ML20217B698

Insp Rept 50-382/98-06 on 980201-0321.Violations Noted.Major Areas Inspected:Operations,Maint & Engineering

ML20217B698
Person / Time
Site:	Waterford
Issue date:	04/21/1998
From:	Harrell P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20217B670	List: ML20217B667 ML20217B673 ML20217B698
References
50-382-98-06, 50-382-98-6, NUDOCS 9804230113
Download: ML20217B698 (21)

See also: IR 05000382/1998006

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ENCLOSURE 2

U.S. NUCLEAR REGU'ATORY COMMISSION

REGION IV

. Docket No.: 50-382

License No.: NPF-38

Report No.: 50-382/98-06

Licensee: Entergy Operations, Inc.

Facility: Waterford Steam Electric Station, Unit 3

Location: Hwy.18

Killona, Louisiana

Dates: February 1 through March 21,1998

Inspectors: J. M. Keeton, Resident inspector

D. R. Lanyi, Resident inspector, Region 11

Accompanied By: J. C. Edgerly, Resident inspector Trainee

M. A. Kotzalas, NRC Headquarters intern

Approved By: P. H. Harrell, Chief, Project Branch D

ATTACHMENT: Supplemental Information

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9804230113 980421

PDR ADOCK 05000382

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EXECUTIVE SUMMARY

Waterford Steam Electric Station, Unit 3

NRC Inspection Report 50-382/98-06

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This routine, announced inspection included aspects of operations, maintenance, engineering i

and plant support activities. The report covers a 7-week period of resident inspection.  !

Ooerations I

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- The licensed operators performed in a professional manner and demonstrated excellent

knowledge and understanding of the safety consequences of the loss of instrument

power event (Section 01.1).

. In general, control room activities were conducted in a very good manner (Section 01.2).

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Inattentiveness to licensed duties by a senior reactor operator resulted in a noncited

violation of Technical Specification (TS) shift-manning requirements when both the shift

superintendent (SS) and the control room supervisor (CRS) were absent from the control

room for 1 minute 38 seconds (Section O4.1).

Maintenance

+ The performance of the check valve leakage surveillance adequately tested the valves.

The inspectors noted good procedural compliance and good questioning attitudes by all

of the operations personnelinvolved in the test (Section M1.1).

• The inspectors determined that the emergency feedwater turbine-driven pump

surveillance was performed in accordance with approved procedures. The operators

were knowledgeable about the test (Section M1.2).

. Valve CVC-103 did not properly perform all its design functions during an event. A

violation resulted because testing was not performed after completion of maintenance

(Section M1.3).

- Personnel failed to implement broad, effective corrective actions following the spent fuel

pool overflow event. Specifically, a violation was identified because the licensee failed to

review the stop nut adjustment on similar valves since the stop nut adjustment was

considered a contributing factor to the overflow of the spent fuel pool (Section M2.1).

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- Engineers had been responsive to the need for developing a technical failure mechanism

for a plant protective system relay (Section E1.1).

• An engineer inappropriately operated equipment in the plant without the SS or CRS

knowledge or concurrence. This was a repeat of a similar occurrence within the last

2-years, and this issue is being treated as a violation (Section E5.1).

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The engineering review and the revised procedures for control of volatile organic

compounds (VOC) was acceptable. This issue is being treated as a noncited violation

(Section E8.1).

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Reoort Details

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Summary of Plant Status

During this inspection period, the plant operated at essentially 100 percent power.

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1. Operations

01 Conduct of Operations (71707)

01.1 Loss of Static Uninterruotible Power Sucolv (SUPS) B

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a. Insoection Scoce (71707)

The inspectors observed the control room operators during the response to a loss of )

SUPS B, the activities involved in prioritizing recovery of power to the SUPS B

distribution panel, and recovery of plant instruments required for continued plant

operation.

b. Observations and Findinas

On February 4,1998, SUPS B failed and caused a loss of electrical power to

instrumentation required for continued plant operation. The CRS entered

Procedures OP-901-112, " Charging or Letdown Malfunction," and OP-901-312, " Loss of

Vital Instrument Bus." The inspectors observed the CRS directing licensed operators in

accordance with the applicable off-normal procedures. The SS directed the shift

technical advisor to verify which TS were in effect and to track time clocks associated

with the action statements in effect. Additionallicensed operators reported to the control

room to assist the shift crew as necessary.

Investigation of the cause of the trip revealed that the SUPS B inverter had blown fuses.

