ML20059F694

Insp Rept 50-298/93-28 on 931108-1230.Violations Noted.Major Areas Inspected:Activities of 931108,that Led Licensee to Declare Both EDGs Inoperable

ML20059F694
Person / Time
Site:	Cooper
Issue date:	01/09/1994
From:	Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20059F670	List: ML20059F667 ML20059F694
References
50-298-93-28, NUDOCS 9401140122
Download: ML20059F694 (14)

See also: IR 05000298/1993028

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APPENDIX

U.S. NUCLEAR REGULATORY COMMISSION i

REGION IV i

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Inspection Report: 50-298/93-28

License: DPR-46

Licensee: Nebraska Public Power District -

P.O. Box 499

Columbus, Nebraska

Facility Name: Cooper Nuclear Station

Inspection At: Brownville, Nebraska

Inspection Conducted: November 8 - December 30, 1993

Inspectors: Ronald A. Kopriva, Senior Resident Inspector  ;

Raymond P. Mullikin, Senior Resident Inspector i

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Approved: s ,

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4 E. g gliardo, Chief, Project Section C Date

Inspection Summary

Areas Inspected: A special safety inspection, which was announced to the

licensee, investigating the activities of November 8,1993, that led the

licensee to declare both emergency diesel generators inoperable, which placed

the plant in an unuseal event, requiring a reduction in reactor power. ,

Results: ,

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e The as-found conditions of Emergency Diesel Relays DG-REL-DGl(59) and

-DG2(59) would have prevented the Emergency Diesels 1 and 2 from ,

performing their intended design function for accident scenarios where .' ,

offsite power is available, and then subsequently lost (Section 2). 'l

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• Failure to follow procedures and inadequate. procedures contributed to -l

the emergency diesel generator relay miscalibration and contributed to

difficulties in past calibrations of these relays (Section 3).

• The licensee's corrective actions were inadequate, in that, they did not '

identify the root cause of emergency diesel generator relay out-of- -

tolerance conditions found in March and April 1993, and did not i

implement actions to prevent recurrence (Section 3). '

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9401140122 940106

PDR ADOCK 05000298-

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• With both emergency diesel generators inoperable, the shift supervisor

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failed to classify the conditions as an Unusual Event in a timely-

I manner. On two separate occasions since July 1991 (one actual, one

simulated), licensee shift supervisors had also failed 'to. classify these

same conditions as an Unusual Event. The licensee's corrective actions,

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in response to these earlier classification failures, had not precluded

! a repetition of the failure on November 8, 1993 (Section 4).

• The inspectors concluded that the corrective action review board's

review of the event was appropriate (Section 5).

! * The loose and uncontrolled methods of documenting data has fostered poor  !

work practices, causing difficulties with completeness of work documents I

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(Section 6).

I * The poor housekeeping practices could have resulted in problems or

concerns with uncontrolled documents and miscellaneous components

(Section 6).

Summary of Inspection Findings:

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• Apparent Violation 298/9328-01 for inoperable diesel generators

(Section 1.2)

l * Apparent Violation 298/9328-02 for inadequate procedures (Section 3.1).

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• Apparent Violation 298/9328-03 for failure to follow procedures

(Section 3.2).

• Apparent Violation 298/9328-04 for. inadequate corrective actions that

did not preclude repetition (Section 3.3).

• Apparent Violation 298/9328-05 for untimely declaration of an unusual

I event and inadequate corrective action (Section 4).

Attachment:

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• Attachment - Persons Contacted and Exit Meeting

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DETAILS

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1 ON SITE RESPONSE TO EVENTS (93702) ,

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1.1 Summar_y of Event

On November 8, 1993, at approximately 7 a.m. (CST), the inspectors observed

the licensee preparing to perform Surveillance Procedure (SP) 6.3.12.1, -

" Diesel Generator Monthly Operability Test," for Emergency Diesel  ;

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Generator (EDG) 1.

The procedure had been recently revised to incorporate the verification for i

continuity of Relays DG-REL-DG1(59) for EDG 1, and -DG2(59) for EDG 2. The

relays provide the permissive to close the 4160 VAC switchgear breakers for i

the emergency electrical buses if the EDG is capable of providing sufficient '

voltage to assume the load. After starting EDG 1 the electricians found that

Relay DG-REL-DG1(59) was not energized, indicating that the permissive to

close EDG 1 output breaker was not satisfied. t

At 8:46 a.m., the licensee declared EDG 1 inoperable. This placed the plant

in a limiting condition for operation requiring the licensee to verify that

the emergency core cooling systems, including EDG 2, were operable.

