IR 05000482/1993001

Insp Rept 50-482/93-01 on 930103-0213.Violations Noted.Major Areas Inspected:Plant Status,Operational Safety Verification,Maint & Surveillance Observations,Preparation for Refueling & Followup of Previous Insp Findings

ML20044B979
Person / Time
Site:	Wolf Creek
Issue date:	03/08/1993
From:	Johnson W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20044B974	List: IR 05000482/1993001 ML20044B973 ML20044B977
References
50-482-93-01, 50-482-93-1, NUDOCS 9303160038
Download: ML20044B979 (30)

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APPENDIX B

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U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

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NRC Inspection Report:

50-482/93-0I Operating License No.: NPF-42 i

Docket:

50-482 Licensee: Wolf Creek Nuclear Operating Corporation

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P. O. Box 411 Burlington, Kansas 66839

Facility Name: Wolf Creek Generating Station Inspection At: Coffey County, Burlington, Kansas

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Inspection Conducted:

January 3 through February 13, 1993

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Inspectors:

G. A. Pick, Senior Resident Inspector L. E. Myers, Resident Inspector Approved:

(14) h er 3/8/f3 W.

D'. Johnfon, Chief, Project Section A ~Uatd Division 6f Reactor Projects

Inspection Summary I

Areas Inspected:

Routine, unannounced inspection including plant status, operational safety verification, maintenance observations, surveillance observations, preparation for refueling, followup of previously identified inspection findings, other followup, and onsite review of a licensee event report.

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Results:

The inspectors identified a violation of Technical Specification 6.8.1.a

with two examples of failure to follow procedures because of inattention i

to detail.

Instrumentation and control technicians initiated performance of a surveillance on the wrong train, and a licensed

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operator inappropriately marked a procedure step "not applicable."

(Sections 2.4 and 2.9).

Several combined instances of inattention to detail resulted in a loss

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of inventory from the refueling water storage tank (RWST). Operators vented the safety injection test header without a procedure or written instruction. Also, the licensee had not modified the system lineup checklists for the affected systems. The inspectors considered the

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licensee's inactivity to be the major deficiency. This was a viols involving the failure to maintain an adequate surveillance procedurt (Section 2.7).

The inspectors considered the failure of system engineers to identify an

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incorrect design document deficiency during previous reviews to be a weakness (Section 2.1).

The engineering support for resolution of the

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potential motor-operated valve (MOV) overthrusts demonstrated increased y

cooperation among licensee organizations and involvement by system

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engineering (Section 2.8).

From review of outstanding clearance orders older than 6 months, the I

inspectors determined that the licensee appropriately used clearance orders (Section 2.2).

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A noncited violation was noted because the licensee identified and

immediateiy replaced missing local alarm response procedures. The

licensee implemented corrective actions to prevent recurrence

(Section 2.3).

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Because the licensee had implemented detailed, conservative corrective

actions in response to a loss of annunciators at a different facility,

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the licensee quickly identified and repaired a failed annunciator power

supply. The corrective actions enabled the licensee to identify the i

number and type of annunciators lost (Section 2.5).

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The inspectors identified a signup discrepancy on radiation work

permits.

This was a noncited violation because the violation had minor

safety significance and because the licensee implemented effective i

corrective actions (Section 2.11).

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i The inspectors determined that licensee personnel performed maintenance

and surveillance activities in accordance with procedures, utilized

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calibrated tools and test equipment, maintained excellent l

communications, and notified the control room prior to performing the

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activity (Sections 3 and 4).

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The inspectors reviewed licensee actions in response to the failure of

• EDG A to stop. The inspectors determined that the EDG system engineer

.i had appropriately addressed a failure of EDG A to shut down in i

October 1991.

Follo sing discussions with the inspectors., the licensee

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implemented interim guidance for operations personnel and developed a.

detailed troubleshooting plan (Section 4.3).

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The inspectors determined that the licensee had detailed, technically

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adequate procedures for conduct of refueling activities. The licensee implemented a proactive process for assessing risk during outage conditions. The inspectors determined that the licensee was well i

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prepared for Refuel VI; however, the li> ansee failed to meet their

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timeliness goals for outage preparation (Section 5).

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Summary of Inspection Findings:

Violation 482/9301-01 was opened (Sections 2.4 and 2.9).

• Violation 482/9301-03 was opened (Section 2.7).

• Inspection Followup Item 482/9301-02 was opened (Section 2.6).

• l Violations 482/9113-01, 482/9126-01, 482/9126-03, and 482/9131-02 were l

closed (Section 6).

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Inspection Followup Items 482/9102-01, 482/9201-01, 482/9201-03, and

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482/9209-02 were closed (Section 7).

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Licensee Event Report 91-022 was closed (Section 8).

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Attachments:

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Attachment 1 - Persons Contacted and Exit Meeting

Attachment 2 - Acroymns Attachment 3 - Diagram of RWST to Recycle Holdup Tank Flowpath

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DETAILS

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1 PLANT STATUS (71707)

The plant operated at 100 percent power throughout the inspection period.

I 2 OPERATIONAL SAFETY VERIFICATION (71707)

The objectives of this inspection were to ensure that the facility was being operated safely and in conformance with license and regulatory requirements and that the licensee's management control systems were effectively

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dischargirg the licensee's responsibilities for continued safe operation. The i

inspectors monitored licensee activities related to residual heat removal (RHR) NOV actuator maintenance, clearance order program reviews,- local alarm response procedure distribution problems, Protection Set III analog channel operational test, loss of annunciators, differential relay testing,

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RWST draindown, potential MOV overthrusts, security drills, increased fuel building pressure, QA operational initiatives, and improper sign-in on l

radiation work permit.

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The methods used to perform this inspection included direct observation of

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activities and equipment, observation of control _ room operations, tours of the

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facility, interviews and discussions with licensee personnel, independent verification of safety system status and Technical Specification limiting

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conditions for operation, verification of corrective actions, and review of

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facility records..

2.1 RHR MOV Actuator Maintenance

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i On January 13, 1993, as electricians installed MOV BN HV88128, RWST to

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RHR B suction valve, they determined that the Limit Switch Rotor 3 contact closure settings specified by the MOV Design Configuration

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Document E-025-00007 were incorrect.

The Limit Switch Rotor 3 contacts

control the. interlock with MOV BB PCV8702B, RHR pump suction from reactor coolant system Loop 4 hot leg. The electricians identified the discrepancy l

when they compared limit-switch contact closure settings on

Schematic E-13BNO3, " Refueling Water Storage Tank to RHR Pump MOV," to the

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limit-switch settings on the MOV E-025-00007 document prior to adjusting the limit switches. The licensee determined that Schematic E-13BN03 contained the

correct contact closure settings, and the electricians adjusted the Limit Switch Rotor 3 contacts on the new actuator in accordance with the electrical-i schematic.

As MOV BN HV8812B traveled from OPEN to CLOSE the MOV E-025-00007-document had-the interlock contacts closed and opening 94 percent FROM FULL OPEN, whereas

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Schematic E-13BNO3 had the interlock contacts open and closing 94 percent FROM

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FULL OPEN. The licensee determined that the limit switch was set correctly

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because, during previous maintenance in November 1992, electricians used i

Schematic E-13BNO3.

If the electricians had set the Limit Switch Rotor 3 i

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contacts incorrectly, MOV BB PCV87028 would not open as designed. The licensee had identified a document error with MOV BN HV8812B in November 1992

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(refer to NRC Inspection Report 50-482/92-31). As a result of the

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November 1992 document error, the licensee initiated Performance Improvement

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Request (PIR) NP 92-0741 to identify a root cause and to implement corrective actions to prevent recurrence.

In response to PIR NP 92-0741, the engineers

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compared the MOV E-025-00007 document to MOV Setpoint Document WCMA-04,

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concentrating on the percentages and the FROM FULL OPEN and FROM FULL CLOSED i

designator transposition error.

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In response to the January 13, 1993, discrepancy, the licensee initiated

PIR NP 93-0028.

Immediate corrective actions included issuing a revision to the MOV E-025-00007 document and reviewing other safety-related valve contact closure diagrams for similar problems. With the exception of MOV BN HV8812A,

RWST to RHR A suction valve, the licensee identified no other contact closure

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diagram discrepancies. The inspectors discussed this error with the personnel involved, including the independent reviewer.

