verify that setpoint changes are supported by setpoint documentation.

- Reviewed the setpoints of PC/H against the EPG's and justification contained in the PSTG for adequacy and identification.

~Res ense Not Required.

21.

Determine that the use of notes and cautions are correct.

- In RPV control some cautions were incorporated into the steps this goes against the philosophy of Revision 4 of the BWROG EPG which is to the cautions stand out.

~Re ense See response to Noted Concerns, Item B.1.

22.

Confirm that cautions identify potential hazards.

- Cautions used were the same found in the EPG's and were used in the locations specified in the EPG's any deviations were justified.

~Res ense Not Required.

23.

Determine that no actions are found in either notes or cautions.

- No,actions were noted in the cautions and notes reviewed in the above listed procedures.

E~es ouse Not Required.

24.

Evaluate the discriminability of decision points.

- There were no problems noted with the discriminability of decision points.

N

EMERGENCY OPERATING PROCEDUREgeesonse Not Required.

25.

Evaluate the clarity of decision points.

- There were no problems noted with decision points.

~Res o se Not Required.

26.

Determine the extent of deviations of the procedures from the current plant writer's guide.

- Reviewed PC/H and MSL against the requirements of AI-1.0 Rev.

0 "Site Writer's Guide" section 7.0B "Unit 2 Emergency Operating Procedures".

The review revealed that the Site Writer's Guide needs to be updated to reflect the current organization with respect to the approval block.

~Res o se An S-SUP-4 has previously been submitted to have AI 1.0 Rev.

0, Section 7.0B, upgraded in its entirety to match N2-EOP-5 "NMP2 Production and control of EOP Revisions.

See attachment 11.

27.

Evaluate the procedures and the plant writer's guide in light of any other significant Human Factors Issues with structure and,format.

I

- A review of the EOP's and Site Writers Guide did not reveal any significant Human Factors Issues.

~es ense Not Required.

USE OP EOP'S I THE PlANT 1.

CONTROL ROOM a)

Physical condition of the EOP's good.

CONTROL ROOM (continued)

- The EOP's are under Plexiglass or laminated with cardboard backing.

The EOP covers are clear with no confusing marks.

The RPV Control EOP has a tom corner and frayed edge this did not cause the EOP to be unreadable.

The Plexiglass in the area of the RPV Control EOP is broken and should be replaced.

~Res onse New nonglare plexiglass has been staged in the control room and simulator.

Additionally a double layer is used in the control room to support the procedure underneath where they previously overlapped the benchboard.

This will help reduce fraying on "RPV Control".

The double layer is not required in the Simulator because the benchboard is physically larger.

~Res onse b)

Pencils and pens available.

- Color markers are used by the SSS and ASSS to keep their places in the EOP's.

Each person uses a

different color marker.

c)

Table space adequate and appropriate.

- Not sufficient space to lay out all EOP's at the same time, but space is sufficient for working with the EOP's and location is good for using the EOP's.

d)

Control room environmental factors do not adversely effect the implementation of procedures (temperature, lighting, noise levels, etc.)

- Lighting excellent, temperature good noise level a little high (due to outage in progress).

Do the units of measure in the EOP's match those used on the control boards?

- Searched all EOP's for parameters that were required to be measured.

All units matched those used on the control boards.

Are the needed controls/displays available and usable (scale selection, range and units consistent with procedure requirements?

I

USE OP EOPCONTROL ROOM (continued)

- All controls/displays were available and usable.

Scales selection and units were consistent with procedure requirements.

The ranges in some instruments were less than was indicated by the EOP figures.

In those cases the graphs stopped at the point where the instrumentation range stopped.

Are control positions easily recognized?

- No problem was noted in control position recognition.

~Res ense Not required for previous six items.

Is location information adequate?

- EOP-6 directs operation in the plant.

EOP-6 appears to rely on operators knowledge of the plant instead of spelling out any locations.

R~es onse See response to item B.3.

Are staffing levels adequate to perform procedures?

- The normal control room manning was sufficient to perform all actions required to perform the EOP's performed.

Are roles and responsibilities clearly defined?

- N2-0DI-1.08 Rev.

4 "Operating Policy For Emergency Procedures",

and N2-ODI-1.09 Rev.

4 "EOP Users Guide" provide explicit guidance on role and responsibilities.

Are there any difficulties in interfacing with departments outside the control room?

- No concerns were identified.

U8E OR EOP'Sll 1.~Res onse Not Required for above 3 items.

2 ~

LOCAL CONTROL STATIONS For the procedure being executed, accident conditions could create a situation where the operator can not carry out his actions at the local control station, due to risks to personnel and/or equipment.

- EOP-6 does not identify potential situations where operators could be impeded in the performance of their duties due to risks to personnel and/or equipment.

~Res ense See response to item B.4.

Is a procedure available to the operator performing local actions?

- The applicable OP was available to the operator at the local stations

however, EOP-6 was not available at the local stations for performance of RWCU Boron Injection and Defeating HVR LOCA Isolation Signals.

~Res ense See response to item B.5.

What is the location of local control station procedures?

- The procedures are in the vicinity of the local control panels.

~Res ense Not Required.

Does the procedure identify safety issues related to performing local actions?

- EOP-6 does not identify potential situations where operators could be impeded in the performance of their duties due to risks to personnel and/or equipment.

r

D.