The licensee performed SP 6.3.12.1.1, " Diesel Generator Demonstration of j

Operability Test," for EDG 2. During the performance of the surveillance, the

licensee found that Relay DG-REL-DG2(59) was not energized after EDG 2 had-  :

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reach rated speed and voltage, indicating that the voltage permissive for

EDG 2 output breaker was not satisfied. The licensee declared EDG 2 t

inoperable at 12:02 p.m.

The shift supervisor declared a Notification of Unusual Event (NOVE) at

12:48 p.m. in accordance with their Emergency Action Level (EAL) 4.1.2, " Loss

of both onsite EDGs, but offsite power is still available." The licensee

completed offsite notifications at 12:55 p.m. which is within the 15-minute

time requirement of the licensee's Emergency Procedure 5.7.6,." Notification."

The licensee completed their notification to the NRC at ~1:26 p.m.

In accordance with the licensee's Technical Specification (TS) 3.5.F.2, the ,

licensee commenced a power reduction at 12:55 p.m.  !

The electrical mechanics tested and reset Relay DG-REL-DG1(59) per Maintenance

Procedure (MP) 7.3.1, " Protective Relays Setting and Testing." The l

electricians were able to reset the relay to actuate within the required

values. The licensee satisfactorily completed SP 6.3.12.1.1, " Diesel

Generator Demonstration of Operability Test," at 5:43 p.m., and declared EDG 1 1

operable. The licensee terminated the NOVE at 5:47 p.m.

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The electricians investigated and repaired DG-REL-DG2(59). EDG 2 was .

satisfactorily tested per SP 6.3.12.1.1 and was declared operable at

11:35 p.m.

2 EMERGENCY DIESEL GENERATOR OPERABILITY (93702)  !

2.1 Emergenc_y Diesel Generator As-Found Conditions

On November 8, 1993, as-found readings were taken on both the live and spare

sets of contacts for Relays DG-REL-DG1(59) and -DG2(59). The as-found pick-up

voltage for Relay DG-REL-DGl(59) was 121 volts. Rated generator output ,

voltage would correspond to 120 volts. Calibration tolerance is 112 volts

15 percent, nominally 94 percent of generator output voltage. The spare set

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of contacts for Relay DG-REL-DGl(59) were found to be within the required

tolerance. The November 8,1993, as-found data for Relay DG-REL-DG2(59)

indicated that the pick-up voltage was 131 and 122.5 volts for the l_ive and

spare sets of contacts, respectively.

2.2 Emergency Diesel Generator Operability

The EDGs at Cooper 'are the standby AC power sources in the event of loss of

normal, startup, and emergency electrical power sources. The EDGs are

designed to start automatically upon indication of a postulated design basis

loss of coolant accident (LOCA), independently-of the availability of offsite

power, to ensure the availability of AC power in the event offsite power is

lost. The EDGs receive automatic start signals, not only on loss of bus

voltage (loss of electrical- power), but also on high drywell pressure and low

reactor water level (LOCA signals).

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Updated Safety Analysis Report (USAR), Chapter VIII, Section 5.3.1, described

scenarios for the LOCA where the EDGs start, but do not immediately load onto

the bus. Loss of the startup or normal electrical power to the emergency

buses results in the automatic starting of the diesel generators and the

automatic connection of the emergency buses to the emergency electrical power

source. The sequences described in the USAR, Chapter VIII, Section 5.3.1,

included a LOCA: (1) where the startup power is available, (2) where startup

power is lost but emergency power is available, and _(3) where neither startup

or emergency power is available. The USAR discussions indicated that the EDGs

were required to be capable of automatically supplying electrical power to the

emergency buses in sequences where offsite power is available, as well as

scenarios where offsite power is not available.

