ML20134L091

Insp Repts 50-321/96-15 & 50-366/96-15 on 961208-970118. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20134L091
Person / Time
Site:	Hatch
Issue date:	01/18/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20134L070	List: ML20134L067 ML20134L077 ML20134L091
References
50-321-96-15, 50-366-96-15, NUDOCS 9702180262
Download: ML20134L091 (46)

See also: IR 05000321/1996015

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O.S. NUCLEAR REGULATORY COMMISSION

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REGION II

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Docket Nos:

50-321, 50-366

License Nos:

DPR-57 and NPF-5

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Report No:

50-321/96-15, 50-366/96-15

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Licensee:

Georgia Power Company (GPC)

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Facility:

E. I. Hatch Units 1 & 2

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Location:

P. O. Box 439

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Baxley' Georgia 31513

Dates:

December 8, 1996 - January 18, 1997

Inspectors:

B. Holbrook. Senior Resident Inspector

E. Christnot. Resident Inspector

J. Canady. Resident Inspector

G. Kuzo. Senior Radiation Specialist (Sections

R1.2 - R8.2)~.

W. Kleinsorge Reactor Inspector (Section M1.4)

Approved by:

P. Skinner. Chief. Projects Branch 2

Division of Reactor Projects

Enclosure 2

9702190262 970213

PDR

ADOCK 05000321

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EXECUTIVE SUMMARY

Plant Hatch Units 1 and 2

NRC Inspection Report 50-321/96-15, 50-366/96-15

This integrated inspection included aspects of licensee operations,

engineering, maintenance, and plant support. The report covers a 6-week

period of resident inspection.

In addition, it includes the results of

an announced inspection by a regional Senior Radiation Specialist and a

Reactor Engineer's inspection of electrical maintenance.

Ooerations

The inspectors concluded that Unit 2 control room operator's

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demonstrated a lack of attention to detail during control room

panel walkdowns.

Operators did not observe an incorrect switch

position and a keepfill pump that had automatically started

(Section 01.2).

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The inspectors identified as a strength operations management's

proactive actions with respect to providing operator training to

correct or prevent some deficiencies (Secticn 05.1).

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The inspectors concluded that the shift of operators reviewed for

fire fighting and fire brigade leader training and qualifications

were trained and qualified for their assigned position.

Corrective lenses for o)erator use while wearing Self Contained

Breathing Apparatus (SC3A) during control room emergencies were

readily available in the control room (Sectiori 05.2).

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The inspectors concluded that plant procedures did not include

guidance for removing valves from backseat following plant

transient conditions that resulted in a reactor cooldown.

This

was identified as a weakness.

After inspector intervention, the

additional guidance and expectations provided to operators during

shift briefings were appropriate (Section M3.2).

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The inspectors concluded that the operations department

demonstrated a commitment to self assessment and a desire for

continued improvement.

Although some corrective recunmendations

contained in the self assessment were not completed, they were

under development and the completed items were thorough and

comprehensive.

The self assessments were conducted by

knowledgeable personnel (Section 07.1).

Enclosure 2

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The failure of the traveling water screen system to operate during

cold weather conditions is identified as a significant weakness in

the area of engineering.

Engineering personnel failed to identify

that the design and system configuration did not adequately ~

3rotect system components from cold weather conditions.

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iaintenance and operations personnel also failed to identify that

portions of the system were vulnerable to cold weather conditions

during their system checks and cold weather preparations

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(Section 08.1),

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Maintenance

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The ins)ectors concluded that the maintenance work activities and

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the worc review by the system engineer for the IB Emergency Diesel

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Generator (EDG) voltage regulator re) air were thorough and

performed in accordance with applica)1e procedures.

Supervisory

and engineering oversight were evident.

The inspectors also

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concluded that the EDG design function capability was not degraded

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(Section M1.2).

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The ins)ectors concluded that the maintenance activities on the

Unit 2 Reactor Core Isolation Cooling turbine identified and

corrected the problem with the fluctuations in turbine speed

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control.

Maintenance activities observed were generally thorough

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and professional.

Supervisory and engineering oversight were

evident (Section M1.3).

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The inspectors identified an Inspector Followup Item (IFI)

50-321, 366/96-15-04:

Switchyard Maintenance and Material

Condition. This was due to the switchyard housekeeping and

material condition discrepancies and the number and age of the

predictive maintenance backlogged items for the switchyard

(Section M1.4).

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As demonstrated by good performance, the level of 3reventive

maintenance for the Reactor Protection System and Reactor

Recirculation System Motor Generator Sets was appropriate for the

circumstances (Section M1.4).

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The lack of records that support differences from equipment

manufacturers'

3reventive maintenance recommendations and

dependance on t1e collective memory of personnel was not a good

practice (Section M1.4).

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Leaving loose conductive material in electrical panels was

identified as a poor work practice for foreign material exclusion

control with the potential of shorting out components.

Some

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housekeeping discrepancies were noted (Section M1.4).

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Enclosure 2

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The inspectors identified Non-Cited Violation (NCV)

50-366/96-15-01:

Inadequate Procedures for Replacement of the

Unit 2 Drywell Hydrogen Recombiner Flow Controller Batteries and

Establishing the Required Controller " Dead Band" Following Certain

Maintenance Activities (Section M2.1).

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Operator performance during surveillance activities for the High

Pressure Coolant Injection System and EDG was generally

professional and competent. The inspectors had observed some

improvements in communications in the recent past but observed

that operations * standards were not met by all crews

(Section M3.1)

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The inspectors identified Violation (VIO) 50-321/96-15-02:

Maintenance Personnel Failure To Follow Procedure During Valve

Backseating Activities. This failure to follow procedure was

generally administrative in nature (Section M3.2).

The inspectors also concluded that some maintenance personnel's

lack of understanding of different types of procedure usage and

implementation demonstrated a weakness (Section M3.2).

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The inspectors concluded that the maintenance procedure for

electrically backseating valves did not fully implement the

requirements of the engineering evaluation. The inspectors

concluded that this deficiency did not result in a

safety-significant concern for the backseated valves

(Section M3.2).

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Inspector Followup Item (IFI) 50-321. 366/96-15-03:

Resolution of

Reactor Core Isolation Cooling (RCIC) and High Pressure Coolant

Injection System (HPCI) Turbine Speed Control Drifting, for

Units 1 and 2. respectively, was identified. The inspectors

concluded that the maximum speed drift observed on the both

systems did not affect the safety function of either system.

The

inspectors concluded that the speed control drifting could be an

indication of pending failures (Section M3.3).

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The inspectors concluded that the Unit 2 loss of feedwater heating

transient on January 5. due to a jumper grounding error,

demonstrated a poor work practice on the part of one individual.

This problem was identified as an isolated occurrence and not a

generic concern. Reviewing this error for human performance

improvements was appropriate (Section M4.1).

Personnel who perform mechanical maintenance on safety and non-

safety related valves were trained and qualified in accordance

with the requirements of ANSI N18.1-1971, the Final Safety

Analysis Report, and other applicable plant qualification

procedures (Section M5.1).

Enclosure 2

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The inspectors concluded that the Unit 1 Standby Liquid Control

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(SLC) pump tripping was an isolated problem. The inspectors

concluded that engineering personnel from the Nuclear Safety And

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Compliance (NS&C) conducted a detailed review of the SLC pump

tripping problem, and was viewed as a positive attribute of the

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department. Replacement of the system components was appropriate

(Section E2.1).

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The inspectors concluded that the engineering evaluation for

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electrically backseating valves located in the drywell was

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satisfactory. The evaluation considered plant safety and

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identified actions to ensure continued system and component

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reliability (Section E3.1).

Plant Suooort

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The inspectors identified a Violation 50-321, 366/96-15-05:

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Failure to Follow Procedures for Contamination Control and for

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Deficiency Card Issuance for Inadequate Bioassay Calibration

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Guidance. Quality control cross-check analyses were conducted in

accordance with procedural requirements (Sections R1.2 and R7.1).

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General employee training and completed medical certifications for

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personnel involved in licensed activities were conducted in

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accordance with the anlicable procedures and met the requirements

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of 10 CFR 19 and 10 C 120 (Section R.5).

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Radiation protection performance indicators verified that licensee

actions to control worker dose were effective and radiological

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effluent releases were minimized (Section R8).

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The inspectors concluded that the inspected areas of the security

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program met the applicable requirements (Section S2).

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The inspectors attended various Outage Management Meetings held at

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the site and concluded that the critical path for the refueling

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outage was identified and that the refueling outage appeared to be

well planned, with realistic goals and adequate support

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(Section X.2).

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Enclosure 2

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Reoort Details

Summary of Plant Status

Unit 1 operated at 100% rated thermal power (RTP) throughout the report

period, except for routine testing activities.

Unit 2 began the report period at 100% RTP. On January 5, power was

reduced to about 93.5% RTP due to a feedwater heater isolation.

Power

was returned to 100% RTP on the same day and operated at this power level

throughout the remainder of the report period, except for routine testing

activities.

I. Operations

01.

Conduct of Operations

01.1 General Comments (71707)

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The inspectors conducted frequent reviews of ongoing plant

operations.

In general, the conduct of operations was

are detailed in the sections below. pecific events and observation

professional and safety-conscious: s

01.2 Control Room Panel Walkdown

a.

Insoection Scooe (71707)

On January 10. the ins)ectors conducted a control room panel

walkdown of Unit 2.

T1e walkdown included safety- and

non-safety-related equipment valve lineups, switch positions and

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process instrument indications.

b.

Observations and Findinos

The inspectors observed that both keepfill pumps on the B loop of

Residual Heat Removal System (RHR) were in service.

One control

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switch was in run and the standby pump control switch was in auto.

This observation was brought to the attention of the control board

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operator.

The operator indicated that the B loop of RHR had been

in service for torus cooling during previous surveillance

activities and had been secured earlier that day, following the

completion of the surveillance activities. Tne operator indicated

that securing the RHR pump may have caused a small pressure surge

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that initiated the automatic start of the standby keepfill pump.

The operator secured the standby pump and system pressure remained

satisfactory.

The inspectors also observed that the by) ass selector switch for

the A Source Range Monitor (SRM) was in )ypass.

This was brought

to the attention of the control board operator.

The operator

Enclosure 2

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stated that the A SRM instrument cabinet had been removed from the

control room panel on January 9. for Instrumentation and Control

~ I&C) work activities. The SRM instrument cabinet had been

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replaced on the previous shift

The SRM bypass selector switch

had not been returned to normal.

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The inspectors brought these deficiencies to the attention of

operations' management for resolution.

Management's expectations

are in part, that the operators walkdown the control room front

panels once per hour and back panels once per two hours and look

for changing trends and incorrect switch positions.

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c.

Conclusions

The inspectors did not consider these deficiencies to be an

immediate concern for plant safety.

The inspectors concluded that

control room operators demonstrated a lack of attention to detail

during control room panel walkdowns. Operators failed to observe

an incorrect switch position and a keepfill pump that had

automatically started.

05

Operator Training and Qualification

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05.1 Review of ooerator "Just in Time" Trainina

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a.

Insoection Scooe (71707)

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A new training initiative, entitled "Just in Time" training

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commenced to address previous problems associated with activities

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that would affect operators.

Operations' management began "Just

in Time" training sessions for 03erators due to previous problems

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with reverse power trips of the EDGs during surveillance

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activities.

On December 26. the inspectors observed two sessions

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of "Just In Time" training for EDG manipulations during

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surveillance activities.

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b.

Observations and Findinas

The inspectors observed that the "Just in Time" training was

conducted on the plant simulator.