USE2

~~Res onse See response to item B.3.

Are additional procedures/operator aids (diagrams) needed at local control stations?

,Yes, EOP-6 is needed at the RWCU control panel and the local HVR control panel.

~Res ense See response to item B.5.

Are personnel available and appropriate?

- Yes, personnel are available, an E operator should be present on any EOP operations in the plant.'Res ense Although licensed operators may be available and present on EOP operations in the plant, nonlicensed operators are trained in EOP-6 attachments concerning in plant operations.

Are controls and displays at local site accessible?

- Controls and displays were accessible.

Are local controls and equipment operable?

- All equipment simulated in this assessment was operable.

Is vital equipment operable?

- All simulated equipment was operable.

~Res ense Not Required for previous 3 items.

A failure in the local environment prevents operator from taking action, if so what are the potential consequences?

USE2.-In defeating the HVR interlocks the HVR ventilation could not be restarted and the SBGTS would have to be left on the line to maintain a negative pressure in the reactor building.

- In the RWCU boron injection, this is a multiple failure situation.

Both SLS pumps would have had to fail, the hydro pump injection method would be unavailable and an environmental condition would have to be present to prevent the use of RWCU. If this happens there is no other method of injecting boron into the vessel identified in the EOP's.

Riess onse No response for the HVR/SBGT item.

For alternate boron injection NMP2 employs both a hydro pump and RWCU systems.

This is beyond that required by the BWROG and considered adequate.

As stated in the QA writeup multiple failures would have to occur in order to get to this point.

This is way beyond licensing basis requirements and does satisfy the BWROG EPG requirements.

t Are adequate tools available?

- Procedure (EOP-6 attachment

19) requires exact weights for boric acid and borax however, there is no method provided to weigh it out.

The Borax and Boric Acid should be located on station instead of picking it up from stores.

Step 19.9.f directs the operator to step F.5.4 of OP-37.

The note prior to 5.4 requires the key lock switch to be positioned to System A or B.

This requires a PA 2235 key, attachment 19 does not point out, that this'key is needed.

- Attachment 26 first note should also include 2 PA 2235 keys ass required by step 26.2.1, these keys are required to be removed in step 26.2.7.c.

~Res ense See response to items B.7 and B.11

USE OP2.-RWCU boron injection (EOP-6 attachment

19) required

gloves, long sleeve shirts and eye protection, none of these items are available at the local operating station.

R~es onse See response to item Be10.

Can local actions be performed when dressed out?

- Local actions could be performed when dressed out

however, a dress out was not performed during the simulations.

Is means of communications usable under existing conditions?

- The means of communications would be a radio and communications with the control room was not observed.

Is means of communication convenient to the user?

- The operator did not have any problems with using the radio for communications.

~Res onse Not Required for previous 3 items.

PERFORMANCE OP EOP~S IN THE SIMULATOR The following scenarios were observed:

02-REQ-009-TRA-2-06 REV 1 "HIGH POWER ATWS WITH MSIV CLOSUREn 02-REQ-009-TRA-2-10 REV.

1 "SMALL STEAM LEAK IN DRYWELL WHICH WORSENS)/NOT ALL RODS INn 02-REQ-009-TRA-2-24 REV.

1 "OFF-SITE RADIOACTIVITYRELEASE" 02-REQ-009-TRA-2-16 REV.

1 "LOSS OF ALL HIGH PRESSURE INJECTION SYSTEMS"-

1.

Are operators able to quickly and accurately access specific EOP's?

1 Il

PERFORMANCE OF2 ~

3

~

4.

5.

6.

- EOP access was quick and accurate.

Is the table space adequate and appropriate?

- Adequate space is available for EOP's.

Are logic statements clearly understood?

- No problems noted with logic statements.

Are step and section numbering clear?

- Sections are clearly marked, but there is no step numbering as EOP's are in flowchart format.

Reference points for moving around within the EOP and from EOP to EOP are clearly marked and easily followed.

I Do operators have difficulty in making transitions within and between procedures?

- The SSS was able to make transitions within and between procedures with no difficulties noted.

Is concurrent use vs.

independent use of procedures clear?

7 ~

8.

9.

- Steps that are to be performed concurrently are clearly marked.

Are place keeping aids used between and within procedures?

- Colored markers are used to keep place within EOP's.

When place keeping is provided for high-level steps only,. do operators have difficulty in keeping their places in low-level steps?

- There was no difficulty noted of operators keeping their places in any EOP step irregardless of the steps importance.

Does physical interference exist between operators?

- The operators all had stations they went to, there was no physical interference noted between operators.

PERFORMANCE OFNOTE At one point the CSO was using the phone from the P603 panel and had the cord stretched out to the back of the computer console.

This created a trip hazard for the operator that was moving from the 851 panel to the back panels.

10.

Are there any unnecessary duplication of operator actions?

At one point the SSS was having the same parameter reported by two different people.

This was not the fault of the EOP's and was brought to the attention of the SSS by training instructor.

He suggested that the SSS designate one individual to keep him of any particular parameter he wanted monitored.

11.

Are operators able to move easily about the control room?

- Movement about the control room was easy and was minimized.

12.

Are non-sequential steps performed correctly?

- Not Observed.

13.

Are recurrent steps performed at correct intervals?

- Not Observed.

14.

Are time-dependent steps performed when necessary?