The power to Distribution Panel PDP3918, which is supplied by SUPS B, was restored

! by energizing the bypass power supply approximately 15 minutes after the SUPS

l tripped. The order of restoration of loads had been priontized using the basic guidance

l in Procedure OP-901-312, and field reports from nuclear plant operators verified that the

loads being restored had not been affected. The inspectors reviewed the off-normal

procedures used during recponse to the transient and noted that the guidelines were

very general in that the procedure required the operators to develop the detailed

restoration plan ad hoc. The operators demonstrated an excellent knowledge and

understanding of the safety consequences of the event.

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All components powered from Distribution Panel PDP3918 had been restored within

approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. All TS action requirements were exited, except for TS 3.8.3.1,

which required the SUPS bus to be energized from the inverter within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. All TS

action statements had been satisfied within the required time limits. The SUPS B

inverter was repaired and returned to service within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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The inspectors discussed the off-normal procedure weaknesses with the Operations

Manager and Operations Superintendent. They agreed to review the procedures and the

actual activities required for event mitigation for potential procedure enhancement.

c. Conclusions

The licensed operators performed in a professional manner and demonstrated excellent

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power event.

O1.2 . Control Room Observations

a. Insoection Scooe (71707)

in addition to routine daily control room observations, on March 11 and 12,1998, the J

Inspectors observed control room activities including accet.s control, operator conduct,

general operator knowledge, and shift tumover,

b. . Observations and Findinas

The inspectors reviewed Administrative Procedures OP-100-001, Revision 14, " Duties

and Responsibilities of Operators on Duty," and OP-100-007, Revision 13, " Shift

Tumover," to determine the requirements for the conduct of control room activities. The

inspectors determined that the observed operations crews were generally meeting these

requirements.

The inspectors noted that control room access controls were good. The layout of the

control room naturally funneled personnel into the SS office or to the entrance of the ,

control room proper. This arrangement minimized personnel congregating in the rear of 1

the control room. Also, extraneous conversations were maintained in the enclosed office

space behind the control room, which minimized distractions to the operators. The i

inspectors also noted that the CRS only allowed entrance to personnel requiring control I

room access for a work- and business-related activity. )

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The inspectors observed several hours of licensed operator activity and noted the l

following:

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. The operation staff's conduct was professional.

. The operators were generally attentive to plant status and indicators.

. Excellent communications were observed among the crew whenever one of the

- crew members left the control room area. Not only did the operators inform their

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partner and the CRS, but they also informed the SS. The inspectors did observe

the SS and the CRS brief each other on plant changes whenever one of them

retumed to the control room.

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Control room command function was clearly delineated, including any changes in

emergency response responsibilities.

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Alarm and annunciator response by the operators was very good. Without fail,

l the annunciators were acknowledged in an appropriate amount of time. The

! alarm was announced to the CRS and/or SS, and shift supervision acknowledged

the alarm and ensured appropriate actions were taken.

. . During shift tumovers, operators followed the requirements in

Procedure OP-100-007. The shift meeting was especially useful in providing the .

appropriate information to all key members of the shift. The CRS was able to

, coordinate conflicting maintenance and surveillance activities that had been

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c. Conclusions 1

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in general, control room activities were conducted in a very good manner.

03 Operations Procedures and Documentation

O3.1 Station Loo Procedures Observations (71707)

The inspectors observed that with the computer logging process, the station log can be

modified anytime within the 12-hour shift. The editing can be accomplished without

appropriately identifying whether a modification was editorial or whether it should have

been identified as a corrected entry or late entry. The logging procedure in Operating )

Instruction 01-004-000, Revision 25, " Operations Narrative and Shift Logs," implied that I

the log was not final until printed at the end of the shift, and that only changes made after

that time would be subject to identifying as a late or corrected entry.

The inspectors have implemented an ongoing review of this issue. An inspection

followup item has been opened to continue review of this issue (50-382/9806-01).

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04 Operator Knowledge and Performance

04.1 Loss of Control Room Command Function

a. Insoection Scoce (71707)

The inspectors reviewed the documentation of circumstances, reviewed the statements

of the supervisors, and interviewed operations personnel regarding a loss of control room

command function.

b. Ohtervations and Findinos

On February 15,1998, with the reactor stable at 100 percent power, the CRS had

notified the SS that he was leaving the control room to get lunch. The SS had

acknowledged the CRS. The SS had been engrossed in an electrical problem, which he

was discussing with an electrician. He accompanied the electrician out of the control

room to the relay room without notifying the remaining control room operators. One of

the licensed operators noticed that neither the CRS nor the SS was in the control room

and went to the lunch room to tell the CRS that the SS had also left the control room.

The CRS reentered the control room and paged the SS to tell him that they had violated

the TS control room manning requirements, as both the SS and the CRS had been

absent from the control room for 1 minute 38 seconds.