One session provided an

o)erator the opportunity to review the procedure and manipulate

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surveillance. prior to performing an inplant Unit 2 EDG

t1e switches

The other training session provided a different

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operator the same opportunity prior to performing a Unit 1 EDG

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surveillance.

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The inspectors observed that the training sessions were self

directed by the operators and required very little instructor

assistance. The operators reviewed the apolicable procedures and

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Enclosure 2

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performed the necessary manipulations to complete the

surveillances.

The inspectors discussed with operations' management if training

on the simulator, which is modeled after Unit 2. may present

additional challenges to operator performance when performing

Unit 1 activities.

Operations' management indicated no and

stated that, even though the simulator was modeled for Unit 2 any

switch manipulation practice would be of benefit to the operators.

c.

Conclusions

The inspectors concluded that operations' management was proactive

with respect to providing operators training to correct or prevent

some deficiencies by the "Just In Time" training.

The inspectors

observed that the "Just in Time" training was not a formal or

proceduralized process; however, operators or super isors may

request training at their discretion.

05.2 00erator Fire Briaade trainina and Qualification

a.

Inspection Scooe 71707

The inspectors reviewed fire training requirements and

qualifications for a shift of operations aersonnel. The review

was conducted for fire fighters and fire ]rigade leaders.

b.

Observations and Findinas

The inspectors reviewed the licensee's Training Records and

Qualification System Matrix Report and confirmed that operators on

shift were indicated as qualified for their fire fighting

positions.

The inspectors also verified that the operators had

successfully completed the required initial and requalification

training to maintain their qualifications.

The inspectors also verified that corrective lenses were available

in the control room for operators' use during emergencies that may

require SCBAs to be worn.

The inspectors observed that six

operators that required corrective lenses license restriction did

not have corrective eye glasses stored in the designated storage

location in the control room. The inspectors were informed by

operations supervision that the six operators wore contact lenses

instead of eye glasses.

The inspectors reviewed ap)licable

procedures that dealt with wearing contact lenses w111e wearing a

SCBA and concluded that the procedures and training were adequate.

Enclosure 2

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c.

Conclusions

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The inspectors concluded that the shift of operators reviewed for

fire fighting and fire brigade leader training and qualifications

were trained and qualified for their assigned position.

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Operators' corrective lenses for use while wearing a SCBA. during

control room emergencies, were readily available in the control

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room.

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Quality Assurance in Operations

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07.1 Licensee Self-Assessment Activities (40500)

a.

Insoection Scooe 40500

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The inspectors reviewed two licensee self assessments and followup

actions and a new procedure for Team Observations.

b.

Observations and Findinas

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The inspectors reviewed a self assessment for operations

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activities with respect to reactivity controls.

Following

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operator errors during refueling activities, control rod movement

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errors, and inattention to detail, the licensee initiated a self

assessment to identify root causes and recommend corrective

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actions.

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The inspectors reviewed the licensee's completed actions with

respect to implementing the recommendations.

The inspectors

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observed that 7 of 20 recommendations were not completed.

However, the licensee's documentation indicated that the remaining

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open items would be com eted prior to the Unit 2 refueling outage

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scheduled for March 199

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The inspectors reviewed an operations department self assessment

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completed on about September 26, 1996 that focused on identifying

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needed enhancements and generating corrective action

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recommendations aimed at hel)ing the department achieve its goal

of excellent performance.

T1e assessment was conducted at the

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request of operations' management and conducted by personnel both

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within and outside the parent organization.

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The inspectors observed that the assessment included safety focus.

management involvement, problem identification, problem

resolution, quality of operations, programs and procedures, and

operations efficiencies.

The inspectors also observed that the

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assessment provided specific observations and recommendations.

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The inspectors also reviewed procedure DI-0PS-59-0896N:

Team

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Observations. Revision 0, and observed that the procedure provided

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Enclosure 2

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a means of observing and reinforcing the operations department's

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expectations by performing supervisory and peer evaluations on

routine tasks.

Checklists for specific activities were included

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and contained a method of identifying whether or not the

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expectations were met.

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The inspectors reviewed some completed observations, checklists.

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and comments and discussed them with operation's management.

Operations' management stated that the process was still being

improved and a revision of the procedure was being developed.

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c.

Conclusions

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The inspectors concluded that the operations department

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demonstrated a commitment to self assessment and a desire for

continued improvement. Although some corrective recommendations

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were not com)leted, they were under development and the completed

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items were t1orough and comprehensive. The self assessments were

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conducted by knowledgeable personnel.

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Miscellaneous Operations Issues

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08.1 Cold Weather Followuo and Walkdown

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a.

Insoection Scooe (71714)(92901)

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The inspectors performed a walkdown of systems and plant

structures during hard freeze warnings.

b.

Observation and Findinas

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The inspectors observed the following during the walkdown:

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Two of the four wall manual louvers in the Fire Pump House were

not closed completely. The louvers were o

The manual roof vent was also open. pen approximately one

inch.

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Three heat trace indicating lights were not illuminated. Two

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were on the fire protection water system and the other was on

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the cooling water to the IB EDG.

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Several automatic louvers in the EDG rooms were not completely

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closed as required.

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The inspectors found from that some deficiencies still existed

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that had been previously observed as documented in

IR 50-321. 366/96-14.

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Following a hard freeze warning on about December 21. Plant

Equipment Operators (PE0) could not get the up-river or the down-

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Enclosure 2

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river traveling water screens to operate.

Subsequent trouble

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shooting by maintenance personnel identified that the pressure

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switches for both screens had frozen. The inspectors observed the

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pressure switch installations and observed that the sensing lines

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to the switches were heat traced, but a problem existed in that

switches were not heat traced or insulated in order to read their

indication. Maintenance personnel corrected this problem and

later enclosed the switches with insulating material, installed

heat lamas and directed the lamps toward the pressure switches. A

design clange was initiated to make permanent repairs.

The inspectors were informed that operations personnel had tested

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the traveling screens due to information received from industry

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experience.

Freezing problems with traveling screens had been

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identified at other sites.

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The inspectors found from the reviews and discussions with

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licensee personnel that the traveling water screen system for both

units would not operate in manual or automatic due to the pressure

switch problem. As a result, the support systems affecting plant

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safety systems, such as Plant Service Water (PSW) and Residual

Heat Removal Service Water "lHRSW). were not available during this

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cold weather condition. The licensee's prompt corrective actions

restored the function of the pressure switches. The affected

plant safety systems would have performed their required

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functions.

c.

Conclusions

The inspectors concluded that the deficiencies obser ved during the

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walk downs were not significant for the existing outside

temperatures and the cleanliness of the river water and river

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level at the time of the walk downs.

Maintenance and operations

personnel failed to identify that portions of the system were

vulnerable to cold weather conditions during their system checks

and cold weather preparations.

Engineering personnel failed to

identify that the design and system configuration did not

adequately protect system components from cold weather conditions.

The failure of the traveling water screen system to operate during

cold weather conditions is identified as a significant weakness in

the area of engineering.

Enclosure 2

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II. Maintenance

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Conduct of Maintenance

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M1.1 General Comments

a.

Insoection Scooe (62707)

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The inspectors observed all or portions of the following work

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MWO 1-96-4722:

Electrically backseat RCIC Inboard

Isolation Valve 1E51-F007

MWO 1-96-4362:

Electrically backseat RWCU Inboard

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Isolation Valve 1G31-F001

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MWO 2-96-3361: Repair 1B EDG Auto Voltage Regulator

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MWO 2-96-0042: Repair Unit 2 RCIC EGM Control Box

MWO 2-96-2976:

Repair Unit 2 RCIC Data Input to DAAS

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MWO 1-97-0066:

Investigate Tripping of 1A SLC Pump

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MWO 1-97-0071:

Replace Overload Heaters in 1A SLC Pump

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MWO 1-97-0092:

Replace Overload Relay for 1A SLC Pump

b.

Observations and Findinas

The inspectors found that the work was performed in accordance

with actively used work packages. Appro)riate post modification

and maintenance tests were performed. Tlese tests consisted of

operating the equipment following the completion of work

activities.

Additional inspector observations are documented in Sections M1.2

and M1.3.

M1 -. 2 Reoairs to 1B EDG Automatic Voltaae Reaulator

a.

Insoection Scone (62707)

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The inspectors observed work activities performed on the IB

Emergency Diesel Generator (EDG) automatic voltage regulator under

Maintenance Work Order (MWO) 2-96-3361. The inspectors discussed

the activities with maintenance, engineering and operations

personnel.

b.

Observations and Findinas

The inspectors were informed that while performing 3rocedure

34SV-R43-002-2S: Diesel Generator IB Monthly Test

Rev.18, with

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voltage regulation in automatic control and the voltage at 4120

volts alternating current (VAC), the voltage could not be adjusted

Enclosure 2

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to the required 4160 VAC. The automatic voltage adjustment must'

be performed at the local panel due to the design of the system.

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Troubleshooting activities discovered defective diodes in the

direct current drive motor circuit of the voltage regulator. The

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motor positions the automatic regulator rheostat which sets the

voltage level for automatic control. The inspectors discussed the

failure of the diodes with engineering personnel and were informed

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that the motor and rheostat were seldom exercised and this may

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have contributed to the failure.

The system engineer indicated

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that a recommendation to exercise the motor and rheostat more

often would be made.

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During the repair activities. the inspectors observed that the new

diodes were installed by craft personnel using applicable

procedures with supervisory and engineering oversight. Subsequent

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to the repair, a new motor-rheostat unit was installed and the

repaired unit was returned to the warehouse as a spare.

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The inspectors were informed by engineering that the EDG would

have controlled the voltage in automatic at 4120 VAC instead of

4160 VAC and the difference in voltage was not enough to affect

safety-related loads.

c.

Conclusion

Maintenance activities observed were generally thorough and

professional.

Supervisory and engineering oversight were evident.

The inspectors concluded that the work activities and the review

by the sy'. tem engineer for the IB EDG voltage regulator were

thorough and performed in accordance with applicable procedures.

The inspectors also concluded that the EDG was capable of

performing the required safety functions.

M1.3 Reoairs to Unit 2 Reactor Core Isolation Coolino (RCIC) Turbine

Soeed Control

a.

Insoection Scone (62707)

The inspectors reviewed the results of the maintenance activities

and observed the post maintenance test of the Unit 2 RCIC turbine.

The system had been declared inoperable due to speed control

problems.

b.

Observations and Findinos

The activities were performed under MW0s 2-96-0042 and 2-96-2976.

and ap)licable procedures.

Trouble shooting activities indicated

that tie electronic governor motor (EGM) was defective. The EGM

Control Box was replaced and the RCIC was satisfactorily tested.

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Enclosure 2

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The defective electronic governor was bench tested and confirmed

that the trouble shooting findings were correct.

Inspector

observations on the Unit 2 RCIC post maintenance and operability

testing are documented in Section M3.3 of this report.

c.

Conclusions

Maintenance activities observed were generally thorough and

professional. Supervisory and engineering oversight were evident.

The ins)ectors concluded that the maintenance activities on the

Unit 2 RCIC identified and corrected the 3roblem with the

fluctuations in turbine speed control. T1e two reversed wires

discovered did not affect system operability but demonstrated a

lack of attention to detail.

M1.4 Electrical Maintenance Imolementation

a.

Insoection Scooe (62700)

To evaluate electrical maintenance implementation as it relates to

motor generator (MG) sets and switchyard equipment, the inspectors

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conducted: walkdown inspections of the Reactor Protection System

(RPS) and Reactor Recirculation System (RR) MG set rooms and

selected areas of the switchyards and the switchyard control

!

house; and reviews of equipment manufacturers' technical manuals.

l

re)etitive task records, maintenance records, and oil analysis and

vi) ration test data.