- Not Observed.

15.

Are continuously monitored steps adequately addressed?

- Operators monitored parameters continuously that were required by EOP's.

16.

Are critical safety functions monitored?

h

- Yes, power, level, pressure, radiation levels, Suppression pool temperature/level, and Dry Well pressure.

E.

PERFORMANCE~es onse Not Required for previous 16 items.

17.

Were there any deviations from written procedures?

If so, what and why?

- EOP MSL does not adequately address/prevent de-pressurization of the RPV to the Main Condenser.

As a result a current operating crew was observed to have erroneously de-pressurized to the main Condenser with indication of Gross Fuel Element Failure.

When questioned, the training instructor indicated that numerous current licensed operating crews have made the same error.

~es onse See response to item Be28.

18.

Communication between procedure reader and operator understood?

Problem Sources

.Inadequacy of content of oral communication

.Interference from noise (HVAC, alarms, other conversation)

- Repeat backs were made by the operators.

The operators ensured that the SSS acknowledged their communications and repeated if necessary to get an acknowledgement.

I

- Oral communication was good, only one discrepancy noted.

The CSO asked for water level and the parameter value was given by the 601 panel operator without identifying which parameter he was giving the value for.

This only occurred once all other times both the parameter and value were given.

- Alarms were the main source of noise, the ASSS informed every one and then went to master silence to keep the noise level down.

'I'

PERFORMANCE OF EOP'819.

Action or consequence of communications between procedure reader and operators acknowledged.

- Yes, at point early in EOP all operators were giving input to the SSS.

The SSS acknowledged what he could and operators repeated what he apparently had missed.

20.

What are the 'user attitudes toward procedures (e.g.

operators perform steps before being instructed or abandon procedures before finished).

- Operators had a good attitude towards the EOP's.

They had a discussion on EOP-6 after their first scenario where the instructor asked for any better solutions or ways that could improve EOP-6 to be inputted to the EOP procedure writer.

21.

Are cooperation and team work apparent?

I

- Yes, good communications.

ASSS kept SSS well informed.

Operators worked well together.

22.

Verify mindsets do not exist which jeopardizes plant safety (e.g., reluctance or refusal to borate when required by procedure).

- There was no reluctance to perform any steps in the procedure.

~Res ense 23.

Not Required for previous 5 items.

n Ask control room staff about their training on the procedures being used (issues addressed,

recency, frequency),

especially when problems are encountered.

- Regarding EOP-6 the operator questioned stated he had read the procedure but received no formal training on that procedure.

~es )ggse See response to item A.1.

'I P"

'Lp

VHRXFXCATXON AND VALXDATXON The following scenarios were observed:

02-REQ-009-TRA-2-06 REV.

1 "HIGH POWER ATWS WITH MSIV CLOSURE" 02-REQ-009-TRA-2-10 REV.

1 "SMALL STEAM LEAK IN DRYWELL (WHICH WORSENS)/NOT ALL RODS IN" 02-REQ-009-TRA-2-24 REV.

1 "OFF-SITE RADIOACTIVITYRELEASE" 02-REQ-009-TRA-2-16 REV 1 "LOSS OF ALL HIGH PRESSURE INJECTION SYSTEMS" Observe EOP exercises on the simulator using an actual operating crew (not technical staff personnel).

Determine that the procedures provide operators with sufficient guidance such that their responsibilities and required actions during the emergencies, both individually and as a team are clearly outlined.

- Sufficient guidance exists to provide operators with their responsibilities and required actions during the emergencies.

2 ~

3 ~

~Res ense Not Required.

Focus on identified areas of concern about usability (examples excessive transitions).

N2-EOP-6 attachment 14 had to be changed due to technical inadequacies due to having a do loop in the flowchart if the scram solenoids could.- not be deenergized.

EOP MSL does not adequately address/prevent depressurization of the RPV to the main condenser with MSIV's stuck open and a fuel element failures demonstrated during this observation period.

When the training instructor, when questioned, indicated that numerous current licensed operating crew made the same.

R~es onse See response to items B.2 and B.28.

4 ~

Verify that when a transition from one EOP to another EOP or,other procedures is required, precautions are take'n to ensure that all necessary

steps, prerequisites, initial conditions, etc.,

are met or completed and that operators are knowledgeable about where to enter and exit the procedures.

- No concerns were identified during this assessment.

5.

Note any activities that would occur outside the control room based on the scenario as presented and follow up as appropriate.

- Activities occurring outside the control room were performed by training personnel.

6.

Audit the EOP Lesson Plans for technical adequacy.

- Review of referenced lesson plans revealed no concerns.

7.

Ensure training covers technical basis.

8.

- Not observed.

Ensure training covers structure and format.

- Not observed (covered during classroom training).

9.

Ensure that simulator scenarios used during training sufficiently covered all EOP's and that multiple malfunctions are included.

- No concerns were identified during this assessment.

P~es )~ouse Not Required for previous 6 items.

10.

Ensure that operator's received training on revised EOP's prior to implementation.

- EOP-6 Attachment 19 did not receive sufficient training prior to issuance.

One operator informed the assessor that he had been required to read the attachment prior to issuance but had not received any training.

", ~

~es ense See response to item A.1.

LONG TERM EVALUATION PROGRAM FOR THE EOP~S Determine if the program provides as adequate system to ensuring technical adequacy by factoring the following factors:

Operating Experience.