Condition Report 98-0222 had been issued immediately following the incident. Also,

personnel statements had been written by the CRS and SS. Review of these documents

revealed no further pertinent information.

A root cause determination was performed by the licensee and it found that the incident

was an isolated human error. The inspectors agreed with this evaluation based on a

review of the documentation and interviews with the individuals who were involved.

Immediate corrective actions included counseling of the SS, issuance of a daily

instruction reminding the control room staff of the procedural and TS requirements, and

discussion of the incident at the next SS/CRS meeting. The long-term corrective actions

identified involved enhanced training during scheduled requalification and additional

management observations. Completion of the long-term actions will be verified during

review of Licensee Event Report (LER) 50-382/98-002.

TS 6.2.2.b states, in part, that at least one licensed operator shall be in the control room

when fuelis in the reactor. In addition, while the reactor is in MODE 1,2,3, or 4, at least

one licensed Senior Operator shall be in the control room.

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TS Table 6.2-1 contains a note that states, in part, that during any absence of the shift

supervisor from the control room while the unit is in MODE 1,2, 3, or 4, an individual,

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other than the shift technical advisor, with a valid senior operator license shall be

j designated to assume the control room command function. )

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Operating Procedure OP-100-001, " Duties and Responsibilities of Operators on Duty," l

l Step 5.4.1.4, states, in part, that before leaving the control room for tours,

troubleshooting, or other reasons; operators, shift superintendents, or control room

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supervisors should inform the remaining control room operating staff of their intended

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activities and the approximate duration of these activities. Additionally, they shall verify {

that the control room command function remains appropnately delineated. l

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Failure to adhere to these TS and procedural requirements demonstrates inattentiveness

to licensed duties by a senior licensed operator. However, this licensee-identified and

corrected violation is being treated as a noncited violation consistent with Section Vll.B.1

of the NRC Enforcement Policy. Specifically, the violation was identified by the licensee,

it was not willful, actions taken as a result of a previous violation should not have

corrected this problem, and appropriate corrective actions were completed by the

licensee (50-382/9806-02).

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l c. Conclusions

Inattentiveness to licensed duties by a senior reactor operator resulted in a noncited

violation of TS control room staffing requirements when both the SS and the CRS were

l absent from the control room for 1 minute 38 seconds.

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08 Mhscellaneous Operations issues (92901)

l 08.1 (Closed) Violation S0-382/9704-01: Failure to comply with working-hour limitations for

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Between February 1 and March 1,1997, the licensee failed to implement the

j requirements of TS 6.2.2.e and Procedure UNT-005-005, " Working Hour Policy for

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Nuclear Safety-Related Work." Working-hour policy guidelines had been exceeded in

several instances without proper approval.

The inspectors reviewed the corrective actions described in the LER and verified

that: (1) the operations, maintenance, radiation protection, and site support department

personnel had been briefed on the root cause of the event and resultant corrective

actions; (2) Revision 5 to Procedure UNT-005-005 had been implemented to clarify the

working-hour policy; (3) the quality assurance department incorporated evaluation of

organizational compliance with the working-hour policy into its audit program; and (4) the

quality assurance department audited the operations and health physics departments

and found these departments to be in compliance with the working-hour policy

guidelines.

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The inspectors concluded, based on verification of these actions, that the licensee j

appropriately addressed this violation.

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08.2 (Closed) LER 50-382/96-01* Control Room Ventilation Valve Leakage. X

l It was identified that the control room normal ventilation isolation valves were leaking

during operation of the emergency filtration system. Assuming a single failure, this

leakage could have resulted in a single individual exceeding the 30 Rem thyroid j

exposure limit in 10 CFR Part 50, Appendix A, Criterion 19 and Standard Review 4

Plan 6.4, Section 11.6. The cause of the leakage was determined to be debris that had

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accumulated inside the valve disc region and prevented the valves from fully closing.

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The inspectors reviewed the root cause analysis and corrective actions and determined i

them to be appropriate. Long term corrective actions included: (1) establishing an

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18-month frequency for leak rate checkirig the isolation dampers, (2) developing a j

procedure with an administrative limit of 8 scfm to leak rate test the isolation valves, and

(3) reviewing the testing configuration for the control room pressure test to ensure

compliance with all licensing documents.

i The implementation of these corrective actions are discussed in NRC Inspection

l Report 50-382/96-21 and found to be fully satisfactory.

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08.3 (Closed) LER 50-382/97-012; Programmatic Breakdown of Overtime Program.

