ML20199B822

Insp Repts 50-321/97-09 & 50-366/97-09 on 970817-1004. Violations Noted.Major Areas Inspected:Operations, Engineering,Maintenance & Plant Support

ML20199B822
Person / Time
Site:	Hatch
Issue date:	11/03/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20199B804	List: ML20199B800 ML20199B812 ML20199B822
References
50-321-97-09, 50-321-97-9, 50-366-97-09, 50-366-97-9, NUDOCS 9711190107
Download: ML20199B822 (38)

See also: IR 05000321/1997009

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U.S. NUCLEAR REGULATORY COMMISSION

REGION II

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Docket Nos:

50 321.50-36t

License Nos:

DPR-57 and NPF-5

Report No:

50-321/97-09, 53-366/97-09

Licensee:

Southern Nuclear Operating Company, Inc. (SNC)

Facility:

E. I. Hatch Units 1 & 2

Location:

P. O. Box 439

Baxley, Georgia 31513

Dates-

Augue.t 17 - October 4. 1997

Inspectors:

B. Holbrook. Senior Resident Inspector

J. Canady, Resident Inspector

Accompanying Inspector:

T. Fredette

Approved by:

P. Skinner Chief. Projects Branch 2

Division of Reactor Projects

Enclosure 2

9711190107 971103

PDR

ADOCK 05000321

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PDR

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EXECUTIVE SUMMARY.

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-Plant Hatch. Units 1 and 2-

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-NRC-Inspection Report 50 321/97-09 50-366/97-09

This integrated inspection includeo aspects-of licensee ' operations

engineering, maintenance, and-plant-support.

The report covers a 7-week-

_ period _of resident inspection activities.

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Ooerations

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During Unit 2 startup activities on September 18,_' operator

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procedure usage, communications, control of activities, and

supervisory oversight during these activities were excellent.

Equipment problems such as control rods that were difficult to

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withdraw - turbine vibration problems during turbine roll, and main

generator automatic voltage regulator problems challenged

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operators-(Section 01.1).

Equipment al'gnment, component _o)erability, and material

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conditions observed-during a wal(down of the Unit 1 Standby Gas

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Treatment System were good in all areas inspected.

Housekeeping

L conditions in the filter train room adjacent to Unit 1 Heating

Ventilation and Air Conditioning room were excellent

(Section 02.1).

Unit I systems responded properly following a trip of the

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1A Reactor Feed Pump Turbine (RFPT) and subsequent Reactor

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Recirculation Runback on September 6.

Operator response to the

plant transient was good (Section 04.1).

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Operations supervision failed to

llow applicable procedures to

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correctly generate a-Maintenance Work Order (MWO) package for a

Reactor Manual Control system relay replacement.

Operations

supervision authorized work and maintenance personnel performed

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work using the incorrectly completed work package.

This was

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identified as an example of Violation (VIO) 50-321, 366/97-09-01,

Fai',ure to Follow Procedure - Multiple Examples -(Section 04.2).

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The inspectors concluded that the operating crew's performance

resulted in additional- challenges during a normal reactor manual

scram.

Operations management prompt actions to correct an

operating crew's weaknesses following a routine manual scram on

-Unit 2 was good (Section 04.3).

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Operations demonstrated poor oversight and coordination of the

battery charger transfer activity. A plant equipment operator

failed to properly follow arocedures governing continuous

activities- that affected tie operability of Emergency Diesel

Enclosure 2

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-Generator 2A and 2C 125-volt direct current subsystems. This

failure to follow procedures was' identified-as an example of-

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VIO 50-321. 366/97-09-01, Failure to Follow Procedure - Multiple

Examples (Section_08.2).

tialptenance

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Routine maintenance activities were generally completed in a

thorough and professional manner.

No deficiencies were identified

by the inspectors for the maintenance activities observed

(Section M1.1).

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Maintenance department response to the Rod Position Indicating ..

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System (RPIS) problem on Unit I was timely 'and engineering support-

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of the maintenance ac.tivity was excellent.

Operator actions for

the failed RPIS were appropriate (Section M1.2).

Maintenance and engineering support following the 1A Emergency

Diesel Generator failure to start on September 4 was excellent.

- The review of past performance and repair history for the failed

fuel oil check valves that resulted in additional check valve

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replacements. demonstrated conservative decision making by the

licensee (Section M1.3;

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Management's oversight and pre-job planning for the forced outage

on the Unit 1 main steam isolation valve limit switch adjustment

was good.

Craft personnel performed the work activity in a

professional and timely manner.

Health Physics personnel

demonstrated a pro-active attitude by identifying the Low Pressure

Coolant Injection check valve leak and notifying maintenance

(Section M1.4).

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Maintenance personnel's attention-to-detail during a walkdown

which discovered broken 31eces of the Unit 2 High Pressure Coolant

Injection (HPCI) flange Jushing was superior.

Engineering support

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of maintenance was excellent.

Foreign Material Exclusion control

measures were satisfactory (Section M2.1).

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Maintenance and engineering oversight of the intake structure

dredging activities was excellent. Foreign material exclusion and'

security control measures were appropriate.

Communications and

departmental-coordination was good (Section M2.2).

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For the surveillances observed all-data met the recuired

acceptance criteria-and the equipment performed sat";factorily,

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The-performance of the personnel conducting the surveillances was

generally professional and-competent (Section M3.1).

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Enclosure 2

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The American Society of Mechanical Engineers (ASME)Section XI

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code requirements for visual inspections were met for the strap

welding on the Unit 2 Safety Relief Valves.

A procedurally

required VT-1 inspection was not com)leted following work on the B

fecdwater check valve hinge pin for Jnit 2.

This was identified

as an example of VIO 50-321, 366/97-09-01. Failure to Follow

Procedure - Multiple Examples (Section M3.2).

The licensee had taken appropriate actions to correct the TIP

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System ASME code. Class 2 issues. The GE Code requirements of the

TIP equipment installed were equivalent to those of the ASME Code.

The proposed UFSAR revision was appropriate (Section M3.3).

The inspectors concluded that Safety Audit and Engineering Review

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(SAER) audit 97-SA-3. Technical Specification Administrative

Control Implementation, was conducted by trained and qualified

personnel.

The audit was thorough and detailed.

The corrective

actions and proposed completion dates were appropriate for the

findings (Section M7.1).

Enaineerina

The inspectors concluded that the licensee was making progress in

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resolving the divisional cable separation issues for both units

(Section E1.1).

The inspectors concluded that new fuel receipt. inspection, and

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storage were completed with appropriate oversight and control, and

in accordance with applicable plant procedures.

Engineering.

Health Physics. and security personnel support for the activity

was satisfactory (Section E4.1).

Plant Supoort

The inspectors concluded that a contract Health Physics

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technician who left the plant site after receiving an alarm on the

exit portal monitor presented minimal safety significance to the

individual or to the public.

The actions taken by the licensee

were a)propriate and no further NRC actions are planned.

Based

upon t1e fact that the individual is no longer employed at the

site and site access was immediately terminated (Section R1.2).

Management personnel had placed special emphasis for improved

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Health Physics and general radiation worker activities.

The stop

work meetino, plant tours for new contractors, and radiation

worker ex]ectations list were identified as a strength

(Section R1.3).

Enclosure 2

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Overall performance during the annual emergency preparedness

exercise was good.

Event classifications during the exercise were

correct. Operator performance in the simulator and overall

performance in the operations support center was excellent

(Section P4.1).

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The areas of security inspected met the applicable requirements

(Section S2).

Enclosure 2

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ReDort Details

Summary of Plant Status

Unit 1 began the report period at 100% Rated Thermal Power (RTP).

End-

of-cycle coast down began on September 2,

On September 6. the 1A

reactor feedwater pump turbine tripped during a weekly turbine test and

resulted in a power reduction to 66% RTP. The unit was returned to

98% RTP. the maximum achievable povci , the same day.

Power was reduced

on September 15 to remove the 1A feedwater pump from service due to a

oil cooler leak. The unit was increased to the maximum achievable coast

down power on September 17. Later on September 17, power was reduced

slightly to verify turbine control valve functions.

Power was returned

to maximum rated the same day.

The unit remained in coast down for the

remainder of the report period except for routine testing activities.

Unit 2 began the report period at 100% RTP. On September 15. power w s

reduced to approximately 75% RTP for main steam isolation valve (MSIV)

testing and was subsequently brounht to Hot Shutdown due to MSIV limit

switch problems. Unit startup began on September 18. and reached 100%

RTP on September 22.

The unit operated at this power level for the

remainder of the report period, except for routine testing activities.

I. ODerations

01

Conduct of Operations

01.1 General Comments (71707)

The inspectors conducted frequent reviews of ongoing plant

operations.

In general, the conduct of operations was

professional and safety-conscious: specific events and

observations are detailed in the section below. In particular, the

inspectors observed that during the Unit 2 startup activities on

September 18. equipment problems such as control rods that were

difficult to withdraw, turbine vibration problems during turbine

roll, and main generator automatic voltage regulator problems

challenged operators. Operator procedure usage, communications,

control of activities, and supervisory oversight during these

activities was excellent.

Enclosure 2

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02-

(Operational Status of Facility _and Equipment-

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02.1- Enaineered Safety Feature (ESF) System Walkdown

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a.

Insoection Scoce (71707)

Thel ins)ectors-performed an inspection of the accessible portions

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of the Jnit I standby gas treatment (SBGT) system.

This-included-

verification of valve alignment, instrumentation, condition of -

-components in service, and general housekeeping for both trains of

the system,

b.

Observations and Findinos

-The inspectors reviewed applicable Piping and Instrumentation

Diagrams (P& ids) and filter train operability verification

procedures in use for the Unit 1 SBGT system.