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The inspectors determined that the software program that produces the

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MOV E-025-00007 document data sheets automatically shaded the contact closure diagrams following a set convention; however, MOVs BN HV8812A and BN HV88128

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contact closure diagrams did not follow the convention. The inspectors

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considered the oversight by the engineers to be a weakness. The inspectors verified that the licensee reviewed the electrical schematics, the MOV setpoint document, and the MOV E-025-00007 document data sheets to ensure no

additional errors were present.

'l 2.2 Clearance Order Program Reviews j

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During this inspection period, the inspectors reviewed clearance orders that were older than 6 months for a total of 44 clearance orders.

The inspectors i

reviewed the purpose of the clearance order and discussed the status of each clearance order with licensee personnel. The inspectors categorized the

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clearance orders reviewed below:

Number Subject i

Plant modification requests (PMRs) or work activities I

ongoing

PMRs scheduled to be implemented during the upcoming refueling j

?MRs to be implemented after Refuel VI

PMRs related to construction of the low-level' waste storage

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Shift supervisor clearance orders for outage-related

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components

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Shift supervisor clearance orders for equipment protection t

Low priority clearance orders with no immediate resolution planned

Clearance orders with planned resolutions but awaiting receipt of parts

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The shift supervisor initiated five of the clearance orders to protect

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equipment from damage and to protect personnel from injury.

The shift supervisor initiated three clearance orders related to the equipment used during an outage, for exr lle, securing the containment purge fans after the ventilation lines are b' ak flanged.

The inspectors determined that the licensee used clearance orders appropriately in that every clearance order

provided equipment protection or personnel safety.

Several outstanding older

clearance orders related to components that should be retired in place but were of low priority and required an engineering evaluation.

The inspectors concluded that the licensee made good decisions about prioritizing their work backlog.

The licensee's activities related to resolving outstanding work-related clearance orders demonstrated that the licensee was sensitive to

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long-standing problems.

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2.3 Local Alarm Response Procedure Distribution Problems I

On January 19, 1993, as a shift clerk removed EDG alarm response procedures from the EDG panels, the clerk noticed that the procedure transmittal provided no replacement procedures.

The shift clerk investigated other plant locations

that had local alarm response procedures, determining that procedures were missing from the circulating water screen house, the unit auxiliary transformer, and the EDG rooms. The shift clerk initiated PIR OP 93-0039 and the shift supervisor described that the deficiency revealed significant concerns, including a lack of understanding of the procedure distribution processes for field organizations and a lack of adequate turnover from the Plant Safety Review Committee (PSRC) to Document Services.

The inspectors reviewed the licensee's actions in response to this deficiency.

The licensee immediately replaced the missing procedures at the remote locations. Tne licensee issued a memorandum to all managers and supervisors that receive PSRC procedures listing all Revision 0 procedures released since

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November 1, 1992.

The memorandum specified that personnel should inventory and replace missing procedures by February 20, 1993.

The licensee initiated an investigation to identify the root cause. The personnel who developed the-alarm response procedures were not familiar with the methods used by Document

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Services for distributing documents. The turnover process from.the PSRC-clerks to Document Services personnel did not fully evaluate all tasks performed by the PSRC clerks. Corrective actions implemented to prevent recurrence included:

(1) changing Procedure ADM 07-100, " Preparation, Review, Approval, And Distribution of WCGS Procedures," Revision 51, by March 1, 1993; (2) reevaluating the turnover between PSRC and Document Services by June 1,

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1993; and (3) placing PIR OP 93-0039 and the revised Procedure ADM 07-100 into

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required reading for all personnel involved in developing or distributing PSRC procedures.

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i The inspectors determined that the guidance specified in Procedure ADM 07-100,

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Section 8.0, failed to ensure all procedures were properly updated. The failure to properly update the local alarm response procedures is violation of

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l Technical Specification 6.8.I.a.

liowever, the violation will not be cited because the criteria specified in paragraph VII.B.2 of the NRC enforcement policy were satisfied.

Licensee personnel identified the discrepancy in procedure distributions and immediately determined whether additional procedures were missing. The licensee addressed the potential for generic

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implications and implement 9d a detailed plan to prevent recurrence.

l 2.4 Protection Set III Analog Channel Operational Test i

i On January 25, 1993, instrumentation and control technicians performed f

functional testing of the differant protection tystems. The technicians

.j initiated testing of Protection Set III in accordance with Procedure STS IC-203A, " Analog Channel Operational Test of TAVG, (delta)T, and Pressurizer Pressure Protection Set III," Revision 0, after receiving l

permission to start the test from control room personnel.

The test procedure j

required that operations personnel defeat selected trips for the affected-i channel and required that the technicians place bistables in test (tripped).

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At Step 5.3.1.14, as the technicians tripped the bistables, the technicians determined that Bistable 03-842, BS-2, did not exist in the logic cabinet. At

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the same time operators noticed that Channel IV bistable lights illuminated instead of Channel III. The technicians stopped all activities and exited the i

procedure.

Subsequently, the technici_.a satisfactorily performed the analog l

channel operational test.

The inspectors evaluated this event and reviewed licensee actions.

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inspectors concluded that Steps 5.3.1.15 and 5.3.1.16 provided sufficient j

information for the instrumentation and control technicians to determine that they were in the wrong protection set and limited the potential for an inadvertent reactor trip.

Step 5.3.1.15 required the technicians to verify i

illuminated bistable lights by designator and by status panel grid position

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(row and number).

Step 5.3.1.16 required the technicians to verify specific j

computer points that differed for Protection Sets III and IV.

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The licensee initiated PIR Technical Specification 93-0051 because this event had the potential for causing a reactor trip. The licensee performed a j

detailed investigation concluding that the problem occurred because of a

mental error by the instrumentation and control technicians.

From interview of the technicians and review of the circumstances, the licensee identified

several contributing causes that included:

(1) one of the technicians was qualified but unfamiliar with performance of the procedure, (2) the technicians paraphrased the bistable designator, (3) with the door to i

Protection Set IV open and the control room annunciator in alarm, the technician documenting procedure step completions was distracted since he was i

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I concerned with how to annotate the procedure step deviation, and (4) since a power supply failure (refer to Section 2.5) delayed the performance of

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Procedure STS IC-203A, the technicians felt a " sense of urgency" to complete

the procedure.

The licensee counseled the instrumentation and control j

technicians involved and stressed.to other technicians in the group that could i

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perform this procedure the 1:nportance of good communications.

Since the licensee considered this occurrence to be isolated and the chance for a

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reactor trip to be remote, the licensee placed PIR Technical i

Specification 93-0051 in required reading as the action to prevent recurrence.

The instrumentation and control manager reiterated to instrumentation and

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control personnel the importance of self-checking techniques. 'Approximately

1 year earlier (refer to NRC Inspection Report 50-482/91-36), instrumentation i

and control technicians valved out the wrong pressure transmitter. The root-l cause of that event was miscommunications over the gaitronics communication-l system and inattention to detail. Although this event'is not significant by itself, the inspectors expressed concern because inattention to detail

problems continue. This is the first example of a violation of Technical

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Specification 6.8.1.a (482/9301-01) involving failure to follow an approved

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procedure.

t 2.5 Loss of Annunciators On January 25, 1993, at approximately 10 a.m. (CST), several control room

~j annunciators alarmed.

Because the control panel indications remained steady,

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the control room operators looked at the annunciator power supply indicators

behind the control panels. The operators determined that Multiplexor Power

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Supply 4 had failed. The operators entered Procedure 0FN 00-023, " Loss of j

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NPIS Computer," Revision 8.

While tne power supply was out of service, the delta flux out-of-band alarm was unavailuble; however, the alarm typer

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remained functional.

The operators contacted electricians and issued Work t

Request (WR) 00414-93. Approximately 13.9 percent of the control room l

annunciators were inoperable. The electricians replaced the power supply, and

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the operators declared the annunciators operable at 1:50 p.m.