! The corrective actions for this LER are the same as the corrective actions for NRC

Violation 50-382/9704-01, discussed in Section 08.1 of this report. ,

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l 08.4 (Closed) LER 50-382/97-018: Dropped New Fuel Assembly.

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During Refueling Outage 8, a new fuel assembly became disengaged from the spent fuel

handling tool and dropped approximately 5 inches. The assembly came to rest at a 40  ;

i angle against the side of the spent fuel pool. No other fuel assemblies were damaged  ;

and no spent fuel pool liner leakage was detected. The root cause of the event was j

determined by the licensee to be human error. j

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l The inspectors reviewed the root cause analysis and considered it to be thorough and

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representative of a good self-assessment. Corrective actions included a revision to the '

l refueling procedure, training, and removal of several environmental distractions. These

l are described in NRC Inspection Report 50-382/97-08.

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Based on the review completed by the inspectors, it was determined that the licensee

had taken the appropriate actions to address this issue. i

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11. Maintenance

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! M1 Conduct of Maintenance (61726,62707)

l The inspectors observed all or portions of the following surveillances:

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OP-903-119 Secondary Auxiliaries Quarterly Valve Tests

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OP-903-046 Emergency Feed Pump Operability Check

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OP-903-068 Emergency Diesel Generator and Subgroup Relay Train B

Operability Test

Additionally, the inspectors observed portions of Work Authorization 01167398, which

was issued to troubleshoot Control Element Assembly 14 to determine why it slipped

l approximately 5 inches while moving it.

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l The inspectors found the conduct of these maintenance and surveillance activities to be

l good. All activities observed were performed with an appropriate authorization package

j or test procedure. The inspectors observed supervisors monitoring job progress.

M1.1 Quarterly Surveillance of Comoonent Coolino Water (CCW) Makeuo System Check l

j Valves

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a. Insoection Scoce (61726) l

l The inspectors observed portions of Surveillance Procedure OP-903-119, Revision 4,

" Secondary Auxiliaries Quarterly IST Valve Tests." The operators performed the

applicable sections to leak test various CCW makeup water check valves.

j b. Observations and Findinas

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On March 12,1998, the operators performed a quarterly leak check on two CCW

makeup system check valves. The procedure required securing CCW Makeup Pump B

for a portion of the test. Not only did the operators declare CCW Makeup System B out

of service, but also those loads sen/ed by the system. Therefore, the cascading TS

action statements for securing CCW System B, Emergency Diesel Generator B, and

Essential Chiller B were entered.

The briefing for the evolution was thorough, covered the details of the test, expected

responses, and personnel responsibilities. All appropriate personnel were present and

actively involved in the briefing. The CRS made it clear to the crew that this was not an

evolution to be rushed. When the operators arrived on station to perform the

surveillance, they found the spent resin transfer cask being moved from the minus

35-foot level. The operators and the CRS made the conservative decision to wait for the

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cask to be lifted from the area prior to beginning work. Their concern was leaving the i

CCW makeup system in a degraded state if there were problems with lifting the cask. l

The inspectors observed the operators perform the surveillance. The operators properly

followed the procedure, recorded all required information, and appeared knowledgeable j

in their tasks. They exhibited good three-part communications between each other and )

the control room. Peer checking was also properly used to ensure that the right i

component was being operated and they used appropriate cleanliness controls.

The inspectors noted that while the CRS was reviewing the procedure and drawings in

preparation for the brief, he noted that a simple addition of a drain line installed on the

nonsafety-related portion of the piping would, in the future, prevent the necessity of

securing Makeup Pump B and cause entrance into cascading TS. The CRS contacted

the system engineer who would look into the matter further.

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The performance of the check valve leakage surveillance adequately tested the valves. I

Very good procedural compliance and questioning attitudes by all of the operations l

personnel involved in the test was noted.

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M 1.2 Emeraency Feedwater (EFW) Pumo AB Surveillance Observation '

a. Insoection Scoce (61726)

On March 12,1998, the inspectors observed the EFW Pump AB surveillance. The

surveillance was performed using Surveillance Procedure OP-903-046, Revision 14,

" Emergency Feed Pump Operability Check."

b. Observations and Findinos

The operators performed a routine run and overspeed trip check of EFW Pump AB. The

inspectors were present for the pretest briefing and for the majority of the test. The

briefing was performed by a licensed operator and contained the appropriate precautions

and limitations. However, the operator stated that the crew was familiar with the

procedure and he would not review it step by step. One of the nonficensed operators

asked several pertinent questions about the procedure. These questions, in combination

with the rest of the information presented, made the briefing information complete.