- No concerns were identified during this assessment.

Training Experience.

- No concerns were identified during this assessment.

Simulator Exercised.

- No concerns were identified during this assessment.

Control Room Walk Through.

- No concerns were identified during this assessment.

In Plant Design

- The EOP coordinator identified a weakness in that modifications, changes in plant design and changes in unit operating license are not presently being appropriately evaluated for impact on the EOP's.

Currently changes are being made to the process to provide adequate controls in the process.

Changes In Technical Specifications.

- No concerns were identified during this assessment.

Changes In Technical Guidelines.

- No concerns were identified during this assessment.

The Site Writer's Guide.

- No concerns were identified during this assessment.

Other Plant Procedures.

l

'= P

LONG TERM EVALUATION PROGRAM FOR THE EOP'S2 ~

- No concerns were identified during this assessment.

Determine if the program provides as adequate system to ensuring structure quality by factoring the following factors:

Operating Experience.

- No concerns were identified during this assessment.

Training Experience.

- No concerns were identified during this assessment.

Simulator Exercised.

- No concerns were identified during this assessment.

Control Room Walk Through.

- No concerns were identified during this assessment.

Changes in plant design.

- No concerns were identified during this assessment.

Changes in Technical Specifications.

- No concerns were identified during this assessment.

Changes In Technical Guidelines.

- No concerns were identified during this assessment.

The Site Writer's Guide.

- No concerns were identified during this assessment.

Other Plant Procedures 1

- No concerns were identified during this assessment.

(

V r

r RPV water level control may be augmented by one or more of the followingsystems:

~

RHR service water crosstie

~

Fire system

~

ECCS keep-full systems

~

SLC (test tank)

~

SLC (boron tank)

~

Condensate Transfer RPV water level control may be augmented by one or more of the followingsystems:

[

RHR service water crosstie]

[

Fire system]

f Interconnections with other units]

[

ECCS keep-full systems]

[

SLC (test tank)]

[

SLC (boron tank)]

~

"Interconnections with other units" was deleted.

NMP2 has no interconnections with other units other than the fire system which is already listed.

~

"Condensate Transfer" is added to the list.

At NMP2, condensate transfer is an additional source of water available for RPV lI injection, and therefore added to the list.

References to plant specific support procedures were added to the flowcharts to assist the operators.

$l

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OPERATOR ACTIONS

Ifawhile executing the followingsteps:

~

Turbine BuildingHVACexhaust radiation level exceeds the Turbine Building Release Limitor cannot be determined, verify the Turbine Building HVACis operating in the un-isolated mode ifavailable (OP-55).

~

Control BuildingHVACradiation level cannot be maintained below 5.92 x 1&pCi/cc, verify that the control building HVAC is operating in the pressurization mode (OP-SBA, Section H).

Not Applicable.

~

The flowchan specifically identifies which procedure sections to use.

~

The flowchart uses the word "normal" instead of"un-isohted mode". The word normal was preferred by the plant's operators during the EOP valitlation process.

There intent ofthe sentetce was maintainad.

I

~

The words "hydrogen mixing systems" were replaced with "drywell unit coolers".

NMP2 utilizes the drywell unit coolers for hydrogen mixing.

~

The words "procedure developed from RPV Control Guideline" were replaced with "RPV Control".

At NMP2 the procedure developed from RPV Control Guideline is called "RPV Control".

~

The words "and hydrogen recombiners" were added to ensure that these are secured should this section be entered by way of the first section override which could bypass the steps which would normally secure the recombiners.

This is necessary due to the format of the flowchart where the Emergency Depressurization override (prior to PSTG Step PC/H-1) enters the sections flowpath (PSTG step PC/H-4),

~

The words "defeating isolation interlocks ifnecessary" are not contained in the flowchart but are contained as part of the purging implementation procedure (N2-EOP-6, Att. 25).

cga.~ /o pa~

I oC This document delineates the.......... as height above sea level.

Based on the various BWR........... specified in these procedures.

The introduction section of the PSTG has been specifically taylored to NMP2.

The EOPs contain no introduction section. This is neither required nor appropriate.

nr V

I

Continued from revious a e

~

The words "injecting into the RPV only" were added to the action as described in the EPG as well as the RPV water level corresponding to the Maximum Primary Containment Water Level Limit. In addition, NMP2 added an additional step regarding injection into the RPV only.

AtNhP2, Primary Containment water level above EL 224 ft. can be determined by M calculation up to El. 296 ft.. Above El. 296 ft., RPV water level must be used for determination ofprimary containment water level as long as the RPV is adequately vented. Ifthe RPV cannot be adequately vented, containment water level may actually be higher than the corresponding RPV water level and the containment vent may be jeopardized.

The only way to assure that containment water level is lower than RPV's and thus lower than the containment vent, is by injecting to the containment through the RPV, El. 292.5 ft. is used in lieu of 296 ft. to account for the inaccuracies of the instruments at elevations 296 ft. and 224 ft. This willassure that ifwater level is higher than anticipated (due to instrument error), itwillstill be below the elevation of the vent, and ifthe level is lower than anticipated (due to instrument eaor), itwillstill be at an RPV water indicated by the Fuel Zone instruments (Reference: Problem Report 9170).

~

Plant qecific ptocedure references were added to facilitate their use.