General Electric Design Specification 22A1040, Revision 1, also stated that

the diesel generators start whenever a low water level (Level 1) or high

drywell pressure is signalled, to provide for automatic energization of

specified minimum critical loads and emergency cooling loads, as required. If

normal power continues to be available after automatic startup, the running i

generators are held in reserve during the emergency period.  ;

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For the sequences where offsite power is available, the EDGs would

automatically start to ensure the availability of AC power in the event

offsite power was subsequently lost. For the sequence where the EDGs

automatically start with offsite power available, and then offsite power is

subsequently lost, the as-found conditions of EDG 1 and 2 relays would have

prevented the output breakers from automatically closing. After the diesel

reached rated speed and voltage, the logic for satisfying the voltage

permissive to close the output breakers would not have been satisfied because

the relays as-found pick-up setpoints corresponded to a generator output

voltage above rated voltage. Thus, for these sequences discussed in the USAR,

the inspectors concluded that EDGs 1 and 2 were inoperable, in that, they were

not capable of performing their intended design function.

For the sequence where offsite power was not available, the as-found condition

of both EDGs apparently would not have prevented the output breaker from ,

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closing because of the voltage transient experienced on diesel starts. The

licensee indicated that satisfactory EDG surveillance testing at the end of

the outage demonstrated that the diesels would start and automatically load

under conditions where offsite power was not available. The licensee stated  !

that the voltage overshoot would satisfy the logic and allow the EDG output

breakers to automatically close. The inspectors noted that neither the USAR

nor the EDG design documents discussed reliance on the overshoot to permit the

EDGs to perform their intended design function. The design setpoint of the

relays was to provide a close permissive to the EDG output breakers at

94 percent of rated generator voltage.

USAR Chapter XIV discusses design basis loss of coolant and steam line break

accidents where offsite power is lost concurrently with the initiation of the

accident condition. The concurrent loss of offsite power and LOCA is a subset

of the third sequence discussed above where offsite power is not available.

USAR Chapter VIII, Section 5.6, states, that a LOCA with a concurrent loss of

startup and emergency power is the basis for the maximum load requirement for

standby AC power, but that load requirements will be less in other operating

conditions.

TS 3.9.A states that the reactor shall not be made critical from a cold

shutdown condition unless both diesel generators are operable. TS 3.5.F.1,

states, in part, "During any period when one diesel generator is inoperable, <

continued reactor operation is permissible only during the succeeding 7 days

unless such diesel generator is sooner made operable." TS 3.5.F.2 states, in'

part, "If this requirement cannot be met, an orderly shutdown shall be

initiated and the reactor placed in the cold shutdown condition within ,

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />." The inspectors concluded that Relay DG-REL-DG1(59) was set

improperly during the refueling outage rendering EDG 1 inoperable since plant

startup in July until November 8,1993, when Relay DG-REL-DG1(59) was reset to

' the proper setpoint. The inspectors concluded that EDG 2 apparently became

inoperable sometime between April and November 8, 1993, although, because of

the procedure inadequacies discussed in Section 3 of this report, the

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inspectors could not eliminate that this relay was also misadjusted during the  ;

refueling outage. This is an apparent violation of TS 3.9. A and 3.5.F

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(298/9328-01).  ;

2.3 Conclusions

The as-found-conditions of Emergency Diesel Relays DG-REL-DGl(59) and -DG2(59)

would have prevented the Emergency Diesels 1 and 2 from performing their

intended design function for accident scenarios where offsite power is  !

available, and then subsequently lost. This is an apparent violation ,

(298/9328-01).

3 CAUSES (93702)

3.1 Inadeauate Maintenance Procedure ]

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On November 8, the licensee was performing SP 6.3.12.1, " Diesel Generator j

Monthly Operability Test," which was revised to incorporate Step 8.1.32, that i

checks for continuity across the terminals of Relay DG-REL-DGl(59). The

revised procedure tests the function of the relays because the relays were

found out of tolerance during the previous refueling outage. Nonconformance

Report 93-048 initiated in March 1993, documented that relays DG REL-DG1(59)

and -DG2(59) had setpoint values above the required settings. The licensee

stated that this was the first recorded occurrence for the out-of-tolerance

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The inspectors reviewed MP 7.3.1 used to test and reset the relays and

discussed with the electricians how the relays were tested and reset. The

inspectors noted that the 59 relays have two. sets of contacts. The

application of the 59 relays for the EDGs used only one set of contacts

(live), with the second set of contacts existing only as a spare set. Al so,

the relay contacts were not labeled live and spare. The inspectors observed

that the procedure aid not identify the fact that there were two sets of

contacts, or provide guidance which set of contacts were to be-calibrated.