I The inspectors observed a licensed operator starting the EFW pump from the control

! room. The operator exhibited good control of the evolution. The inspectors noted that

the procedure was in constant use in the control room. The operators used good

three-part communication among each other and with the operators in the field.

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The inspectors observed the pump operate from the minus 35-foot level of the reactor

auxiliary building. Besides the operators and system engineer, there were several

mechanics in the area with measuring equipment. One of the operators was surprised

by the number of mechanics assigned to the job since they had not been present for the

briefing in the control room. The inspectors spoke to the system engineer about the

mechanics. The system engineer stated that he had been working on gathering pump

data for some time. The inspectors noted that the mechanics worked well together in

gathering the required data.

The inspectors observed the overspeed trip test of the pump. The operators then

restored the pump to service. No problems were noted with this portion of the test.  ;

Procedure adherence by the operators was good. The inspectors asked several l

questions about the pump operation. The inspectors found the nonlicensed operators l

knowledge level good.

c. Conclusions

The surveillance test of the EFW turbine-driven pump was very good. The operators

were knowledgeable about the test.

M1.3 Postmaintenance Testina of Valve CVC-103

a. Observations and Findinas

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In September 1997, SUPS SB failed as a result of an internal fault. Failure of SUPS SB

resulted in a loss of power to a number of components, one of which was

Valve CVC-103. All other components responded as designed without any problems.

Valve CVC-103 is installed in the letdown line and serves as a containment isolation

valve for the line. As such, it is required to close to prevent flow from the reactor coolant

system to the auxiliary building in the event of a line break outside containment.

When power from SUPS SB was lost, Valve CVC-103 closed, but the valve did not fully

shut, which allowed flow through the valve of approximately 25 gpm. Another valve in

the letdown line was shut to stop the flow.

Licensee personnel made a containment entry to inspect the valve to verify there was no

physical damage to the valve. After verifying no damage occurred, the licensee

inspected the valve stem travel stop nut and noted that it appeared to be misadjusted.

The stop nut was adjusted and a subsequent leak test performed. The test results

indicated no further leakage through the valve.

During review of this issue by the inspectors, it was noted that maintenance had been

performed on Valve CVC-103, and no postmaintenance test had been performed to

verify that the valve could perform its intended function of isolating letdown flow.

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The failure to provide instructions to specify postmaintenance testing of Valve CVC-103

is a violation of TS 6.8.1 (50-382/9806-03).

b. Conclusions

Valve CVC-103 did not properly perform all of its design functions because testing was

not performed after completion of maintenance.

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Soent Fuel Pool (SFP) Overflow Corrective Action Followuo

a. Insoection Scooe (62702)

The inspectors assessed the adequacy of the licensee's corrective actions pursuant to a

SFP overflow event that occurred in May 1997. '

b. Observations and Findinas

On May 21,1997, approximately 5000 gallons of radioactive water had overflowed from

the SFP into the fuel handling building (FHB). The licensee had estimated that

approximately 2500 gallons was contained in the FHB railroad bay and that between 230

and 1850 gallons had escaped outside the FHB through the railroad bay doors, where it

had contaminated a large area of asphalt and gravel within the protected area and the

storm drain system. The remainder of the spilled fluid was captured in the reactor

auxiliary building sump and waste systems. Condition Report (CR) 97-1284 had been

initiated and an event review team was convened on May 21 to investigate the event.

The event review team had concluded that the spill had been the result of a combination

of tagging and communication errors, which had resulted in dead-heading of a

purification pump, combined with a leaking SFP purification isolation valve. The

investigation revealed that the travel stop nuts on SFP isolation Valve FS-345 (a

manually-operated diaphragm valve) had been incorrectly positioned %-inch lower than

required by the valve technical manual. The mispositioning occurred during a

maintenance activity in May 1992, when reach rods were installed per Design

Change (DC) 3211. DC 3211 had required the travel stop nuts to be removed; however,

neither DC 3211 nor the associated work authorization had contained specific

instructions as to the required position for the travel stop nuts upon replacement. This

resulted in the valve not fully blocking flow when it indicated shut. The licensee had

taken soil and liquid samples to determine if any reportable releases to the environment

had occurred and concluded that 10 CFR Part 20 limits had not been exceeded.

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! The event review team had determined that isolation Valve FS-345 and four other

diaphragm valves had extension stems installed per DC 3211, as required. These

valves were checked and the travel stop nuts were adjusted. The licensee had not

inspected any other diaphragm valves.