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The inspectors considered the licensee's actions in response to the Callaway l

Nuclear Station loss of annunciators to be commendable (refer to NRC t

Inspection Report 50-482/92-31). Because of their previous actions, the

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licensee quickly identified and repaired the failed power supply. Also,.the l

licensee easily determined the affected annunciators.

The inspectors reviewed

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the annunciator power supply card work history and found that one annunciator t

power supply card had failed in 1985. The licensee conducted troubleshooting

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on the power supply card and found that the transformer windings had failed.

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From discussions with licensee personnel, the inspectors determined that the l

licensee considered.this an isolated failure.

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l 2.6 Differential Relay Testinq l

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On January 21, 1993, while performing current transformer testing for the

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LDG A differential relay in accordance with Procedure RNM C-1301, l

" Miscellaneous Relay and Meter Equipment," Revision 2, instrumentation and j

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control technicians found jumpers across the Phase A to B terminals and the Phase C to ground terminals. Normally, instrumentation and control i

technicians remove relays and bench test them to assure proper actuation but do not review the field wiring.

The licensee implemented the additional i

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testing to verify that the as-built wiring to the differential relays from the current transformers was correct.

During the testing, the technicians determined that the current required to trip Phase A to ground and Phase B to ground was twice the current specified. When the technicians applied the test

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current from Phase C to ground, the differential current relay did not trip.

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The instrumentation and control technicians initiated WR 00361-93 to_ verify i

that no other jumpers were installed and to verify the wiring was correct

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after removal of the jumpers. The licensee initiated PIR Technical Specification 93-0056 and Reportability Evaluation Request 93-002 so that the root cause could be identified and reportability evaluated.

The inspectors i

determined that, including the EDG A differential relay, the licensee has i

completed 23 as-built wiring checks.

The licensee evaluated the effects of the Phase C to ground short on the operability of the EDG and determined that the EDG remained operable because

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the EDG would start and load during an accident. The licensee determined that

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the event was not reportable because the differential relay provides

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protection to limit massive damage to the EDG should an internal fault occur.

The inspectors determined from review of PIR Technical Specification 93-0056

that the licensee will accelerate their inspections of current transformer

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wiring. At the end of the inspection period, the licensee continued to evaluate the effects on other safety-related equipment.

Followup of licensee

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actions to develop an inspection schedule is an inspection followup _

item (482/9301-02).

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2.7 RWST Draindown

i On February 4,1993, Annunciator 47E, RWST Level Hi/Lo, alarmed because of low

level, 99 percent, in the RWST.

The licensee investigated several potential l

causes for the loss of inventory from the RWST.

Initially, licensee personnel l

. believed that the loss of-inventory occurred because the RHR A discharge l

relief va'.ve had lifted. The operators determined that the loss of inventory i

began at the time of the RHR Pump A inservice test, which commenced at.

l 11:23 p.m. on February 3,1993.

In addition, existing WR 01605-92 identified l

that the valve lifted early and was scheduled for repair during the upcoming

refuel outage.

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Upon further investigation, the licensee determined that the loss of RWST

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inventory was caused by an improper valve alignment. Operators had opened ~

Valve EM V120, safety injection test header to recycle holdup tank isolation,

and shut BN V004, safety injection to RWST isolation, to depressurize the l

safety injection test header to the recycle holdup tanks.

During.the I

subsequent performance of Procedure STS EJ-100A, "RHR System Inservice Pump A

Test," Revision 10, Valve BN V004 was opened.

The procedure did not contain a

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step to close the valve and, thus, it remained open following completion of the test. This valve alignment, EM V120 and BN V004 open, created a flow path from the RWST to the recycle holdup tank.

Additionally, because of cold weather, the licensee used the spent fuel pool

cooling pumps to recirculate the RWST to prevent freezing the lines. The-

recirculating water provided sufficient motive force and pressure to route

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some of the RWST inventory through Valves BN V004 and EM V120 to the recycle

holdup tank (refer to Attachment 3).

The licensee closed Valve BN V004 and verified that the RWST level decrease i

stopped. The licensee initiated PIR OP 93-0084 to assure corrective actions I

would be implemented. The PIR described in detail the initial conditions and the sequence of events. The licensee identified several deficiencies that

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contributed to the event:

(1) Procedure STS EJ-100A required Valve BN V004 to

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be open and did not provide a step for reclosing the valve, (2) operations policy had Val"e EM V120 open and Valve BN V004 closed to allow the test header to be depressurized to the recycle holdup tank with minimal valve

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manipulations and with no written procedure, (3) control room personnel were

busy, consequently, no one carefully considered all possibilities, and (4)

personnel failed to refer to the procedure change forms in front of

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CKL BN-120, " Refueling Water Storage System Lineup," Revision 7, and t

CKL EM-120, " Safety Injection System Lineup Checklist," Revision 8.

E The licensee implemented actions to prevent recurrence. The licensee initiated development of a procedure for safety injection header i

depressurization. The licensee implemented procedure changes to

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Procedures STS EJ-100A and STS EJ-100B, "RHR System inservice Pump B Test,"

Revision 8, to assure Valve BN V004 is closed and Valve EM V120 is open. The i

licensee plans to conduct training on this event and to incorporate the

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changes into the system lineup procedures. The inspectors considered the

failure to establish'a procedure appropriate to the circumstances to be a l

violation of Technical Specification 6.8.1.a (482/9301-03). The inspectors

considered this another example of inattention to detail.

l 2.8 Potential MOV Overthrusts l

On January 19, 1993, while reevaluating Valve Operation Testing Evaluation System test data in response to Industry Technical Information Program

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Item 02102, " Liberty Technologies: 10 CFR Part 21 Notification, Stem Material

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Constants And Torque Calibrator Effects Impact VOTES Testing l

Accuracy - Potential For overthrusts," the licensee questioned the operability-

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of MOV EN HV015, spray additive tank outlet to Containment Spray A isolation, and of MOV EN HV016, spray additive tank outlet to Containment Spray B i

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isolation. The licensee immediately evaluated the operability of the valves in accordance with Procedure KGP-1215, "Evaluatwn of Nonconforming Conditions

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of Installed Plant Equipment," Revision 1.

The design information indicated i

that the yoke arms could not withstand valve operation concurrent with a

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seismic event after using the torque correction factors provided.in the l

10 CFR 21 report.

The operability evaluation determined that-the valve would

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perform its design function without failing. The licensee determined that the

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original _ thrust calculation used conservative accelerations. When

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recalculating the thrust, the licensee used lower, more appropriate accelerations and limited the axis on which the accelerations were applied.

The licensee planned to lower the torque switch settings during the torque switch replacement in Refuel VI, thus reducing the valve thrust.

I 2.9 Increased Fuel Buildina Pressure

On January 14, 1993, as licensed operators investigated the cause of increased

fuel building pressure, they discovered that two dampers required to be opened

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in accordance with Procedure SYS GG-200, " Fuel Building Emergency Exhaust l

Operation," Revision 4, Step 4.3.6, were. closed. Operators immediately opened the dampers.

The licensee normally maintains the fuel building ~at a negative

pressure; however, licensee personnel noticed that, when they opened doors, the doors did not close as required. The licensee discovered that Step 4.3.6

had been inappropriately marked as "not applicable" and initiated

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PIR OP 93-0025 to evaluate corrective actions. The inspectors determined that i

the person performing the procedure read the steps too quickly and believed i

Step 4.3.5, which required closure of the supply dampers to the affected emergency exhaust train, pertained to Train A and Step 4.3.6 pertained to Train B.

The failure to follow procedure is a violation of Technical l

Specification 6.8.1.a (482/9301-01). This is an example of inattention to detail. The inspectors considered this misalignment of concern because the potential existed for the release of unmonitored and unfiltered air.

i 2.10 QA Operational Initiatives j

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During control room observations on February 4, 1993, the inspectors observed a QA auditor preparing a WR.

The auditor, an experienced, former licensed operator, explained that he prepared the corrective WR to resolve an i

instrument ' discrepancy discovered between control room-and local indications during observation of the performance of Procedure STS AL-102, "MDAFW Pump.B i

inservice Pump Test," Revision 15, on January 6, 1993. The auditor explained

'that he had discussed the issue with the-shift supervisor who determined that j

the discrepancy had minor safety significance and did not affect operability or the surveillance results. Consequently, since the auditor identified the discrepancy, the auditor initiated the WR in accordance.with plant procedures.