System control

switches, valves and dampers were verified to be in the correct

positions.

Proper operation of control room flow recorders and

indications were confirmed following routine atmospheric venting

of the primary containment using the "A" SBGT filter train,

c.

Conclusions

Equipment alignment, component opertbility, and material condition

were good in all-areas inspected. _ Housekeeping conditions in the

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filter train room adjacent to Unit 1 Heating Ventilation and Air

Conditioning room were excellent.

04.0 Operator Knowledge and Performance

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04.1

1A Reactor Feedoumo Turbine (RFPT) Trio Durina Routine Turbine

Testina

a.

Inspection 5 ooe (71707) (92901)

- The insSectors reviewed procedure 34IT-N21-003-1S, "RFPT Weekly

Test". Revision (Rev.) 4. and operator performance and plant-

response following a 1A RFPT trip on September 6.

b.

Observations and Findinos

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Licensee management-had deferred routine RFPT_ testing during hot

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- weather conditions and times of peak load demand.

0n' September 6.

the 1A RFPT trip. test was scheduled.

This was one of the first

weekly turbine tests performed following resumption of the-RFPT

testing. While performing section 7.3. "RFPT 011 Trip Test " the

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Enclosure 2

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operator stated that when he released the Overs)eed Trip Test

Lockout Switch, the RFPT immediately tripped. Other than the RFPT

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trip. there were no indications of abnormal system resp (onse.

RFPf trip caused a Reactor Recirculation Systa runbac .

The inspectors reviewed plant data and discussed the RFPT trip

with operations and management personnel.

The inspectors observed

that all systems responded correctly. The Reactor water level

decreased to about 15 inches and a Reactor Recirculation System

Runback occurred as expected.

Reactor power stabilized at about

66% Rated Thermal Power (RTP).

The region of potential

instability of the power to flow map was never entered.

Operations personnel discussed the pump trip and later

successfully completed the turbine testing on the 1A and 1B RFPT.

During subsequent testing. the operators did not release the

Overspeed Trip Test Lockout Switch until a few seconds had passed

after receiving the green reset permissive light. Operations

personnel told the inspectors that they believe that holding the

Overspeed Trip Test Lockout Switch depressed for a few seconds

longer may have prevented the initial trip.

Reactor power was

increased to maximum rated within about 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following the

RFPT trip and subsequent testing.

The licensee initiated a review of the procedure and system

response to determine if possible procedure problems existed or if

improvements could be made to ensure that no future RFPi trips

occurred.

A temporary change to clarify some procedure steps for

both units was completed.

The licensee concluded that the root

cause of the RFPT trip was mechanical linkage not being in the

proper position when the overspeed lockout switch was released.

The procedure revision addressed this problem.

The inspectors observed that the testing procedure had been used

numerous times in the past and no known previous problem or RFPT

trips had been identified.

The inspectors reviewed the procedure

in detail and walked through the procedure at the local panels to

ensure switch nomenclature and procedure wording were clear.

No

procedure deficiencies were observea.

c.

Conclusions

Unit 1 systems responded properly following the tri) of the

1A RFPT and subsequent Reactor Recirculation Runbacc on

September 6. Operator response to the trip and runback'was good.

Enclosure 2

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04.2 Unit 1 Reactor Manual Control System (RMCS) Relay ReDlacement

a.

Insoection Scoce (71707) (62707)

On August 15. Operations supervision prepared a maintenance work

order (MWO) for the re)lacement of a failed relay associated with

the RMCS on Unit 1.

T1e MWO was provided to maintenance personnel

as guidance for component replacement. The inspectors reviewed

applicable procedures and otler documentation associated with the

work activity,

b.

Observationsandfindinas

On August 15, while performing surveillance procedure

34SV-C11-003-IS. " Control Rod Weekly Exercise." Rev. 10. Edition

(ED) 1. the control rods in row 34 could be selected but would not

actuate the RMCS for manual insertion. Troubleshooting activities

by maintenance personnel revealed that relay 1C11-K033 had failed

and required replacement.

Operations supervision on shift 3repared MWO 1-97-1979 and grantec

approval for the maintenance tec1nician to replace the relay.

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MWO prepared and approved was not properly completed.

The MWO dic

not'have any work instructions or procedural references, and other

items of importance were not indicated. The inspectors reviewed

the MWO that was used by the maintenance technician and observed

that the technician documented the work performed on the MWO. The

technician documented that the K033 relay was defective, had been

replaced with a new one, and the RMCS operated satisfactorily.

A later review by maintenance personnel identified several

discrepancies with the MWO and initiated a deficiency card.

The

inspectors reviewed the deficiency card that identified the

discrepancies on the MWO used by the technician to re) lace the

failed relay. Also, reviewed was a second MWO with t1e same

control number that was prepared after the relay replacement. This

MWO corrected the discrepancies identified for the earlier MWO.

The inspectors reviewed MWO 1-97-1979 to determine if the

requirements of Administrative Control procedure 50AC-MNT-001-05.

" Maintenance Program." Rev. 25, were met for the maintenance work

activities.

The following discrepancies were identified:

Step 4.2.5 of the procedure required. in part that plant

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maintenance be performed and controlled within the

boundaries of " work instructions" of MW0s and/or procedures.

Work instructions were not provided to replace a failed RMCS

relay.

Enclosure 2

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Section 8.2.2 and sub-step _8,2.1.2 required, in part, that

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block:23 of the MW0' state a specific sco)e of work using

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referenced material as ap)licabler The iWO failed to enter

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the specific scope of. wort and references in block 23 of the

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MW0.

-Step 8.5.-1 requires. in' part, that prior to the start of

. plant maintenance, the responsible personnel will perform a

-cursory review of the MWO package-to ensure the contents are'-

adequate. Responsible operations and maintenance personnel-

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.did not ensure that the contents of the MWO package were

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Conclusions

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The inspectors concluded that. operations supervision' failed to

follow applicable procedures to correctly generate a MWO package'

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for a-RMCS relay replacement. - Additionally, operations

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supervision authorized work and maintenance personnel performed

work'using the MW0. Operations'and maintenance personnel failed

-to ensure that the MWO package contents were adequate. This was

identified as an example of Violation (VIO) 50-321. 366/97-09-01,

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Failure to-Follow Procedure - Multiple Examples.

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04.3 Doerator Performance Durina Normal Plant Shutdown

a.

Insoection Scoce (71707)

The inspectors reviewed an operating crew's performance and

management's corrective actions following deficiencies identified

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during a forced outage of Unit 2-on September 15.

b.

Observations and Findinas

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-Unit 2 was being shut down to conduct a drywell entry to~ adjust

inboard main Steam Isolation Valve (MSIV) limit switches.

Maintenance activities associated with the limit switch

adjustments are discussed'in Section M1.4 of this Inspection

Report (IR),

Following a manual scram from about 20%

aower.

reactor water level increased to about 88 inches, at w1ich time

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operators closed the HSIVs. About 36 inches is the normal reactor _

water level. Maintaining an approximately normal reactor water

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-level is generally not a problem during a manual scram condition

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from low )ower, and the MISVs are not normally closed during

routine slutdowns._ Closing the MSIVs isolated the RFPT (normal-

water control system) steam supply and the main condenser for

normal pressure control. These actions can complicate a routine

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manual scram and present additional challenges to the operating

" crew. The. operators stated that they. closed the MSIVs to prevent

-exceeding the reactor: vessel cooldown rate. The potential for

Enclosure 2

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exceeding the vessel cooldown rate was due to abnormally high

water level.

Following the MSIV closure at 4:42 p.m. the Reactor-

Core Isolation Cooling System (RCIC) was manually placed in

service for reactor pressure control.

The MSIVs were reopened at

6:40 p.m. and norml pressure control was established.

The inspectors-discussed the operating crews performance with

operations management.

The inspectors were informed that the

perforinance of the operating crew did not meet managements

expectations. Operations management stated that the operators'

response to chcnging reactor water level was slow.

Management

personnel also stated that operations )ersonnel were slow to reset

the reactor scram and this also contri)uted to the high reactor

water level.

Operations management and the operating crew conducted a critique

of the crew performance and unit response using unit chart

recorders and the safety parameter display system tape

information. Management stated the crew acknowledged that their

performance could be inproved. As part of the corrective actions,

simulator training was provided to the crew to practice similar

m&nual scram con itions. Additionally, low power reactor

shutdowns will be evaluated for inclusion into the regularly

scheduled operator license requalification training.

c.

Conclusions

The inspectors concluded that the operating crew's performance

resulted in additional challenges durin9 a normal reactor manual scram. Operations management prompt actions to correct an

operating crew's weaknesses following a routine manual scre a on

Unit 2 was good.

04.4 Review of Unit 2 Emeraency Diesel Generator (EDG) Battery Charaer

Transfer

a.

Insoection Scooe (71707) (92901) (62707)

The inspectors reviewed the circumstances associated with an

activity on September 11, when a plant equipment operator (PE0)

improperly transferred battery chargers for the 2A and 2C

Emergency Diesel Generator (EDG) 125-Volt Direct Current (VDC)

subsystems, rendering both subsystems inoperable.

The inspectors

reviewed the ap)licable procedures, control room logs. TSs. rfi0s,

and discussed t11s problem with licensee management.

Enclosure 2

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b.

Observations and Findinas

The control .roon -logs indicated that the unit shift supervisor had

authorized a maintenance electrician to conduct preventive

maintenance (PM) on battery charger feeder breakers in accordance

with MWO 29701339. In order to facilitate taking the battery

chargers out of service to perform the PM. the electrician

requested the assistance of the outside roving PE0 to transfer

battery chargers. The PE0 performed the transfer without using

)rocedure 34S0-R42-001-25. "125/250 VDC Station Service Charger

Rotation & Breaker Racking." and failed to connect the in-service

battery chargers to their respective 125 VDC cabinets. As a

result, both EDG 125-VDC subsystems were left misaligned with

control power being provided by the EDG batteries.