On February 2,1998, the inspectors performed an inspection of travel stop nuts on other

diaphragm valves in the FHB and noted the following deficiencies: )

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l Valve Condition

FS-1058 - Fuel Pool Pump B Discharge Drain No travel stop lock nut

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l FS-210 - Refueling Canal Drain Pump Discharge Loose travel stop lock nut

FS-212 - Refueling Canal Drain Pump Discharge Drain No travel stop lock nut

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FS-214 - Refueling Canal Drain Pump Discharge No travel stop lock nut

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isolation to Fuel Pool

The inspectors notified the licensee of the above conditions. The licensee initiated i

l CR 98-0146 to address the identified deficiencies. At the end of this inspection period, {

the licensee was in the process of inspecting approximately 800 other diaphragm valves l

installed in the plant.

l When the event team identified that the stop nut on Valve FS-345 was incorrectly

installed, the team incorrectly limited the population of other potentially affected valves to

l those modified per DC 3211. No effort was made by the licensee to inspect other similar ]

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valves to determine the full scope of the stop nut misadjustment problem. As a result, full l

and effective evaluation did not occur for the hardware deficiencies on the relatively large

population of valves.

The failure to promptly identify and correct the travel stop nut deficiencies, after having i

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attributed the misadjustment as a contributing factor to a SFP overflow event, is a

violation of Criterion XVI (50-382/9806-04).

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The scope of the corrective actions identified after the SFP overflow event was j

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i inadequate because other similiar diaphragm valves were not deficiencies. This is a l

violation of Criterion XVI.

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111. Engl.neerina

E1 Conduct of Engineering (37551)

E1.1 Enaineerina Evaluation of Delaved Reactor Trio Breaker (RTB) Ooenina

a. Insoection Scoce (37551)

The inspectors reviewed enginecring activities associated with evaluating the delayed

opening of RTB 2.

b. Observations and Findinas

On February 8,1998, while performing Procedure OP-903-107, " Plant Protection System

Functional Test," RTB 2 opened 15 seconds after the trip signal was initiated. RTB 6,

which is designed to open concurrently, did respond and open immediately. RTB 2 was

declared inoperable and both breakers were left in the tripped position to comply with

TS 3.3.1-13, Action 5. CR 98-0182 was written to address the issue. Electrical

maintenance technicians determined that the K2 relay had failed. The relay was

replaced, the breakers retested satisfactorily, and the RTBs were declared operable.

The K2 relay was a Potter & Brumfield MDR Model 170-1 with Date Code 9416. A

generic issue related to these relays was reported in NRC Inspection

Report 50-382/98-02, Section M2.1. Inspection Followup Item 50-382/9802-01 was

opened to track the status of the action plan to identify, evaluate, and replace MDRs prior

to failure. The inspectors determined that this relay had failed before the program had

been effectively implemented.

The K2 MDR relay was sent to Combustion Engineering in Windsor, Connecticut, for

failure analysis. The failure was determined to most likely be caused by a slight

misalignment of the shaft and top end bell. This condition caused excessive wear, a

buildup of wear materials, and binding of the shaft, which prevented full rotation. Glass

fiber contamination was also discove ed (in the grease) and may have been a

contributor.

A review of the relay history for the plant protective system indicated that the K2 relay

had been replaced in April 1997. On that occurrence, RTB 6 had been slow to open.

Failure analysis had indicated that hardened grease, mechanical binding, and grease

contamination had contributed to that failure. CR 97-0787 had been initiated.

The inspectors questioned the engineer to determine if they had checked the other three

relays in the plant protection system to identify the date codes. The response wat, that

they had not checked those relays. After checking the other relays, the date codes found

were: K1 - 9404; K3 - 9345; and K4 - 9416. Relay K2 had been replaced with Date

Code 9730. The inspectors asked if these relays were going to be replaced because

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their date codes were part of those of originalindustry concem. The reply was that they

would not be replaced unless they failed. The justification was that each relay was

tested quarterly.

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The inspectors found that the engineers had been responsive to the need for providing

root cause determination. Tne technical approach and understanding of the mechanical

problems were good.

c. Conclusions .

Engineers had been responsive to the need for developing a technical failure mechanism

for plant protective system relays.

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l E5 Engineering Staff Training and Qualification

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E5.1 Ooeration of EFW Pumo AB without Control Room Concurrence

a. Insoection Scooe (37551)

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The inspectors reviewed the licensee's findings and corrective actions related to this l

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b. Observations and Findinas l

On March 5,1998, an engineer determined that he had been operating equipment in the

plant without the SS or CRS knowledge or concurrence. He had been partially stroking j

EFW Turbine Governor Valve MS-417 by moving the stem approximately % inch for the  !

purpose of detecting stem binding. The engineer wrote CR 98-0333 to address the i

issue, which involved operation of equipment in the plant without the consent of the l

control room staff. l

This activity constituted a violation of Procedure OP-100-001," Duties and

Responsibilities of Operators on Duty," Section 5.8.1.3, which stated, in part, that

l operational activities performed locally in the plant to support overall plant operating

activities must take place under the direction of or with the concurrence of the SS/CRS.