The inspectors compared the equipment

manufacturers' maintenance recommendations with the licensee's

maintenance program for both scope and periodicity.

b.

Observations and Findinas

Reactor Protection System and Reactor Recirculation System MG Sets

Housekeeping was good with the following exceptions:

o

A number of structural fasteners were missing from control

panels.

The concern was that the missing fasteners could

abrogate the seismic qualification of the pariels.

e

The closure devices on a number of panel doors were not secured

such that the weather stripping was compressed.

The concern

was that the improper sealing of the panels could abrogate the

environmental qualification.

e

Metal shavings (probably the debris left from drilling) and

miscellaneous fasteners were found adrift inside control

panels.

Leaving loose conductive material in electrical panels

was identified as a poor work practice control with the

Enclosure 2

.

_ _ _ _

. _ . _

,

.

,

10

potential of shorting out components.

The fasteners were

removed by the licensee,

e

The Reactor Recirculation System MG set oil circulation systems

leak.

To address this issue, the licensee conducts daily wipe

downs and was actively pursuing a permanent repair.

There was a number of areas where the liccnsee's repetitive

preventive maintenance program was not consistent with the

<

equipment manufacturer's recommendations. The licensee was unable

)

to provide documented justifications for the differences.

i

However, the licensee was able to provide anecdotal information

j

remembered by maintenance personnel that supported the deviations.

>

Records, examined by the inspectors. reflected that repetitive

preventive maintenance activities were completed within the

scheduled time period.

I

Records reflect that the repetitive preventive maintenance program

!

'

had been effective as few repetitive corrective maintenance

i

activities were required.

l

i

Switchyards

Maintenance in the switchyards was performed by Georgia Power

Company Transmission Maintenance Center with procedures issued by

l

l

the Transmission Operation and Maintenance Manager.

Some

j

surveillances were performed by Plant Hatch Operations Department

l

personnel.

Ins)ection of housekeeping and material condition revealed a

I

num)er of items that needed attention.

Protective coatings on

4

l

exterior equipment had deteriorated, as evidenced by many areas of

)

l

rust and missing closure fasteners.

Inside the switch house, the

inspectors noted un-taped spare electrical leads in the back board

i

area, trash, and evidence of feline habitation.

Conductive

material (metal shavings and fasteners) was found in both exterior

l

<

panels and in the back board area in the switch house.

The

'

fasteners were removed on the spot. The effectiveness of rain

,

gutters on the switch house was minimal in deflecting water away-

t

i

from the structure, due to advanced corrosion.

l

l

There was a number of areas where the licensee's repetitive

maintenance program for switchyard equipment was not consistent

!

with the equipment manufacturer's recommendations. The licensee

'

was unable to 3rovide documented justifications for the

!

differences,

iowever, the licensee was able to provide anecdotal

.

information, remembered by Transmission Maintenance Center

personnel, that supported the differences.

l

3

Enclosure 2

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_

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. ____ _ _ _ _ _ . _ . . _

_ _ _ . _

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11

<

Transmission Maintenance Center records reflected that there were

,

19 repetitive maintenance tasks that were overdue, the oldest of

which had a due date of July 23, 1992.

The overdue activities

were various 3reventative diagnos11c tests of air blast breakers.

Transmission iaintenance Center records were such that timeliness

.

of completed maintenance tasks could not be determined.

!

c.

Conclusions

'

As demonstrated by good performance, the level of 3reventive

maintenance for the Reactor Protection System and Reactor

Recirculation System Motor Generators (MG) was a?propriate for the

4

circumstances.

Some housekeeping discrepancies were noted. The

,

lack of records that support differences from equipment

I

manufacturer's areventive maintenance recommendations, and

dependance on t1e collective memory of personnel was not a good

practice.

Due tc the switchyard housekee)ing and material condition

discrepancies identified and tie number and age of the predictive

maintenance backlogged items, switchyard maintenance will be the

subject of a future NRC inspection. This matter will be

identified as Inspector Followup Item 50-321, 366/96-15-04:

Switchyard Maintenance and Material Condition.

'

M2

Maintenance end Material Condition of Facilities and Equipment

!

'M2.1

Hydroaen Recombiner Unit 2

a.

Insoection Scooe (92902)

.

!

On November 21. 1996, the ins)ectors observed that an 18-month

surveillance for the Unit 2A )rywell Hydrogen Recombiner System

-

(HRS) could not be performed to due problems with inlet valve.

2T49-F003A. The controller for the valve was not operating

3roperly. The inspectors reviewed past performance and work

listory for the system. The system had been declared inoperable

so that corrective maintenance could be completed.

i

'

b.

Observations and Findinas

The inspectors reviewed documentation dated from November 20

,

to 24, concerning the HRS and observed the following:

1

-

On November 20. the HRS 2A, Panel 2T49-P600A was removed from

i

service for testing of motor operated valves (MOVs) and the

i

replacement of MOV electrical overloads

Enclosure 2

, , - ,

.-.y

.,

,.

,,

-

.

m

u,

.a__._..uua-.m

.__..___,.2

w.,

-

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.

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l

12

On November 21, the surveillance for the HRS valve operability

l

-

was satisfactorily completed and the recombiner functional test

]

was started at 3:30 a.m.

-

On November 21. at 5:20 p.m., a functional test was

unsatisfactory due to a controller memory loss for inlet

'

MOV 2T41-F003A. The loss of memory was due to a loss of power.

The controller loses power when the breaker for the MOV is

<

racked out.

-

On November 22 problems continued with valve 2T41-F003A. The

valve cycled partially open and closed and technicians were

concerned that the motor on the valve would overheat, causing

damage. The gain on the controller was adjusted with no affect

and engineering personnel continued their investigation.

Licensee documentation revealed the problem was corrected and the

2A HRS was returned to service at 11:45 p.m. on November 24.

The inspectors identified from reviews and discussions with

f

licensee personnel the following:

the batteries located in the

'

flow controllers have a service life of five years, and a shelf

life of about three to four years, according to vendor

information: the batteries had not been changed since Unit 2 was

licensed in 1978: and the batteries were installed in order to

protect the controllers from a loss of programming during a loss

,

of power.

The inspectors also identified that no procedure discussed the

batteries, required that they be functionally tested, nor that

they be changed in accordance with vendor recommendations.

EDG

3ersonnel responsible for the system failed to ensure that the

l

3attery replacement was specified in plant procedures.

The inspectors were later informed that, following maintenance

activities on the valve a controller " dead band" was required to

,

be established for proper operation of the valve and valve

controller.

This requirement was also not identified in any

,

procedure, post maintenance testing, or calibration activity.

l

t

When the maintenance activities on the valve were completed. I&C

l

completed the required calibrations and the old battery was

>

tested.

It satisfactorily performed.

Since the licensee did not

!

have a spare battery, the old one was left in place.

The licensee

i

initiated procurement activities to purchase a new battery.

.

The inspectors verified that procedures were revised to identifv

I

~

establishing the require " dead band" following maintenance or

i

calibration activities. The inspectors verified that procedures

Enclosure 2

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13

were scheduled to be revised to include replacing the battery

within the required vendor recommended frequency.

c.

Conclusions

The inspectors concluded from reviews and discussion with licensee

personnel that the Unit 2 Drywell HRS flow controller batteries

exceeded the vendor recommended service life.

Procedures were

inadequate in that battery replacement was not identified.

Additionally, the procedures were inadequate for establishing the

required valve controller " dead band" following certain

maintenance activities. This violation constitutes a violation of

minor safety significance and is being identified as

NCV 50-366/96-15-01:

Inadequate Procedures for Replacement of the

Unit 2 Drywell Hydrogen Recombiner Flow Controller Batteries and

Establishing the Required Controller " Dead Band" Following Certain

Maintenance Activities, consistent with Section IV of the NRC

Enforcement Policy.

M3

Maintenance Procedures and Documentation

M3.1 Surveillance Observations

a.

Insoection Scooe (61726)

The inspectors observed all or portions of the following Unit 1

and Unit 2 surveillance activities:

- 345V-E41-002-15: HPCI Pump Operability.. Revision (Rev.) 19

- 34SV-R43-001-1S: DG 1A Monthly Test, Rev. 17. ED 1

- 34SV-E41-002-2S: HPCI Pump Operability. Rev. 23

- 34SV-E51-002-1S:

RCIC Pump Operability. Rev. 17

- 34SV-E51-002-2S:

RCIC Pump Operability. Rev. 16

b.

Observations and Findinas

On December 26, the inspectors attended the pre-job briefing in

preparation for the Unit 1 High Pressure Core Injection (HPCI)

surveillar,ce activities and observed operator actions during

portions of the surveillance.

The test was also >erformed to meet

the Inservice Testing (IST) requirements for the iPCI system.

The

inspectors observed that a member of engineering su) port,

maintenance, health physics (HP), o)erations and t1e system

engineer were present at the pre-jo) briefing.

The Assistant

General Manager - Plant Support (AGM-PS) was present for the

majority of the briefing.

During the briefing, operations personnel requested that HP ensure

j

that no personnel were in the torus area.

This was for personnel

protection, based upon previous industry operating event history

Enclosure 2

J

,-

l

.

I

14

i

for failure of small turbine exhaust diaphragms.

HP personnel

ensured that no personnel were in the area and posted it.

The inspectors observed that hydrogen injection was lowered to

about 8 standard cubic feed per minute (SCFM) and that the

applicable technical requirements manual (TRM) action statement

for the main steam line radiation monitors being set

non-conservatively was entered.

3

The inspectors observed that a HP technical was present locally

and had identified the HPCI room as a High radiation area. A

minimal number of personnel entered the HPCI room during

operation, consistent with As low As Reasonably Achievable (ALARA)

considerations. Maintenance and other personnel were on standby

at a designated low dose area.

The inspectors observed that operator actions in the control room

were adequate. Appropriate attention to detail, procedural usage,

and supervisory oversight were demonstrated. Communications were

not all 3-part, but did not present any observable problems during

The i'spectors discussed operator

the surveillance.

n

communications during the surveillance and general communications

with operations * management. Operations * management stated that a

j

renewed emphasis had been placed on communications and that some

crews demonstrated better communications than others.

The inspectors toured the EDG building and observed the 1A EDG

during the surveillance run. The inspectors identified a small

oil leak on the governor that had not been previously identified.

The leak was brought to the attention of operators stationed at

the EDG who contacted maintenance personnel, who repaired the

leak

c.

Conclusions

The Unit 1 HPCI and EDG systems performed as required and met the

ap)licable TS criteria.

However, the HPCI pump outboard bearing

vi) ration increased to the alert range. requiring that the

surveillance test frequency for HPCI pump be doubled.

The

performance of the operators and crews conducting the

surveillances was generally professional and competent.

The

inspectors had observed some improvements in communications in the

recent past but observed that operations * standards were not met

by all crews.

No other deficiencies were identified.

Enclosure 2

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i

t

H3.2 Review of Maintenance Activities to Electrically Backseat Valves.

!

a.

Insoection Scooe (62703)

The inspectors reviewed maintenance activities and documentation

i

for electrically backseating two Primary Containment Isolation

'

valves. The licensee electrically backseated the valves in an

i

attempt to identify and reduce the unidentified drywell leakage-

f

for Unit 1.