Control room operators subsequently received an annunciator for

" Battery Volts Low or Fuse Trouble" for both the 2A and 2C EDGs.

An operator was dispatched to investigate the problem.

Normal

battery charger alignment was restored: however, the misaligned

battery chargers had rendered the 125-VDC subsystems inoperable

for a total of 36 minutes.

Engineering conducted an analysis and

determined that a loss of function of the 2A and 2C 125-VDC

systems did not occur due to the fact that the total energy loss

from the batteries was only 2 amp-hours, compared to load profiles

of 66 amp-hours and 37 amp hours for the 2A and 2C DC subsystems,

respectively.

The inspectors reviewed procedure 34S0-R42-001-2S. Rev. 4, which

is classified as a " continuous use" procedure in accordance with

10AC-MGR-019 0S. " Procedure Use and Adherence." Rev. O.

Specifically MGR-01900S stated, in part, that a " continuous use"

procedure is required at work activities that affect safety-

related system operability, and that procedure steps will be

reviewed, read, and initialed during the activity. The inspectors

verified that the )rocedure was adequate to perform the DC system

transfers for the

EDGs.

The inspector's review indicated that at the pre-job briefing, the

Unit 2 shift supervisor had designated a performance team PE0 to

perform the battery charger transfers. This PE0 was never in

attendance at the pre-job briefing, nor was the PE0 who

subsequently performed the improper transfer.

In addition, a review of the operations logs revealed that the

shift supervisor documented the maintenance being performed under

MWO 29701339 as " Battery Charger Clean and Inspect." when the

actual maintenance was to clean and inspection of the battery

charger feeder breakers. The inspectors determined that

operations * oversight and coordination of the battery charger

transfer evolution was poor.

Enclosure 2

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c.

Conclusions

Operations demonstrated poor oversight and coordination of the

battery charger transfer activity. A PE0 failed to pro >erly

follow procedures governing continuous use activities tlat affect

the operability of EDG 2A and 2C 125-VDC subsystems.

This failure

to follow procedures was identified as an example of Violation

(VIO) 50-321. 366/97-09-01. Failure to Follow Procedure - Multiple

Examples.

08

Miscellaneous Operations Issues (92901) (82301)

08.1

(Closed) IFI 50-321. 366/96-13-04:

Inability to Correctly

Classify Events.

This IFI was initiated following

misclassification of events during simulator scenarios observed

during a licensed operator requalification program assessment. The

licensee revised procedure 73EP-EIP-001-05. " Emergency

Classification and Initial Actions." to improve usability and

increase training emphasis on event classifications.

Based upon

the inspectors' review of licensee actions and demonstrated

improvements in simulated event classifications this item is

closed.

08.2 (Closed) LER 50-366/97-09:

Removal of DG Battery Chargers From

Service Results in Inoperability of Both the 2A and 2C DG DC

Electrical Power Subsystems. This LER is discussed in

Section 04.4 of this IR.

Based upon the inspectors review of

licensee actions, this item is closed.

II. Maintenance

M1

Conduct of Mcintenance

M1.1 General Coments

a.

Jnsoection Scoce (62707)

The inspectors observed or reviewed all or portions of the

following work activities:

MWO 1-97-2223:

realace RPIS 28 volt power supply

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MWO 1-96-2099:

re) lock 1B EDG generater winding at next

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outage

MWO 1-96-3225:

inspect 1B EDG engine per applicable

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6-year PM procedures

MWO 1-97-1998:

perform inspection of 18 EDG jacket

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coolant pump in accordance with procedure

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52PM-R43-017-0S

MWO 1-96-4145:

Jerform 18-month grease inspection on

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iPCI CST suction valve 1E41-F004

Enclosure 2

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-b.

Observations and Findinas

The inspectors found that the work was performed with the work

packages present and being actively used.

c.

Conclusions

Maintenance activities were generally completed in a thorough and

professional manner. No deficiencies were identified by the

inspectors for the maintenance activities observed.

M1.2

Rod Position Indicatina System (RPIS) and Drywell-to-Torus Vacuun

3reaker Problems on Unit 1

a.

Insoection Scope (62707) (37551) (71707)

The inspectors observed portions of the work activities associated

with the re)lacement of the 28-volt RPIS power sup)ly and

discussed tie activity with the system engineer.

)iscussions were

also conducted with operations' management concerning the opening

of a drywell-to-torus vacuum breaker during drywell venting

activities.

Additionally the inspectors reviewed the Technical

Specifications (TSs). Technical Requirenent Manual (TRM). abnormal

operating procedure. MWO 1-97-2223. and applicable work packages

associated with the problems.

b.

Qbservations and Findinas

Unit 1 entered TRM Action Statement. Section T3.3.3. on

September 16. due to an inoperable RPIS.

The TRM Action Statement

required that the unit be in Mode 3 (Hot Shutdown) within 12

hours. The RPIS became inoperable due to a failed 28-volt power

supply. The operators lost a portion of the full core display

panel.

Operators were able to determine control rod positions

using the process computer.

The manual and automatic shutdown

functions of the control rods were still operable.

Similar RPIS and drywell-to-torus vacuum breaker (DW/ torus)

3roblems occurred on June 30 and July 20.

The 5-volt power supply

lad failed for the RPIS system and the 1T48-F323F DW/ torus vacuum

breaker had failed to close due to mechanical binding.

Details of

these problems are documented in section 01.3 of Inspection Report

(IR) 50-321, 366/97-07.

i

'

The inspectors observed a portion of the RPIS power supply

replacement activity and its return to service. The system

indicating lights operated properly and the RPIS functioned

properly.

Enclosure 2

1

,

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-

-

...

.

.

~

.

J

14

Engineering personnel informed the inspectors thai; the current

i

5 volt and 28-volt RPIS power supplies are obsolete and a design

change to realace the existing power sup) lies ds being prepared.

The design clange will be installed in tie future.

On Seatember 15 during drywell (DW) venting activities, the

IT48

323A DW to torus vacuum breaker openec and would not close.

Operations 'ersonnel entered the correct TS Required Action

>

Statement ( RS)

3.6.1.8. Suparession Chamber-to-Drywell Vacuum

i

Breakers. This TS requires tlat the vacuum breaker ce closed

within two hours.

The operating crew aligned the SBGT system to

take suction from the torus as allowed by procedure and the vacuum

breaker closed within the required two hours.

The TS RAS for the

opened vacuum breaker was terminated.

Operations management informed the inspectors that the operating

crew allowed the DW-to-torus differential pressure (DP) to become

lower than desired during DW venting activities.

The F323A vacuum

breaker has a history of opening sooner than the other vacuum

breakers, and it o]ened at the higher DP.

Operations management

further informed t1e inspectors that a night order was written for

the operators to use during drywell venting activities.

The night

order instructed the operators to keep the DW-to-torus DP greater

than 0.2 pounds per square inch differential (psid).

The TS

opening setpoint is less than or equal to 0.5 psid. The

inspectors reviewed the night order and system operating procedure

3450-T48-002-15. " Containment Atmospheric Control and Dilution,"

Rev.1.6. and no deficiencies were identified.

The inspectors also reviewed Section T3.3.3 of the TRM and

abnormal operating procedure 34AB-C11-002-1S. "RPIS Failure."

Rev.1. Edition (ED) 1. to verify that the appropriate actions

were taken by the o)erating crew.

The inspectors reviewed

MWO 1-97-2223 whic1 provided instruction for the replacement of

the 28-volt RPIS power supply.

No deficiencies were identified.

c.

Conclusions

Maintenance's response to the RPIS problem was timely; engineering

support of the maintenance activity was excellent: and operations

personnel took the appropriate actions for the RPIS failure.

Enclosure 2

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.

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,.

15

M1.3 LA Emeraency Diesel Generator Failure To Start Durina Surveillance

M

,

xa.

-Insoection Scone (61726) (92902)

.

The inspectors reviewed applicable maintenance procedures,

associated MW0s,_and work packa9es associated with the repair of

>

the 1A EDG following a: failure to start on September 4, 1997-.- The

inspectors discussed the EDG failure with operations, maintenance.

,

and engineering personnel.

b,

l Observations and Findinas'

,

% ring the performance of surveillance test 34SV-R43-001-1S.

" Diesel Generator 1A Monthly Test." Rev. 17. ED1. the-1A EDG

failed to start. Operations personnel contacted maintenance for'

,

their assistance in troubleshooting activities.

Operations

declared the EDG inoperable and initiated the correct TS RAS. The

maintenance investigation revealed that the fuel oil check valve

had stuck in the open position. This check valve is on the down-

stream: side of the injectors and allowed the fuel oil to drain

from the fuel oil header back into the clean fuel oil drain tank.

As a result an inadequate supply of fuel oil existed for the EDG

,

-start.

-

Maintenance replaced the-check valve and the EDG surveillance was

'

successfully completed.

Hintenance and engineering personnel

conducted a review of pa~

nerformance and repair history for the

o

check valves and issued at e Mneering evaluation to document the

results of the review. The mspectors reviewed the engineering

evaluation and other licensee documentation and observed the

following:

.In 1987, all check valves (one for each of the five EDGs)

.

were replaced due to suspected problems.

From the total of five valves, two valves had 10 years or

e

,

~

more of service life with no problems.

Check valves for

EDGs 2A and 2C were replaced in 1987 and in March 1997.

-respectively, with no problems observed.

One valve had five years of service life with no problems.

.

The check valve for-EDG 1B was replaced in October 1992 and

.