This was a repeat of Violation 50-382/9605-02. The !!censee had taken immediate steps

to stress proper conduct of any operations with plant personnel. Long-term corrective

actions had not been finalized (50-382/9806-05).

c. Conclusions  ;

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An engineer inappropriate!y operrated equipment in the plant without the SS or CRS l

knowledge or concurrence.

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E8 Miscellaneous Engineering issues (92903)

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E8.1 (Closed) Unresolved item 50-382/9704-04: Failure to have a procedure addressing

VOCs in areas serviced by engineered safety features (ESF) filtration units.

NRC Inspection Report 50-382/97-04 identified two issues that remained unresolved

pending additionalinput from the licensee and a response from the Office of Nuclear

Reactor Regulation (NRR). The first issue identified a failure to have a procedure that

specifically limited the amount of VOCs in an area that could adversely affect

safety-related ventilation charcoal adsorbers. The second issue involved use of a

waiting period in lieu of performing testing following painting in an area served by

charcoal filters. This issue was referred to NRR for resolution.

The inspectors performed a detailed review of the procedure that had been revised in

response to the first issue. Procedure PMC-002-007, " Installation Procedure

Maintenance and Construction Painting," limits the amount of VOCs in the areas that

would affect ventilation charcoal filters. A detailed engineering review was performed to

evaluate the amount of VOCs it would require in a given area to inhibit adsorption in the

charcoal filter to the extent that it could not perform its safety function. Engineering

Request Response ER-W3-97-0040, "VOC Limits for Insulation Cement and Painting in

ESF Areas," dated April 11,1997, provided conservative calculations showing the

maximum VOC loadings in critical areas. The procedure further reduces the amount of

VOC allowed in any critical area to less than that shown in the engineering evaluation.

The response from NRR was in a letter to Mr. Jerrold D. Dewease from

Jack N. Donohew, SUBJECT: "lNTERPRETATION OF FILTRATION UNIT

FREQUENCY-OF-TESTING REQUIREMENTS SPECIFIED IN THE TECHNICAL

SPECIFICATIONS AND REGULATORY GUIDE 1.52 FOR ARKANSAS NUCLEAR

ONE, UNITS 1 AND 2, GRAND GULF NUCLEAR STATION, UNIT 1, RIVER BEND

STATION, AND WATERFORD 3 STEAM ELECTRIC STATION (TAC NOS. M98367,

M98368, M98369, M98370, AND M98371)," dated September 11,1997. The oveiall

conclusion of the issued response was that the licensee had the responsibility to define

the criteria based on a well-documented, sound, and conservative technical basis. The

letter stated that the staff considered that a painting, fire, or chemical release was not

communicating with a ventilation system only if the ventilation system is not in operation

and the isolation dampers for the system are closed and leaktight thereby preventing air

from passing through the filters.

The inspectors determined that the engineering review and the procedure appropriately

addressed this unresolved issue and the licensee was in full compliance with NRC

regulations. This licensee-identified and corrected violation is being treated as a

i noncited violation consistent with Section Vll.B.1 of the NRC Enforcement Policy.

Specifically, the violation was identified by the licensee, it was not willful, actions taken as

a result of a previous violation should not have corrected this problem, and appropriate

corrective actions were completed by the licensee (50-382/9806-06).

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E8.2 (Closed) LERs 50-382/97-007-00 and 50-382/97-007-01: Refueling Water Storage I

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Pool (RWSP) Level Indication inaccuracies and Discovery of Additional Refueling Water

Storage Pool Instrument Uncertainty

The licensee discovered that the analytical limit for tha RWSP level instrument was

exceeded due to an inadequate design of the level transmitter reference leg. The low

side of each RWSP level transmitter was vented to an area filtered by the controlled

l ventilation area system, whereas the high side was connected to the RWSP. Operation

of the controlled ventilation area system caused indicated RWSP level to differ from

actuallevelin the nonconservative direction. This would have resulted in a recirculation

actuation signal being generated below the TS allowed value. ,

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The inspectors determined that adequate corrective actions were implemented, dunng l

Refueting Outage 8, in that a design change was initiated to reroute the reference legs

for the RWSP level instruments back to the RWSP. This change eliminated any i

ventilation system interactions. The corrective actions are discussed in NRC Inspection

l Reports 50-382/97-12 and 50-382/97-27.

