ML20135F987

Insp Rept 50-298/97-02 on 970112-0222.Violation Noted.Major Areas Inspected:Licensee Operations,Maint,Engineering & Plant Support

ML20135F987
Person / Time
Site:	Cooper
Issue date:	03/31/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20135F984	List: ML20135F981 ML20135F985 ML20135F987
References
50-298-97-02, 50-298-97-2, NUDOCS 9704040067
Download: ML20135F987 (19)

See also: IR 05000298/1997002

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ENCLOSURE 2

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.: 50-298

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License No.: DPR-46

Report No.: 50-298/97-02

Licensee: Nebraska Public Power District

Facility: Cooper Nuclear Station

Location: P.O. Box 98

Brownville, Nebraska

Dates: January 12 through February 22,1997

Inspectors: Mary Miller, Senior Resident inspector

Chris Skinner, Resident inspector

Approved By: Larry Yandell, Acting Chief, Project Branch C

Division of Reactor Projects

Attachments: Supplemental Information

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9704040067 970331

i PDR ADOCK 05000298

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EXECUTIVE SUMMARY

Cooper Nuclear Station

NRC inspection Report 50-298/97-02

Operations

• Control room crews evidenced comprehensive turnovers and strong ownership of

plant safety.

• Inspectors identified that the licensee had failed to enter the action statement for

the inoperable limit switch for residual heat removal train crosstie Valve RHR-MO-

20, for over a year. Inspectors also identified that the licensee had failed to

document the basis for tagging Valve RHR-MO-20 in the closed position, had f ailed

to declare the limit switch inoperable, and did not perform Technical Specification

monthly surveillance tests for the valve or the associated limit switch for the entire I

cycle. The inspectors determined that the licensee staff held a consistent rationale

for not performing the monthly surveillance tests, which considered cycling the

valve undesirable because it cross-tied both residual heat removal trains.

• A weakness was identified in that the licensee's interim corrective actions I

associated with a f ailure to implement Technical Specification requirements were

not clearly understood. A second failure, one month later, almost occurred.

• Inspectors and a licensee supervisor concurrently identified a weakness in that the

licensee did not convene the Safety Operations Review Committee to review the

safety impact of resetting alllow power range monitors prior to the work being

performed under an emergency work order.

Maintenance

• Inspectors identified a violation that included three examples of a failure to properly

implement a calibration procedure. The examples included: (1) the f ailure to

provide appropriate instructions to determine the as-found condition of a relay,

which caused technicians to perform actions outside the proceduro, (2) the f ailure

to perform an action step included in a note until prompted by the inspectors, and

(3) the f ailure to provide correct information regarding the test status of a relay.

The inspectors noted that the procedure had been performed at least three times

and technicians had failed to recognize that the procedure was inadequate.

• Inspectors identified a violation in that licensee personnel did not initiate a PIR to

address three examples of a failure to properly implement a calibration procedure.

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• Inspectors identified that the maintenance program did not provide clear guidance

on the use of the PIR process to document discrepancies.

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Ennineerina

• Engineers were proactive in identifying a potential issue with taper pins on the

diesel generators.

• In a reevaluation of the standby gas treatment system, and the associated

evaluation of the stack effect discussed in Information Notice 88-76, the licensee I

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identified that the reverse of the stack effect was applicable at Cooper Nuclear

Station and evaluated this condition. Inspectors noted that the information notice

did not address this reverse of the stack affect.

• Inspectors identified that, in an operability evaluation and PIR associated with

moisture accumulation in an outocor tank communicating with secondary

containment atmosphere, the licensee did not address the generic applicability of

the f ailure mechanism. In particular, the licensee did not address the effects of

warm, moist air, by contact with cold piping, resulting in an unexpected

accumulation of moisture in vital equipment.

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Report Details

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Summary of Plant Status

The plant was maintained at 100 percent power for the reporting period, except for routine  ;

main turbine governor valve testing, when power was reduced to approximately j

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l. Operations

01 Conduct of Operations

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01.1 General Comments

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a. Insoection Scope (71707)

j Inspectors observed routine control room turnovers and crew activities during the

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b. Observations and Findinas

inspectors' observations of more than 30 control room crew turnovers found that

j the turnovers provided information to oncoming crew members which addressed all  !

j relevant concerns noted by the prior shift. Shift crew briefings clearly )

i communicated expectations for operations ownership of day-to-day plant safety and )

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demonstrated thorough familiarity with plant conditions and operational evolutions l

< and testing.