August 1997-, with.no problems observed.

<

L.

One valve had less than five years of service life with one

failure.

- The check-valve for EDG 1A was replaced in April 1993 and -

.

had failed in September 1997.

Enclosure 2

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. . - . . -

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, - - - , - -

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.

.

.

16

Maintenance personnel inspected the check valve installed in the

1C EDG and discovered that it was also open. The check valve was

replaced, and post maintenance testing was successfully performed.

The check valve had been replaced in March 1993.

The engineering evaluation recommended that the check valves be

replaced every five years, however, maintenance management was

evaluating whether or not the frequency snould be every 18 me hs.

The inspectors were informed that the check valve was suspected of

causing sluggish EDG start times in 1987.

The inspectors were not

aware of any recent operability concerns or sluggish EDG start

proi>lems .

c.

Conclusions

Maintenance and engineering support following the 1A Emergency

Diesel Generator failure to start on September 4 was excellent.

The review of past performance and repair history for the failed

fuel oil check valves that resulted in additional check valve

replacements demonstrated conservative decision making.

M1.4 Unit 2 Forced Outaae

a.

Insoection Scooe (6270171

The inspectors reviewed applicable procedures and MW0s associated

with the main steam isolation valve (MSIV) limit switches on

Unit 2.

Limit switch adjustments were discussed with maintenance,

engineering, and operations personnel.

Additionally, the

inspectors reviewed procederes applicable to the repairs performed

on the low pressure coolant injection (LPCI) check valve during

management and engineering personnel

pairs with maintenance

the forced outage and discussed the re

b.

Observations and Findinas

On September 14. While performing quarterly MSIV surveillance

)rocedure 345V-B21-001-25. "MSIV Exercise and Closure Instrument

unctional Test." Rev. 5. ED 1: the 2C71-K3G and 2C71-K3H relays

r

failed to re-energize when the 'O' inboard MSIV was returned to

its fully opened position.

Because a s-imilar relay associated

with the 'B' MSIV was already de-energized due to a similar

failure during the previous surveillance a half scram resulted

which the operators were unable to reset.

The failure of the

relay associated with the 'B' inboard MSIV is documented in

Section M1.3 of IR 50-321. 366/97-07.

The licensee decided to bring the unit to Hot Shutdown for entry

into the drywell to ins)ect and/or adjust the limit switches that

provide the signal to t1e relays that failed to re-energize.

Enclostre 2

.

.

..

~

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-

. . - - -

- -

. .

-.

. .. .

- - ~ . - . . -

.

n

+

-

i

.

.

-

li

.

Maintenance work was completed for limit switch adjustments and-

-

unit startup was commenced on September 18.

The unit achieved

100% RTP on September 22.

Due to the failure of the relays to reset on September 14 and on

June 22,1the licensee initiated a root- cause investigation of the

,

MSIV limit switch problems.

The licensee root cause investigation:

!

concluded that the limit switch setup methodology was a-possible-

,

contributor to the problem.-.The-limit switch reset positions

'

i

criteria was not specified by procedure and was left to the

judgement of the electrician performing the work. A new type of

i

limit switch was installed during the-last unit refueling outage

-

and craft judgement-was again used to set the limit switch reset

positions. However, small changes in valve stroke length (due to

unknown causes) when steam flowed through the MSIV may have

prevented the' limit switches from resetting'when the MSIV-was very

close to the valve full-open position. Maintenance personnel also

determined that the new limit switch reset position was not

consistent and predictable like the previous limit switches. The

4

root cause investigation report-recomnended that the maintenance

4

department revise applicable procedures to include specific

instructions on limit switch reset positions.

The inspectors reviewed surveillance procedure 52SV-B21-001-0S.

"MSIV Limit Switch Inspection," P.ev. 4.

The revision of the

procedure included an addition which required a confirmation that

-

the MSIV limit switch resets when the MSIV is taken back to the

.

fully opened )osition.

Other procedure steps were either deleted

or added to t1e preventive maintenance procedure.

Health Physics personnel identified a leak on the Low Pressure

Coolant Injection (LPCI) check valve 2E11-F050B upon initial entry

into the drywell for the MSIV limit switch adjustment work

-

activity.

The valve was leaking steam from the hinge pin area.

Maintenance attempted to stop the leak by torquing the hinge pin.

The valve was_ repacked after the torquing failed to stop the leak.

l:

c.

. Conclusions

Management's oversight and pre-job plconing for forced outage

act'vities on the MSIV limit switch adjustment was good.

Craft

personnel performed the work activity in a professional and timely

<

manner. Health Physics personnel demonstrated a aro-active-

attitude by identifying the LPCI check valve leac and notifying

maintenance.

,

L

Enclosure 2

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18

M2

Maintenance and Material Condition of Facilities and Equipment

M2.1

Inocerable Unit 2 Hiah Pressure Coolant In.iection (HPCI) Pumo

a.

Inspection Scone (62707)

On August 18 the Unit 2 HPCI pump was declared inoperable due to

a broken flange bushing that was discovered by maintenance

personnel.

The inspectors reviewed a)plicable drawings.

3rocedures. TS. MW0s. Licensee Event Re] orts (LER), and the

Jpdated Final Safety Analysis Report (U SAR) associated with

repairs of the pump. The inspectors also held discussions with

.

involved maintenance, engineering, and vendor personnel,

b.

Observations and Findinas

On August 18. during a routine housekeeping wal!:down of the HPCI

system. maintenance personnel discovered pieces of metal in the

shaft drain casing of the HPCI main pump.

The metal pieces were

from the pump shaft flange bushing (six pieces) and one of the

shaft's split rings. The flangt bushing is designed to limit the

water flow from the shaft of the pump in the event of a

catastrophic failure of the mechanical seal.

The split ring is

one of two semicircular rings that assists in maintaining the

shaft sleeve in proper alignment.

Operations personnel declared the HPCI system inoperable after

being informed of the damage.

The RAS of TS 3.5.1. Condition C,

was entered. The required 10 CFR 50.72 notification was made to

the NRC.

housing and

The inspectors observed the disassembly of the bearir.g/ repair

removal of pum) shaft components during the inspection

activities.

T1e inspectors observed that the lubricant piping

removed was not immediately sealed for foreign material exclusion

(FME) control.

The inspectors observed that sawing activitias of

metal components were in progress in the immediate area and had

the potential of FME contamination.

Maintenance personnel

eventually taped the lubricant piping for FME protection. The

inspectors were later informed that the piping and components were

flushed and cleaned prior to installation.

The inspectors observed the recovered pieces of the bushing

flange.

It was noted by the inspectors that all pieces necessary

to reconstruct the flange bushing were not present. The

inspectors were informed by maintenance personnel that six pieces

of the flange bushing were recovered and the remaining missing

part or parts were not found.

A search of the immediate area was

conducted but did not locate the missing parts.

Enclosure 2

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_

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_

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_

--

_ _ . . ~ _ - _ _ . . _ _

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19-

The licensee contacted the aump vendor to assist with the failure L

mechanism determination. Tle inspectors discussed the possible

-

'

cause of the flang,e bushing failure with-the vendor

~

representative.

nie vendor representative informed the inspectors

that he suspected that shaft movement caused by the bearing-

failure cn the-shaft between the main pump and the booster pump -

allowed the shaft to rub against'the flange bushing, thus causing

,

a: failure of the flange bushing.

The licensee suspected that the bearing failed due to a small

amount of particles that contaminated the main pump journal

1

2 earing housing. This caused damage to the bearing babbitt-

.!

material which led to increased pump vibration sufficient in

'

magnitude to cause the shaft-to impact, crack, and. break the-

flange bushing and displace the spl:t ring retainer. The licensee

indicated that the damage to the seal likely occurred during the

performance of the HPCI operability surveillance performed on

August 11, but was unable to determine the source and type of

.contamiration that caused the bearing damage.

The inspectors reviewed the data package for the most recently:

-performed o)erability surveillance procedure: 34SV-E41-002-2S,

+

"HPCI Pump Operability." Rev. 26, and noted that the main pump

inboard horizontal vibration (point H03) was in the alert range.

This required the operability test to be performed at double the

,

normal frequency.

A review of MWO 2 96-0024 by the inspectors indicated that a small

water leak at the mechanical seals had been identified earlier.

i

Since the leak did not affect pump operability the work for the

mechanical seal repair / replacement was initially deferred until

the next Unit 2 refueling outage. The MWO was revised to include

>

the work scope for the replacement of the damaged bearing.' the

flange bushing and the split ring. All work was performed and the

HPCI-system was returned to an operable status-en August 24.

The inspectors reviewed LER 50 366/97-08, Main Pump Journal

Bearing Damage Renders HPCI System Inoperable.

As part of the

>

corrective actions, the licensee inspected and replaced the

i

inboard and outboard main pump bearings and rebuilt the pump shaft

bearing. The damaged outboard main pump mechanical seal was

replaced and the bearing lubrication oil system was drained,

flushed, and cleaned. : The lubricating' oil system filters were

also replaced.

Following-system repairs. maintenance engineering

personnel confirmed that vibration levels and alignment of the

l

turbine and main' pump were within acceptable tolerances.

l

Enclosure 2-

l

. - -

- -

.-

-

.

- - . . -

..

_- ,

,

-

_

.

-.

.

. . , - -

--.

-.

- - ~ - - - - - - - -

_ . . - _

--

,

,-

. . -

_;

-

1

.20-

The inspectors-reviewed vendor. drawings S-25084. "HPCI Pump he

l

Sectional-GE VPF #3076-13." and the associated drawing for t

mechanical seals. Additior, ally. Unit 2 UFSAR Section 7.3.1.2.1.

1'

High Pressure Coolant Injection System Instrumentation and

Centrol, was reviewed.