The inspectors. reviewed the. Wolf Creek Nuclear Operations Corporation QA

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Surveillance TE:

53359 S-1996, " Operations Backshift Activities," dated January 21, 1993. QA Surveillance S-1996 contained Unresolved' Item 93-001

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pertaining to the instrument' discrepancy.

QA distributed the surveillance for

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action to the operations manager and the instrumentation and control

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supervisor. QA forwards the surveillance report to the Vice President of-Plant Operations and the' Chief Executive Officer for information.

The QA manager assured the-inspectors that he could and had, at times, communicated

significant QA findings immediately to senior management.

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Recently, QA changed the method of reporting deviations and violations identified during audits.

Previously, a QA procedure was utilized which.

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issued Quality Performance Violations or Deviations forms based on findings of'

the audit. The Quality Performance Violations or Deviations forms specified the violation or deviation, specified the corrective actions to be initiated

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and c..mpleted, and tracked the completion of the specified corrective actions.

QA hao been criticized by management for specifying the corrective actions i

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rather than letting the group responsible for the findings determine the

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corrective actions. As a result, QA changed the method of reporting deviations or violations by utilizing the plant PIR procedure and form. The

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PIR initiated by QA would require the group responsible to develop corrective action and initiate the corrective actions with a commitment date specified by QA.

QA procedures were changed to incorporate this plant PIR procedure

accordingly.

2.11 Improper Sian-In on Radiation Work Permits The inspectors discovered on December 14, 1992, that security guards incorrectly signed onto Radiation Work Permit 92-008.

The licensee developed Radiation Work Permit 9?.-008 for routine NRC inspector tours in radiologically controlled areas. The inspectors immediately brought the improper signing to

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the attention of the health physics supervisor. The inspectors reviewed the

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PIR initiated and discussed the corrective actions with the radiation protection manager.

The inspectors concluded that the licensee appropriately

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addressed the error and initiated corrective actions sufficient to prevent recurrence. The inspectors received a verbal commitment from the radiation

protection manager to frequently audit the signing of radiation work permits and to track the finding.

The radiation protection manager stated that I

radiation protection personnel would monitor the understanding of radiation work permit requirements by field personnel.

In addition, when the inspectors randomly sampled personnel knowledge of their radiation work permit requirements, they identified no discrepancies.

The inspectors considered this violation of radiation work permit requirements to have only minor. safety-significance. The inspectors determined that the-violation of radiation work

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permit requirements violated Technical Specification 6.8.1.a.

However, the t

violation will not be cited because the criteria specified in

paragraph VII.B.2 of the NRC Enforcement Policy were satisfied.

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2.12 Conclusions

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Electricians identified and corrected a document discrepancy prior to setting l

an MOV limit switch.

The licensee determined that review by engineering

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personnel in response to a previous document discrepancy failed to identify

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this error. The inspectors considered the oversight by-the engineers to be a i

weakness.

The inspectors reviewed clearance orders older than 6 months and determined that the licensee appropriately utilized the clearance orders.

From discussions with licensee personnel, the inspectors determined that the licensee was sensitive to eliminating long-standing clearance orders.

The

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licensee determined that they failed to replace deleted alarm response

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procedures. This was a noncited violation because the licensee promptly i

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corrected the deficiency and initiated thorough corrective actions to prevent i

recurrence.

Inattention to detail resulted in instrumentation and control technicians entering the wrong protection set while performing a Technical Specification required surveillance. This was an example of a violation of Technical Specification 6.8.1.a and indicated that inattention to detail issues continue. The inspectors determined that the potential for a reactor trip was remote because of checks contained in the procedure. The licensee's

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sensitivity to loss of annunciators resulted in the addition of power. supply

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operability indicating lights. The inspectors considered this action

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commendable because it resulted in the licensee's ability to quickly identify and repair the failed component. The licensee inadvertently drained inventory from the RWST to a recycle holdup tank.

The licensee determined.the root

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cause and initiated thorough actions to prevent recurrence. However, the inspectors expressed concern because the occurrence highlighted inattention to detail in updating and developing procedures appropriate to the circumstances.

This was a violation of Technical Specification 6.8.1.a.

The licensee performed an excellent evaluation of the factors that potentially affected the operability of safety-related M0Vs.

Inattention to detail while performing a procedure resulted in the potential for release of unmonitored, unfiltered air. This was an example of a violation of Technical Specification 6.8.1.a.

The inspectors identified a signup discrepancy on radiation work permits. The violation had minor safety significance and was not cited because of the licensee's thorough root cause analysis and effective corrective actions.

3 MAINTENANCE OBSERVATIONS (62703)

The purpose of inspections in this area was to ascertain that maintenance activities on safety-related systems and components were conducted in accordance with approved procedures and Technical Specification. Meb.vds used in this inspection included direct observations of maintenance activities, interviews with personnel, and review of records.

3.1 RHR MOV Actuator On January 13, 1993, the inspectors observed mechanics refurbish the actuator for MOV EJ FCV611, RHR B miniflow valve, using WR 05047-92. The WR provided instructions to refurbish the actuator and implemented the requirements of PMR 04131. The PMR specified changing the motor-pinion gear-to-worm shaft gear ratio from 36.5 to 40 in order to increase the thrust capabilities.. The licensee had calculated that the previous gear ratio provided adequate thrust

for the valve to perform the required safety-related functions; however, the.

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MOV required stroke time had enough margin to allow the licensee to increase

the thrust and meet the stroke time.

Upon reassembly, the licensee did not change the motor-pinion gear because the motor had a 1/2-inch diameter shaft

and the. vendor supplied motor-pinion gear was 3/8-inch diameter.

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The inspectors discussed with licensee personnel why they did not-have the correct motor-pinion gear.

The licensee stated that they had discussed the potential of the motor shaft being oversized with the vendor because their motor developed more torque than the standard motor.

The vendor assured the

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licensee that the motor-pinion gear for a standard M0V motor would fit.

Following discussions with the vendor, the licensee was unable to determine how they were originally supplied with 1/2-inch motor-pinion gears to fit the shaft. At the end of the inspection period, engineering personnel continued to evaluate retaining the present gear ratio or boring the motor-pinion gear

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shaft hole to fit a 1/2-inch diameter shaft. The licensee will complete the

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. engineering disposition prior to the refueling outage.

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The inspectors determined that the qualified mechanics followed the detailed

work instructions and the refurbishment procedure.. The inspectors verified that the mechanics used the proper grease and calibrated tools.

From i

discussions with the mechanics at critical steps, the inspectors determined that they were knowledgeable.

3.2 TDAFW Pump Woodward Governor On January 13, 1993, during performance of the TDAFW operability test, the

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TDAFW pump tripped on mechanical overspeed.

The licensed operator stopped the test, declared the pump inoperable, and initiated a WR to troubleshoot the

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problem.

Instrumentation and control technicians used applicable portions of.

r Procedure STS10-241, " Channel Calibration Auxiliary Feedwater Pump Turbine Speed Control and Indication," Revision 3, to diagnose the deficiency.

While.

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performing Procedure STS IC-241, the technicians verified that the current to voltage signal converter failed to respond.

Subsequently, the instrumentation and control technicians identified a failed dropping resistor.

On January 14,.)93, the inspectors observed instrumentation and control

.i technicians replace the dropping resistor in accordance with work' instructions attached to WR 00187-93.

The work instructions referenced Procedure INC S-0506, " Wire Splicing and Termination of Raychem," Revision 4, and Procedure INC S-0500, " Compression and Connector Standards and Practices,"

Revision 6, for performing environmentally qualified splices and in line wire

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connections, respectively. The procedures provided detailed, explicit guidance for performing the splicing and assembling the connectors.

Personnel i

reviewed the procedures prior to performing the splices and referenced the procedure periodically. A quality control inspector witnessed the repair activities and independently verified critical measurements.. The

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postmaintenance tests demonstrated that the repairs corrected the deficiency.