~

This step was modified to reflect the intent to use fuel zone level instruments when containment level is above El. 292.5 ft. This 'implementation item's due to a potential error with the instruments used when the operators calculate containment water level. If lt this precaution is not taken, an unconservative eaor may lead to water covering the containment vent. In addition to this change in the step, a caution is added to further identify the need to use fuel zone instruments.

I P

The direction to vent the suppression chamber ifsuppression pool water level is below the "elevation of the bottom of the suppression chamber vent", was replaced with "highest instrumented suppression pool water level".

The range of suppression pool instrumentation does not extend up to the elevation of the bottom of the suppression chamber vent. Although the actual margin to the limitmay be wider, this conservative substitution eliminates the possibility af attempting to vent the suppression chamber when its vent is submerged.

The highest instrumented suppression pool water level is El. 217 ft.

~

The words "in accordance with procedure for primary containment venting" were replaced with NMP2's plant specific procedure.

Continued next page

i4 C,

44ch~@

8 p~ Zoh3

~

The EOPs use drywell pressure and suppression pool water level as parameters which govern the initiation ofdrywell purge. Ifdrywell pressure is below the scram setpoint and suppression pool water level is below the high water level LCO, purging is done into the drywell and out of the suppression chamber. Ifat or above these limits, the purge is done into and out of the respective space (ie: no communication between the drywell and the suppression chamber).

Establishing a purge path into the drywell and out of the suppression chamber, requires pressurizing the drywell by as much pressure as the column ofwater form the bottom of the downcommers to the surface of the suppression pool. At normal water level, the pressure differential between the drywell and the suppression chamber is just under 5 psi.

Hence, at higher suppression pool water level the drywell may have to be pressurized by up to 12 psi over the pressure at the suppression chamber. Ifa pressure problem already exists in the drywell, such vent path (into the drywell and out the suppression chamber) will escalate the severity of the problem.

Therefore it was decided that when a pressure problem or suppression pool water level problem exist",

purging willnot be done by utilizing the path that willincrease the magnitude of the problem. By deciding not to utilize this path the atmosphere of the primary containment willbe purged offsite as is and the benefit ofscrubbing willnot be realized.

However, should a detonation occur (HQOz concentration problem) it willbe at lower containment pressure and its risk to the containment integrity willbe lower.

Furthermore, some measure of scrubbing willbe realized since containment spray will be initiated at that time, and in addition to that, a higher containment pressure willreduce the total volume of nitrogen available for diluting the hydrogen and oxygen concentrations.

Therefore, it is concluded that after weighing the advantages and disadvantages of purging the drywell through the suppression chamber, it is prudent to do so as long as neither a pressure problem nor a high suppression pool water level problem exist.

k

PC/H-4.3 Ifthe suppression chamber or drywell can be vented, initiate and maximize the drywell purge flow.

PC/H-4.3 Ifthe suppression chamber or drywell can be vented, initiate and maximize the W

drywell purge flow.

BZVZAFZ N None.

Refer to EOP variance forPC/H-4.2.

~

The direction to vent the suppression chamber ifsuppression pool water level is below the "elevation of the bottom of the suppression chamber vent", was replaced with "highest instrumented suppression pool water level".

The range of suppression pool instrumentation does not extend up to the elevation of the bottom of the suppression chamber vent. Although the actual margin to the limitmay be wider, this conservative substitution eliminates the possibility of attempting to vent the suppression chamber when its vent is submerged.

The highest instrumented suppression pool water level is El. 217 ft.

~

The Drywell Spray InitiationLimitcurve was truncated at 350'F.

Although the actual margin to the limit may be wider, the curve was conservatively truncated at 350'F since the indicating range of the suppression chamber temperature instrumentation does not extend past this value.

~

The words "RHR" and "operation in the LPCI mode were deleted.

The word "injection was added.

In accordance with BWROG EPG ISSUES RESOLUTION FILE 8923 which provides for use ofpumps other than RHR for'ontainment sprays.

1 l

,S

~

Plant specific procedure reference was added foroperation ofdrywell sprays to facilitate its use.

~

The words "and the primary containment vent path is established" were added.

This is done since initiation of a spark by the actuation of sprays is possible. It is preferable to initiate sprays after the vent lineup is established to limitthe pressure spike should an explosion take place.

Additionally, purging is designed to solve the problem while spraying just mitigates the problem.

See discussions ofEPC Resolutions File No. 9022.

T NIAGARA U MOHAWK TRAININGMOOIFICATION RECOMMENDATlON OFFICE USE ONLY TMR

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PHONE: EXT. 1123 I TMR'5 MAYBE INITIATEDBY ANY EMPLOYEE.

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~ WHEN INITIATlNGA TMR, COMPLETELY DESCRIBE ANYEVENTS OR PROBLEMS LEADINGTO THE RECOMMENDATION.

I IF A DOCUMENT(IE; NOTICE, LETTER, MEMO, ETC. ) IS THE BASIS OF A RECOMMENDATION,PLEASE ATTAC COPY TO TMR.

I I PLEASE PROVIDE YOUR NAMEANDPHONE NUMBER TO ALLOWFOR FEEDBACKAND FOR CLARIFICATION NECESSARY.

~

FORWARD THIS FORM TO THE SPECIFIC TRAININGAREA SUPERVISOR, THE SUPERINTENDENT TRAINING-NUCLEAR OR THE TRAININGANALYSISSUPERVISOR ATTHE NUCLEARTRAININGCENTER.