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inspectors noted that operators requested resolution from engineering concerning

repeated failures of a secondary containment ventilation valve solenoid. Previous

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failures had been noted on problem identification reports (PIRs), but engineering's

resolution consisted only of solenoid replacement. Operations refused to accept

further replacements of the solenoid without additional engineering evaluation to

correct the problem. Subsequently, the licensee promptly evaluated the issue and

i initiated discussions with the vendor. The licensee has not yet identified the root

l cause for this problem, but is frequently (e.g., monthly) replacing this solenoid to

' assure operability of the valve.

, c. Conclusions

Operations turnovers, familiarity with plant conditions, and ownership of plant ,

safety was strong. Operations evidenced strong ownership of the plant by requiring I

appropriate resolution of a repeated equipment failure.

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O2 Operational Status of Facilities and Equipment

O 2.1 Diesel Generator iniector Pumo Leak

a. Inspection Scope (71707)

The inspector reviewed the licensee's actions to addre:s a leak on Fuel injector 4L

on Diesel Generator 2.

b. Observations and Findinqs

On February 10,1997, during a routine monthly surveillance test on Diesel

Generator 2, the licensee identified a fuel leak on Cylinder 4L. A similar railure was

noted on Cylinder 7R approximately 6 months earlier. Both times, the licensee

attributed the problem to cracks in the fuel lines which were replaced.

Subsequently, the licensee determined the root cause of the leak to be a crack in

the injector pump. Injector pump cracks on this diesel generator design have

occurred previously and were described in vendor information letters. The licensee

replaced the pump ar'd tested the diesel generator satisfactorily. The licensee also

ran Diesel Generator 1 to verify its operability, because they were unable to

determine if a common mode f ailure existed.

Because of this f ailure and a similar prior failure during the cycle, the inspectors

questioned if assumptions regarding probability of diesel generator failure were

nonconservative. The licensee concluded that the current probabilistic risk of diesel

generator failure assumptions bounded the frequency of observed failures. The

inspectors agreed with that conclusion.

c. Conclusions

The inspectors concluded the diesel generator was run an additional two times due

to an incorrect determination of the root cause of the fuel leak. Inspectors noted

that the licensee had not addressed whether increased failures were still bounded

by probabilistic risk assumptions, until questioned by the inspector.

07 Quality Assurance in Operations

07.1 Inadeauate Interim Corrective Actions

a. Insoection Scope (717071

The inspectors reviewed actions by the licensee to correct an earlier problem

associated with entry into a Technica! Specification (TS) action statement.

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i b. Observations and Findinas

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i On January 28,1997, an oncoming licensee shift supervisor identified that a TS

] action statement had not been implemented in that an inoperable secondary

I containment ventilation valve was open when TS 1.0.v.3 required that the valve be

l closed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of being declared inoperable. The shift supervisor directed

i that the valve be closed and noted that the action was completed within the 4-hour i

j action statement.

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Although the direct safety significance of this occurrence was minimal, the f act that

this was a fortuitous catch by the oncoming shift supervisor caused the NRC to

question whether the interim corrective actions from a similar event on

December 24,1996, were effective. The licensee had identified this problem and

documented it in PIR 96-1119. The permanent corrective action proposed for this

PIR was a change to procedures, but the change had not _been implemented by

January 28,1997, when the second instance occurred.

In a separate PIR, the licensee's Quality Assurance (QA) organization identified

several inste. ces where the licensee had failed to implement a required TS action

statement. This QA-identified weakness indicated a broader concern regarding

operating crews' implementation of TS requirements, and implied that past efforts

to correct this concern were not successful,

c. Conclusions

The inspectors identified that the licensee's interim corrective actions for a

December 1996 failure to follow TS requirements were weak and almost resulted in

a recurrence of the same violation of TS. Additionally, a QA audit had indicated an

increasing trend in the failure of the licensee to enter TS action statements.