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The technicians reperformed Procedure STS IC-241, and the operators completed the quarterly inservice test of the TDAFW pump in accordance with Procedure STS AL-103, "TDAFW Pump Inservice Pump Test," Revision 16.

During the test, the TDAFW pump failed to achieve rated speed within 10 seconds as required by the test procedure. The pump took 13 seconds to

achieve rated speed. The licensee determined from review of USAR Table 3.3-5,

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" Engineered Safety features Response Times," and Auxiliary feedwater Pump Design Specification 10466-M021 that the overall response time of 60' seconds includes a 20-second pump start time. Consequently, the licensee

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changed the procedure to allow a 20-second start time and retested the.TDAFW

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pump.

The pump achieved rated speed in 9 seconds.

The inspectors determined

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that the licensee performs the surveillance test annually. During the

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previous two tests, the pump achieved rated speed in approximately 8 seconds, i

i 3.3 ESW and EDG Work Activities

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On January 21, 1993, the licensee conducted a planned maintenance outage for

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both the ESW A and EDG A systems. The inspectors observed the work activities l

listed below:

Number Title i

WR 51574-92 EDG A Lube Oil Filter and Strainer Maintenance

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WR 52185-92 EDG A Relay Panel Maintenance WR 52253-92 ESW A 4160 Vac Circuit Breaker WR 52606-92 EDG A 4160 Vac Feeder Breaker

WR 60005-92 EDG A Lube Oil Cooler Temperature Control Valve i

WR 60007-92 EDG A Intercooler Temperature Control Valve

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From discussions with the craft personnel, the inspectors determined that they

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were knowledgeable and familiar with the work instructions. The inspectors

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verified that the craft personnel utilized calibrated tools and test i

equipment, that they referred to procedures, and that personnel used materials

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designated on the bill of materials.

Quality control personnel witnessed the_

work activities and verified critical measurements.

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3.4 ESW Air Release Valve Repairs

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On January 21, 1993, the inspectors observed mechanics refurbish the motor actuator for MOV EF HV097, ESW A dise..sge air release valve. The machanics refurbished the actuator in accordance with special instructions attached to

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WR 02293-91. During a preventive maintenance grease inspection in June 1991, j

the licensee personnel determined that the operator grease originally supplied

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with the MOV was dark and runny. NRC addressed the operability review of this

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component in NRC Inspection Report 50-482/92-01, Section 5.2.1.

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When the mechanics disassembled the MOV actuator, they noticed scratch marks

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on the worm gear and a 3/4-inch section of one worm thread broke.

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mechanics replaced the grease, the failed parts, and other parts required by

the procedure and common maintenance practice. The' work instructions provided i

excellent guidance to the mechanics.

Exploded view drawings provided easy to

read instructions for reassembly.

From discussions with the personnel, the l

inspectors determined they had a significant amount of experience maintaining i

MOVs. The mechanics used calibrated tools.

Electricians performed both

as-found and as-left Valve Operation Test Evaluation System tests, and the

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operators stroked MOV EF HV097 in accordance with Procedure STS EF-201, "ESW

System Inservice Valve Test," Revision 9.

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3.5 Breaker Maintenance

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On January 21, 1993, the inspectors observed electricians perform corrective maintenance on 4160 kV breakers in response to industry information.

The

licensee had initiated Industry Technical Information Program Item 01576: "GE

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Service. Advice Letter 348.1," in response to a vendor letter. The vendor

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letter described prop spring failures in vertical lift 5 kV, 7.2 kV, and

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13.8 kV breakers. The prop spring provides pressure to the internal

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mechanical mechanisms foll3 wing the closing cycle to assure the breaker

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remains closed. The licensee tracked this information by Industry Technical Information Progrom Item 01327 in response to Information Notice 90-41, l

" Potential Failure of GE Magne-Blast Circuit Breakers and AK Circuit l

Breakers." The licensee determined that 32 safety-related and 57 nonsafety-i related breakers were affected. The licensee replaces the prop spring as each l

breaker undergoes routine preventive maintenance. The licensee planned to

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complete the prop spring replacement during Refuel VII. To date the licensee.

has replaced 21 safety-related and 48 nonsafety-rM ated prop springs.

The vendor recommended that the prop springs be replaced prior to exceeding

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2000 breaker cycles. The licensee determined that the breaker cycles will l

range from 150-700 cycles, depending on the breaker, by the end of Refuel Vll.

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The inspectors reviewed completed WR 02344-91 and verified that the electricians completed the work as specified. The electricians replaced the

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prop springs on the 4160 kV breaker; NB0ll5, ESW A pump breaker; and NB0111, (

EDG A feeder breaker. The electricians demonstrated familiarity with the work

instructions and the purpose of the maintenance activities.

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3.6 Conclusions

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The licensee provided detailed, easy to follow work instruction for performing MOV overhauls.

Qualified instrumentation and control technicians utilized well written procedures for performing corrective maintenance on the TDAFW Woodward Governor control system dropping resistor. The licensee specified i

appropriate postmaintenance tests. After the TDAFW pump failed to achieve the

rated speed within the procedure time requirements, the licensee performed a

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thorough evaluation determining the design startup requirement was 20 seconds.

l The inspectors determined that the licensee performed all aspects of the ESW and EDG work activities in an excellent manner and the work instructions l

provided clear and concise guidance. The licensee implemented appropriate

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corrective actions in response to industry information.

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f 4 SURVEILLANCE OBSERVATIONS (61726)

The purpose of inspection in this area was to ascertain whether surveillance l

of safety-significant systems and components was being conducted in accordance l

with Technical Specifications and approved procedures.

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4.1 Undervoltage Relay protection Test On January 20, 1993, the inspectors observed instrumentation and control

.f technicians perform a monthly functional test of the safety-related bus

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undervoltage protection relays. The technicians performed the test in

i accordance with Procedure STS10-208, "4 kV Loss of Voltage and Loss of Offsite Power Trip Actuating Device Operational Test," Revision 3. -The

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instrumentation and control technicians received permission from the control

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room to initiate the testing and properly communicated the test completion.

The inspectors observed the functioning of the control room logic cabinet and I

the activities of the technician located in the control room. The technicians

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communicated in a clear and concise manner, repeating that he understood the

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information. The inspectors reviewed the completed procedure and verified that all data met specifications.

l The inspectors observed an information tag located on the control-room logic cabinet. The information tag specified that anytime the annunciator alarmed operators.should determine the channel affected prior to resetting the alarm.

After questioning the technicians, the inspectors determined that the licensee used the information tag appropriately. The licensee placed the information tcg on the control room logic cabinet following spurious alarms in October 1992. The guidance reminds operators responding to alarms to note the channel in alarm and report the alarm to instrumentation and control personnel. The technicians replaced a power supply card that eliminated the spurious alarms; however, the licensee will not remove the information tag until they are confident that the replacement card corrected the problem.

4.2 ESW Surveillance On January 22, 1993, the inspectors observed licensed operators perform a postmaintenance operability test of ESW Pump A in accordance with Procedure STS EF-100A, "ESW System Inservice Pump A Test and ESW A/ Service Water Cross Connect Valve Test," Revision 9.

The licensee haJ scheduled the ESW Train A outage to coincide with the scheduled quarterly inservice testing of the pump and valves to limit the outage time.

The inspectors observed the licensed operator perform the surveillance. The surveillance required coordination among the control room, the auxiliary building, and the ESW pump house. The inspectors determined that the procedure was well written and detailed and that the personnel exhibited excellent communication / coordination. The licensed operator used calibrated test equipment and all data met specifications.

4.3 EDG Operability Test On January 22, 1993, following completion of work activities on EDG A, the licensee vented the EDG cooling water system in accordance with Procedure SYS KJ-121, " Diesel Generator NE01 and NE02, Lineup for Automatic-Operation," Revision 12, step 3.1.7.

After operators started and fully loaded the EDG, the nonlicensed operator monitoring EDG conditions reported that the intercooler temperature indicated greater than 200 F.

The control room-immediately shut down the EDG. The inspectors interviewed licensee personnel who stated that the intercooler system temperature dropped rapidly seconds after EDG A received the stop signal. The inspectors determined from

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discussions with licensee personnel that personnel observing the EDG believed that the intercooler temperature control valve had stuck closed then popped open. The system engineer had decided that the temperature control valve would be repaired and the power pills replaced during the outage because of the high temperature in the intercooler system. The licensee' identified no additional temperature problems during the subsequent maintenance run or operability test.

