IR 05000313/1989045

Insp Repts 50-313/89-45 & 50-368/89-45 on 891116-1231. Violations Noted.Major Areas Inspected:Plant Status, Followup of Events,Operational Safety Verification, Temporary Instruction,Maint,Surveillance & Personnel Errors

ML20006D472
Person / Time
Site:	Arkansas Nuclear
Issue date:	01/30/1990
From:	Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20006D469	List: IR 05000313/1989045 ML20006D467 ML20006D470
References
50-313-89-45, 50-368-89-45, NUDOCS 9002130290
Download: ML20006D472 (18)

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APPENDIX B

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U.S. NUCLEAR REGULATORY COMMISSION-

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REGION IV

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NRC-Inspection Report:

50-313/89-45 Licenses:. DPR-51 i

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50-368/89-45 NPF-6-

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f Dockets:: 50-313-50-368

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x Licensee: Arkansas Power & Light Company (AP&L)

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P.O. Box 551

a-Little Rock. Arkansas: 72203

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Facility Name: -NrkansasNuclearOne(ANO), Units 1and2 q

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Inspection At: ANO Site, Russellville, Arkansas Inspection.Conductedi November 16 through' December 31, 1989

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Inspectors::

C., C. Warren Senior Resident Inspector -

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Project Section A. Division of Reactor Projects

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R. C. Haag, Resident Inspector, Project Section A, Division of Reactor Projects C. CJ Harbuck NRR Project Manager

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Approved:

D. Oc/Lnamberlain, cr 1ef, Project.

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Date Section A Division of Reactor Projects

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Inspection Summary-Inspection. Conducted November 16 thro' ugh December 31, 1989 (Report 50-313/89-45; s

50-368/89-45)

Areas-Inspected:. Routine, u'nannounced inspection including plant status,-

- followup of events,1 operational safety verification, a temporary instruction,.

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maintenance, surveillance, Unit 1 outage activities, and personnel errors.

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~ Results: :Two apparent violations of NRC requirements were identified:

Failure

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to maintain electrical tape splices in accordance with the environmental

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. ualification program (Section 6.1), and failure to comply with procedural q

requirements while performing maintenance activities (Sections 3.2 and 6.0).

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One inspector followup item involving the licensee's corrective actions for

. Unit'2 moderator dilution event is discussed in the report (Section 3.3).

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Strengths:

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Outage management continued to improve during the Unit 1 midcycle outage.

Strengths that were evident during the recent Unit 2 refueling outage were lalso observed during the Unit 1 outage.

Specifically, the control of reduced t

reactor coolant system (RCS) inventory operations and the RCS hydrogen peroxide flush were examples of. improvement from past Unit 1 outages. The initiative to resolve longstanding deficiencies in the Unit 1 secondary plant is an early

indication of management's overall commitment to improve AN0's operation and (performance.

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Concerns:

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. Personnel errors continued to have an impact on plant operations.

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during this inspection report period led to a plant trip (Section 9.3), an engineered safeguards actuation (Section 9.2), and an interruption of

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decay heat removal- (DHR) flow (Section 9.1). Management's actions to reduce personnel errors-are being closely monitored by the inspectors.

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.The corrective action to resolve a concern over the control of lifted electrical leads was ineffective.

In addition, management was unaware that the actions they had initiated to resolve the concerns of lifted leads were not being-implemented.

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The-response to the Unit 2 moderator dilution event lacked overall coordination. Management attention-is needed to ensure that the final

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-resolution to this event provides the operators with sufficient guidance to prevent recurrence.

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. Inconsistencies were noted with level of housekeeping standards for some areas.of~theplant(Section4.0).

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. Ongoing concerns exist with licensee actions on resolving longstanding low priority neintenance items. An example is noted in Section 6.0 for repair of ventilation fans, e

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J DETAILS j

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1.0 Persons Contacted

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• N. Carns, Director Nuclear Operations K.' Coates,. Unit 1 Maintenance Manager A. Cox, Unit'l Operations Manager R. Eddington, Unit 2 Outage Manager

• E. Ewing, General Manager Technical Support and Assetsment

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• R. Fenech, Unit 2 Plant Manager L. Gulick, Unit 2.0perations Manager

• L. Humphrey, General Manager, Nuclear Quality

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• J. Jacks, Nuclear Safety and Licensing Specialist

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• R. King, Plant Licensing. Supervisor

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J. Kowalewski, Mechanical Engineer l

• J. Mueller, Manager, Central Support

• A. Sessoms, Plant Manager, Central

• J. Vandergrift, Unit 1-Plant Manager

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J. Waxenfelter,-Unit 2 Maintenance Manager

• Present at-exit interview.

.The NRC inspectors also contacted other plant personnel, including -

operators, engineers, technicians, and administrative personnel.