Although the immediate safety significance of the event was minor, this was an

example of weak corrective actions by the operations staff,

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08 Miscellaneous Operations issues

G 08.1 (Closed) URI 298/96009 01: Adequacy of administrative control of disabled

annuncetors. Although guidelines were provided for disabling annunciators, the

inspectors identified that the licensee did not specify requirements to determine if

an evaluation in accordance with 10 CFR 50,59 was necessary, nor were operators

required to determine if the disabled annunciator was required by abnormal

procedures or_ described in the Updated Safety Analysis Report (USAR). These

evaluations were necessary in order to determine the consequences of and proper

compensatory action for a disabled annunciator.

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The licensee stated that a Station Operations Review Committee (SORC)-approved

procedure would be initiated to address the process for disabling annunciators and

would include appropriate requirements for review of applicable procedures, license

commitments, and design requirements.

Based on the inspectors' review of disabled annunciators and their compensatory ,

actions to date, no violations were identified. The licensee's plans to provide more  !

comprehensive controls for disabling annunciators appeared appropriate. However,  !

due to the slow implementation of a controlled procedure and the lack of sensitivity i

to address the annunciation function of the sump fill rate timer by engineering (see l

NRC Inspection Report 50-298/96-31), this issue will be tracked as an inspection  !

followup item (298/97002-01).

II. Maintenance

M1 Conduct of Maintenance

M 1.1 General Comments .

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i a. Inspection Scope (62707 and 61726)

The inspectors observed all or portions of the following work activities:

Procedure Title

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SP 96-1002 Relay PC-REL-RMAX Contact 2 and

Relay PC-REL-RMBX Contact 5 Replacement

6.LPRM.302 LPRM Calibration and Setpoint Adjustments

MWR 97-0168 250v Battery Charger C Rela */ K5 Replacement

7.3.1.6 125/250vdc Station Battery Charger Protective Relays

Testing and Calibration l

7.3.28.1 Lead Removal and Installation

b. Conclusions

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Maintenance observed by the inspectors appeared appropriate, with exceptions

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M2 Maintenance and Material Condition of Facilities and Equipment

M 2.1 Absence of Taoer Pins Render Diesel Generators inoperable

a. Inspection Scone (62707)

Inspectors followed an engineering issue regarding the absence of taper pins on the

diesel generator fuel rack housings.

b. Observations and Findinas

On January 22,1997, licensee engineering identified an absence of several taper

pins used to help secure the fuel rack housing system (located between each diesel

generator cylinder), which could cause the fuel rack supports to have inadequate

seismic support capability. The vendor stated that, without taper pins, the bolts

securing the fuel rack bearing housing required at least 30 thousand pounds per

square inch (ksi) preload. No preload had been recorded for these bolts on diesel

generator work orders. The licensee's walkdown found that for Diesel Generator 1,

one housing did not include all required taper ains. For Diesel Generator 2, four

housings did not have the required taper pins. The licensee was unable to

determine if greater than 30 ksi preload had been applied to the associated bolts.

At 12:05 p.m. the licensee declared both diesel generators inoperable, entered the

appropriate TS action statement, and planned the required plant shutdown. An

emergency work order was written to implement appropriate preload on the affected

fuel rack bearing housings and determine as-found conditions with match-marks.  ;

The bolts were then tightened to 30 ksi. The licensee concluded that, based on the

location of final match-marks, greater than 30 ksi preload had been applied to the

bolts.

Inspector followup concerning how these diesel generators could be restored from

thei; previous overhaul with the missing taper pins will be tracked as an inspection

followup item (298/97002-02).

The engineering performance related to this problem is discussed in Section E2.1.

c. Conclusions

Resolution of two inoperable diesel generators due to lack of taper pins in same fuel

rack housings appeared appropriate.  !

M2.2 Recovery From Failed Surveillance of Core Power Distribution

a. Insoection Scope (61726)

The inspector reviewed the licensee's recovery from a failure of a traversing incore

probe (TIP) surveillance test of core power distribution and subsequent resetting of

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local power range monitors (LPRMs) to return the plant to the as-found i

configuration. This surveillance allows for resetting the gains of the LPRMs to l

properly reflect core power distribution.