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On January 22, 1993, the inspectors observed licensed operators set up and perform an operability test of EDG A in accordance with Procedure STS KJ-005A,

" Manual / Auto Start Synchronization, and Loading of Emergency Diesel Generator NE01," Revision 17. The inspectors observed continuous communication between the control room and the EDG room.

The operators followed the well-written detailed procedure, and all data met specifications.

From discussions with the licensed operator, the inspectors determined he was knowledgeable about the procedure sequence. The inspectors noted that the control room rtaff used the repeat back technique and demonstrated excellent communications during evolutions.

While performing the operability test, EDG A did not stop when operators pressed the control panel stop switch. After the turbine building watch contacted the control room, the licensed operators again pressed the stop switch, whicn stopped the EDG.

From discussions with the turbine building watchstander, the inspectors determined that approximately 45-60 seconds passed between the stop commands. The inspectors determined that the licensee suspects that this problem was caused by sticking excess flow check valves and a sticking in-line check valve in the EDG starting air system.

The excess flow check valves prevent a loss of air from the starting air tanks in the event the 3/8-inch air lines to the local control panel instruments experience a catastrophic failure. The in-line check valve is located upstream of the shutdown air tank. The vendor designed the in-line check valve to prevent bleed off of the shutdown air tank following a loss of starting air so that the EDG could still be secured from the control room.

The inspectors reviewed the work history associated with the excess flow check valves. The inspectors determined that the licensee identified this condition in September 1991 following completion of an EDG test. When initially identified, the licensee had initiated PIR OP 91-0608 because personnel had closed the inlet and outlet isolation valves and opened the bypass valve for the excess flow check valves without changing the valve lineup. The licensee used this configuration to prevent the excess flow check valves from slamming shut when the operators started the EDG, which caused a loss of local indication.

The licensee initiated WRs 04018-91 to 04021-91 documenting this condit' ion for each excess flow check valve.

Also, the licensee placed WR tags on the excess flow check valves that stated, " Valve goes shut on a diesel start, must manually equalize pressure downstream to reopen valve."

In 0 tober 1991, instrumentation and control personnel placed snubbers in the instrument air lines to prevent cycling the gauge.

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i In October 1991 the system engineer performed troubleshooting to identify the

reason EDG A failed to stop when operators pressed the stop pushbutton

following the maintenance test run.

The licensee:

(1) monitored the shutdown i

boost cylinder delay time to verify that shutdown air was supplied for at least 140 seconds, (2) verified that no oil blew from the three-way booster valve vents, and (3) determined that the mechanical components operated smoothly.

The licensee installed a temporary gage on the shutdown air tank and determined that the air pressure slowly bled off. When the system

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engineer observed the EDG, as operators stopped the engine, he noticed that

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the fuel racks failed to go to zero. The system engineer determined that the

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excess flow check valves and the in-line check valve stuck, which allowed the shutdown air tank pressure to decrease.

Because of the troubleshooting

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results, the EDG system engineer initiated Memorandum MA 91-0367 to-the-j manager, operations notifying him that the excess flow check valves were sticking.

Further, the system engineer recommended that the bypass valve

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around the inservice excess flow check valve be cracked open to equalize

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downstream pressure during startup transients or have the operators manipulate the bypass valves. The system engineer ordered internal parts and submitted

an engineering evaluation request to have removal of the valves evaluated.

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However. he cautioned that the N-stamped parts had long lead times.

t in July 1992, the licensee developed Engineering Evaluation Request 91-KJ-06

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that recommended drilling a 1/16-inch hole in the center of the check valve poppet to lower the differential pressure.

The modification would facilitate

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reseating the excess flow check valves and eliminate operating the bypass

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valves.

The inspectors determined that the parts had not been received at the time of this event.

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The inspectors reviewed licensee activities in response to the failure of

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EDG A to stop as required, and the inspectors asked the licensee whether the i

failure to shut down made the EDG inoperable.

The inspectors determined that j

the EDG failure to stop on January 22, 1993, was only the second occurrence of this phenomenon.

The inspectors verified from review of licensee data that

the system engineer initiated procurement documents in November 1991. The licensee was having trouble obtaining the appropriate valve internals and 0-rings.

In response to the inspectors' inquiries regarding operability of

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the EDG during an emergency trip signal, the licensee demonstrated that the

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emergency trips provide protective trips to prevent massive damage to the EDG.

The licensee believed that the sticking excess flow check valves caused the

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mal function. However, in response to the inspectors' concerns, the licensee developed a troubleshooting plan and committed to complete the troubleshooting during the refueling outage. Until the outage, to ensure proper actions would be implemented, the licensee developed a memorandum describing the problem and specifying alternate means to secure the EDG.

To enhance personnel understanding, the operations manager attached the engineering description and the troubleshooting plan to the memorandum.

The operations manager made the memorandum " essential reading." Operators onshift are required to read

" essential reading" prior to standing watch. During a conference call. with the Office of Nuclear Reactor Regulation and Region IV, the licensee described that when EDG alarms are received, an operator is dispatched to the EDGs to I

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identify the problem. For a loss of aii, the annunciator alarms long before

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the air pressure decreases below the air pressure needed to shut down the EDG.

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From further discussions with licensee personnel and review of the procedures-i at the local panels, the inspectors determined that the licensee modified the local alarm response procedures. The inspectors considered the licensee's

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actions in response to this event appropriate.

l 4.4 Conclusions

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-ii The inspectors observed good communication between test performers during conduct of a surveillance test. The inspectors evaluated the licensee's use

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of an information tag, determining that the licensee used the tag appropriately. The inspectors determined that licensee personnel used i

calibrated test equipment and excellent communication techniques while performing the ESW and the EDG operability tests.

Following maintenance on i

EDG A,.the intercooler water temperature increased above 200 F.

The licensee

initiated a PIR to address corrective actions. Upon completion of the EDG operability test, the EDG did not stop on the first attempt, and licensed i

operators prc~ 'ied another stop signal to shut down the EDG.

The inspectors

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this event occurred one time previously and that the engine determined it t could not be.epaired because of parts unavailability.

From previous

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troubleshooting, the licensee believed the problem to be the excess flow check valves. Hcwever, following discussions with the inspectors, the licensee developed an extensive troubleshooting plan and committed to perform the-

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troubleshooting during Refuel VI. As interim compensating measures, the

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licensee initiated a DIR, inodified procedures, and heightened the operators

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understanding of th'.. issue.

5 PREPARATION FOR REFUELING (60705)

I 5.1 Procedure Reviews The inspectors performed this inspection to evaluate the licensee's l

requirements for conduct of refueling operations and for control of plant i

conditions during the outage.

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The. inspectors reviewed the following procedures for technical adequacy:

FHP 01-001, "New Fuel Receipt," Revision 15 l

FHP 02-001, " Refueling Procedure," Revision 11

FHP 02-004, " Refueling Cavity Exclusion Area," Revision 1 e

FHP 02-011, " Fuel Shuffle and Position Verification," Revision 13

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FHP 03-006, " Fuel Transfer System Operating Instructions," Revision 4

FHP 03-007, " Spent Fuel Pool Bridge Crane Operating Instructions and

Daily Checks," Revision 15 y

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The procedures provided clear, concise guidance for performing the activities.

The notes, cautions, and precautions provided clear limits for performance of j

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ensure the correct conditions existed for the performance of the activity.

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5.2 Risk Assessment

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while shutdown. The licensee implemented a process prior to Refuel VI to

determir.e the level of risk during the outage under different system configurations. The licensee assessed the risk in accordance with

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Procedure ADM 01-249, " Outage Risk Management," Revision 0.

The procedure provided guidance for assessing reactivity control, core cooling, electrical.

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power availability, inventory control, and containment integrity. The procedure required a risk assessment to be performed addressing defense in

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depth prior to the outage. The procedure required a daily shutdown risk

assessment to be performed to assess conditions and outage' schedule changes:

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that could affect plant safety. The procedure includes an equipment checklist to assure that the appropriate equipment is addressed.