The over/under Voltage Relay Test Data Sheet incorporated requirements for _one

set of contact data. The inspectors questioned the licensee how in the past

that they had assured themselves that the. correct set of contacts had been

calibrated and adjusted, and which set of contact data had been recorded. The )

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licensee representatives were unable to provide any definitive answers _or ,

documentation to resolve this concern. l

Since Relay DG-REL-DGl(59) had been found approximately 10 volts low in April-  ;

1993 and the relay was adjusted to increase the pickup voltage by about i

10 volts, the licensee concluded that the electrician had tested the spare set- i

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of contacts in April 1993 and had adjusted the spare set of contacts without.

ever testing the live contacts. For EDG 1, the electrician was not able to

specifically recall which set of contacts were checked and adjusted on i

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The licensee found Relay DG-REL-DG2(59) out of tolerance in March 1993 with a

pick-up voltage of 121 volts, and had reset the pick-up voltage within the

tolerance range. The electrician that performed the testing in March 1993

indicated he always tested and calibrated both sets of contacts. When ,

questioned which contact data was recorded, the electrician indicated the

right hand set of contacts, which were live. When asked why he recorded the

data for that particular set of contacts, he replied that it was the

electrician's discretion. *

The inspectors reviewed the last 10 years of surveillance documentation for  ;

MP 7.3.1 and noted that the problem with the procedure had existed for several  !

years. The licensee had not previously questioned the adequacy of the

procedure.

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10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and

Drawings," states, in part, " Activities affecting quality shall be prescribed

by documented instructions, procedures, or drawings, of a type appropriate to  ;

the circumstances and shall be accomplished in accordance with these  :

instructions, procedures, or drawings." The inspectors concluded that 3

MP 7.3.1 was not appropriate to the circumstances, in that, the procedure did  ;

not identify which set of contacts the electricians were to test and reset.  ;

As-found conditions on' November 8, 1993, and interviews with the electrician  ;

indicated that Relay DG-REL-DG1(59) spare contacts were apparently adjusted on l

April 9,1993, resulting in the live contacts being out of tolerance.  !

As-found conditions on November 8,1993, also showed that the live contacts  :

for Relay DG-REL-DG2(59) were out of tolerance. The inadequate procedure

resulted in relay misadjustment which represented a common mode failure

mechanism for both EDGs. This is' the first example of an apparent violation

of an inadequate procedure (298/9328-02). The inspectors could not eliminate l

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the possibility that Relay DG-REL-DG2(59) was also misadjusted on March 27,

1993. Another possible cause of Relay DG-REL-DG2(59) being out of tolerance

was degradation of the relay. If the relay was correctly set on March 27,

1993, then the relay may have drifted out of its allowed tolerance.

The inspectors also found that MP 7.3.1, Step 8.2.5, states, "If AS-FOUND

values were not within tolerance, make necessary adjustments per

manufacturer's instruction manual, retest relay and record AS-LEFT data."

After reviewing the vendor manual, the inspectors noted several items that the

licensee had not performed during the relay adjustments in March and

April 1993, and justification for deletion of these items was not provided. ,

included in the maintenance section of the vendor manual under PERIODIC i

TESTING it states, "An operation test and an inspection of the relay at least

once every 6 months are recommended." The only testing the licensee performed i

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on these relays were a continuity check performed during the sequential load

test performed every outage (approximately every 12 months), and the testing

performed per MP 7.3.1, which indicated that the 59 relays were tested and  ;

calibrated every second cycle (approximately every 2 years).

10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and

Drawings," states, in part, " Activities affecting quality shall be prescribed

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by documented instructions, procedures, or drawings of a type appropriate to

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the circumstances and shall be accomplished in accordance with these

instructions, procedures, or drawings." The inspectors concluded that

MP 7.3.1 was not appropriate to the circumstances, in that, it did not specify

the frequency of testing of the relays in accordance with the manufacturer's ,

recommendation and no justification was provided. This is the second example

of an apparent violation of an inadequate procedure (298/9328-02).

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3.2 Failure to Follow Maintenance Procedure 7.3.1

Under " Adjustments and Inspection" the vendor manual specified that the normal

adjustment of contacts is 3/64-inch wipe. The manual described how to adjust

the contact wipe of the relay contacts and that adjusting the contact wipe

could change the pickup and dropout voltages. The inspectors questioned the

licensee how and when the contact wipe was measured, and the licensee

responded that the contact wipe had never been checked. >

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To address the broad question of the implementation of vendor recommendations,

the licensee initiated a review of other vendor manuals to confirm that the ,

vendor recommendations were considered and incorporated into the appropriate i

procedures, where required.