Reactor Water Cleanup (RWCU) Inboard Isolation

j

valve 1G31-F001, and RCIC Inboard Isolation valve 1E51-F007. were

!

electrically backseated on November 14 and December 27. 1996.

i

'

respectfully. The inspectors reviewed the corporate engineering

evaluation (section E3.1 of this report) to ensure that all

a>plicable actions were completed. Additional inspector

o)servations are discussed in section E3.1 of this report.

b.

Observations and Findinas.

'

The inspectors reviewed procedure 51GM-MNT-034-05:

MOV Electrical

f

Backseating With Instantaneous Circuit Breaker Trip Protection,

j

Rev. 2. The following are deficiencies that were identified by the

'

inspectors:

'

-

The Evaluation section of the corporate engineering evaluation

stated that procedure 51GM-MNT-034-05, limits the motor current

(of the valve being backseated) to twice the rated current.

However, step 7.6 of the procedure states, in part, to " adjust

breaker 2 on the backseat apparatus to 2 times rated amps

(+/- 50%)." This would allow a maximum of three times rated

motor current, not twice the motor current, as s)ecified in the

engineering evaluation.

Engineering concluded tlat this

difference was not a safety concern for the valve since the

engineering evaluation was more concerned with locked rotor

current.

-

Special requirements. Step 4.3.2 of the backseating procedure

and the engineering evaluation, states, in part, that prior to

performing backseating, the Shift Supervisor on duty will

review the engineering evaluation for the impact on stroke time

requirements and will indicate the results cf Ms review in the

work performed section of the MW0.

This documentation was not completed for either of the two

valves that were backseated. The inspectors discussed this

deficiency with maintenance and operations personnel.

The

operations supervisor on shift during one of the backseating

activities stated that he did not review the maintenance

procedure and was not aware of the documentation requirement.

The inspectors discussed maintenance activities with respect to

Enclosure 2

_

.

.

.

16

reviewing procedures prior to their use and how maintenance

communicated specific requirements to operations personnel. The

inspectors were informed that if a maintenance procedure

contained specific requirements for operations personnel,

maintenance personnel were required to bring the requirement to

the attention of operations.

,

i

The inspectors reviewed procedure 10AC-MGR-019-05:

Procedure

l

Use and Adherence Rev. O, and observed that step 4.3.4,

!

stated, in part, that all plant personnel were responsible ~for

.

reviewing and understanding procedures prior to using them.

The inspectors concluded that in at least one example discussed

above, maintenance personnel responsible for the valve

backseating procedure did not bring the specific documentation

requirement to the attention of operations' supervision. The

,

inspectors noted that after bringing the deficiency to the

attention of the maintenance personnel..the documentation was

later completed.

i

During the discussion with maintenance personnel concerning

!

procedure use, the inspectors were informed that some sections

of maintenance procedures may be considered continuous use,

-

some sections may be considered reference use, and other parts

may be considered information use. The inspectors discussed

different procedure usage with at least five different

i

maintenance personnel and discovered that no clear

understanding of procedure usage was evident. The inspectors

.

reviewed Procedure 10AC-MGR-019-0S. Rev. O. and discussed

!

procedure usage with maintenance management. The inspectors

i

were informed that improvement in procedure usage continued to

be a challenge and management's expectations were not being

!

met.

,

!

It was not clear to the inspectors how some personnel's

misunderstanding of procedure usage would ensure effective and

i

consistent implementation of the procedures.

Procedure usage

j

appeared to be very subjective on the part of the user and

!

would not necessarily ensure that management's expectations for

i

procedure usage were consistently met.

The inspectors

'

concluded that maintenance personnel's understanding of

different procedure usage and implementation demonstrated a

,

weakness.

-

-

Procedure step 4.3.4 stated, in part. that the engineering

,

evaluation must be attached to Attachment 1 of the procedure

i

and filed in Document Control with a copy attached to the MWD.

The inspectors observed that during the review of the MWO work

[

package for the backseating completed on November 14 the

Enclosure 2

!

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!

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--- --

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.

- - - -.

. - - ~_.-.

_

_ - -

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!

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$

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i

17

engineering evaluation was not part of the MWO work package and

)

.

was not attached to Attachment 1.

The inspectors noted that

!

the MWO work package was being maintained open until after

outage work. After bringing this deficiency to the attention

j

of maintenance personnel. the engineering evaluation was

included as-part of the MWO package and properly attached to

i

!

the procedure.

j

.

v._adure step 4.3.5 stated. in part, that a MWO must be

i

-

initiated for internal inspection on the valve to be

i

j

backseated.

The inspectors observed that the engineering evaluation did not

l

-

specify that an internal inspection of the valve be completed.

i

.

i

However, the evaluation identified that the procedure required

an internal inspection of the valve that was backseated.

The

,

inspectors observed that a MWO was not initiated for an

internal inspection of the valve backseated on December 27.

During a discussion with the system engineer he indicated that

i

-

'

!

an internal valve inspection would be completed provided other

inspections of the valve and or actuator indicated that an

j

internal inspection was warranted.

i

For the valve backseated on November 14. the MWO identified

l

that an internal valve ins)ection be performed but referenced

an incorrect procedure.

T1e procedure referenced and

'

!

documented on the MWO did not exist.

This deficiency was

maintenance personnel. pectors identified the problem to

corrected after the ins

'

4

l

-

The engineering evaluation recommended that o)erations

implement administrative controls to ensure tlat the backseated

l

valves would be removed from backseat prior to a 100 degree

Fahrenheit ( F) cooldown of the reactor.

Operations placec

caution tags on the valves to meet this recommendation.

The inspectors observed the caution tags placed on the

i

backseated valves and noted that the caution tags stated that

the valves were electrically backseated.

The caution tag book

did not contain any additional information.

The inspectors

>

.

reviewed procedure 34G0-0PS-013-2S:

Normal Plant Shutdown.

Rev. 21. and observed that step 7.3.26 stated, in part, that

!

3rior to cooldown greater than 100 F. remove all MOVs that have

3een electrically or manually backseated from their backseat.

The procedure did not provide additional instructions for the

activity.

.

The ins)ectors discussed a concern with operations' management

as to w1 ether the operators had sufficient guidance for

,

removing valves from their backseated condition during all

,

.

Enclosure 2

i

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i

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_

, _ . . _

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18

plant conditions. The normal method of removing a valve from

its backseat was to close the valve using the control room

handswitch. The inspectors concern was that if operators used

this method of removing valves from their backseat. RCIC and

RWCU system (and other systems with backseated valves) would be

isolated when they may be needed for continued safe unit

shutdown.

As a result of this discussion operations'

management provided additional instructions for the beginning

of shift training (BOST) for each operating crew informing

them of expectations and priorities during plant transient

conditions. The inspectors did not identify similar

instructions in the unit's scram proced r e.

c.

Conclusions

The inspectors concluded that failure to follow procedures

51GM-MNT-034-OS and 10 AC-MGR-019-0S by maintenance personnel to

ensure that steps were completed was a violation.

This was

identified as Violation 50-321/96-15-02: Maintenance Personnel

Failure To Follow Procedure During Valve Backseating Activities.

The inspectors concluded that maintenance personnel's lack of

understandina of the different types of procedure usage

requirements and implementation demonstrated a weakness.

The inspectors concluded that the maintenance procedure for

electrically backseating valves did not fully implement the

requirements of the engineering evaluation.

The inspectors

concluded that this deficiency did not result in a safety

significant concern for the backseated valves.

M3.3 Unit 1 RCIC and Unit 2 HPCI Soeed Control Chances

a.

Insoection Scooe (92902)

The ins)ectors observed upward drifts in the Unit 1 RCIC and

Unit 2 iPCI turbine speed controls during the 3erformance of

surveillance tests. The drifting occurred wit 1out operator

actions. The inspectors reviewed and discussed the results of the

Unit 2 RCIC test performed on January 9 with operations and

engineering personnel.

The inspectors also observed a

post-maintenance test of the Unit 2 RCIC system on January 10 (See

Section M1.3).

b.

Observations and Findinas

The inspectors observed, reviewed, and discussed the results of

the operability surveillance tests for the Unit 1 RCIC Pump and

the Unit 2 HPCI Pump.

The ins)ectors also observed maintenance

activities for the repair of t1e Unit 2 RCIC pump.

The inspectors

Enclosure 2

.m,

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_

-. . - ,...

'

.

,

19

-

attended the operations pre-job and post-job briefings..

The

briefings were thorough and stressed effective communications,

procedure adherence. job assignments, responsibilities, and test

results.

The inspectors observed the following during the Unit 1 RCIC

turbine test:

-

The RCIC pump turbine was manually started and after one minute

into the test the turbine speed appeared to stabilize at about

4460 revolutions per minute (rpm), as required oy procedure

-

At approximately four minutes into the test the turbine speed

drifted up to 4500 rpm

-

The operator took control of the turbine and lowered the speed

to 4460 rpm and at eight minutes into the test the turbine

appeared to stabilize at that speed

-

At approximately 15 minutes into the test the turbine speed

started to drift up again

-

The test was completed at approximately 25 minutes and the

turbine speed had drifted up to 4490 rpm

The inspectors reviewed test results data which verified what the

ins)ectors had observed concerning the upward drift of the RCIC

tur)ine speed.

During discussions with operators and engineers,

the inspectors were informed that the Control Room (CR) turbine

speed indication was 100 rpm lower than the actual turbine speed.

The inspectors observed the following during the Unit 2 HPCI

turbine test:

The HPCI turbine was started, came up to set speed, and

-

appeared to stabilize at 3865 rpm

-

Shortly after the speed stabilized, a gradual upward drift

began. At the end of the test, which lasted for 21 minutes,

the turbine appeared to be controlling at 3910 rpm

-

The lowest rpm observed by the inspectors was 3862 and the

highest was 3918 rpm

The inspectors found from the observations, discussions and

reviews taat the upward drift of the Unit 1 RCIC turbine speed was

not expected.

The turbine speed drift should not have occurred

because of the design of the system. The system should have

stabilized around 4460 rpm instead of having a constant upward

l

Enclosure 2

j

i

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. . --, -._-

- -

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20

drift.

The system engineer, stationed locally at the Unit 1 RCIC

pump, assumed that the upward drift was due to operator action.

The upward drift observed on the Unit 2 HPCI turbine continued

throughout the test. The inspector discussed the observation of

the drift with operations personnel.

Licensee personnel discussed

several possibilities for the deficiencies which included out of

calibration electronics, a test valve gradually clogging up with

debris, or a mechanical malfunction of the test valve.

!

Subsequent to the Unit 1 RCIC turbine test a Unit 2 RCIC turbine

test was performed.

During the test the operators observed

i

significant changes in the speed of the Unit 2 RCIC turbine. The

I&C technicians informed the operators that the turbine control

i

'

valve was receiving full open signals followed by full closed

signals on a continuous basis.

The turbine control valve appeared

to go to the fully open position and immediately go to the fully

closed position.

This caused observed fluctuations in turbine

speed of up to plus-or-minus 160 rpm. The operators declared the

Unit 2 RCIC system inoperable.

The RCIC system engineer informed

the ins)ectors that the Unit 2 RCIC system would operate in this

manner )ut not for very long.

The inspectors observed the

post-maintenance test of the Unit 2 RCIC and did not observe any

deficiencies.

c.

Conclusions

The inspectors concluded that the maximum drift observed on the

Unit 1 RCIC turbine was 40 rpm.

The upward drift of the Unit 2

HPCI turbine was about 45 rpm. The inspectors concluded that the

drifts could be an indication of pending failures.

The erratic

speed control of the Unit 2 RCIC was a significant problem. This

was identified as IFI 50-321, 366/96-15-03:

Resolution of RCIC

and HPCI Turbine Speed Control Drift Units 1 and 2. respectively.