2.0 Plant Status-(Units 1 and 2)

-Unit'l escalated power to 74 percent at the beginning of the inspection i

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period and remained at that power-level until the. unit was shutdown on-November 26, 1989, for a scheduled midcycle outage. The unit was restarted

.on December 23, 1983, and operated at power levels up to 80 percent until December 28, 1989, when the unit-trippedEdue to a'feedwater transient.

The unit was restarted on December 29, 1989, and reached 80 percent power-operations at the end of the inspection period.

Unit 2 went critical on November 17, 1989, after completion of the seventh refueling outage. The unit reached 100 percent power operations on November 29, 1989, and remained at or near that' power level until December 7,1989, when power was reduced to 80 percent for condenser tube n

leak repairs. Power was increased to 100 percent on December 9,.1989, and

' remained at that level'until the unit tripped on December 31, 1989,

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~because of a feedwater transient.

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3.0 Followup of-Events- (Units 1 and 2) (93702)_

3.1 Design Calculations for Unit 1 "B" Reactor Building Spray Pump While reviewing design basis documents for the DHR system as part of its

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design basis documentation program, the licensee identified errors and inconsistencies related to the determination of the available net

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the containment spray (NPSH) to the low pressure injection (LPI) pumps and positive' suction head (

CS) pumps during the containment sump recirculation l

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mode of operation. Two examples of the errors and. inconsistencies noted-

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were:

(1).the higher nominal level of the borated water storage tank was'

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the value used'in all' calculations rather than the Technical

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Specification (TS) minimum required level (this represented an -

85,000 gallon reduction in available water and a 1.4 foot reduction in sump

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water level); and.(2) the-LPI and CS flows permitted by the Unit 1:

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h emergency operating procedure (EOP) were greater than the flows assumed in

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the NPSH calculation. AP&L initiated Condition Report (CR) 1-89-0634 on

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December 14,1989, and, subsequently, on December 15 determined that the

"B" spray. pump would not have sufficient NPSH AP&L made a 10 CFR 50.72 l

report to the NRC and designated the resolution of the spray pump p

operability as a heatup restraint. The licensee designated 15' action items

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to resolve the CR.

These were:

(1) Determine root cause.

Long-term action (2) Revise NPSH calculations.

Heatup restraint

(3) Revise containment water level Heatup restraint calculation.

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(4) Revise emergency sump vortexing Heatup restraint calculation.

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(5) Revise E0P guidance to throttle Heatup restraint LPI and CS flow during

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recirculation to acceptable values.

s (6) Review containment pressure /

Heatup restraint-

temperature analysis to evaluate impact of reduced

LPI and CS flow.-

(7) Determine if.the incore detector Heatup restraint tunnel door can be left open during operation to preclude trapping water in the tunnel

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and reactor vessel cavity.

(8) Prepare engineering evaluation Heatup restraint report to document the acceptance criteria of the short-term actions.

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(9) Consider raising the TS limits Short-term on Borated Water Storage

Tank (BWST) level.

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(10) Develop a long-term corrective '

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action plan to systematically

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revise and optimize all related calculations.

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(11)RevisetheSafetyAnalysisReport.

Long-term 1(12)DocumentapplicabilitytoUnit2.

Short-term

(13)-Implementadministrative Heatup restraint controls-to ensure that the

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incore tunnel door is left open during power operations.

(14) Expedite resolution by performing Long-term

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relevant' calculation assuming operation above 80 percent power.

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~(15) Review design basis of ventilation Criticality restraint system criticality restraint for the reactor vessel cavity and

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incore detectors to ensure thatL propping the incore tunnel door open 4; inches would not adversely affect the ventilation flow, The NRC: inspector. verified that the above noted heatup restraint items had ry

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' been adequately dispositioned by AP&L prior to heat up of the unit. This verification' consisted of discussions with the cognizant representative and review of the below listed documentation:

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Temporary Modification 89-1-028, dated December 18, 1989, to securely l

prop.open the incore tunnel door, about 4 inches.

It was noted that

the door would still provide adequate restriction to personnel access

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for high radiation protection.

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Engineering Report No. 89R-1006-01,. dated December 18, 1989, "ECCS

Emergency Sump Recirculation - DCD Identified Inconsistencies." This report addressed Action Items (3) and (4).

i Revision 19 to Procedure 1202.01, " Emergency Operating Procedure,"

addressed Action Item 5.

CR 1189-0634 was reviewed and found to be adequate.

• Calculation 896-0010-26, dated December 15, 1989, "LPI Pump NPSH

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Available.with 254 F Sump,1400 gpm spray flow, and 3200 and 3700 gpm LPI flow," addressed the staff's concerns.

Licensee actions relative to this problem were considered prompt and responsive.