10 CFR Part 50, Appendix B, Criterion V, states, in part, " Activities

affecting quality shall be prescribed by documented instructions, procedures,

or drawings of a type appropriate to circumstances and shall be accomplished

in accordance with these instructions, procedures, or drawings." MP 7.3.1,

Step 8.2.5, stated, "If AS-FOUND values were not within tolerance, make

necessary adjustments per manufacturer's instruction manual, retest relay and

record AS-LEFT data." On March 27 (EDG 2) and April 9 (EDG 1), the licensee

failed to follow MP 7.3.1, in that, the manufacturer's recommended i

measurements of the wipe were not performed. This is an apparent violation of

failure to follow procedure (298/9328-03).

3.3 Resolution of Relay Problems in Ma-ch and April 1993

The inspectors reviewed the completed st rveillance results for these relays

for the past 10 years and noted that in March 1993 the licensee initially

identified that the relays were outsioe of the required tolerance. The

inspectors questioned the licensee ab)ut this finding. When performing the

surveillance in March and April, the licensee recognized and identified this' I

problem and issued Nonconformance Report 93-048 and Deficiency Report 93-116 i

for DG-REL-DGl(59). The root cause for both the deficiency report and the

nonconformance report was identified as "other," setpoint drift - unknown.

The licensee indicated that the root cause of "other" was assigned since it

had been the first time that these relays had drifted out of limits. There

were no documented previous cases of this relay type with setpoint drift

problems at Cooper Nuclear Station or in industry data bases. The inspectors i

noted that the nonconformance report recommended verification of relay

operation more frequently than once per cycle.

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The nonconformance report resolution also recommended a procedure change I

notice for the EDG SP 6.3.12.1 to have the operators check DG-REL-DG1(59)and

-DG2(59) after the start of the EDGs to ensure that the respective 59 relays

had picked up, and to make this step acceptance criteria for procedure

completion. The licensee's outage was completed July 30, 1993. The

nonconformance report was officially closed out on September 21, 1993. The

revised SP 6.3.12.1 which incorporated the procedure change notice was not

approved until November 4, 1993. The revised surveillance test identified the

relay problems on November 8, 1993. .

In April 1993, the licensee formed the Corrective Action Program Overview-

Group. They had been tasked with reviewing the licensee's corrective action

program and for reviewing current and posted deficiency reports and

nonconformance reports. During their review, the Corrective Action Program

Overview Group did not identify any concerns with Honconformance Report 93-048 1

or Deficiency Report 93-116 pertaining to the inadequacy of the root cause -i

determination or the untimely commitment for implementing the procedure change

notice into SP 6.3.12.1.

10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," states, in

part, " Measures shall be established to assure that conditions adverse to

quality, such as failures, malfunctions, deficiencies, deviations, defective

material and equipment, and nonconformances are promptly identified and

corrected. In the case of significant conditions adverse to quality, the

measures shall assure that the cause of the condition is determined and

corrective action taken to preclude repetition." The licensee did not

effectively identify or address the relay out-of-tolerance conditions

identified in March and April 1993, and the corrective actions taken did not

preclude repetition. This is an apparent violation (298/9328-04).

3.4 Conclusions

Failure to follow procedures and inadequate procedures contributed to the EDG

relays miscalibration and contributed to difficulties in past calibrations of

these relays. These were apparent violation (298/9328-02 and -03).

The licensee's corrective actions were inadequate, in that, the nonconformance

report resolution did not identify the root cause of the relay out-of-

tolerance conditions found in March and April 1993, and did not implement

actions to prevent recurrence. This is an apparent violation (298/9328-04).'