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b. Observations and Findinas ]

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At 9:10 p.m. on January 23,1997, the licensee identified that a TIP detector f ailed  !

during performance of an LPRM calibration. The licensee had completed the first ,

half of the surveillance which involved evaluating and adjusting gains on LPRMs to ]

reflect power distribution during that T!P assessment. During the second half of the

surveillance, which provides dMa to the core thermal limit computer, the TIP failure

occurred. As a result, the licensee did not have a baseline for the core power

calculation with the LPRMs at their newly adjusted setting. The licensee then

determined that the LPRMs should be returned to the presurveillance LPRM gain

settings.

Since the surveillance could not be completed, an emergency maintenance work -

request (MWR), which provided instructions to operators to reset LPRMs to prior

LPRM gain settings, was initiated. Technicians started returning LPRMs to the as-

found condition at 3:48 a.rn. on January 24. The inspectors noted that the control

room had declared the appropriate average power range monitor inoperable, while

the associated LPRMs were being reset, and had entered and exited appropriate TS

action statements. During the recovery from the failed surveillance, the

instrumentation and control supervisor questioned the lack of SORC review of this

process. A short time later, the inspectors independently questioned the lack of

SORC review of the evolution.

Based upon the concerns identified by the supervisor and the inspectors, the

licensee convened a SORC meeting, evaluated the recovery from the failed

surveillance, and determined that the in-progress activity was being performed

appropriately and the instructions appeared to return the LPRMs to the as-found

status.

The inspectors also noted that no interim guidance had been provided to the control

room during this evolution which would have provided operators with instructions

during this anomalous condition. For example, inspectors questioned what

operators would be expected to do if a power transient were to occur during this

evolution, since all LPRM settings were in transition from an as-left to as-found

condition and information provided to calculate thermal limits may not have been in

an analyzed state. Licensee interviews with control room supervision indicated that

control room supervisors would consider tripping the unit if a power transient

condition occurred during this time frame. inspectors noted a need for

unambiguous guidance prior to the evolution so that operators would know what

actions were expected of them if challenges to plant operation occurred.

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c. Conclusiom

The inspectors found that operators initiated an emergency maintenance work

i request (MWR), which required resetting all LPRMs to the as found condition, to

recover from a TIP failure during the core power calculation surveillance. The

j inspectors noted that the lack of a SORC review of the evolution prior to or

concurrent with the evolution indicated a weakness in the proactive review of plant

! operations. This issue was raised independently by a licensee supervisor. No

i specific guidance was provided to operators on how to respond to abnormal

} conditions which could have occurred during this evolution.

! M2.3 Licens' ee Evaluation of Secondarv Containment Testina Reaardina Stack Effect

l .(!nformation Notice (IN)88-761

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a. Insoection Scoce (62726)

- The inspector reviewed the licensee's evaluation of the containment differential

pressure testing described by IN 88-76,' which concerned stack effects of

temperature differential between the inside and outside of a containment building.

These effects could cause a nonconservative pressure differential between inside

and outside secondary containment.

b. Observations and Findinas

During routine inspector review of containment differential pressure testing,

inspectors noted that the licensee had reviewed and evaluated IN 88-76. The

licensee concluded that, because the pressure sensor for secondary containment

was located high in the reactor building, the stack effect described by IN 88-76 did

not result in a secondary containment differential pressure concern.

The inspector inquired if a reverse of that effect, caused by low temperatures inside

the reactor building and high temperatures outside the reactor building, would cause

a nonconservative pressure differential at the base of the reactor building due to the

different densities of air and the location of the detector high in the plant. The I

licensee acknowledged that the reverse of the stack effect discussed by IN 88-76 l

was possible and could affect the plant in a nonconservative manner and that this

phenomenon had been evaluated. However, the effect was very small since river

water provided cooling to the reactor building. The licensee had concluded that

river water temperatures and available heat exchanger capacity in the reactor ,

building did not significantly lower reactor building temperature with respect to l

outdoor ambient temperature. The reverse of the stack effect at the base of the

reactor building would, therefore, result in an insignificant differential pressure  ;

change of approximately 0.01 inch water gauge. I

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c. Conclusions

The licensee's evaluation of the stack effect on containment testing appeared

appropriate and thorough and included vulnerabilities beyond that described by

IN 88-76.