M4

Maintenance Staff Knowledge and Performance

M4.1

Inadvertent Feedwater Heater Isolation.

a.

Insoection Scooe (62707)

J

The inspectors conducted a review of maintenance work activities,

reviewed documentation and discussed maintenance personnel

performance with licensee personnel with respect to an inadvertent

isolation of a Unit 2 feedwater heater,

b.

Observations and Findinas

On January 5, during maintenance activities to replace a relay on

the 6th stage A heater steam trap bypass to the condenser. a fuse

Enclosure 2

.

.

.

.. . - .

_ - _ .

.-. --

-- - _ ..- - -

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.

21

blew.

As a result, steam from the high pressure turbine to the

6th stage heaters was isolated, causing feedwater heater levels to

become erratic.

Operators observed that feedwater temperature decreased and

entered the abnormal procedure for loss of feedwater temperature.

Power was reduced to about 93.5% RTP. The blown fuse was

replaced, heater levels were stabilized and power was later

returned to 100% RTP.

The relay, which remained in the energized

state even though the relay fuse had blown, was not immediately

replaced.

The relay was replaced the following day after a work

plan was completed by engineering and maintenance personnel. The

inspectors noted that while similar relays had failed, sticking in

the energized condition was an unusual case.

The inspectors reviewed procedure 34AB-N21-001-2S:

Loss of

Feedwater Heating. Revision 2. and observed that operators

initiated the correct actions for the plant transient.

The inspectors discussed maintenance personnel's actions involved

with the relay replacement with maintenance supervision.

The

inspectors were informed that an I&C technician was in the process

of jumpering out the relay to be replaced had connected one end

of the jumper to a hot lead, and was routing the jumper through

the panel toward the other lead that was to be jumpered.

The

jumper was inadvertently grounded blowing the fuse, and

initiating the transient.

The inspectors discussed expectations for jumper usage with

maintenance management.

Management indicated that connecting a

jumper to a hot lead and then routing it through a panel did not

meet their expectations.

The inspectors reviewed several

maintenance procedures and observed that general jumper usage and

expectations for jumper usage was lacking.

In April and May 1995. the licensee conducted an extensive review

of jumper types, and jumper usage at the site. This review was

conducted as a result of a reactor scram following operator

deficiencies using jumpers. The inspectors observed that as a

result of this licensee review, several recommendations for jumper

types and jumper usage, and written expectations were developed.

Most departments held special training sessions for jumper usage

and the proper types of jumpers to be used.

Operations issued a

special procedure detailing operations management's expectations

for jumper usage.

The inspectors observed that maintenance management issued a

Maintenance Training Bulletin, dated April 1995, that dealt with

jum3er usage. The bulletin stated, in part, that personnel

autlorized to use jumper wires are expected to know and use the

Enclosure 2

1

__

__

_ _ _ _ _ _ _ _ _ _

._ _

__

_

_

. _ _

___

i

1 ..

?

'

-

_;

i

)

$

22

~

,

correct type.

Maintenance management informed the inspectors that

i

proper jumper usage was taught in craft training and was primarily

l

i

considered skill of the craft.

This maintenance jumper error that

!

j

initiated this feedwater level transient was being reviewed for

j

human performance improvements.

l

1

i

q

c.

Conclusions

I

The inspectors concluded that this maintenance jumper error

demonstrated a poor work practice on the part of one individual.

-

Similar jumper usage error has not been a concern and this error

J

was an isolated occurrence.

Reviewing this error for human

j

performance improvements was appropriate.

,

'

i

M5

Maintenance Staff Training and Qualification

MS.1 Maintenance Trainina and Qualification Review

,

j

a.

Insoection Scooe (62707)

,

'

.

A review of maintenance training documentation was conducted to

!

verify that personnel involved in the repair and maintenance of

valves were appropriately trained and qualified. Also, the

training and qualification recuirements for valve maintenance were

discussed with Maintenance anc Training staff members.

i

l

b.

Observations and Findinas

.

A review of training documentation for mechanics was conducted by

)

i

the inspectors.

This review was conducted to determine the

.

qualification status of personnel assigned to perform valve

)

maintenance on safety-related and those non-safety-related valves

i

that are within the purview of the Maintenance Rule.

The

mechanical maintenance training staff informed the inspectors that

the training and cualification requirements were the same for work

l

on both safety anc non-safety-related valves.

The training staff

j

maintains the training and qualification status of personnel in a

!

computer data base referred to as the Training Records and

j

Qualification System (TRAQS).

!

t

The inspectors reviewed the following documents which provided the

]

training and qualification requirements:

-

ANSI N18.1-1971:

Selection and Training of Nuclear Power Plant

j

Personnel

HNP-2-FSAR-13:

Section 13.1.3 Qualification Requirements for

-

Nuclear Plant Personnel and Section 13.1.3.1.16 Maintenance

'

l

Personnel

Enclosure 2

2.

i

..

-

.

. . _

_

.,

23

-

10AC-MGR-007-05: Personnel Qualification Requirements. Rev. 5

-

DI-MNT-11-0287N: Qualification of Maintenance Personnel. Rev. 2

The inspectors were informed during a discussion with maintenance

staff members that there were some Building and Grounds (B&G)

personnel who were trained and qualified to perform valve packing.

These individuals are assigned to the various performance teams.

They perform valve packing activities as well as laborer type

.

work. A followup discussion with the mechanical maintenance

training staff indicated that these individuals attend a special

course to become qualified as Valve Packing Technicians.

They are

provided training in mathematics, precision tools, torquing,

gasket replacement and valve packing. The instructions in this

special course is an excer)t from the curriculum for the mechanics

and the content of each su) ject area is the same.

The successful

completion of this special course qualifies a B&G individual for a

Valve Packing Technician position on the Performance Team. The

names of these individuals are entered into the TRAQS computer

data base as being qualified.

The inspectors reviewed a sampling of MW0s associated with

mechanical work activities performed on valves by Mechanics and

B&G personnel. The MWO sampling included the following MW0s:

-

MWO 2-94-3430:

2B21-F013A. Replace SRV Top Works and Stump

-

MWO 1-95-2627:

Prepare SRV Solenoid Valve Assembly and Stump

for Shipment to Wyle Laboratory

,

-

MWO 2-95-1035:

Remove. Test. Replace / Repair RCIC Suction

Relief Valve

-

MWO 1-95-2942: Clean and Torque Valve IN22-F6081

-

MWO 1-96-0089:

Repack Valve Per 52CM-MME-001-0S

-

MWO 1-95-2934:

Inspect Valve IN22-F1114A for Packing

'

Adjustment / Repacking

!

-

MWO 2-95-3370:

Repair Galled Valve Stem on 2E11-F015B

!

-

MWO 2-95-3639:

Repair LPCI Valve 2 Ell-F015A Ball Stem / Valve

Stem Coupler

-

MWO-2-94-1732:

Perform Mechanical Portion of 52SV-T48-001-0S

,

!

i

Enclosure 2

i

!

-, .

_ . , . _ , . .

. .

-

_

_ . . _ .

.__

- . _ .

a

.,

24

MWO-1-94-5335:

Repair / Replace and/or Bench Test Relief Valve

-

IN22-F070A

-

MWO-1-96-1000:

Repack Valve IN21-F023A

The names of the persons who aerformed the work activity as listed

in the MWO were compared to t1ose on the list of individuals

qualified to perform the work activity on TRAQS.

No discrepancies

were identified in this comparison.

c.

Conclusions

Personnel who perform mechanical maintenance on safety and

non-safety-related valves are trained and qualified in accordance

with the requirements of ANSI N18.1-1971. the FSAR, and other

applicable plant qualification procedures.

M8

Miscellaneous Maintenance Issues (92700) (92902)

M8.1

(Closed) VIO 50-321/96-06-04:

Failure to Meet TS Surveillance

Recuirements Prior to Withdrawal of a Control Rod While in Cold

Shutdown

This Violation was identified when, on two occasions, licensee

personnel withdrew a control rod with accumulator pressure below

the TS requirement.

The activities were performed for maintenance

purposes.

The licensee's response was provided in correspondence dated

July 10. 1996.

The response indicated that procedure

34G0-0PS-066-05: Single Control Rod Withdrawal in Shutdown or

Refueling, was revised to clarify the requirement that an

accumulator pressure of equal to or greater then 940 pounds per

square inch gauge (psig) must be present before any rod

withdrawal. The inspectors reviewed the revised procedure.

Based

on the reviews by the inspectors and the actions taken by the

licensee, this violation is closed.

M8.2 (Closed) LER 50-321/96-06:

Inadeauate Procedure and lack of Work

Coordination Result in Withdrawal of Inocerable Control Rod

.

This problem was discussed in IR 50-321.366/96-06.

No new issues

were revealed by the LER. This LER is closed.

Enclosure 2

_ _ _ . . _ ._

. . . _ _ _ _ _ _ _ _ _

. . _ _ _ .

!

.,

25

III. Enaineerina

!

!

E2

Engineering Support of Facilities and Equipment

'

E2.1 Trio and failure to Start Problems For the Unit 1 A Standby liauid

Control (SLC) Pumo

,

a.

Insoection Scooe (92903)

'

The inspectors reviewed engineering activities of an investigation

of the 1A SLC pump tripping and failure to start. A review of the

MW0s, work completed, procedures, and discussions with engineering

personnel were conducted.

b.

Observations and Findinas

On January 10, during operations performance of a routine

operability surveillance, the 1A SLC pump tripped.

The system was

declared ino)erable and actions to investigate the problem were

4

initiated.

,iaintenance found the motor overloads trip)ed.

!

Maintenance later replaced a pump control switch and clanged the

overload relay setting from 100% to 115%, per a telephone

conversation with engineering personrel, and in addition meggered

the pump motor.

Later, operations personnel ran the pump for

about 20 minutes and it ran properly.

On January 12. operations began another operability surveillance

during which the pump did not start on three attempts.

Maintenance personnel were contacted to investigate.

A worn

i

control switch block was identified as the problem and was

replaced. The pump then started properly.

During the investigation of this problem, technicians identified

,

that the overload heaters were not the size s?ecified in procedure

4

52PM-R24-001-05: Allis Chalmers Low Voltage iCC Inspection,

'

Revision 12.

The procedure specified that the overload heaters

'

should be size H80s, and size H78s had been installed.

Maintenance personnel installed the correct heaters and later

,

changed the relay setting to 125%.

Engineering personnel were

'

contacted to investigate the problem with the overload heaters and

to further investigate the SLC pump tripping problem to ensure

that the correct failure mechanism was identified.

The inspectors discussed the discrepancy of the installed overload

l

heaters with respect to procedural requirements with engineering

!

personnel. The inspectors were informed that a work history

review had been completed back to about 1984 and no evidence of

'

heater overload changeout was observed.

Documentation reviewed

did not indicate what size overload heaters should be installed or

'

when size H78 overload heaters were placed in the system.

i

Enclosure 2

,

i

'

.

.__

_

.

'

..

i

26

i

!

Engineering personnel stated that at some time P the past, size

t

H78s may have been the correct size.

Engineering personnel did

l

not determine how the size H78 become installed in the system.

Engineering also indicated that the overload relay was suspected

!

as the cause of the problem and not the size of the overload

t

heaters.

Maintenance personnel replaced the overload relay.

Both

i

the overload heaters and the overload relay that was replaced were

tested by engineering and revealed that the pump motor would have

!

o)erated properly and within the expected overload condition of

i

t1e pump motor.