No discrepancies were identified.

I

c.

Conclusions--

Maintenance personnel's attention-to-detail during the walkdown

which discovered the broken pieces of the HFCI flange bushing was

superior.

Engineering support of maintenance was excellent.

FME-

i

control measures were satisfactory.

M2.2 Intake Structure Dredaina Activities

a.

InsoectionScone(62727.1

.

The inspectors observed activities associated with the dredging

and cleaning of the intake structure water pit.

The inspectors

also reviewed MWO 1-97-1453 and the data package of )rocedure

52PM-MME-006-05 " Intake Structure Pit Inspection." Rev. 6.

Discussions were conducted with maintenance supervision and

v

engineering. A representative sampling of clearance tags was

verified,

b.

Qbservations and Findinas

On September 26. the inspectors observed activities associated

with the preparation-to dredge and clean the intake structure pit.

The inspectors observed that a FME area boundary had been

established inside the intake structure on the ground level and

FME was properly controlled.

The inspectors verified that a representative sampling of the-

'

clearance tags associated with the work activity was properly-

placed.

The inspectors discussed communication aspects of this activity.

-with engineering and maintenance supervision. The inspectors

observed that communications had been established with the divers.

the divers' attendant. the control room, and with a member of the

>

diving ~ team that--was located on the dredge platform.

The dredge platform was afloat-on the river with a suction hose.-

that ran through an opening in the travelling screens. The

opening was made by removing necessary sections of the traveling

The opening in the travelling screen was large enough to

screen.

insert an 8-inch diameter suction line into the pump suction pit

e

L

area.: Security personnel appropriately monitored the area.

Enclosure 2

!-

L

. _

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,

.

-

.

.,.

-

-

~ -

-

.

21

A review of MWO 1-97-1453 and the data package for procedure

52PM-MME-006-0S revealed that the intake pit dredging and cleaning

activity was completed by the divers on October 2.

The divers had

cleaned the pit to an acceptable level per the requirements of

procedure 52PM-MME-006-0S.

c.

Conclusions

The ins)ectors concluded that maintenance and engineering

oversialt of the activities was excellent.

FME and security

control measures were appropriate.

Communications and

departmental coordination was good.

H3

Maintenance Procedures and Documentation

M3.1 Surveillance Observations

a.

Inspection Scoce (61726)

The inspectors observed various surveillance activities. The

procedJres to accomplish the activities provided instructions for

demonstrating that the referenced safety-related equipment

functioned as required by TSs and the Inservice Testing procram,

b.

Qbiervations and Fin.fdn_qi

The inspectors observed all or pcrtions of the following Unit 1

and Unit 2 surveillance activities:

345V-E11-001-1S:

Residual Heat Removal Pump Operability.

.

Rev. 20. ED 1

345V-E41-002-1S: HPCI Pump Operability. Rev. 21

.

345V-R43-003-2S:

Diesel Generator 2C Monthly Test. Rev. 18

.

34SV-SUV-018-1S:

ECCS Status Checks. Rev, 6

.

57SV-N62-001-2S:

Off Gas Hydrogen Analyzer FT&C. Rev. 10

.

The inspectors attended the pre-evolution briefing for all of the

surveillance activities.

During the Unit 1 HPCI o)erability

briefing, appropriate precautions were emphasized )y the Unit 1

Shift Supervisor regarding torus temperature. Communications

between maintenance, engineering operations, and HP personnel

were excellent. The inspectors observed that, during the test.

operations personnel were very cognizant of monitoring suppression

pool temperature.

Coordination between the test lead operator and

the shift operator when placing the RHR system in the suppression

pool cooling mode was good.

The inspectors observed that during the Unit 1 RHR operability

pre-evolution briefing, the lead operator appeared unfamiliar with

specific aspects of the test as they related to items on the

Enclosure 2

.

.

22

pre-evolution checklist.

Specifically, the operator was unsure of

what permission was required to initiate this surveillance,

whether FME would be a concern, and whether or not a post-

evolution briefing would be conducted to discuss results of the

test.

The inspectors discussed this observation with operations

management.

During the Unit 1 RHR pump operability test,

the inspectors

observed that operations personnel collected in Service Testing

(IST) vibration readings at two )oints on the motor mounting

flange in the radial direction. )ut took no axial vibration

readings.

Discussions with the licensee's IST engineer and a

review of the RHR pum) IST plan revealed that these pumps were not

equipped with thrust 3 earings, therefore axial vibration readings

were not required.

The inspectors examined the IST test data for the 1A RHR pump and

verified that reference parameters were correctly extracted from

the Unit 1 IST data book.

No deficiencies were identified,

c.

Conclusions

For the surveillance activities observed, all data met the

required acceptance criteria and equipment performed

satisfactorily. The surveillance tests were conducted in

accordance with procedures and with cversight from supervisors and

system engineers.

With minor excepticns, all involved personnel

were knowledgeable of the tests and system performance

requirements. Overall, performance was professional and

competent.

M3.2 Review of The American Society of Mechanical Enaineers (ASME) Code

Visual Examinations for Unit 2

a.

Insoection Scoce (62707) (929021

The inspectors reviewed the work packages for maintenance

activities performed during the Unit 2 Spring Outage of 1997.

This review was to ascertain whether applicable visual

examinations, as required by Section XI of the ASME code, were

met.

The inspectors conducted discussions with Quality Control

(OC) supervision and engineering. Additionally, the inspectors

reviesed the following plant procedures:

Engineering Service Procedure 42EN-ENG-014-05. "ASME

.

Section XI Repair / Replacement." Rev. 9.

Quality Control Procedure 450C-0CX-009-0S. " Quality Control

Document Review and Inspection Point Assignment." Rev. 5.

Enclosure 2

.

,

,

c

_

23

-

• -

Administrative C6ntrol: Procedure-40AC-0CX-001-05.J" Quality

Control -Inspection Program." Rev

7.

b.

.0bsersations and Findinas

IThe ins)ectors were informed by quality control (0C) supervision

that-a QC review of work packages for the recent Unit 2 outage

(Spring 1997) revealed that-some required Section XI ASME code

~

visual inspections were not performed. The work packages in-

question were 2-96-0834. 2 96-0836, and 2-97-0686. The work

packages were identified on deficiency card (DC) C09703695.

~

The inspectors discussed the work packages with engineering

personnel assigned to perform the root cause determination for the

deficiencies.

Engineering informed the inspectors that the ASME

Section XI Code-required visual inspections (VT-1 and VT-3) were

performed but some were not performed per.the guidance provided 'in

procedure 42EN-ENG-014-05.

The inspectors reviewed the three work packages listed on

DC-C09703695, the Root Cause Analysis Summary for the DC, and the

engineering evaluation for the vendor-performed VT-1 for the

feedwater check valve hinge pin installation. This review

indicated the following:

Work packages 2-96-0834 and 2-96-00836 provided wark

.

,

instructions for outage re) air / replacement activities on

safety relief valves.2B21

013E and 2B21-F013G.

respectively.

The work activity in question was for the

welding of a strap onto the safety relief valve to support a

pilot sensing tube. The licensee treated the work activity

as an ASME Section XI repair / replacement activity, thus

requiring a VT-3 examination. However, the VT-3 post

maintenance requirement was not listed on the Section XI

Examination Plan, attachment 4. of procedure

,

42EN-ENG-014-05, and the VT ' was not com)leted. However.

'

l

' credit was taken after the tag because t1e OC inspector

assigned to the work cctivities was VT-3 qualified and had

c

performed other visual examinations-on the valves. A review

'

of the ASME Section XI code revealed that this work was not

-

required to be treated as ASME Section XI.

-

• -

Work package 2-97-0686 provided work instructions-for outage

repair / replacement activities performed cn feedwater inboard

check: valve-2821-F0108. The work activity in question was

for the installation of a new u) graded hinge-pin assembly.

The Quality Control Ins)ection )oint Assignment Sheet of

procedure 450C-0CX-0094S (generic hold point sheet)

required a VT-1 based upon the repair / replacement program.

This generic hold sheet was in the work package. A

t

,

Enclosure 2

4

o

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.=

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>

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.-

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24

documentation review revealed that an initial baseline VT-1

-

(prior to valve hinge pin work) was performed by site OC

Sersonnel in accordance with the repair / replacement program,

Jut was not performed on the replacement bolting after the

new hinge pin was returned to service. An engineering

evaluation of the VT-1 performed by the vendor was conducted

by the licensee. The evaluation concluded that the visual

examinations performed by the vendor met all the

requirements to fulfill the ASME Section XI pre-service

examinations of a VT-1.

'

Procedural enhancertents were recently implemented for the

Section XI Examination Plan of procedure 42EN ENG-014-0S and the

Quality Control Ins)ection Point Assignment Sheet of procedure

450C-0CX-009-0S. T1ese enhancements provide more clarity as to

when post repair / replacement inspections are required.

The inspectors reviewea administrative control procedure

40AC-0CX-001-05. Step 8.6.5 of the procedure required, in part,

that th? qualified OC inspector perform inspections in accordance

with an a> proved Quality Control Inspect.on Point Assignment Sheet

(generic lold point sheet).

Site OC personnel did not perform a

VT-1 inspection for replacement work activities on feedwater check

valve F010B during the Unit 2 spring outage of 1997 per plant

procedures.

Credit was taken, after an engineering evaluation,

for a vendor-performed VT-1.

The inspectors reviewed licensee performance for the past two

years with respect to Section XI ASME code VT inspections. A

violation was identified in Ins)ection Report 50-321. 366/96-11

for a failure to perform an ASME Code-required VT-3 inspection on

HPCI Valve 1E41-F006.