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! Based on reviews performed by the inspectors, it was concluded that the licensee had

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taken the appropriate actions to address this issue.

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F8 Miscellaneous Fire Protection issues (92904)

F8.1 (Closed) Insoection Followuo item 50-382/9708-08

Reactor coolant pump (RCP) oil fill

i administrative controls.

There was no separate oil collection system under the remote fill lines for the RCP lube

oil system. This condition did not meet 10 CFR Part 50, Appendix R, requirements. The

licensee recognized that their system did not meet Appendix R requirements and

submitted an exemption request (Letter W3F1-97-0021, February 10,1997). The letter

addressed administrative controls that would be implemented if the licensee had to use

the RCP remote lube oil fill lines. The inspectors concluded that the controls were

generally adequate, except for monitoring levelin the reservoirs. The licensee did not

have a formal reservoir volume versus indicated level curve for either the upper or lower

RCP oil reservoir. The licensee informed the inspectors that they would generate formal

curves for both the upper and lower reservoir.

t The inspectors verified that volume versus level curves for both the upper and lower

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RCP oil reservoirs were incorporated into Volume 1 of the RCP vendor technical manual.

The actions taken by the licensee to address this issue were acceptable. ,

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V. Manaaement Meetinas

l X1 Exh Meeting Summary

The inspectors presented the inspection results to members of licensee management on

March 20,1998. The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during the inspection 1

l should be considered proprietary. No proprietary information was identified.

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ATTACHMENT

SUPPLEMENTAL INFORMATION

PARTIAL LIST OF PERSONS CONTACTED

Licensee

F. J. Drummond, Director Site Support

C. M. Dugger, Vice-President, Operations

E. C. Ewing, Director, Nuclear Safety & Regulatory Affairs

C. Fugate, Operations Superintendent

T. J. Gaudet, Manager, Licensing

J. G. Hoffpauir, Manager, Operations

T. R. Leonard, General Manager, Plant Operations

G. D. Pierce, Director of Quality

D. W. Vinci, Superintendent, System Engineering

A. J. Wrape, Director, Design Engineering

INSPECTION PROCEDURES USED

IP 37551 Engineering

IP 61726 Surveillance Observation

IP 62702 Maintenance Program

IP 71707 Plant Operations

IP 92901 Followup - Operations

IP 92903 Followup - Engineering

IP 92904 Followup - Plant Support

ITEMS OPENED. CLOSED. AND DISCUSSED

Ooened

50-382/9806-01 IFl Station logkeeping procedures (Section O3.1) ,

50-382/9806-02 NCV Loss of control room command function (Section 04.1)

50-382/9806-03 VIO Postmaintenance Testing of Valve CVC-103 (Section M1.3)

50-382/9806-04 VIO Corrective Actions for Diaphragm Valves (Section M2.1)

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50-382/9806-05 VIO Operation of EFW Pump AB without control room concurrence

(Section E5.1) J1

50-382/9806-06 NCV Failure to have procedure addressing VOCs in areas serviced by i

ESF filtration units (Section E8.1)

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50-382/9806-02- NCV Loss of control room command function (Section 04.1)

50-382/9704-01 VIO Failure to comply with working-hour limitations for operations

personnel (Section 08.1).

50-382/96-011 LER Control Room Ventilation Valve Leakage (Section 08.2)

50-382/97-012 LER Programmatic Breakdown of Overtime Program (Section 08.3).

50-382/97-018 LER Dropped New Fuel Assembly (Section 08.4)

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50-382/9704-04 URI Failure to have a procedure addressing VOCs in areas serviced by

ESF filtration units (Section E8.1).

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50-382/9806-06 NCV Failure to have a procedure addressing VOCs in areas serviced by

ESF filtration units (Section E8.1).

50-382/9708-08 IFl RCP oil fill administrative controls (Section F8.1).

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50-382/97-007-00 LER RWSP Level Indication inaccuracy (Section E8.2)

50-382/97-007-01 LER RWSP Level Indication inaccuracy (Section E8.2)

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Discussed

None

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LIST OF ACRONYMS USED

CCW component cooling water

CR condition report

CFR Code of Federal Regulations

CRS control room supervisor

DC design change

EFW emergency feedwater

ESF engineered safety features

FHB fuel handling building

gpm gallons per minute

LER licensee event report

NRC Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

MDR motor-driven relay

RCP reactor coolant pump

RTB reactor trip breaker

RWSP refueling water storage pool

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SFP spent fuel pool

SS shift superintendent

SUPS station uninterruptible power supply

TS Technical Specifications

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VOC volatile organic compound

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