~

YOUR RECOMMENDATIONWILLBE REVIEWED. YOU WILLBE NOTIFIED OF THE FINALDISPOSITION OF YO RECOMMENDATION.

g:0q.~gp.4 q~~~~~P NO TRAININGREVISION NECESSARY I

TMR ISSUED 4 I COMMENTS/EXPLANATIONS:

TRAININGSUPERVISOR g(lgpos I'fzcTnM~y 313 264 N06 86 P.~I OATE'YMBOL NO. SS-3M72

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hTTLCHNENT I S>>SUP 4

PROCEDUB EV hTION BE UEST Fo Rat Lag e Page 2 of 2 Sec o

it atio 1)

Unit S:

2)

Pc'oc s:

2-/ 0 3)

Ownership Departisent:

4)

Description

and/or Reason necessary):

Rov 0~

Ttt1o:

fiA (skit Rck

~s -~ M~c4 for Change (kttach additional pages if WO l

a 5)

Priority: 1 0 2 0 5)

Request Initiated by:

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- Ds s

o Request, Received/Logged by:

I Date Recosssended Disposition/Corrective Actions

<attach additional pages if necessary):

9)

Supervisoc'ccepts Request:

Yes No Date

10) Superintendent/l5anager hppc'oval:

~

Yes No Date

11) Pinal Copy to:

Initiatoc'aae Date Sent

12) Copy to file/close out:

Sy Date

- S-SUP&

- 5 Nay 1987

4 J

lie SURVEILLANCEREPORT U MOHAWK.o"~

SYMBOLNO 55 32 34O FACILITY Nine Mile Point Unit 2

SUbjECT:

tAGE 1

OF 2

)

OA SECTION/GROUt

, ~PORT~

NQAO/Surveillance RESPONSIbLE ORGANIZATION:

0 erations 2Gl 1 llAaal *llO COOl

)

~

CHECKLISTOR GOVERNING OOCUMEHTa REV.

'oRK oocUMENT N2-EPP 5

Rev.

P 0- I: ~i>>

SCIIEOULEO YES Q NO Q 1 3 ORSERVATIONS )

OA CATEGORY:

$AFETY RELATEO X

OUALITYRELATEo APPUCAbLE 10CFR50 APP. b CR)TE)uA(IF SAFETY RELATEO):

6 NON ~ SAFETY RELATEO GENERAL PURPOSE AND RESULTS:

Observation of validation by simulator tests for revision 4 to the Unit 2 Emergency Operating Procedures (EOP's).

Evaluation of the process for compliance with N2-EOP-5 "Production and control of NMP2 EOP Revisions" revealed no discrepancies.

Conduct of the process was of the highest professional standards which was reliant on the interaction of involved personnel from Operations, Training and Nuclear Engineering Departments.

SPECIFIC OBSERVATIONS:

In addition to observation of the validation process a review of the current revision of EOP-5 against NUREG-1358 "l.essons Learned from the Special Inspection Program for Emergency Operating Procedures" and revision 1 of "NRC Inspection manual for Emergency Operating Procedures Team Inspections",

was performed with no discrepancies noted.

Validation was conducted in 2 identical structured weeks beginning the week of May 14.

Each of the 2 ~eeks utilized different operating shifts to perform the validation process.

Each week provided the operating, shifts with a

day of familiarization with the revised procedures, followed by 4

days of execution in the simulator.

hpproximately 31 different simulator scenarios were required to fully validate all parts of the procedur'es.

15 M. REM EXPOSURE:

SURVEKLAH<<E QX SAT. Q UHSAT.

RESULTS 19 OISTRIbUTION:

C. Beckham, J. Burton, J. Dillo Dahlber R. Abbott M. Colomb, D. Topley, E. Townsend, G. Lapensky, J. Helker, S. Dort ill ~ S

~ b b 6 SO PREPAREO bY W. Julian PRINT:

SIGH:

1b APPROV EO Y ~

SIGH; DATE: (-I9

- ~ n

SURVEILLANCEREPORT (CONTINVATIONSHEET) 2 FAGS 2

OF.

2 REPORTNo.gP-2P i22 Concurrent validation of the proposed modification to the Unit 2 safety parameter display system (SPDS) was performed per "Nine Mile Point Safety Parameter Display System Man, in the Loop Test Plan" Rev.

1 (MILT).

The purpose of this test was to validate the usability, understandability, and other relevant human factors (man-machine interface).

The validation of SPDS was not evaluated by Quality Assurance.

Quality Assurance observed approximately 20 of the validation scenarios and the associated debriefing after each.

Conduct of the simulation and the required following briefing afterward each was evaluated for compliance with N2-EOP-5, Section 7 with no identified. discrepancies.

All documentation required by N2-EOP-5 was present to support the validation process.

Resolution of the comments by the operation management is to be conducted in the next portion of the validation process.

RECOMMENDATIONS:

The only recommendation identified is there is currently no provision or guidance for documentation of comments generated during the required training portion of the validation process.

REFERENCES:

N2-EOP-5 Rev.

0 "Production and Control of NMP2 EOP Revisions" NRC Inspection

Manual, Temporary Instruction 2515/92, Revision 1,

Emergency Operation Procedures Team Inspections NUREG-1358 "Lessons Learned from the Special Inspection Program for Emergency Operating Procedures" NMP2 EOP Rev.