During the procedure review and through discussions with

engineering personnel, the inspectors observed that procedure

guidance for determining the correct size of overload heaters was

-

not clear.

Engineering personnel stated that procedure

clarifications would be recommended.

c.

Conclusions

l

The inspectors concluded that engineering personnel from NS&C

-!

conducted a detailed review of the SLC pum) tripping problem and

consider this as a positive attribute of t1e engineering

i

department effort.

The inspectors also concluded that the SLC

l

pump tripping problem was an isolated occurrence.

The inspectors

-

did not consider that this installation of incorrect size overload

heaters was an example of poor configuration control or

contributed to the tripping problem.

E3

Engineering Procedures and Documentation

l

E3.1 Review of Engineering Evaluations

l

!

a.

InsDeCtion SCoDe (37551) (92903)

'

The inspectors reviewed licensee activities and engineering

evaluations completed for electrically backseating two Primary

Containment Isolation valves.

The licensee electrically

~

backseated the valves in an attemat to identify and reduce the

unidentified drywell leakage for Jnit 1.

Reactor Water Cleanup

.

(RWCU) Inboard Isolation valve 1G31-F001, and Reactor Core

!

Isolation Cooling (RCIC) Inboard Isolation valve 1E51-F007, were

!

electrically backseated on November 14 and December 27, 1996.

i

respectfully.

l

t

b.

Observations and Findinas

!

!

The inspectors reviewed an engineering evaluation conducted by

I

corporate engineering and transmitted to the site by interoffice

!

correspondence, dated February 21, 1994, for Backseating of

Enclosure 2

f

i

!

I

i

>

-

-

_-

--

---

-

.

-

'

.

27

Motor-0perated Valves (MOVs) in the Drywell. The engineering

evaluation identified a total of 16 valves that were evaluated and

included both Unit 1 and Unit 2 valves.

Post backseating

inspections were identified for some valves and no inspection was

identified for others. The evaluation specified the correct

!

maintenance procedure used for electrically backseating the valves

i

and identified that the plant maintenance procedure used to

backseat the valves currently required that the backseated valves

be disassembled and inspected for damage at the next opportunity.

The evaluation also identified the actuators for both valves were

to be inspected for damage to thrust components.

The evaluation addressed valve actuator torque ratings, active

thrust ratings and valve thrust limit in the open direction. The

evaluation concluded that "the backseat may be damaged on many of

the valves in cuestion if they are electrically backseated.

,

However, this camage is not postulated to prevent the valve from

i

performing its safety functions.

Other valve components are not

I

likely to be damaged by electrically backseating."

'

The inspectors reviewed table 7.3-1 of the Unit 1 FSAR and

observed that the safety function of the valves was in the closed

direction.

The safety evaluation satisfactorily addressed valve

closing requirements and stated that deformation of the backseat

would not prevent the valves from closing.

The inspectors also reviewed the interoffice correspondence

(memorandum) from site engineering to operations endorsing the

1994 corporate engineering evaluation and identified other

specific stipulations. The memorandum identified that the valves

duty cycle was 15 minutes and provided guidance for not exceeding

the duty cycle time. Also recommended was that administrative

controls be placed on a valve to inform operators that the valve

was backseated and to take actions to prevent thermal binding

during cooldown.

The inspectors identified a weakness with the

administrative control placed on the valves.

This and other

inspector identified deficiencies are discussed in section M3.2.

Also stipulated was that maintenance must generate or confirm the

existence of MW0's to perform repacking of the backseated valve.

The inspectors observed that the memorandum referenced maintenance

procedure. 52GM-MNT-034-05, as the procedure used to backseat the

valves.

The correct procedure reference was 51GM-MNT-034-0S.

The inspectors discussed with engineering whether any changes to

the valves, valve motors or actuators were made since 1994 that

affected the evaluation.

Engineering personnel stated that no

changes were made that affected the previously completed

evaluation.

Enclosure 2

.

-

.,

28

c.

Conclusions

The inspectors concluded that the engineering evaluation for

electrically backseating valves located in the drywell was

,

satisfactory. The evaluation considered plant safety and

!

identified actions to ensure continued system and component

!

reliability. The typographical error on the procedure reference

'

in the memorandum was not a significant concern.

j

E8

Miscellaneous Engineering Issues (92700) (92903)

l

E8.1

(Closed) LER Licensee Event Reoort (LER) 50-321/96-14:

Incorrect

Circuit Breaker Settina Results in Emeraency Diesel Generator

l

Beina Inocerable.

l

This problem was discussed in IR 50-321, 366/96-14. Sections M2.2

and E2.2, and was identified as an example of Violation

50-321. 366/96-14-03:

Failure to Implement Configuration Control

i

Requirements. The licensee determined during a system walkdown

that the overcurrent protection trip setpoint for the normal

sup}ly breaker to Motor Control Center (MCC) 1R24-S026. from the

IB 1mergency Diesel Generator (EDG). was not set properly. The

problem occurred as the result of a failure to incorporate

information developed in a design calculation into appropriate

electrical single line drawings and plant maintenance procedures.

Poor labeling for setting the breaker trip device was also a

contributor. The long time delay pickup of the trip device should

have been set at 450 amps but was left at 300 amps instead.

This

problem made the IB EDG inoperable.

The licensee promptly initiated a temporary modification to remove

the largest load from this MCC and powered it from another source.

The trip device installed on the Unit 1 600-volt feeder breaker to

the subject MCC was disabled, leaving the upstream 4160-volt

feeder breaker to the MCC to provide overcurrent 3rotection.

Additional corrective actions will be to remove tie trip devices

from the primary and alternate feeder breakers on the bus by

June 15, 1997. The inspectors will review licensee activities to

complete the corrective actions, which are documented as IFI

50-321/96-14-05:

Restoration of IB EDG Motor Control Center.

Based upon the inspectors review and licensee actions, the

issuance of an NOV and IFI. this LER is closed.

I

E8.2

(Closed) LER 50-321/96-14. Rev 1.:

Incorrect Circuit Breaker

Settina Results in Emeraency Diesel Generator Beina : nooerable.

]

This LER was discussed in Section E8.1 of this report.

The LER

j

corrected a date that licensee corrective actions will be

completed.

No new issues were revealed by this revision to the

LER.

This LER is closed.

Enclosure 2

tui

vr-

w

w

m

w--

--

- - - -

- -

-

u-

a

-

.

---

-

.

__.

\\

-

.

,

29

E8.3

(Closed) IFI 321/96-07-03: Dearadation and Reolacement of Unit 2

Station Service Batterv 28 Due to Builduo of Cell Sediment.

This item addressed an observation of sediment buildup in the

cells of the Unit 2 Station Service Battery (SSB) 28.

The vendor

,

determined that the buildup was due to a curing 3rocess at the

factory. Of the 248 battery cells supplied for )oth trains of

i

Unit 2. 56' cells showed signs of sediment. All of the cells were

j

located among the 120 cells in SSB 28. At the end of the report

period sediment had not been observed in the cells of SSB 2A. The

,

licensee has received replacement cells from the vendor.

MWO 2-96-1929 has been issued to replace all 120 cells of SSB 2B

-

during the upcoming Spring 1997 Unit 2 refueling outage. The MWO

will be followed up as part of the inspectors *

alanned outage

inspection activities.

Based on the actions tacen by the

licensee, this item is closed.

E8.4

JClosed) LER 50-321/96-07:

Failed Comoonent Results in

i

nadvertent Emeraency Diesel Generator Start.

'

This LER was issued on May 21, 1996, when the 1A EDG was

inadvertently started.

Based on the actions taken by the

licensee, this item is closed.

E8.5 (Closed) LER 50-321.366/96-08:

Inadeouate Procedure Results in

Reactor Pressure Increase and Automatic Reactor Scram.

This problem was discussed in IR 50-321.366/96-06.

The inspectors

reviewed the revised procedure 3450-N32-001-1S:

EHC Hydraulic

System. Rev. 17.

The inspectors also reviewed the previous

.

i

revision.

The inspectors observed that sections 7.3.1. System

.

Isolation With Bypass Capacity, and 7.3.2 Restoring the System to

,

Operation, had been deleted. This would preclude isolating

1

portions of the Electro Hydraulic Control (EHC) system which

)

!

caused the increase in reactor pressure.

Based on the actions

taken by the licensee, this item is closed.

'

IV Plant Support

,

R1

Radiological Protection and Chemistry Controls

1

.

R1.1 General Radiological Controls

'

Insoection Scone (71750)

'

General Health Physics (HP) activities were observed during the

report period.

This included locked high radiation area doors,

proper radiological postings, and personnel frisking upon exiting

the Radiologically Controlled Area (RCA).

The inspectors made

i

Enclosure 2

.

.

.

.

.

-

-

.

,

30

frequent tours of the RCA and discussed radiological controls with

HP technicians and HP management.

No significant deficiencies

'

were identified.

R1.2 Radiological Controls

j

a.

Insoection Scooe (83750)

Radiological controls associated with ongoing operational

activities were reviewed and evaluated.

Controls for both routine

operations and specific non-routine tasks were included in the

review

In particular. housekeeping and cleanliness, area

postin s radioactive waste (radwaste) container labels, and

contro s for high radiation areas were reviewed for adequacy.

Licensee controls for ongoing operations were compared against

documented requirements in applicable sections of Technical

i

Specifications (TSs). Final Safety Analysis Report (FSAR). and

10 CFR Part 20.

The inspectors made frequent tours of the RCAs.

In addition.

specific radiation work permit (RWP) procedural guidance and

selected survey results were reviewed and discussed with

responsible HP staff and supervisors.

Operations and radiological

controls associated with the low-level radioactive waste storage

j

building were observed and evaluated.

Controls for specific tasks

'

performed in accordance with the following RWPs were evaluated in

detail.

e

RWP 197-0005. Remove old obsolete drum capping equipment and

support work, effective January 10. 1997.

e

RWP 097-0017. Process / ship / receive / load out/ transport

radioactive materials and support work including alpha trending

and Waste Separation and Temporary Storage Facility (WSTSF)

work, effective January 10, 1997.

In addition the inspectors reviewed and discussed program

guidance and results of internal exposure evaluations made by the

licensee during 1996.

b.

Observations and Findinas

High and locked high radiation area controls were verified to be

implemented in accordance with TS requirements.

Postings of

radwaste storage areas were proper and in accordance with TS or

10 CFR 20 Subpart J requirements.

Overall, containers holding

radwaste, contaminated materials, and equipment were labeled in

accordance with 10 C.FR 20.1904 requirements.

Excluding activities

associated with construction of a hot tool room and an isolated

example of trash and debris in the Unit 2 (U2) Radioactive Waste

Enclosure 2

--

.

.

.

.-.

.

.

.

'

,

l

31

(RW) building area 164 foot (*) elevation floor, cleanliness and

housekeeping within the RCAs. outside radwaste ]rocessing and

storage areas, and the low-level waste storage Juilding were

acceptable.

Radiation control activities associated with ongoing

radwaste processing, storage and shipping operations were adequate

and conducted in accordance with applicable RWPs and procedures.

During facility tours, the inspectors observed several poor

radiological control practices associated with demolition of a

'

concrete wall located in the Unit 1 (U1) RW area 132' elevation.

Demolition activities were in preparation for construction of a

hot tool room and were performed under RWP 197-0005. Remove Old

Obsolete Drum Capping Equi) ment and Support Work. effective

January 10.197

The wort area was roped-off equipped with a

step-off pad, cad posted as a Contaminated Area. On

!