M3 Maintenance Procedures and Documentation

M 3.1 Maintenance on 250v Batterv Charaer C

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a. Inspection Scone (62707)

The inspector observed the testing and replacement of an alarm relay for 250v

Battery Charger C.

b. Observajions and Findinas

On February 4,1997, the inspectors observed replacement of a battery charger

relay which provided an alarm signal to the control room on battery charger high '

output voltage. MWR 97-0168 instructions required that the as-found values for

the old relay be determined using Procedure 7.3.1.6, "125/250v Station Battery

Charger Protective Relays Testing and Calibration," Revision 7.

The inspector identified three issues concerning the implementation of ,

Procedure 7.3.1.6. To obtain the as-found data, Step 4.6 required that the '

minimum range for the relay be selected for the initial test voltage input. The

electrician used the minimum tolerance value as the minimum range value. The

next step (Step 4.7) required that the voltage be increased until the relay closed.

When the electrician applied the test voltage, the relay closed. In response,

therefore, the electrician decreased the voltage until the relay opened then increased

the voltage until the relay closed. While the actions did determine the as-found

condition, Procedure 7.3.1.6 did not contain any steps specifying the actions that

the electrician performed.

The second problem was that a note preceded by a place-keeping check-off box,

just before Step 4.1, required an action to be performed. The inspectors identified

that the electrician performed Steps 4.1 and 4.2 prior to performing the action

stated in the note.

The licensee responded that the note should have been a step and that the wording

of Step 4.7 would be changed to allow the electrician to vary the voltage. The

licensee stated they would correct the procedure and a PIR was written.

The electrician identified a third problem in that Step 4.15 incorrectly required

decreasing voltage "until the relay closes," instead of "until the relay opens." When

this problem was identified, the job was stopped and the battery charger restored to

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its normal configuration. The procedure was corrected and then the electricians

completed the procedure. The inspectors identified that the procedure had been

performed three times in the past few weeks without identification of this concern.

Procedure 7.3.1.6 was not appropriate to the circumstances in that actions had to

be performed which were not listed in the crocedure, a note in the procedure

required an action to be performed whic. < ". missed, and a step listed the

incorrect test position of the relay. This is ? violation of 10 CFR Part 50,

Appendix B, Criterion V, which requires procedures appropriate to the

circumstances (298/97002-03).

After the job was completed, the inspectors discussed these findings with the

electricians. During the discussion, the electricians stated that the actions to vary

the voltage were beyond the procedure steps, but necessary in order to obtain the

required as-found data, inspectors agreed that as-found data could not be obtained

without varying the voltage.

On February 6,1997, the inspectors determined that no PIR was initiated until the

inspectors questioned why a PIR had not been written to document the identified

problems with Procedure 7.3.1.6.

The failure to initiate a PlR to document three procedural deficiencies in the

l ficensee's corrective action program is an example of a violation of 10 CFR Part 50,

Appendix B, Criterion XVI, which requires conditions adverse to quality to be

promptly identified (298/97002-04).

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c. Summarv

The inspectors identified two violations in that maintenance personnel failed to

properly implement a calibration procedure and failed to document the identified

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problems in the problem identificatinr1 system.

M4 Maintenance Staff Knowledge and Performance

M4.1 Failure to Resolve TS Discrepancy

a. Insoection Scope (71707)

Inspectors reviewed actions and documentation associated with the lack of

surveillance on Limit Switch RHR-MLS-16, for RHR Crosstie Valve RHR-MO-20.

This valve separates the two redundant residual heat removal (RHR) trains.

b. Observations and Findinas

Crosstie Valve RHR MO-20 was declared inoperable and tagged shut on

January 23,1995, when the licensee recognized that required monthly surveillance

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tests would crosstie both trains of RHR. Since this valve is not required, except in

J certain beyond-design-basis events, this appeared to be a valid concern. The

licensee identified that the associated limit switch, RHR-MLS-16, was incorrectly

j listed in TS Table 4.2.814 as RHR-MLS-8. Additionally, the TS required a

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functional test once per month, and this involved cycling RHR-MO-20. Inspectors

also noted that the action required when the component operability is not assured

! for that limit switch was stated in Note 1.e as " repair as soon as possible. It does

not directly affect systems operations."

i The limit switch provided indication that the valve was closed, thereby confirming

that the RHR trains were not crosstied, inspectors noted that, although the

j surveillance test had not been performed since January 1996, the TS action

statement for the limit switch had not been entered, no evaluation had been

performed concerning its safety function, and no action was pending,. except

j' resolution in the upcoming improved TS implementation. I

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3 Inspectors also noted that no documentation was available to address the licensee's

] lack of entry into the TS action statement or the lack of testing of the limit switch.

l The licensee stated that, because the action statement described in TS 3.5.f.1 for

I Valve RHR-MO-20 was entered and tracked, it was understood that the limit switch '

would not be tested. The inspector noted that this rationale did not address the

i reason for not entering the action statement for the limit switch or for not

3 documenting an evaluation for the failure to return the switch to an operable status

i as soon as possible as required by TS.