4 Ualidation Test Plan (2200S) 823 ~ 12 R01.90 SYM80L HO, SS~8~aa

'IO-5 ~ 0- 10.15.87

I',

I

AN ASSESSMENT OF THE UNIT 2 EMERGENCY OPERATING PROCEDURES REVISION 4 USING THE US NRC CRITERIA AS DEFINED IN "NRC INSPECTION MANUAL'I TEMPORARY INSTRUCTION 2515/92 REVISION 1 "EMERGENCY OPERATING PROCEDURES TEAM INSPECTIONS".

THIS ASSESSMENT WAS PERFORMED IN DECEMBER BY QUALITY ASSURANCE AND INVOLVED THE FOLLOWING:

REVIEW AND COMPARISON OF THE FOLLOWING EOP'S TO THE APPLICABLE PSTG'S AND EPG'S:

- REACTOR PRESSURE VESSEL CONTROL

- MSIV LEAKAGE CONTROL

- PRIMARY CONTAINMENT HYDROGEN CONTROL CONTINGENCIES C2i C3i C6 OBSERVATION OF AN OPERATING CREW PERFORMING EOP'S ON THE UNIT 2 SIMULATOR.

SIMULATION OF ATTACHMENTS 19 AND 26 OF N2-EOP-6 IN THE PLANT.

VERIFICATION THAT THE UNITS OF MEASURE IN THE EOP'S MATCHED THOSE USED ON THE CONTROL BOARDS.

VERIFICATION OF THE VERIFICATION AND VALIDATIONPROCESS.

REVIEW OF THE EOP ON-GOING EVALUATION PROGRAM.

THE FOLLOWING AREAS OF STRENGTHS WERE NOTED:

ENGINEERING INVOLVEMENT IN THE DEVELOPMENT OF THE REVISION 4

OF THE EOP'S.

TECHNICAL REVIEW AND CONTENT OF PLANT SPECIFIC GUIDELINES THE FOLLOWING WEAKNESSES WERE NOTED:

IN RPV CONTROL SOME CAUTIONS WERE INCORPORATED INTO THE STEPS.

THIS GOES AGAINST THE PHILOSOPHY OF REVISION 4

OF THE BWROG EPG'S WHICH IS THAT THE CAUTIONS STAND OUT.

EOP-6 APPEARS TO BE DEFICIENT IN LOCATION IDENTIFICATION EOP-6 DOES NOT IDENTIFY OR CAUTION PERSONNEL OF POTENTIAL HAZARDS AND RISKS TO THEMSELVES AND/OR EQUIPMENT WHILE EXECUTING SPECIFIC TASKS THROUGH USE OF THE VARIOUS ATTACHMENTS.

EOP-6 WAS NOT AVAILABLEAT LOCAL CONTROL STATIONS CONDENSATE TRANSFER WAS ADDED TO PSTG STEP RC/L-3 THIS IS A DEVIATION FROM THE EPG'S.

NO JUSTIFICATION WAS PROVIDED FOR THIS DEVIATION.

PAGE 35 OF ATTACHMENT 8 IS MISSING FROM THE SAFETY EVALUATION FOR THE EOP'S.

"~

a li 0

P

EOP RC/P-2 REQUIRES 2ZAS*SOV164g 165t 166@

184 TO BE REOPENED IF NECESSARY, THIS IS NOT MENTIONED IN PSTG OF EOP VARIANCE IN ATTACHMENT 8 OF THE EOP SAFETY EVALUATION. IF ADDED THE PSTG NEED TO HAVE A DEVIATION JUSTIFICATION.

THERE IS A VARIANCE BETWEEN THE EOP

& PSTG ON PAGE 182 OF ATTACHMENT 8 OF THE EOP SAFETY EVALUATION. ONE REFERS TO HE NORMAL MODE AND THE OTHER REFERS TO UNISOLATED MODE UNDER EOP VARIANCE IT STATES THAT THERE IS NO VARIANCE.

IN THE PCH SECTION OF PRIMARY CONTAINMENT CONTROL THE PSTG ADDS DEFEATING OF INTERLOCKS WHICH DEVIATES FROM THE EPG.

THIS DEVIATION IS EXPLAINEDi HOWEVERS THE INTERLOCK DEFEAT IS NOT IN THE PCH STEPS OF THE EOP-THIS IS NOT COVERED IN THE EOP VARIANCE.

TYPO PAGE 286 OF ATTACHMENT 8 OF THE EOP SAFETY EVALUATION FIRST BULLET ITEMS TYPO EOP RR NRADIOACTIVZTY RELEASE CONTROL" STEP TO "ISOLATE ALL PRIMARY SYSTEMS.0 '

THE ALL IS SPELLED "AL" STEP C6-3 THE EOP CONTAINS A CAUTION STEP AND INSTRUCTION TO USE FUEL ZONE INSTRUMENTATION. THESE ITEMS ARE NOT IN THE PSTG.

IN STEP PC/H 4.2 IT WAS DECIDED TO USE 201 FEET SUPPRESSION POOL LEVEL AS THE MAXIMUM LEVEL, THIS APPEARS TO BE A DEVIATION AND AS SUCH SHOULD BE REFLECTED IN THE PSTG STEP.