Emergent work outside the scheduled outage scope will be evaluated in accordance with Procedure ADM 01-249 to ensure that an acceptable level of risk will be maintained. The procedure requires a postoutage review to evaluate the j

program effectiveness.

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The inspectors interviewed licensee personnel who participated in the risk

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assessment and reviewed'the report'that resulted from the review of the outage schedule by the risk assessment team.

From review of the outage schedule, the licensee developed a contingency plan to provide a backup generator to supply

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power to the equipment hatch hoists at the beginning of the outage.

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of high decay heat loads, the time to boil is 34 minutes. This contingency

plan provides for improved safety and reduced risk.

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5.3 Outage Preparations

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-The inspectors reviewed the licensee's controls established for conduct of the outage and establishment of the outage organization.

Procedure ADM 01-108,

" Outage Planning and Implementation," Revision 8, specified milestones for

development of items (work activities, PMRs, testing, inspections, etc.) to be worked during the outage and provided a description of the outage

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organization.

Procedure ADM 01-108 described the function and responsibilities of the outage shift managers and the. containment coordinators.

Further, the procedure specified that morning and evening turnover meetings be conducted and specified the information required to be i

discussed and personnel who should attend.

Procedure ADM 01-108 required that a postoutage critique be implemented and outlined. items required to be addressed. The inspectors interviewed personnel and reviewed licensee documents to evaluate the licensee's readiness for Refuel VI. The licensee defined times for conduct of meetings, developed laydown areas inside the containment building and the turbine building, assigned outage window managers, defined a policy for control ~ of work hours including overtime, and assigned the containment coordinators and outage shift managers. The inspectors determined that the licensee developed the outage window manager

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concept to improve control of work activities related to specific areas, (e.g., EDG overhaul, MOV testing).

The licensee assigned the outage shift managers, the containment coordinators, a Nuclear Safety Engineering representative, and an outage group supervisor to conduct, 3 months prior to the outage, the outage risk assessment and determine shift start times, outage meeting times and attendance.

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The inspectors determined that the licensee did not meet all goals for preparation of outage items as required in Procedure ADM 01-108.

On February 13, 1993, the inspectors determined that the outage work activities were approximately 55 percent prepared, 51 percent of the parts received, 57 percent of the WRs were prepared, and 47 percent of the PMRs were approved.

The licensee had engineering completed for 85 percent and had prepared work

packages for 11 percent of the MOVs to be worked during the outage that begins March 4, 1993.

5.4 Conclusions The inspectors reviewed selected refueling procedures, determining they were technically adequate, and provided good guidance for performing the activities. The licensee established an outstanding program for evaluatino levels of risk through01t the outage. A risk assessment team developed a formal contingency plan to lower the risk during a very high risk period.

The licensee prepared for the outage in accordance with their programs.

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inspectors determined that the licensee did not meet their established goals; however, the licensee should be prepared for the outage prior to March 4, 1993.

6 FOLLOWUP ON CORRECTIVE ACTION FOR VIOLATIONS (92702)

l 6.1 (Closed) Violation 482/9113-01:

Failure to Lock Valve in Accordance With procedure j

NRC issued this violation because the locking device for Valve AL-V063, 1DATW pump discharge to Steam Generator D, was improperly attached.

The licensee's immediate corrective actions included locking Valve AL V063 in the correct position and performing a walkdown of accessible locked valves.

The licensee identified two additional valves correctly positioned but not locked.

The licensee issued a memorandum to shift supervisors discussing the locked valve discrepancies.

The memorandum recommended that the shift supervisors discuss the significance of locked components with their crews and how to inspect locked valves.

As a long-term corrective action, the licensee implemented weekly inspections of locked valves.

The licensee inspects two or three systems weekly, verifying that the accessible valves are properly locked.

The licensee assigned a licensed operator to walk down all inaccessible locked valves prior to the plant startup from Refuel V to assure that they were properly secured.

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The inspectors revicwed the locked valve audits and verified that the licensee corrected several deficiencies identified during the initial audits.

From discussions with licensee personnel, the inspectors determined that no additional problems were identified during the audits following the initial reviews.

The inspectors determined that the licensee formalized the weekly audits in October 1992 by issuing Procedure STN LV-001, " Weekly Audit of Selected Accessible Locked Valves," Revision 0.

From discussions with licensee personnel, the inspectors determined that the procedure will not be conducted during Modes 5, 6, or E (no fuel in the reactor vessel) because the locked valve log is not required to be maintained during outage activities.

This situation is acceptable because all locked valves are required to be verified in their proper position prior to heatup above 200of.

6.2 1_ Closed) Violation 482/9126-01:

Inadeouate Emergency Operatinq Procedure This violation documented the failure of Emergency Operating Procedure LMG E-0, " Safety injection," Revision 2, to specify contingencies to assure that an inoperable contial room ventilation train could be isolated within 30 minutes, as specified in the control room habitability analysis.

The licensee changed Procedure EMG E-0 to instruct the operator to refer to Procedure SYS GK-122, " Manual Control Room CRVIS Line Up," when the control room ventilation system filtration fan fails. The licensee revised Procedure SYS GK-122 to instruct personnel to isolate the affected ventilation train. The licensee revised the appropriate alarm response procedure providing the same guidance.

The licensee conducted an evaluation that resulted in increasing the response time from 30 minutes to 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> without significantly increasing the dose received by control room operctors.

The licensee committed to review accidents and transients in the USAR to identify other activities that take credit for operator actions.

The inspectors verified that the licensee implemented the procedure changes described.

I In October 1992, the licensee requested and was granted an extension from September 1992 to february 1, 1993, to complete the reviews.

The licensee requested the extensions because the licensee expanded the scope of the review from timed operator actions to any operator action such as vent, isolate, or close.

The review identified several changes to selected procedures and

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The inspectors verified selected changes were l

implemented.

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6.3 (Closed) Violation 482/9126-03:

Failure to Control Work Practices l

This violation documents the f ailure to properly control work activities to

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prevent making equipment inoperable. On September 9 and 10, 1991, with the plant in Mode 1, personnel inadvertently rendered both control room ventilation trains and auxiliary building emergency exhaust trains inoperable when they removed five control room ventilation damper inspection covers for preventive maintenance inspections. The licensee attributed the root cause to

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inadequate work control and the failure of control room operators to understand the work activity. The work turnover process contained several additional weaknesses.

Immediate corrective actions conducted by the licensee included the restoration of the damper covers. On September 13, 1991, the licensee

performed a pressure test with the five affected damper covers removed. The

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licensee stationed dedicated personnel near each of the damper covers. The licensee determined that the control room could not be pressurized as required

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by Technical Specification 3.7.6.

An engineering evaluation of the test determined that the Train B ventilation system was also inoperable. The test also verified that the requirements of Technical Specification 3.7.7 for the auxiliary building ventilation could not be met for either train. The licensee developed a checklist to be used by craft personnel during system

restoration, and the licensee stressed the importance of a proper shift turnover.

To pictent recurrence of this type of failure, the licensee formalized the

procedure for performing maintenance on ventilation dampers.

The inspectors

verified that the procedure cautioned craft personnel about the ability to

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make the control room ventilation systems inoperable.

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6.4 (Closed) Violation 482/9131-02:

Inadequate Corrective Actions Related to

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Repair of a Safety-Related Flow Transmitter This violation documented the failure of the licensee to take timely and adequate corrective actions for repair of a flow transmitter used to verify performance of a safety-related pump. The licensee provided training to 830 personnel on the corrective action program and 330 personnel on PIRs.

The inspectors verified that this particular event was included as an example during the training.

The inspectors determined that the licensee presented the PIR lesson plan to supervisors and managers.

In addition to providing a review of the process,

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the lesson plan stressed the responsibilities of management to improve the company culture and attitude toward use of the corrective action program. The lesson plan stressed the importance of interviewing the PIR initiator. The inspectors verified that the corrective action program training provided guidance on:

(1) the program purpose and the need to implement corrective actions, (2) situations that require corrective actions, (3) the role of employees, (4) how an effective corrective action program would improve licensee performance, and (5) the mechanics of the program.