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j A discussion of surveillance testing issues, as noted in NRC Inspection Report 50-

j- 298/95-001, documented that this issue need not be resolved before plant restart.

} The inspection report noted that RHR Crosstie Valve RHR-20 had been tested on a

} monthly basis; however, the licensee determined the test was not desirable since it

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temporarily tied the two divisions of RHR together and made them vulnerable to a I

single failure. The limit switch could not be tested independently of valve ,

i operation. The inspection team informed the licensee that the proposed procedure

! change to test only from the nearest relay downstream of a limit switch rather ,

i cycling the valve, did not actually test the limit switch and, consequently, would  ;

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not have satisfied the TS requirement. As stated in NRC Inspection Report 50

] 298/95-01, the licensee subsequently decided that the proper course of action was

to declare the limit switch inoperable and enter and follow the TS action statement,

! which was to repair the instrument as soon as possible.

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j The inspectors noted that as of January 31,1997, the licensee had neither entered

j the action statement to declare the limit switch inoperable, nor implemented actions'

! to address this apparent contradiction in the administrative control of the limit

switch. This oversight illustrates a lack of rigorous attention to TS tracking.

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c. Conclusions

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For a period of over 2 years,Jhe licensee did not address a discrepancy in the TS I

and did not enter an action statement

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for a limit switch for which required TS i

surveillance was not performed.\ For this issue and a related valve testing concern, I

no safety evaluations were documt.qted, although the licensee staff could verbally

articulate an evaluation for these con. erns. A preliminary NRC review concluded i

that the verbally stated evaluation to amid an RHR train crosstie was appropriate. I

M8 Miscellaneous Maintenance issues (92902)

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M8.1 LOcen) Violation 298/94016-02: 480v breaker s.vstem surveillance testing l

inadequate. .-The corrective actions implemented ter this specific event were

documented in NRC Inspection Report 50-298/94-31.

As part of the corrective actions for this issue, the licenst.9 initiated a surveillance i

testing validation program (STVP) to verify that all surveillarne requirements l

contained in the TS, USAR, and design criteria have been adequately translated into l

surveillance test requirements. In October 1996, during the insp9ctors' review of i

the corrective action for the violation, a number of USAR deficienc:9s were noted as l

3r lentified by the licensee in 1995, but were not corrected. Additionk1y, a j

significant number of corrective actions were not documented as closed Based on I

the inspectors' findings, the licensee performed a review of the STVP iteres to l

determine if any other items were still open.

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On January 20,1997, a PlR was written which described the inability to verify

closure of 95 open items documented in the STVP. On January 29,1997, aprojeta

team was forrned to determine the status and close or resolve those items that still

remained open. On February 13,1997, the project team completed their review N

-~and determined that 66 of the 95 items had not been implemented, and that all of N

the 95 STVP items were of minor safety significance. All 95 items were N"

subsequently completed.

This violation remains open pending evaluation by the inspectors of the adequacy of

licensee corrective actions.

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Ill. Enaineerina

E2 Engineering Support of Facilities and Equipment

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E2.1 Enaineerina identification and Resolution of Potentially inoperable Diesel Generators l

Due to Lack of Fuel Rack Housina Taper Pins I

Inspection Scope (37551)  !

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The inspector observed engineering's contribution to the identification and  ;

resolution of a potential diesel generator inoperability. l

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b. Observations and Findinas l

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As discussed in Section M2.1, the diesel system engineer identified that taper pins l

! were not installed on all diesel fuel rack bearing housings located between each l

l cylinder. The lack of taper pins brought into question the seismic qualification of ,

t these housings. ,

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The diesel vendor determined that, in the absence of taper pins, the fasteners on .

each housing would maintain the housings in place if 30 ksi preload was applied. i

The diesel generator system engineer identified that, for some housings on each l

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diesel generator, taper pins were not installed, and identified that 30 ksi preload on  !'

each bolt could not be verified using maintenance records.