January 15. 1997, the ins)ectors noted that the demolition

activities generated visi)le and potentially contaminated dust

which subsequently became airborne and also covered the step-off

pad and areas surrounding the posted area.

The only established

engineering control provided was use of a High Efficiency

Particulate Air (HEPA) filtered portable exhaust ventilation

i

system but without an enclosure surrounding the work area. The

most recent quantitative contamination and air sample survey

results conducted on January 11, 1997, verified contamination on

the wall. approximately 1000 to 3000 disintegration per minute per

l

2

100 centimeters square (dpm/100cm ) but did not identify an

airborne hazard.

However, the inspectors noted that no additional

airborne surveys were conducted within the work area and that the

most recent quantitative radiation surveys completed on

January 13. 1997, were in response to unexpectedly elevated

electronic dosimeter readings.

!

Discussions with responsible HP and maintenance personnel

indicated that the tools used for the demolition changed and that

the staff was aware of the increased levels of potentially

contaminated dust outside of the designated area.

Licensee

representatives stated that additional gross contamination surveys

of the floor conducted outside of the posted area using Masslin

cloth were conducted but not documented.

Responsible HP personnel

stated that the gross surveys did not indicate any contamination

outside of the roped-off area. TS 5.4 requires that written

procedures be established implemented, and maintained covering

activities delineated in Appendix A of Regulatory Guide (RG) 1.33.

Rev. 2. dated February 1978.

Regulatory Guide 1.33. Appendix A.

" Typical Procedures for Pressurized Water Reactor and Boiling

Water Reactors." Paragraph 7.e. requires radiation protection

procedures for Radiation Work Permit System and for Contamination

Control.

Health Physics procedure 60AC-HPX-004-0S, Radiation and

Contamination Control. Revision (Rev.) 14. effective October 15,

1996, specifies that HP will:

initiate controls, e.g..

Enclosure 2

L

-

-

-

_ ___ _ _

_

_.

.

.

32

l

engineering controls, to ensure that spread of contamination is

minimized; will perform non-routine radiation and contamination

surveys as required, to support operation and maintenance: will

-

perform airborne su veys during radioactive work which is expected

to cause airborne radioactivity unless constant air monitors are

,

provided: and perform periodic air sampling to evaluate the

effectiveness of filtered ventilation used to control airborne

radioactivity. The inspectors noted that the established

engineering controls and the contamination and airborne surveys

conducted for the observed demolition activities were not in

,

accordance with the established procedure.

]

The inspectors did not identify any significant concerns regarding

use of the whole body counter (WBC) equipment used for in vivo

.

analyses and results.

Excluding concerns identified for WBC

calibration guidance detailed in Paragraph R7.1. the applicable

licensee procedures were determined to be satisfactory and staff

knowledge adequate to implement the current program.

Potential

procedural enhancements discussed with responsible licensee

representatives included:

improved guidance for evaluating

potential internal exposure resulting from non-gamma-emitting

i

radionuclides; collection methods for bioassay sam)les and

associated vendor capabilities; and inclusion of t1e standup WBC,

t

currently used for qualitative (screening) analyses, in the

crosscheck program.

Results of all )ositive internal ex)osures of

workers analyzed in 1996 were less tlan one percent of tie Annual

Limits of Intake (ALIs) documented in 10 CFR Part 20.

'

c.

Conclusions

Radiological controls for high and locked high radiation areas

were maintained in accordance with TS requirements. Area postings

and container radiation labels were appro)riate. Housekeeping and

cleanliness were adequate.

In general, t1e licensee was

controlling internal exposure effectively.

The poor engineering

controls and survey practices observed were identified as an

example of VIO 50-321, 366/96-15-05: Failure to Follow Procedures

for Contamination Control and for Deficiency Card Issuance for

Inadequate Bioassay Calibration Guidance.

R5

Staff Training and Qualifications in Radiation Protection and

Chemistry

a.

Insoection Scone (83750)

General employee training provided to meet the requirements of

10 CFR Part 19. and specific training and medical certification.

required by 10 CFR Part 20 for persons who used or were designated

to wear respiratory protective equipment. were reviewed and

evaluated during the onsite inspection.

Enclosure 2

,

,

33

Selected 1996 training and medical certification records for

selected personnel within the following groups were reviewed and

discussed with responsible licensee representatives.-

Personnel evaluated by the licensee for potential internal

e

exposure during 1996.

e

All licensee and contract personnel involved in the transfer of

a full radwaste liner from the radwaste processing facilities

to a shipping cask during the week of January 13. 1997.

e

All contract personnel involved with routine operations at the

low-level radioactive waste storage building.

b.

Observations and Findinas

The inspectors verified that general employee and respiratory

protection training, and medical certifications were conducted in

accordance with training procedure 73TR-T-RN-001-0S General

Employee Training Programs. Rev. 9. effective June 1. 1996.

The

guidance met the requirements of 10 CFR 19.13 and 10 CFR 20.1703.

Review and discussion of training records verified that all

)ersonnel met the required general employee training requirements.

rom review of training records and selected Respirator Device

Issuance Reports, the inspectors verified that all persons who

used respiratory protection equipment were trained and medically

certified in accordance with the applicable procedures.

c.

Conclusions

General employee training and completed medical certifications for

personnel involved in licensed activities were conducted in

accordance with the a)plicable procedures and met the applicable

requirements of 10 CFR 19 and 10 CFR 20.

R7

Quality Assurance in Radiation Protection and Chemistry Activities

R7.1

In Vivo Ouality Control Analyses

a.

Insoection Scooe (83750. 84750)

During the inspection, the 1996 quarterly Quality Control (OC)

cross-check results for the in vivo WBC quantitative (chair

geometry) radionuclide analyses were reviewed and discussed.

b.

Observations and Findinos

For the first and fourth quarter cross-check samples, all results

for torso, lung and thyroid were in agreement with the vendor

Enclosure 2

j

-..

_

._

._

_ _ . _ _ _

._._. .

. _ _

.

__.

_.

!

l

.

.

i

!

34

!

i

values.

Disagreements between selected licensee analysis results

i

and the known values were identified for the second and third

cuarters of 1996. -For the second quarter samples analyzed on

!

Fay 23, 1996, the identified disagreements resulted from an

<

improper calibration conducted April 23, 1996.

Responsible

i

licensee representatives stated that the improper calibration

,

resulted from misinterpretation of calibration guidance provided

l

by the vendor software-driven calibration menu.

.

!

From review of the applicable procedure and discus. ions with

cognizant licensee representatives, the inspectors determined that

i

no changes to, nor 3rocedural warnings regarding applicable

i

computer-based cali] ration menu were implemerted.

A licensee

review of.the WBC chair in vivo analysis results determined that

the improper calibration had no significant effect on assignment

l

of internal exposure for the two individuals who were evaluated

i

using the WBC chair between the dates of the improper calibration

l

and when the deficiency was identified and corrected. However,

the inspectors noted that the subject evaluations were not

documented.

The inspectors noted that RG 1.33 recommends written

procedures for bioassay programs and that contrary to

,

administrative control procedure 10AC-MGR-004-05. Deficiency

l

Control System, Rev.10. dated March 3,1996, a Deficiency Card

i

for the calibration procedural inadequacy was not initiated.

For

the third quarter, disagreements in results of the crosscheck

comparisons resulted from failure to load all the provided cross-

i

check samples and did not affect the calibration accuracy.

1

'

c.

Conclusions

Quality control cross-check analyses were conducted in accordance

with procedural requirements.

However, the failure to issue a

deficiency card was identified as an additional example of

.

procedural VIO 50-321, 366/96-15-05: Failure to Follow Procedures

for Issuance of a Deficiency Card for Inadequate Bioassay

Calibration Procedural Guidance.

'

{

R8

Miscellaneous Radiation Protection and Chemistry Issues

l

a.

Insoection Scooe (83750. 84750. 86750)

I

The status of selected radiation control and radwaste performance

indicators was reviewed and discussed with licensee

,

j

representatives.

i'

b.

Observations and Findinas

i'

Since 1993, annual dose expenditure per unit outage continued to

decrease.

For 1996, dose expenditure was approximately 441

person-rem and was within the established goal of 575 person-rem.

Enclosure 2

,

i

w

-

-

, , , , .

.

.r.

,

,,.,-.r

,

.-

-v--

, .

-

- - - - - - -

. . -

-

.

-

-

_ .

-

-

_-- . _

_ - . _ - . -

. - - - - -

.- _

.-

<

i

35

For 1996, licensee representatives informed the inspectors that no

I

abnormal effluent releases were identified.

The 1996 dose

!

estimates from both liquid and gaseous effluents were small

l

percentages of the Offsite Dose Calculation Manual (ODCM) limits.

l

No significant trends or changes in radiological environmental

i

monitoring program sample radiological analyses were identified.

l

!

c.

Conclusions

j

Radiation protection performance indicators verified that licensee

actions to control worker dose were effective and radiological

effluent releases were minimized.

j

R8.1

(Closed) Insoector Followuo Item (IFI) 50-321. 366/95-05-01:

-

Review Post Accident Samolina System (PASS) Proaram Enhancements.

[

This item was opened pending completion of equipment modifications

and procedural changes identified for the PASS system by the

!

licensee.

From selected comparison of installed PASS equipment

,

j

with configuration control documents arid review of current

procedures, the inspectors verified completion of modifications

,

and procedural revisions.

On January 16, 1997, the inspectors

observed licensee representatives successfully demonstrate PASS

operability by collecting, processing, and analyzing a U2 reactor

coolant system (RCS) liquid sample in accordance with Chemistry

(CH) Sampling (SAM) procedure 64CH-SAM-020-0S, Rev. 1.

From

review of selected August 1996 through January 1997 PASS In-Line

Analyses records and discussions with the licensee, the ins)ectors

verified that both containment air and RCS samples from bot 1 U1

and U2 were collected and processed by chemistry personnel using

the PASS equipment on a routine basis.

Excluding several

instances of low RCS pH determinations relative to reference

samples, no other analysis accuracy issues were identified. The

licensee stated that a review of the low pH values would be

conducted. As of November 1996. PASS availability was listed as

95 percent in licensee maintenance records.

Based on licensee

actions and current system reliability. this item is closed.

R8.2

(Closed) Unresolved Item (URI) 50-321. 366/96-14-07:

Determine if

Certificate of Comoliance (C0C) and Associated Vendor Documents

for Packaae No. USA /5805/B() Were Controlled in Accordance with

Administrative Procedure 20AC-ADM-003-05. Vendor Manual Review and

Control.

During review of C0Cs and associated documentation for package

type USA /5805/B() used for an August 7, 1996 Type B shipment of

irradiated hardware to a licensed burial facility, the inspectors

determined that current manuals and procedures were received

directly by the radaaste staff from the vendor. However, the

inspectors noted that the subject documents may not have been

Enclosure 2

..-

.- - -

-

.

.

--

.

---

.

. -

.-

-

.

-

- .

-

u

j

,,

,

36

i

reviewed and controlled in accordance with the applicable

administrative procedure, and thus may not have met the intent of

i

10 CFR 70.113 quality assurance (0A) requirements for shipping

program activities. A review of licensee records identified that

the C0C and procedures were maintained in accordance with the

applicable administrative procedure. However, the licensee was

unable to demonstrate that the subject manual was received.

!

reviewed, processed, and maintained in accordance with the subject

administrative control procedure. All other documents associated

with shi) ping containers which were, or could be used to make

,

Type B slipments were maintained in accordance with the licensee *s

procedure.

1

Prior to the current inspection. the licensee requested all

uncontrolled copies of C0Cs. and associated documents from staff

members involved in transportation activities.