4 UNUSUAL EVENT DECLARATION (93702)

On November 8,1993 during surveillance testing of both EDGs, Relays

DG-REL-DGl(59) and -DG2(59) did not perform satisfactorily. As a result, at

12:02 p.m. both EDGs were declared inoperable. At 12:48 p.m., an Unusual

Event was declared by the shift supervisor as a result of the EDGs being

declared inoperable.  ;

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The Unusual Event declaration was made pursuant to Emergency Plan Implementing l

Procedure 5.7.1," Emergency Classification," EAL 7.1.2. This EAL initiating l

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condition states, " Loss of both onsite emergency diesel generators, but

offsite power is still available." Step 8.2.1 of the procedure requires that,

"If an EAL is met, the shift supervisor / emergency director declares the

emergency class corresponding to the EAL met." Step 2.7 of the same procedure

states that with regard to a TS' system, subsystem, train, component, or

device, the term " loss" that is used throughout this procedure is the same as

not having " operability" as defined in TS.

Following the NOVE, the licensee performed an internal investigation into the

event and concluded that the decision to classify the Unusual Event was

" slow." The classification was made 46 minutes after the EDGs had been

declared " inoperable" in the control room. According to the licensee's

investigation, the Unusual Event was not promptly classified by the shift

supervisor after the EDGs were declared inoperable. The shift supervisor and

the station technical advisor had reviewed the EAL proc 2dures and concluded

that they did not apply because they did not consider the inoperability of the

EDGs to meet the classification initiating conditions which specify " loss." ,

The shift supervisor apparently failed; however, to review Attachment 2 of

Emergency Plan Implementing Procedure 5.7.1, which contained a full text of *

the EAL examples.

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Licensee representatives stated that the shift supervisor understood that the

EDGs could have operated under all emergency conditions following operator

actions to close certain breakers in the control room. Thus, despite the fact

that the EDGs were declared inoperable, the shift supervisor believed that  !

they were available for use, if needed, following simple operator actions to i

restore operability. Later, the plant manager notified the shift supervisor .

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that an Unusual Event should be declared and the reason for the declaration.

The shift supervisor then declared the Unusual Event at 12:48 p.m.

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In addition, to the failure to classify the November 8, 1993, conditions in a

timely manner, the inspectors identified that similar failures had occurred

previously. Specifically, NRC Inspection Report 50-298/91-27 identified  ;

Unresolved item 298/9127-002 that on July 30, 1991, with both EDGs inoperable, <

an Unusual Event was not declared. The licensee's corrective actions included '

revision of Emergency Plan Implementing Procedure 5.7.1 on June 4, 1992, to

clarify the term " loss," and routing of the revised procedure to the licensed ('

operators with the changes being located in the body of the procedure and in-

the example on the classification flowchart. Also Step 2.7 defines the term

" loss" the same as "inoperability" as defined in the TS. Unresolved

Item 298/9127-002 was closed in NRC Inspection Report 50-298/92-10 based on i

the revision to the procedure. Further investigation by the inspectors-

revealed; however, the licensee has not incorporated this event in their

routine training. The event was' covered in a simulator emergency plan

training scenario, and the scenario had been used for operator training from

April through June 1993.

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On a separate occasion during an emergency preparedness walkthrough inspection ,

conducted January 1992, a weakness was identified in the area of emergency

classification, in part, because a shift supervisor did not recognize that a

loss of both onsite EDGs satisfied the emergency action level for a NOUE. His ,

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weakness was documented in NRC Inspection Report 50-298/92-01. In response to

this weakness, the licensee retrained and reevaluated operating crews,

enhanced classroom EAL training, and simulator emergency response training as

part of the licensed operator requalification training program.

10 CFR 50.54(q) requires that a licensee authorized to possess and operate a ,

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nuclear power reactor shall follow and maintain in effect emergency plans.

which meet the standards in 50.47(b) and the requirements in Appendix E of

this part. On November 8, 1993, the licensee failed to follow the emergency

plan when an Unusual Event was not declared in a timely manner following both ,

EDGs being declared inoperable at 12:02 p.m. 10 CFR Part 50, Appendix B,  ;

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Criterion XVI, " Corrective Action," states, in part, that in the case of

significant conditions adverse to quality, the measures shall assure that the >

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cause of the condition is determined and corrective action taken to preclude

repetition. On November 8, 1993, the licensee's corrective actions taken to

identify, clarify, and train on the recognition and classification of l

conditions involving the inoperability of both EDGs did not preclude a  ;

repetition of the prior failures to classify these conditions as an Unusual I

Event. The untimely declaration and ineffective corrective actions are an

apparent violation (298/9328-05).