! Engineering promptly communicated this concern to coerations and maintenance i

and, with bolt match-marks, determined that the as-found" condition of the bolting i

indicated that adequate preload had been applied, i

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c. Conclusions {

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The. diesel system engineer evidenced strong problem identification and resolution '

capabilities regarding the potential inoperability of both diesel generators due to lack  !

of taper pins on some fuel rack bearing housings. The root cause of this issue will l

be tracked as an inspection followup item (298/97002-02).  ;

E2.2 Operability Evaluation of Containment Penetrations Affected by an Unevaluated

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N Failure Mechanism

's a. inspection Scoce (37551)

The inspectors evaluated the licensee's resolution of unexpected ice in a tank,

N which was not previously considered a failure mechanism in the design of the tank.

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b. Observations and Findinas

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On January 28,1997, the licensee initiated a PIR which described an unexpected

ice blockage in the drain valve of a tank. The tank, located just outside secondary

containment, communicated with the interior of secondary containment via a 3-inch

drain line and a 2-inch vent line. The tank's purpose was to provide a drain path,

accessible from outside containment, for changing motor generator set oil during

outages. This finding by the licensee indicated that humidity from the reactor

building atmosphere had been drawn into the tank as a result of daily temperature

cycling, had condensed in the tank, and had later frozen. The inspector recognized .

that the accumulation of water and/or ice in this tank was a vulnerability which

apparently had not been considered in the design and control of this tank's

configuration.

The licensee stated that the tank was for maintenance convenience only. The l

associated safety analysis required that the tank not adversely interact with the

Class I seismic secondary containment structure and that the secondary

containment penetrations not fail.

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On January 30, the inspector requested a licensee engineering manager to tour the

outside of the secondary containment and turbine building structures to address

potential vulnerability brought to light by the liquid condensation mechanism. The

inspector noted that, to date, the broader scope of building penetration vulnerability ,

to condensation and subsequent fleeze/ thaw effects had not been addressed by the

l licensee's response to the problem. The inspector noted that two TS systems had

been affected by similar moisture buildup over the past 5 years and identified the

need fcr appropriate sensitivity to this type of mechanism. During the tour, the

inspector noted several containment and turbine building penetrations which

appeared to be vulnerable to similar condensation and freeze / thaw effects, although

no imminent failures were noted. The engineering manager agreed that these

questions should be evaluated.

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c. Conclusions  !

The inspectors concluded that the licensee prablem identification and operability l

evaluation was timely and showed improved rigor and safety focus. However,  !

further inspector involvement was required for the licensee to evaluate the broader

implications of a potential failure mechanism caused by condensation.

E4 Engineering Staff Knowledge and Performance

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E4.1 (Ocen) IFl 298/96026-07: Potential nonconservative failure of average power range

monitor (APRM) flow bias circuit. On November 22,1996, during a surveillance

} test of APRM E, alarms indicated an unexpected condition in the Division I reactor

protection system. Instrument and control technicians correctly diagnosed that the ,

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negative voltage to the flow bias unit power supply failed. The flow bias unit

provided scram signal input for all three APRMs in Division 1.

Inspector followup on February 4,1997, identified that, although similar

vulnerability of other power supplies in the reactor protection system (RPS) was

noted in the services information letter, no detailed licensee evaluation had been

documented which addressed operability of the RPS with respect to the failure of

those other power supplies. On February 12, the licensee completed a detailed

evaluation of RPS power supplies and concluded that no significant vulnerability

existed. The inspector review of this evaluation is continuing.

The inspector identified that the licensee had not yet performed a detailed

evaluation to determine the cause and extent of the problem concerning reset of the

flow bias scram, although the licensee had provided interim compensatory action for

the individual failure which occurred in November. Followup will evaluate a

potentially nonconservative reactor protection system failure mode, timeliness of

evaluation and corrective action, and failure to incorporate industry experience.