The inspectors concluded that the

circumstances surrounding the missed VT-3 on the HPCI valve were

different and the corrective actions for that violation would not

have reasonably prevented the VT-1 problem with the feedwater

check valve hinge pin replacement.

c.

Conclusions

ASME Section XI code requirements for visual inspections were met

for the strap welding on the SRVs and the hinge pin replacement on

the feedwater inboard check valve. The acceptance of credit for

-the VT-1 performed by the vendor for the feedwater check valve was

reasonable.

The inspectors concluded that site OC personnel

failed to follow the requirements of plant procedures for the VT-1

listed on the generic hold inspection sheet for replacement work

on the feedwater check valve hinge pin. This was identified as an

example of VIO 50-321, 366/97-09-01, Failure to Follow Procedure -

Multiple Examples.

Enclosure 2

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,

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,

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25

M3.3

Review of Traversina Incore Probe (TIP) Flance Reolacement On

-

Jnit 2

a.'

-Insoection Scoce (62707)

.

The inspectors reviewad procedure 42EN-ENG 014-0S. "ASME

Se: tion XI Repair / Replacement." Rev 9.-and documentation

associated with ASME Code.Section III. Class 2. requirements for

4

i

the Unit 2 primary containment' TIP penetration flanges,

'

b..

Observations and Findinas

The inspectors were informed by Nuclear Safety and Compliance

(NSAC). personnel that they were conducting a review of whether or

-

not the Unit-2 primary containment TIP penetration flanges meet

ASME Code Section III. Class 2. requirements.

Table 3.2-1 of the

' Unit 2 UFSAR lists the TIP piping as ASME Code Section III.

Class 2.

This included the flange. TIP tubing, and tubing valves.

This review was initiated following a review of maintenance work

activities conducted during the last Unit 2 refueling outage.

~

The inspectors reviewed E.I. Hatch Nuclear Plant

Unit 2 Safety

Assessment for Primary Containment TIP Penetrations, dated

September 10, 1997, and Hatch Project Support - Engineering

Operability-Evaluation - Unit 2 TIP Penetrations, dated

.

September 16. 1997.

The inspectors also reviewed Table 3.2-1 of

the Unit 2 UFSAR.

GE h'd verbally informed the licensee that, even though the TIP

systen flanges were not what the code s)ecified in the UFSAR,

there was no operability concern with t1e TIP system.

The

licensee stated that GE informed it that other sites had

identified similar problems with respect to the TIP system and

that the components supplied by GE were equivalent to those

required by ASME.

By letter dated October 21. 1997. entitled-

Hatch Tip System ASME Code Compliance Evaluation. GE concluded

that the portion of the TIP system that is considered part of the

primary containment supplied for Hatch Units 1 and 2 during

construction and as replacement parts meet the intent of ASME

Section III. Class 2.

The licensee also informed the inspectors

that a proposed UFSAR change for table 3.2-1 was being reviewed

=for the next scheduled UFSAR submittal.

The inspectors reviewed applicable documentation and observed that

all applicable-inspection requirements of the ASME code were met

following the flange installations on Unit 2.

Enclosure 2

.

_

.

.

.

.

.

. - -- . . , .

- ~-

.

-

-

. - -

-- - -

-;

.

9

26

1

c.

-Conclusions-

a

-

-

r

The licensee had taken appropriate actions-to correct the TIP

.

_.

.-System ASME code, Class 2-issues. ,The GE Code requirements of the

'

'

TIP equipment installed were equivalent to those of the ASME Code.

-"

The proposed UFSAR revision was appropriate.

M7_

Quality Assurance in Maintenance Activities

,

M7.1

Review of Safety Audit end Enaineerina Review (SAER) Audit

ReDort 97-SA-3 (62707)

The-inspectors reviewed audit report 97-SA-3. Ventilation Filter

Train Testing, dated July 24, 1997. The audit included a review

of procedures, methodology, and employee performance of testing

activities for plant-ventilation systems described in the

Technical Specifications (TSs) and UFSARs for both units to ensure

'

that the ventilation filter testing program was being correctly

implemented. The audit included a detailed review of the TS and

UFSAR requirements and the testing requirements and methodology

outlined in Regulatory Guide 1.52 and ASME/ ANSI N510.

The inspectors concluded that the audit was conducted by trained

'

and qualified personnel. The audit was thorough and detailed. The

inspectors observed that the audit findings identified were

submitted to appropriate management and department personnel.

Corrective actions were-identified and tracked in accordance with

applicable plant procedures. The corrective actions and proposed

completion-dates were appropriate for the findings.

M8-

Miscellaneous Maintenance-Issues (92700) (92902)

M8.1

(Closed) LER 50-366/97-08: Main Pump Journal Bearing Damage

Renders HPCI System inoperable.

This item is discussed in

licensee actions,- this

_ER is closed.pon the inspectors' review of

Section M2.1 of this re)crt.

Based u

-

,

M8,2_ (Closed) IFT 50-321. 366/96-14-02:

Potential Single Failure

Vulnerability in the Freeze Protection System.

This item was

opened'to review whether or not a loss of power from Unit 1 to the

freeze protection for the service water cooling plaing to the

IB Emergency Diesel Generator (EDG) could impact t1e EDG's

operability support to Unit 2.

Corportte engineering reviewed the

issue and determined that a potential

Ligle failure vulnerability

in the freeze protection heat tracing system does not exist.

-dated February 10.pectors* review of the engineering evaluation.

Based upon the ins

1997, this item is closed.

-

r

n

Enclosure 2

'

,

,_ .

, , - . . -

= . - . - - - . - - .

- - - ,

.

- ,.

- - . -

-

.

.

,

27

M8.3 (Closed) IFl 50-321/96-15 04:

Switchyard Maintencnce and Material

Condition.

Ihis item was initiated following an inspection to

evaluate electrical maintenance in the switchyard as it relates to

the Maintenance Rule.

The following completed or long term

planned corrective actions associated with the IFl were described

in documentation provided by central scheduling personnel during a

discussion:

An independent review team performed a thorough housekeeping

inspection of the switchyard on January 19.1997.

The

inspection identified the items listed in the IFl and a

determination was made that che housekeeping and material

conditions did not meet the expectations and standards of

plaat Hatch, but no items were identified that were

detrimental to the proper operation of switchyard equipment.

An evaluation of overdue PMs indicated that they were not

.

applicable to Plant Hatch.

PMs (performed every eight

years), which are applicable to Hatch, were current.

The following long-term process was developed to avoid

.

future concerns:

Southern Transmission Maintenance Center (STMC) will ensure

that adequate housekeeping standards are maintained in the

switchyard.

,

Dispatchers in central scheduling will function as the

primary contact for planning and performing switchyard

maintenance.

STMC and central scheduling agreed that the policy and

practice will be that there will be no overdue PMs.

Those

chat are currently overdue will be completed by the end of

the year.

STMC will arepare a yearly schcdule of planned PMs for

central scleduling to review and approve.

The inspectors performed a tour of t5e switchyards and the

switchyard cont N1 house on October 2.

The inspectors questioned

central scheduling personnel about untaped s)are electrical leads

observed in the switchyard control house. Tlese electrical leads

were identified in the IFl.

The inspectors were informed by

central scheduling and STMC personnel that it was a common

practice of the switchyard maintenance crew state wide, to leave

the ends of the electrical leads pointing straight up and un-

taped.

Housekeeping and material conditions were good.

Enclosure 2

_ _ . . _ . _ _ _ _

_ _ _ _ _

. _ . . _ . . , _ . _ . . _ . - . _ _ . _ _ . _ . _ . _ _ _ . _ _ _

.

,

i

I

i

4

28

j

-Basea upon the inspectors * review of licensee actions, this item

I

is closed.

j

.

M8,4 (Closed) IFI 50-321. 366/97-0 D J:

Review of Licensee's

i

Assessment of the ALARA Process for the Unit 2 Reactor Coolant

!

~

Leak Repair on the RWCll Heat Exchanger,

This item was identified

due to a significant difference between the ALARA staff's

estimated dose of (15 person rem) and the actual dose

(28.33 person rem) received during the leak repair activities,

'

,

The licensee conducted a review of the activities and identified

i

that the type of welding process and the amount of welding-

!

contributed to the dose received,

Ins)ection report

50 321, 366/97-07- identified other worc coordination and

exmunication deficiencies that also contributed to the increased

i

dose.

The licensee's review did not identify any significant new

l

information.

The inspectors concluded that the initial ALARA

!

assessment, the followup ALARA review, and the ALARA review

.

methodology were satisfactory.

Based upon the inspectors' review

of licensee actions, this item is closed.

3

III. Enaineerina

El

Conduct of Engineering (37551)

On site engineering activities were reviewed to determine their

effectiveness in preventing, identifying, and resolving safety

issues, events, ma problems,

,

1

El.1 Review of Units 1 and ? Inadeauate Cable Seoaration Issues (37551)

i

,

(92903)

The inspectors continued to monitor the licensee's progress and

work activities associated with the cable separation issue.

This

i

issue was originally documented as IFl 50-321, 366/97-03 05 and

!

was discussed in Inspection Report 50 321, 366/97-07.

The

inspectors have concluded that-the licensee is making progress in

resolving the issue.

E4

Engineering Staff Knowledge and Performance

E4,1

Pre Outaae Fuel Insoection and Preoaration

.a.

Insoection Ccooe (60705l

The inspectors reviewed procedure 42FH ERP-012-05, "New Fuel and

New Channel Handling." Rev, 7. and observed licenree activities

i

-

for new fuel receipt, inspection, and-storage.

>

h

!

Enclosure 2

t

- ---

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-

.,.__._._,,..,m__

_ - . - - -

. _

- -

-

-

.

p

.

..

29

i

!

- b.