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4.1 Conclusion

Once both EDGs had been declared inoperable, the shift supervisor failed to

classify the conditions as an Unusual Event in a timely manner. On two

separate occasions since July 1991 (one actual, one simulated), the shift

supervisors had also failed to classify these same conditions as an Unusual

Event. The licensee's corrective actions in response to the earlier

classification failures had not precluded a repetition of the failure on

November 8, 1993. This is an apparent violation (298/9328-05).

5 LICENSEE CORRECTIVE ACTIONS (93702) q

The licensee established a Corrective Action Review Board (CARB) 93-02 to l

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investigate the circumstances surrounding the inoperability of both EDGs on

November 8, 1993, and to make recommendations to preclude recurrence. The

CARB members included the system engineer, a lead maintenance instructor, an

ex-instrument and controls technician, and other personnel.

The inspectors had attended the CARB report briefing to licensee management

and had reviewed the written report for activities identified, root cause

evaluations, and recommendations made.

The CARB report identified 33 items that the licensee had assigned closure

responsibilities. Preliminary due dates assigned the action items ranged.from

December 15, 1993, through October 1, 1994.

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The CARB review appears to have been sufficient to identify the inadequacies

and weaknesses encountered through their investigation. The CARB had

addressed the concerns of operability of the EDGs and for verifying

operability of other relays throughout the plant.

5.1 Conclusion

The inspectors concluded that the CARB's review of the EDG event was

appropriate.

6 RELATED ISSUES (93702)

While reviewing the activities. associated with the testing of the relays on

November 8, 1993, the inspectors noted that the licensee had indicated that

data had been taken for both set of contacts. A review of the work package

did not reveal the as-found data for both contacts, only those for the

contacts in use. Further discussions with the electrical shop personnel

indicated that they had taken as-found data for both sets of contacts and

after searching for the information, it was located on a data sheet and scraps

of paper. The electricians indicated that the information had not been

included in the work package. The CARB reviewed these actions and recommended

that electricians complete the documentation when performing work items aad

the supervisor question the completeness before signing off the work item.

During the inspection of the EDG control cabinet housing the 59 relays, the

licensee identified that uncontrolled process and instrument diagram prints

were located in the cabinets. The electrical supervisor was notified to

remove the prints and informed the plant manager. The system engineer also

identified several miscellaneous components (i.e., light bulbs, indicating

lights, varistors, lugs, test cables, tape, and chart paper) in the box on the

inside of the cabinet door. The items were also removed and the systems

engineer initiated a deviation report. The licensee's actions were to inspect

electrical cabinets throughout the plant for uncontrolled items such as those

found in the EDG cabinets. The poor housekeeping practices could have

resulted in problems or concerns with uncontrolled documents and miscellaneous

components.

6.1 Conclusions

The informal methods of documenting data has fostered poor work practices,

causing difficulties with work document completeness.

The poor housekeeping practices could have resulted in problems or concerns

with uncontrolled documents and miscellaneous components.

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ATTACHMENT

1 PERSONS CONTACTED

1.1 Licensee Personnel

R. Brungardt, Operations Manager

J. E. Dunn, Records Specialist

J. R. Flaherty, Corrective Action Program Overview Group

R. W. Foust, Assistant Engineering Manager

S. S.. Freborg, Plant Engineering Supervisor

R. L. Gardner, Plar.t Manager

G. R. Horn, Vice President, Nuclear (by telecon)

E. M. Mace, Senior Manager of Site Support

J. M. Meacham, Site Manager

C. R. Moeller, Technical Staff Manager

D. L. Reeves, Senior Staff Engineer

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D. R. Robinson, QA Assessment Manager

G. E. Smith, Quality Assurance Manager

M. E. Unruh, Maintenance Manager  :

1.2 NRC Personnel

R. A. Kopriva, Senior Resident Inspector

J. L. Pellet, Regional Inspector

J. E. Gagliardo, Chief, Project Section C (by telecon)

The pe/sonnel listed above attended the exit meeting. In addition to the

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personnel listed above, the inspectors contacted other licensee personnel

during this inspection period.

2 EXIT MEETING

An initial exit meeting was conducted on December 3, 1993. The final exit

meeting was conducted by telephone on January 6, 1994. During the meetings,

the inspectors reviewed the scope and findings of this report. The licensee

acknowledged the findings and did not identify as proprietary ~any information

provided to, or reviewed by, the inspectors.-

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