E8 Miscellaneous Engineering issues

E8.1 (Closed) URI 50-298/95018-05: Automatic depressurization system accumulator

test. This item addressed the change of automatic depressurization system valve

accumulator pressure to a higher pressure to address the need to overcome

accident pressure during a design basis event. The accumulators provide motive

force to operate the automatic depressurization system relief valves. The inspectors

questioned past operability of the valves before the pressure was raised. The

licensee was unable to address the question at that time.

A recent licensee investigation into past operability concluded that the automatic

depressurization system would have been operable under design basis events. The

licensee investigated accumulator pressure design basis requirements and found

that, for a valve to be operable, a minimum of 68 psi was required for five

actuations at atmosphere pressure, subsequent to one actuation at design pressure

or two actuations at 70 percent design pressure. The inspectors had questioned if

this finding was reportable in accordance with 10 CFR 50.73. Based on the

licensee finding that past equipment configuration indicated operable valves, they

determined the requirements of 10 CFR 50.73 did not apply. These actions

appeared appropriate to the inspectors.

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IV. Plant Support

S2 Status of Security Facilities and Equipment

S 2.1 Control of Security Plan in Control Room

a. Inspection Scope

inspectors reviewed control of personnel access to the security plan,

b. Observations and Findinas

inspectors noted that a security plan located in the shift supervisor's desk in the

control room did not appear to have any restricted access control other than the

access restriction required for entry into the control room. The shift supervisor's

desk is located in an open cubicle in the control room. The licensee believes that

the security plan was not read by unauthorized personnel since the shift supervisor

has observation of his desk area and because of the questioning attitude of other

operators who may observe individuals at the shift supervisor's desk during his

absence. The security manager relocated the plan to a controlled security area near

the control room immediately. '

The licensee stated that this issue was minor since operators would have identified

and questioned individuals reviewing documents in the shift supervisor's cubicle

without a need to know. 10 CFR 73.21(d) requires that security documents be I

locked while not attended, but the licensee's procedures allowed the security plan l

to be in the shift supervisor's desk. This issue will be followed up by inspectors l

from the regional office (298/97002-05).

c. Conclusions

A minor security issue identified by the inspectors will be followed up by inspectors

from the regional office.

VI. Manaoement Meetinas

X1 Exit Meeting Summary

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

exit meeting on February 25,1997. The licensee acknowledged the findings presented.

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

should be considered proprietary. No proprietary information was identified.

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SUPPLEMENTAL INFORMATION

PARTIAL LIST OF PERSONS CONTACTED

Licensee

Mike Bennett, Licensing Supervisor

Dan Buman, Engineering Support Manager

Jack Dillich, Maintenance Manager

Fadi Diya, Design Engineering Manager

Rick Gardner, Operations Manager

Philip Graham, Vice President-Nuclear Energy

David S. Kimball, Radiation Operations Supervisor

Ole Olson, Plant Engineering Manager

Mike Peckham, Plant Manager

Jim Pelletier, Senior Manager of Engineering

INSPECTION PROCEDURES USED

IP 37751: Onsite Engineering

IP 61726: Surveillance Observation

IP 62707: Maintenance Observation

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 92901: Followup - Plant Operations

IP 92902: Followup - Maintenance

IP 92903: Followup - Engineering

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened.

298/97002-01 IFl Review of administrative controls of disabled annunciators

(08.1)

298/97002-02 IFl Diesel generator taper pins not installed (M2.1 and E2.1)

298/97002-03 VIO Failure to properly implement a procedure (M3.1)

298/97002-04 VIO Failure to document problems in the problem identification

system (M3.1)

298/97002-05 IFl Evaluation of storage of security plan in the control room

(S2.1)

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Closed

298/96009-0~l URI Control of disabled annunciators (08.1)

298/95018-05 URI Automatic depressurization system accumulator test (E8.1)

Discussed

298/94016-02 VIO 480v breaker system inadequate (M8.1)

298/96026-07 IFl Potential nonconservative failure of APRM flow basis circuit

(E4.1)

LIST OF ACRONYMS USED

APRM average power range monitor

IFl inspector followup item

IN information notice

ksi thousand pounds per square inch

LPRM local power range monitors

PIR problem identification report I

OA quality assurance

RHR residual heat removal

RPS reactor protection system

SORC Station Operations Review Committee

TIP traversing incore probe

TS Technical Specification

URI unresolved item

USAR Updated Safety Analysis Report

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