Observations and Findinas

j

i

i

-The inspectors observed that new fuel received on site was

i

temporarily stored at a location near the intake structure.

The

'

materials area. y identified and controlled as a radioactive

area was properl

The inspectors observed the shi> ping crate

unloading, crate disassembly, and HP survey of tie new fuel.

4

Reactor engineering personnel were present and provided oversight

and direction of the activity.

Inventory sheets-for

.

accountability and tracking of the new fuel were completed.

!

Security personnel provided satisfactory security oversight.

,

The inspectors observed new fuel inspection and channeling

.

activities from the Unit I refueling floor.

New fuel channels

!

were Installed and the fuel was moved to the spent fuel pool for

!

storage.

1

'

- c.

Conclusions

The inspectors concluded that new fuel receipt. inspection, and

storage were completed with appropriate oversight and control, and

^

>

in accordance with applicable plant 3rocedures.

Engineering. HP.

and security personnel support for t1e activity was satisfactory.

I

E8

, Miscellaneous Engineering Issues (92903)

$

E8.1

(Closed) IFI 50 321/96-14-05:

Restoration of IB EDG Motor Control

,

Center (MCC).

This item was initiated following the

implementation of temporary modification (TM) 1-96-41, This TM

i

was implemented because the Unit 1 supply breaker in the IB EDG

'i

MCC 1R24-S026 did not coordinate properly with its downstream load

breakers. This was an operability concern for the MCC and the

A fault at any of the r: quiring alignment of the 1B EDG to Unit 1.

IB EDG during events re

on-safety related loads supplied from

1

MCC 1B had the potential to cause the breaker to trip, thus

leaving the safety related loads su) plied by MCC IB inoperable.

-

The TM resolved the immediate opera)ility concern t./ moving the-

.

non-safety related loads to another bus.

As a permanent resolution, the licensee implemented design change

request (DCR) 1 96-055. The.DCR modified safety-related EDG

-

.

building 600/208-volt MCC 1B 1R24-S024 to eliminate possible

non coordination-between safety-related supply breakers and

>

downstream non safety related loads for certain postulated faults.

'

Based upon the inspectors' review of DCR 1-96-055. licensee's-

!

actions, and discussions with the system engineer, this item is

closed.

,

!

Enclosure 2

l

. .

.

.

.

,

4

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ev-e

v

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"30

l

IV P1 ant Suooort-

}

R1

Radiological Protection and Chemistry Controls

t

R1.1 Observation of Routine Radioloaical Controls

i

a.

insoection Scone (71750)

)

General Health Physics (HP) activities were observed during the-

{

report period. This included locked high radiation area doors.

,

proper radiological posting. and personnel frisking upon exiting

j

the Radiologically Controlled Area (RCA). The inspectors made

frequent tours of the RCA and discussed radiological controls with

>

-

HP technicians and HP management. - Minor deficiencies were

t

-

discussed with HP technicians and HP management personnel.

RI.2

person Exits Plant Site A'ter Receivina Alarm on the Exit Portal

ionitor Wearina Potentially Contaminated Clothina

!

a.

Insoection Scoce (71750)(92904)

i

t

On September 29, 1997, a contract HP technician left the plant

!

site after receiving an alarm on the exit portal' monitor.

This

i

was contrary to HP practices and plant procedures. The inspectors

,

reviewed documentation provided by HP personnel and plant

-

procedures. and discussed the issue with licensee management.

i

b.

Observations and Findinas

On September 29, the ins)ectors were informed by HP supervision

that a contractor HP tec1nician exited the Plant Entry Security

Building (PESB) on September 26 after receiving an alarm on the

)ortal monitor.

This portal monitor is located at the exit of the

,

)ESB and is the final monitoring point for contamination prior to

leaving the protective area.

l

The licensee informed the inspectors that upon initial exit

'

through the portal monitor the individual received an alarm.

Since.there was a HP technician monitoring personnel leaving the

area, to assure that the people used the exit portal monitor

properly, the individual was monitored using a PM 6 radiation

detector.

This monitor also alarmed,

The individual was

instructed to report-to the HP office for assistance in

determining why the contamination alarms were sounding.

After

about 10 minutes. he returned to the PESB and attemated to exit

again. This time he again-received an alarm from tie monitor and

was told by the HP technician that he could not leave the site.

The individual ignored alarm and the instructions of the HP

-technician, exited the PESB.'and left the site.

,

!

Enclosure 2

,

- -

- .

~

+

_

_

_

-

-

,s _.~ _.- _ . _ . _ . _ _ _ . . _

..

.

_ _ . . _ . . _ _ _ _ . _ , , ,

---

-.

- _ -

-

!

.

,

i

i

31-

!

i

The inspectors reviewed a written statement provided by the HP

l

foreman who spoke with the individual u)on his return to the HP

k

office.

The statement indicated that tle HP foreman did not

-

recall many of the details of the conversation he had with the

individual but did recall that the individual ap> eared unhappy

'

about not being allowed to exit.from the PESB.

Tie individual did

not agree with the reasons provided by the HP assigned at the exit

'

'

point in the PESB for not allowing him to leave.

The HP foreman

also indicated in the written statement that he is certain that he

,

would not have given the individual authorization to ignore an

.

alarming portal monitor.-

,

in followup actions by the licensee. HP supervision called site

j

security and requested that access to the protective area be

-

denied to the individual upon his return.

The individual returned

i

to the site the following morning (September 27) and was met at

the entrance to the PESB by his contract su>ervisor and two HP

i

-foremen.

The individual was instructed by MP supervision to take

.

the weekend off and report back to work on Monday morning for a

discussion of the issue with HP supervision. The individual

objected to returning the following Honday morning for a

discussion and indicated that he resigned.

The individual was then escorted to dosimetry by his contract

i

supervisor for a whole body count.

The results of the whole body

I

count were normal and the individual was escorted to the exit of

the PESB.

,

The HP survey taken when the individual initially attempted to

exit the site indicated a reading of approximately 8500

.

disintegrations per minute (dpm) on one of the individual's knees.

'

The portal monitor was set to alarm at 5000 dpm.

The inspectors were informed by HP personnel that four different

scenarios were run using computer modeling to determine a

hypothetical dose which the individual would have received.

Each

scenario was based upon conservative assumptions and assumed a

point. source of radiation and a 4-hour exposure to the radiation.

Two of the scenarios constituted a set that assumed that the

contamination was due to the decay of noble gases-such as krypton.

'

xenon. and iodine. One of these scenarios assumed that the 8500

dpm obtained from the HP survey was contamination on the pant leg

with an air gap to the skin. The dose resulting from this.

scenario was 6 milli-rem (mrem) to the skin. The other scenario

in this set assumed that the contamination was on the skin.

resulting in a dose of 79 mrem to the skin.

Enclosure 2

. _

_ - _ _ _

-

-;

--

- - .- - -,_.

,,...-.m--

, _ _ _ - . . , _ _ . . - - - - . _ , - , ,

, . _ _ . - . . - _ ,

. ~ , , -

-

.

-.

-- -. -

- -

--

.-

_

- -

- _ _

_

- -

.

.

.

.

32

The remaining scenarios assumed that the 8500 dpm contamination

was from a hot particle that resulted from activated corrosion

contamination was on the pant leg with an air gap and 28 mrem

'

products. A 1 mrem dose was received when it was assumed that the

resulted when it was assumed that the contamination was on the

skin.

The results of the above computer modeling was provioM by Plant

Hatch's HP personnel to the company's corporate office.

The

corporate office provided the information to the states of Georgia

and Alabama,

Based upon the results of the computer modeling, the

states decided not to pursue the issue.

The inspectors were informed by Nuclear Safety and Compliance

management that the company will continue to pursue the matter

'

because the contaminated clothing was not recovered for frisking.

The insores were later informed that telephone contact was

later m&:e M that the individual was reluctant to discuss the

issue. Tre &tn',ee also indicated that there is a high

probability t u the contamination was due to short-lived decay

products, but that there was a concern that it may be due to a hot

particle.

The inspectors reviewed Administrative Control Procedure

60AC-HPX-012-05. " Overview of Radiological Work Practices and

Radiation Protection ACPS." Revision 4. and observed that all

procedure requirements were not met. The cause of the

contamination alarm should have been determined and a)propriate

corrective actions taken before the individual left t1e site.

c.

Conclusions

The inspectors concluded that the contract HP technician who left

the plant site after receiving an alarm on the exit portal monitor

presented minimal safety significance to the individual or public.

The actions taken by the licensee were appropriate and no further

NRC actions are planned based upon the fact that the individual is

no longer employed at the site and site access was immediately

terminated.

R1.3 Pre-Outaae Radiolooical Protection Activities

a.

Insoection Scone (60705) (71750)

The inspectors observed licensee HP activities in preparation for

the upcoming Unit I refueling outage.

Enclosure 2

_

_

]

.

33

b.

Observations and Findinas

The inspectors observed that HP management initiated several

actions to strengthen the HP area.

Meetings were held with all

Hatch personnel to communicate management's expectations for HP

activities.

The meetings included discussions on procedural

requirements, required actions for unexpected conditions, and

recent changes for radiological work permit (RWP) requirements.

Health Physics department management issued " Rad Bulletins" to

remind all plant personnel of the renewed emphasis for HP

improvements. The Bulletins communicated new RWP requirements a

special emphasis to eliminate personnel contaminations, and to

improve contamination controls and overall radiation worker

practices.

The Bulletins were made available to all site

personnel.

A new listing of radworker expectations was developed

ana conspicuously posted in various areas of the plant.

HP

management developed a checklist for good rad practices. The

checklist was used as a quick reference and feedback tool by

various managers. supervisors, and coworkers during plant tours

and peer checks.