The inspectors

reviewed a January 7.1997, letter confirming that a single copy

of shipping container documents would be sent to the licensee.

Consistent with Section IV of the Enforcement Policy based on

!

corrective actions taken prior to the end of the inspection, this

i

issue was identified as Non-cited Violation (NCV)

t

50-321, 366/96-15-06: Failure to Maintain Shipping Cask Manuals in

Accordance with Established Procedures to Meet 10 CFR Part 70.113.

52

Status of Security Facilities and Equipment

!

The inspectors toured the protected area and observed that the

perimeter fence was intact and not compromised by erosion nor

i

disrepair. The fence fabric was secured and barbed wire was

i

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 personnel and packages entering the

protected area were searched either by special purpose detectors

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

Badge issuance was observed, as was the processing and escorting

,

of visitors.

Vehicles were searched, escorted and secured as

described in the PSP.

)

The inspectors concluded that the areas of the PSP inspected met

the PSP requirements.

V. Manaaement Meetinos

,

X.

Review of UFSAR Commitments

A recent discovery of a licensee operating its facility in a

i

manner contrary to the Updated Final Safety Analysis Report

(UFSAR) description highlighted the need for a special focused

review that compares plant practices, procedures and/or parameters

Enclosure 2

l

l

-

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.

.

'

k

e,

37

to the UFSAR description. While performing the ins)ections

discussed in this re) ort, the inspectors reviewed t1e applicable

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

inspectors verified that the UFSAR wording was consistent with the

observed plant practices procedures, and/or parameters.

X.1

Exit Meeting Summary

The inspectors presented the inspection results to members of the

licensee management-at the conclusion of the inspection on

January 31, 1997.

The licensee acknowledged the findings

presented. An interim exit was conducted on January 17, 1997.

The inspectors asked the licensee whether any materials examined

during the inspection should be considered proprietary.

No

proprietary information was identified.

X.2

Refueling Outage Management Meeting

The inspectors attended several Outage Management Meetings

conducted at the site. Among the items discussed were: The

Fall 1997. Unit 1 outage status: the Spring 1997. Unit 2 outage

status: the Unit 2 maintenance planning update: the Unit 2 scope

additions: the status of outage requisitions; and the status of

design changes. The ins ectors observed that the critical path

was identified as the hi h pressure turbine modifications. A fuel

shuffle, and not a fuel

ff load, will be performed.

However. the

'

visual inspection of the vessel internal core spray piping could

>

impact the outage schedule.

The inspectors concluded that the

'

outage is well planned. with realistic goals, with adequate

.

support.

!

X.3

Management Meeting in Region II Office

i

i

A licensee-requested meeting was held in the Nuclear Regulatory

Commission (NRC) office in Atlanta. Georgia on January 8.1997.

.

The purpose of the meeting was to discuss Georgia Power Company's

!

Self-Assessment for the Hatch nuclear plant.

The NRC concluded

that the meeting was beneficial in that it provided a better

>

t

understanding of accomplishments and improvement initiatives at

the Hatch facility.

A meeting summary was documented under

l

separate correspondence dated January 9. 1997.

.

4

Enclosure 2

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38

1

,

\\

PARTIAL LIST OF PERSONS CONTACTED

)

Licensee

Anderson, J., Unit Superintendent

Betsill, J., Operations Manager

!

Coggin

C., Engineering Support Manager

i

Curtis, S., Operations Support Superintendent

!

Davis

D., Plant Administration Manager

!

Fornel, P., Performance Team Manager

Fraser, 0., Safety Audit and Engineering Review Supervisor

Hammonds, J., Regulatory Compliance Supervisor

Kirkley, W., Health Physics and Chemistry Manager

Lewis, J., Training and Emergency Preparedness Manager

Moore, C,. Assistant General Manager - Plant Support

Reddick, R., Site Emergency Preparedness Coordinator

Roberts, P., Outages and Planning Manager

Sumner, H., General Manager - Nuclear Plant

!

Thompson, J., Nuclear Security Manager

Tipps, S., Nuclear Safety and Compliance Manager

>

,

Wells, P., Assistant General Manager - Operations

l

!

INSPECTION PROCEDURES USED

'

-

IP

'551: Onsite Engineering

IP 90500:

Effectiveness of Licensee Controls in

-

Identifying, Resolving, and Preventing Problems

l

IP 61726:

Surveillance Observations

IP 62700: Maintenance Implementation

IP 62703:

Maintenance Observations

IP 62707: Maintenance Observations

IP 71707:

Plant Operations

IP 71714: Cold Weather Preparations

IP 71750:

Plant Support Activities

IP 83750: Occupational Radiation Exposure

IP 84750:

Radioactive Waste Treatment and Effluent and

Environmental Monitoring

IP 86750: Solid Radioactive Waste Management and

Transportation of Radioactive Materials

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

j

Enclosure 2

I

.

.

.

_

. .

-

.a

_7

_ . _

_

_

_ _ _ _ .

_ . _ _ _ _ _ . _ _ _ _ _ . _ _

_.

. - _ _

,

?

s . .. '

!

39

i

ITEMS OPENED. CLOSED. AND DISCUSSED

'

Ooened

j

50-366/96-15-01

NCV Inadequate Procedures for Replacement of the

Unit 2 Drywell Hydrogen Recombiner Flow

Controller Batteries and Establishing the

j

Required Controller " Dead Band" Following

Certain Maintenance Activities identified

(Section M2.1).

j

50-321/96-15-02

VIO Maintenance Personnel Failure To Follow

Procedure During Valve backseating Activities

i

(Section M3.2).

'

50-321.366/96-15-03 IFI Resolution of RCIC and HPC1 Turbine Speed

Control Drift Units 1 and 2. respectively

(Section M3.3).

50-321.366/96-15-04 IFI Switchyard Maintenance and Material Condition

(Section M1.4).

50-321.366/96-15-05 VIO Failure to Follow Procedures for Contamination

Control and for Deficiency Card Issuance for

Inadequate Bioassay Calibration Guidance

(Sections R1.2 and R7.1).

l

50-321.366/96-15-06 NCV Failure to Maintain Ship)ing Cask Manuals in

accordance with Establisled Procedures to Meet

'

10 CFR Part 70.113 (Section R8.2).

!

Closed

50-366/96-15-01

NCV Inadequate Procedures for Repl6 cement of the

Unit 2 Drywell Hydrogen Recombiner Flow

,

Controller Batteries and Establishing the

,

Required Controller " Dead Band" Following

Certain Maintenance Activities (Section M2.1).

50-321.366/96-15-06 NCV Failure to Maintain Ship)ing Cask Manuals in

Accordance with Establisled Procedures to Meet

10 CFR Part 70.113 (Section R8.2).

50-321.366/96-14-07 URI Deteimine if Certificate of Compliance (C0C) and

Associated Vendor Documents for Package

No. USA /5805/B() Were Controlled in Accordance

with Administrative Procedure 20AC-ADM-003-0S.

Vendor Manual Review and Control (Section R8.2).

Enclosure 2

.

.

. ..

40

50-321/96-14

LER Incorrect Circuit Breaker Setting

Results in Emergency Diesel Generator Being

Inoperable (Section EB.1).

50-321/96-14. R1

LER Incorrect Circuit Breaker Setting

Results in Emergency Diesel Gcnerator Being

Inoperable (Section E8.2).

50-321.366/96-08 LER Inadequate Procedure Results in Reactor Pressure

Increate and Automatic Reactor Scram

(Section E8.5).

50-321/96-07

LER Failed Com)onent Results in Inadvertent

Emergency )iesel Generator Start (Section E8.4).

50-321/96-07-03

IFI Degradation and Replacement of Unit 2 Station

Service Battery 2B Due to Buildup of Cell

Sediment (Section E8.3).

50-321/96-06

LER Inadequate Procedure and Lack of Work

Coordination Result in Withdrawal of Inoperable

!

Control Rod (Section M8.2).

50-321.366/95-05-01 IFI Review Post Accident Sampling System (PASS)

Program Enhancements (Section R8.1).

S0-321/96-06-04

VIO Failure to Meet TS Surveillance Requirements

Prior to Withdrawal of a Control Rod While in

Cold Shutdown (Section M8.1).

Enclosure 2

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,

41

LIST OF ACRONYMS USED

l

l

ALARA- As Low as Reasonably Achievable

Annual Limit of Intake

ALI

i

-

ANSI - American National Standards Institute

i

Building and Grounds

l

B&G

-

BOST - Beginning Of Shift Training

CFR - Code of Federal Regulations

AGM-PS- Assistant General Manager, Plant Support

1

CH

- Chemistry

cm

- centimeter

l

C0C - Certificate of Compliance

Control Room

CR

-

degrees Fahrenheit

j

• F

-

Deficiency Card

DC

t

-

DG

- Diesel Generator

disintegrations per minute

dpm

-

ECCS - Emergency Core Cooling Systems

i

EDG - Emergency Diesel Generator

!

Electronic Governor Motor

i

EGM

-

Electro Hydraulic Control

EHC

-

FME - Foreign Material Exclusion

FSAR - Final Safety Analysis Report

Georgia Power Company

GPC

-

HEPA - High-Efficiency Particulate Air Filters

Hatch Nuclear Plant

HNP

-

HP

- Health Physics

HPCI - High Pressure Coolant Irjection

HRS - Hydrogen Recombiner System

Instrument and Control

I&C

-

IFI

-

Inspector Followup Item

IR

-

Inspection Report

IST

Inservice Testing

-

Kilowatt

KW

-

KVAR - Kilovolts Ampere Reactive

LER - Licensee Event Report

LPCI - Low Pressure Coolant Injection

MCC - Motor Control Center

MG

- Motor Generator

MOV - Motor Operated Valve

MWO - Maintenance Work Order

Non-Cited Violation

NCV

-

NRC - Nuclear Regulatory Commission

NRR - Nuclear Reactor Regulation

,

i

NS&C - Nuclear Safety and Compliance

,

ODCM - Offsite Dose Calculation Manual

l

i

PASS - Post Accident Sample System

PDR

Public Document Room

-

Plant Equipment Operator

PE0

-

,

PM

- Preventative Maintenance

.

Enclosure 2

l

,

h-

-

-

. -

- - ..

. - - . -

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

t

"

..

3

42

PSIG -

Pounds Per Square Inch Gauge

PSP - Plant Security Program

PSW - Plant Service Water System

OA

- Quality Assurance

QC

- Quality Control

RCA - Radiologic 61 Controlled Area

RCS - Reactor Coolant System

RCIC - Reactor Core Isolation Cooling

Rev - Revision

RG

- Regulatory Guide

RHR - Residual Heat Removal

RHRSW- Residual Heat Removal Service Water

RPM - Revolutions Per Minute

RPS - Reactor Protection System

RR

- Reactor Recirculation

RTP -

Rated Thermal Power

RW

- Radioactive Waste

RWCU - Reactor Water Clean-up

RWP - Radiation Work Permit

SAM - Sampling

SCBA - Self Contained Breathing Apparatus

SCFM - Standard Cubic Feed Per Minute

SLC - Ltandby Liquid Control

SRM - Source Range Monitor

SRV - Safety Relief Valve

SSB - Station Service Battery

TRAQS- Training Record and Qualification System

TRM - Technical Requirements Manual

TS

- Technical Specifications

Ul.U2- Unit 1. Unit 2

UFSAR- Updated Final Safety Analysis Report

URI

- Unresolved Item

VAC - Volts Alternating Current

VIO - Violation

WBC - Whole Body Counter

WSTSF- Waste Separation and Temporary Storage Facility

,

Enclosure 2