6.5-Conclusions The inspectors determined that licensee corrective actions in response to violations were appropriate.

Development of a procedure to evaluate the status of accessible lock valves and review of all action statements in the.

USAR demonstrated sensitivity to performing thorough corrective actions.

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7 FOLLOWUP (92701)

7.1 (Closed) Inspection followup Item (482/9102-01): Reactor Vessel Head Vent System (RVHVS) Reanalysis NRC initiated this inspection followup item to ensure that licensee corrective

actions would be monitored.

In January 1991, the nuclear steam supply system i

vendor notified the licensee that their RVHVS may not be qualified under all

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circumstances. Specifically, under some circumstances pipe stresses, support loads, and valve end loads may exceed industry allowables because of large

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thermal stresses.

The licensee determined that the RVHVS needed to be

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redesigned and initiated PMR 03666 to accomplish the task.

The inspectors reviewed the licensee's 10 CFR 50.59 unreviewed safety question evaluation, the engineering disposition that described the scope and purpose

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of the modification, and the field drawings for PMR 03666.

The design change separates the vent paths into two independent paths, adds one additional pipe whip support, and strengthens one existing support.

The inspectors found the proposed actions to be satisfactory. Also, the inspectors will verify the as-built configuration of the modification that will be implemented during Refuel VI.

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7.2 (Closed) Inspection Followup Item (482/9201-01): USAR Revisions-The inspectors initiated this followup item to assure that specific USAR deficiencies would be corrected.

The inspectors identified four separate USAR

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discrepancies and minor discrepancies in a design calculation.

The inspectors verified that USAR Change Requests 060, 109, 110, and 111 incorporated the required changes. Additionally, the inspectors reviewed the design calculation retision to ensure that the changes were incorporated.

From discussions with licensee personnel in the Regulatory Services Department, the inspectors determined that the above USAR change requests had gone to print and will be included in the March 1993 USAR update.

7.3 (Closed) Inspection Followup Item (482/9201-03):

Relief Valve Mounting Position The inspectors initiated this item to ensure followup of the licensee's resolution of the required orientation for horizontally oriented EDG lube oil

pump discharge pressure relief valves. As documented in NRC Inspection

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Report 50-482/92-01, the licensee had demonstrated that the valves remained operable.

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The inspectors reviewed the evaluations for WRs 01999-92 and 02000-92. The licensee concluded that installing the relief valves upright instead of horizontal would optimize reliability and maintenance of-the relief valves.

The evaluation documented that altering the relief valve configuration would

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reduce some pipe stresses. The evaluation properly referenced installation

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specifications and specified a visual inspection instead of a pressure test because of low system pressures. The inspectors determined that the relief valves will be rotated to a vertical position during the Refuel VI outage.

7.4 (Closed) Inspection Followup Item (482/9209-02):

Review of the Bases for

not Reorienting the Downstream RVHVS Valves The inspectors initiated this item to document the lack of information related to the licensee's withdrawal of a commitment to rotate the RVHVS valves.

In May 1990, the licensee initiated engineering studies to evaluate reorientation of the their Target Rock valves.

The licensee planned to rotate the valves during Refuel V (refer to NRC Inspection Report 50-482/90-22).

In a letter to NRC dated May 13, 1991, the licensee extended the date for completing the

RVHVS valve modification because field walkdowns would be necessary to

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identify potential interferences. The licensee stcied the valves would be reoriented prior to the plant startup following Refuel VI.

Subsequently, in July 1992 the licensee submitted a letter to NRC Region IV retracting their commitment to rotate the RVHVS valves. The licensee provided information stating that the first set of RVHVS valves in series were not subject to the sr irious opening phenomenon. The RVHVS valves have two trains with two valves in series in each train.

The licensee identified four situations in w! ich the downstream, second set of RVHVS valves could be subjected to sptrious opening. The four situations included:

(1) deliberately opening, (2) operability testing, (3) an electrical ground fault, and (4) inadvertent operation.

During this inspection period, the _ inspectors performed field walkdowns and reviewed the documentation that supported the licensee's decision not to rotate the RVHVS valves.

The inspectors reviewed the licensee'a basis for resolving the four concerns and identified no problems. The licensee tests the valves in Modes 5 or 6 under conditions which could not create a pressure transient.

Deliberate opening is controlled by plant emergency procedures.

A direct current ground f ault could not generate sufficient current to cause l

solenoid actuations.

Inadvertent opening could not occur because of the handswitch position on the control board.

8 ONSITE REVIEW 0F A LICENSEE EVENT REPORT (92700)

1 Closed) Licensee Event Report 482/91-022: Technical Specification Violation - Failure to Verify that the EDGs are Capable of Rejectinq 1352 kW On November 12, 1991, the licensee determined that they had not verified that the EDGs could reject 1352 kW as specified in Technical Specification 4.8.1.1.2.g.2.

The 1352 kW load value was the designed load of an operating ESW pump under full-flow conditions.

Surveillance Procedures S15 KJ-001A, " Integrated D/G and Safeguards Actuation Test -

Train A," Revision 10, and STS KJ-001B, " Integrated D/G and Safeguards

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Actuations and Test - Train B," Revision 10, required verifying the ability of

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the EDG to reject the ESW pump load but failed to specify that the load be

greater than or equal to 1352 kW.

Immediate corrective actions inciuded determining when the licensee had last

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L met the Technical Specification surveillance requirements and demonstrating that both EDGs could reject the required load of 1352 kW (refer to NRC

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Inspection Report 50-482/91-31, Section 6.4).

As part of long-term corrective i

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actions to prevent recurrence, the licensee decided to review other numeric acceptance criteria contained in the Technical Specification to assure that no similar problems existed. The licensee determined that all other Technical Specifications that had numerical values that must be verified were properly verified by a test procedure. The licensee decided that the intent of the

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Technical Specification was to reject the largest single load, consequently,

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the licensee submitted a Technical Specification change to eliminate the numerical value.

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ATTACHMENT 1

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1 PERSONS CONTACTED P. D. Adams, Supervisor, Reactor Engineering M. R. Barbee, Supervisor, Engineering, System Engineer Electrical R. S. Benedict, Manager, Quality Control A. B. Clason, Supervisor, Maintenance Engineering T. F. Deddens, Manager, Outage M. E. Dingler, Manager, Nuclear Plant Engineering Systems, Support C. W. Fowler, Manager, Maintenance and Modifications R. B. Flannigan, Manager, Nuclear Safety Engineering D. E. Gerrelts, Manager, Instrumentation and Control S. E. Hedges, Supervisor, Engineering, System Engineer Auxiliary N. W. Hoadley, Manager, Equipment Engineering R. W. Holloway, Assistant to Vice President, Operations D. Jacobs, Supervisor, Mechanical Maintenance W. M. Lindsay, Manager, Quality Assurance J. D. Lutz, Regulatory Compliance Engineer T. S. Morrill, Manager, Radiation Protection W. B. Norton, Manager, Technical Support L. D. Ratzliff, Supervisor, Engineering, System Engineer Component j

F. T. Rhodes, Vice President, Engineering T. L. Riley, Supervisor, Regulatory Compliance j

J. D. Stamm, Manager, Plant Design Engineering l

J. D. Weeks, Manager, Operations S. G. Wideman, Supervisor, Licensing i

M. G. Williams, Manager, Plant Support The above licensee personnel attended the exit meeting.

In addition to the personnel listed above, the inspectors contacted other personnel during this inspection period.

2 EXIT MEETING I

An exit meeting was conducted on February 16, 1993. During this mer e

i inspectors reviewed the scope and findings of the report.

The lict

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not identify as proprietary any information provided to, or reviewed D3

'b inspectors.

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ACRONYMS EDG emergency diesel generator ESW essential service water MOV motor-operated valve PIR performance improvement request PMRs plant modification request PSRC Plant Safety Review Committee QA quality assurance RHR residual heat removal RVHVS reactor vessel head vent system RWST refueling water storage tank TDAFW turbine driven auxiliary feedwater USAR Updated Safety Analysis Report WR work request

ATTACHMENT 3

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REFUELING WATER STORAGE TANK

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RECYCLE HOLDUP TANK