The General Manager conducted a period of stop work and assembled

all available aersonnel in order to communicate his expectations

for improved H) practices. A resident inspector attended the

meeting and observed that several key items were discussed. A

video tape was made available for site personnel who were not able

to attend the stop work meeting.

During the last refueling outage, and for the upc'aing Unit I

refueling outage the HP department conducted tours of the cite

for new contractor personnel. The inspectors observed one site

tour for new contractors.

The tour included discussions for

site-specific frisking techniques, egress points, and routine

posting and boundaries.

The licensee completed approximately 25

tours for about 150 personnel and additional tours were planned.

The inspectors attended several HP shift briefings and observed

some improvements in communications. specific job assignments, and

overall HP staff work practices.

The inspectors observed

pre-staging activities for Unit I refueling activities and

observed that radiological and contamination control boundaries

were correctly established. The inspectors oLserved that HP

personnel routinely toured the site to assist other workers.

The

inspectors observed some minor deficiencies that were attributed

to individual worker poor work practices.

This included some

anti-contamination clothing that was not properly placed in the

l

disposal containers.

Other items were laying across the

contamination control boundary markers,

These deficiencies were

l

brought to the attention to HP personnel for resolution.

I

Enclosure 2

l

- . . - ---.- _~ ~ - _ - _ _

- - - - .

- _ . .

-

,

j

'

.

)

34

i

c.

Conclusions

l

t

i

The inspectors concluded that management personnel had placed

special emphasis for improved HP and general rad worker

activities. The stop work meeting, plant tours for- new

contractors, and radworker expectations list were identified as a

strength.

P4

Staff Knowledge and Performance in EP

P4.1 Annual Emeraency Preoaredness (EP) Exercise

- a.

Insoection Scoce (82301)

The inspectors reviewed procedures 73EP-EIP 063 05. " Technical

Support Center Activation," Rev. 6, 73EP-EIP-001 05. " Emergency

Classification and Initial Actions," Rev.12. and the Hatch

Emergency Plan for Unit I and Unit 2. and observed licensee

actions during the annual exercise.

Federal, state and county

officials participated in the annual exercise.

b.

Observations and Findinas

On August 20, 1997, the inspectors participated in the licensee's

annual EP exercise. One inspector observed overall activities and

<

monitored licensee performance._ The inspectors observed operator

performance in the plant simulator technical support center

(TSC), operations support center (OSC) and emergency operation

facility (EOF).

The inspectors concluded that operator

performance in the simulator was excellent. Operators correctly

classified the events in accordance with procedure

73EP EIP-001-0S.

The inspectors observed that event

classification problems identified in past exercises had been

corrected.

This was demonstrated by actual event classification

and observed in training and during this and previous exercises.

The inspectors noted that the TSC was activated in accordance with

'

procedure 73EP-EIP-063-05.

The inspectors verified that minimum

manning,hed. communication links, and TSC habitability were

establis

The inspectors observed that analysis of plant

"

conditions and corrective actions were correct and appropriate.

- Interactions with offsite agencies were appropriate and timely.

- The.-inspectors noted that several people assigned to key TSC

positions were alternates.

The inspectors confirmed that the

alternate personnel were qualified-to perform their assigned

.

positions.

-

.

'

Enclosure 2

l

-

-

'*o

e

4

-M-gie-

@

Pe + - r b gp wa r-

(-

.-.g4-

g

-

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,

.

'

l

i

35

.The inspectors verified that the areas identified for improvement

during previous exercises were addressed and had improved in all

areas.

The inspectors did not identify an

l

deficiencies with performance in the TSC. y significant

'

i

The inspectors observed that control of the activities in the OSC

l

had improved over the last several exercises.

Control, noise

!

>

level, and individual attention were areas on which the licensee

'

had placed increased emphasis during this and otner recent-

,

exercises. OSC performance during this exercise was excellent.

The inspectors attended the post-exercise critique and observed

i

that the licensee was very self-critical.

Ope,n and frank

discussions were held with respect to ir.di,idual and overall' site

exercise performance. Areas for improvement were identified as

. well as aspects of the exercise that were considered strengths.

The ins)ectors identified the post exercise critique process as a

strengt1.

'

Following a detailed review and assessment of overall performance.

the licensee determined that all exercise objectives were met.

The inspectors did not identify any significant deficiencies,

c,.

Conclusions

Overall performance during the annual exercise conducted on

>

August 20, 1997, was good.

Event classifications during the

,

exercise were correct. Operator performance in the simulator and

overall performance in the operations support center were

'

excellent.

.

S2

Status of Security Facilities and Equipment (71750)

The inspectors toured the protected area and observed that the

!

perimeter fence was intact and not compromised by erosion nor

disrepair. The fence fabric was secured and barbed wire was

angled as required by the licensee's Plant Security Program (PSP).

Isolation zones were maintained on both sides of the barrier and

were free of objects which could shield or conceal an individual.

The inspectors observed that personnel and packages entering the

protected area were searched either by special purpose detectors

or by a physical patdown for-firearms. explosives, and contraband.

Bad e issuance was observed, as was the processing and escorting

of isitors. Vehicles were searched, escorted, and secured as

described in applicable procedures.

The inspectors observed on the morning of August 21 that the

elevated lights at the front of the PESB were not lit. This

resulted in reduced visibility in the area leading to the entry to

Enclosure 2

.

- , - -

....w,.-

v

-.,m.wr.-.

. . - - . -

vy.-+-.

e

,-

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.

.

36-

-the protected area. -The inspectors observed upon entry into the

protected area that a com)ensatory post was established to provide

a visual observation of tie area-leading to the entrance of the

PESB.

The inspectors concluded th'at the areas of security inspected met

the applicable requirements.

V. Manaoement Meetings

'X.2

Review of UFSAR Commitments

A recent discovery of a licensee operating its facility in a

manner contrary to the Updated Final Safety Analysis Report

(UFSAR)' description highlighted the need for a special focused

review that compares plant aractices, procedures and/or parameters-

to the UFSAR description. While performing the ins)ections

discussed in this re> ort the inspectors reviewed tie applicable

portions of the UFSAR that related to the areas inspected. The

inspectors verified that the UFSAR wording was consistent with the

observed plant )ractices, procedures, and/or parameters, except as

noted above in )aragraph M3.3. Table 3.2-1 of the Unit 2 UFSAR

lists the TIP piping as ASME Code Section Ill. Class 2.

This

included the flange. TIP tubing and tubing valves.

All TIP

flanges, TIP tubing and tubing valves do not meet the ASME Code

Section 111. Class 2-requirement. The licensee is evaluating a

change to table 3.2-1 of the UFSAR for submittal.

X3

Exit Meeting Summary

The inspectors presented the inspection results to members of the

licensee management at the conclusion of the inspection on October

16. 1997.

The licensee acknowledged the findings presented.

The

inspectors asked the licensee whether any materials examined

during the inspection should be considered proprietary.

No

proprietary information was identified,

PARTIAL LIST OF PERSONS CONTACTED

Licensee

Anderson, J., Unit Superintendent

Betsill'. J., Assistant General Manager - Operations

Breitenbach.-C.. Engineering Support tanager - Acting

Curtis. S.. Unit Superintendent

Davis. D.

Plant Administration Manager

Fornel. P,

Performance Team Manager

Fraser. 0.. Safety Audit and Engineering Review Supervisor

Hammonds'. J., Operations Support Superintendent

Kirkley,LW.,- Health Physics and Chemistry Manager

Enclosure-2

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Lewis, J., Training and Emergency Preparedness Manager

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Madison. 0.. Operations Manager

Moore. C.. Assistant General Manager - Plant Support

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Reddick. R., Site Emergency Preparedness Coordinator

Roberts. P.. Outages and Planning Manager

Thompson. J., Nuclear Security Manager

Tipps. S.. Nuclear Safety and Compliance Manager

Wells. P.

General Manager - Nuclear Plant

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 60705:

Preparations for R.efueling

IP 61726: Surveillance Observations

IP 62707: Maintenance Observations

IP 71707:

Plant Operations

IP 71750:

Plant Support Activities

IP 82301:

Evaluation Of Exercises for Power Reactors

IP 92700:

Onsite follow up of Written Reports of Nonroutine

Events at Power Reactor Facilities

IP 92901:

Followup - Operations

IP 92902:

Followup - Maintenance / Surveillance

IP 92903: Followup - Followup Engineering

IP 92904: Followup - Plant Support

ITEMS OPENED. CLOSED AND DISCUSSED

Opened

50 321, 366/97-09-01

V10

Failure to Follow Procedures -

Multiple Examples (Sections

04.2. 08.2 and M3.2).

Closed

50-321, 366/96-13-04

IFI

Inability to Correctly

Classify Events

(Section 08.1).

50-366/97-08

LER

Main Pump Journal Bearing

Damage Renders HPCI Systen

Inoperable (Section M8.1).

50-321, 366/96 14-02

IFl

Potential Single Failure

Vulnerability in the Freeze

Protection System

(Section M8.2).

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50-321, 366/97-07-01

IFl

Review of Licensee's

Assessment of the A&LARA

Process for the Unit 2 Reactor

Coolant Leak Repair on the

RWCU Heat Exchanger

(Section M8.4).

50 321/96 14-05

IFI

Restoration of IB EDG Motor

Control Center (MCC)

(Section E8.1).

50-321/96-15-04

IFI

Switchyard Maintenance and

Material Condition

(Section M8.3).

50-366/97-09

LER

Removal of DG Battery Chargers

From Service Results in

Inoperability of Both the 2A

and 2C DG DC Electrical Power

Subsystems (Section 08.2).

Discussed

50 321, 366/97-03-05

IFI

Review of 4160-VAC Wiring

Separation Deficiencies

(Section E1.1).

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