BWROG STEP PC/H 4.3 IS NOT REFLECTED IN THE PSTG

STEP, EOP-6 ATTACHMENT 25 OR IN THE EOP'S.

THERE IS NO DEVIATION OR VARZANCE TO JUSTIFY WHY IT HAS BEEN EXCLUDED.

STEP PC/H 4.4 ADDS AN ADDITIONAL STEP TO MEET CONDITIONS TO SPRAY THE DW WITH NO JUSTIFICATION IN THE DEVIATION OR VARIANCE SECTIONS.

STEP PC/H 2.1, 2.2, 3.1, AND 3.2 CONFLICT WITH THE MAXIMUM 02 CONCENTRATION ALLOWED FOR HYDROGEN RECOMBINER OPERATION IN N2-OP-62 D.5.0g WHICH DEFINES THE MAXIMUM 0 CONCENTRATION AS 2.5%

WITH GREATER THAN 5% H2.

THIS STEP ALLOWS U TO 5% 02 WITH H2 GREATER THAN 5%.

STEP RC/L 2 NO DIRECTION ZS PROVIDED FOR CONTROLLING PUMP FLOW TO PREVENT DAMAGE DUE TO NPSH.

N2-EOP-6 ATTACHMENT 14 HAD TO BE CHANGED DUE TO TECHNICAL INADEQUACIES' DO LOOP CURRENTLY EXISTS IN THE FLOWCHART IF THE SCRAM SOLENOIDS CAN NOT BE DEENERGZZED.

4 l

4 0

EOP MSL DOES NOT ADEQUATELY ADDRESS/'PREVENT DEPRESSURIZATION OF THE RPV TO THE MAIN CONDENSER WITH A GROSS FUEL ELEMENT FAILURE.

AS A RESULT A CURRENT OPERATING CREW WAS OBSERVED TO HAVE ERRONEOUSLY DEPRESSURZZED TO THE MAIN CONDENSER WITH INDICATION OF GROSS FUEL ELEMENT FAILURES WHEN QUESTIONED, THE TRAINING INSTRUCTOR INDICATING THAT NUMEROUS CURRENT LICENSED OPERATING CREWS HAVE MADE THE SAME ERROR.

0 ZN LETTER FROM C.

MANGAN TO THE U.S.

NRC IT WAS COMMITTED THAT, PRIOR TO INITIAL CRITICALITY~ THAT UNIT 2 OPERATING AND/'OR EMERGENCY OPERATING PROCEDURES WILL BE UPDATED TO ADDRESS EACH RECOMMENDATION OF THE BWROG AS CONTAINED ZN NEDO 30324, EXCEPT FOR THOSE RELATING TO A LEAKAGE CONTROL SYSTEM".

CONTRARY TO THIS COMMITMENT QUALITY ASSURANCE COULD FIND NO CONTROLLED DOCUMENT THAT SATISFIED THIS COMMITMENT AS THE APPENDIX A TO THE PSTG INDICATES THAT BWROG STEPS ARE NOT APPLICABLE. IT APPEARS THAT APPENDIX A WOULD BE THE PROPER PLACE TO ADDRESS DEVIATIONS ZN UNIT 2

EOP-MSL FROM THE BWROG RECOMMENDATZONS CONTAINED IN NEDO 30324.

0 AI 1 '~

REV 00 SITE WRITER S

GUIDE SECTION 7

OB UNIT 2 EMERGENCY OPERATING PROCEDURES" NEEDS TO BE UPDATED TO REFLECT THE CURRENT ORGANIZATION WITH RESPECT TO THE APPROVAL BLOCK.

0 N2-0DI-5.10 REV.O "EOP ONGOING EVALUATION PROGRAM" STATES ZN SECTION 2.2.D S

SUP 4g PROCEDURE EVALUATION REQUEST PROVIDE A METHOD FOR THE PROCEDURE USER TO REQUEST CORRECTIONS'HANGES'R IMPROVEMENTS TO EXISTING PROCEDURES".

THIS SUGGEST THAT THE S-SUP-4 PROCESS IS TO BE USED TO ADDRESS CONCERNS WITH UNIT-2 EOP'S.

LATER ZN THE PROCEDURE, A NEW PROCESS FOR ADDRESSING CONCERNS WITH THE UNIT 2 EOP'S IS DESCRIBED INCLUDING A NEW FORM.

WHY IS A NEW PROCESS NECESSARY TO EVALUATE CONCERNS WITH THE UNIT 2 EOP'SV IT IS NOT CLEAR WHICH OF THE PROCESSES IS THE PREFERRED ONE TO USE.

THE S-SUP-4 PROCEDURE NEEDS TO BE MODIFIED TO ADDRESS THE CHANGES DESCRIBED ZN THIS PROCEDURE.

0 N2-MSL PSTG STEP MSL-3 IS NOT CONTINGENT ON STEP WHICH STATES "OPERATE AVAILABLESJAE'S THROUGH OFF-GAS".

THIS SHOULD BE A SEPARATE STEP IAW AI-1' "SITE WRITER'S GUIDE" SECTION 7.0B.

I J

P

05000410/LER-1989-014, :on 890413,unit Reactor Experienced Reactor Scram Which Was Result of Turbine Trip Due to Actuation of Generator Protection Circuitry.Turbine Trip Caused by Disconnected Wire.Wire Relanded

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