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3.2-Unit 2-Trip On December 31,1989, Unit 2 experienced a trip from 100 percent power due to high level in the "B" steam generator (SG). A malfunction of the

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feedwater control (FW) system caused the overfeeding of the SG which resulted in level reaching the high level trip setpoint. Troubleshooting by the licensee identified a loose connection in the "B" FW control cabinet. This lead transmits the "B" loop feedwater flow signal to the

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cabinet. A review of the trip data indicates that both FW pumps increased speed and "B" FW control valve opened further while "A" FW control valve responded to the level increase and prevented an overfill of "A" steam generator. The FW control system is designed such that a change in FW demand from either cabinet will change the speed of both FW pumps; however, each cabinet controls only the corresponding control valve.

While_ the unit was shut down, the licensee simulated a momentary loss of the FW flow signal to the "B" FW control cabinet. The response to this test was similar to the plant trip in that an increase speed signal was sent to both FW pumps and an increase open signal was also sent to the "B" FW control valve. Based on this test and a review of the trip data, the licensee concluded that the trip was caused by the loose wire connection in the FW control cabinet.

l The most recent work on the FW control system was the system calibration

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that was performed in October 1989, during the last refueling outage.

While the calibration records do not contain a list of leads which were L

_ lifted, the licensee stated that the FW flow signal lead would have

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required removal during the calibration.

H In-response to concerns by NRC over the control of lifted electrical leads

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l and the licensee's review of existing controls, additional controls were-L implemented at the end of September 1989. These additional controls l:

consisted of:

A change to Procedure 1025.003, " Conduct of Maintenance," that

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required lifted leads be marked to aid in retermination and that I

L independent verification of retermination be performed. The earlier L

revision to this procedure included the same instructions; however, ll the actual performance of these steps was left to the discretion of -

L the craftsman.

Implementing a new " lifted lead signoff sheet" to document the lifting of an electrical connection, the retermination of the connection, and the independent verification of the retermination.

While this new signoff sheet was not included in the procedure

change, the intent of management was that this new signoff sheet L

would be used to document the additional controls on lifted leads, unless the working procedure already had signoffs for the lifted leads.

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-7-Informing applicable superintendents and supervisors of the new l

requirements and signoff sheet and directing them to train the j

craftsman on implementing these new controls, j

i The records for the recent FW control system calibration do not contain

.any of the lifted lead signoff sheets. The fact that the connection for the FW flow signal in "B" cabinet was four turns from being tight indicates

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that the independent verification of the retermination was not performed or was inadequate. The. failure to implement the requirements of Procedure 1025.003, " Conduct of Maintenance," for this maintenance

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activity is an apparent violativn (313/8945-02; 368/8945-02).

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t 3.3 Unit 2 Dilution Event

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On November 22,1989, at 11:56 a.m., control room operators noted that i

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levels in "A" and "B"' steam generators were decreasing while operating at

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29 percent steady state power. A small increase in steam flow was noted.

Since feedwater control was in manual, an increase in steam flow would cause a decrease in steam generator level. Main generator output was noted to be increasing which indicated that the increase in steam flow was through the main turbine. ' A review of RCS parameters indicated that Tave,

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pressurizer level, and pressurizer pressure were increasing.

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l At 11:59 a.m., the abnormal operating procedure (A0P) for moderator dilution was. evoked. The Demineralized Makeup Water Pump 2P-109B was secured, and the remaining actions of the A0P were completed. The overall changes in plant parameters during the event included a 6'F increase in

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i Tave, a 27 psi increase in pressurizer pressure (which included opening

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the spray valve twice), and an approximate 2 percent increase in reactor

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power.

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t The licensee believed an unplanned moderator dilution event caused the increase in reactor power and changes in RCS parameters.

Earlier, a planned dilution of the RCS' occurred with 2P-109B being the source of water.

The licensee theorized.that. Flow Control Valve 2CV-4927, downstream of Valve-2P-109B, failed-to fully close after the planned dilution. -A review-

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of data indicates that the actual dilution time was 6-8 minutes. Boron concentration in the RCS decreased approximately 10 PPM which corresponds to an addition of approximately 400 gallons of demineralized ' water to the RCS.

S The licensee's initial corrective action for this event was to place a caution card on downstream Valve 2CV-4941-2, which required the valve to be closed unless~a planned dilution activity is being performed. The

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caution card was subsequently removed from 2CV-4941-2. Management has reemphasized the need for close operator attention when performing dilution activities with particular importance given to the verification that the dilution activity has stopped. However, the inspector is i

concerned that the operator may not have sufficient information in the

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s control room to ensure that a dilution activity has been stopped.

In lieu of this' infonnation, the operator may have to rely on verification that

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RCS parameters are not changing to verify that the dilution has stopped.

During the recent dilution event, it was reported that the closed

indication (greenlight)-fortheflowcontrolvalve(2CV-4927)waspresent

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in the control room, however, the valve was not fully closed.

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The licensee assigned additional' corrective action for this event; which included adjusting-the limit switches for Valve 2CV-4927 and repairing the '

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seat leakage by Valve 2CV-4941-2 Additional. controls on the position of i

Valve 2CV-4941-2 are also being reviewed. This issue will be tracked by

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inspector followup item (368/8945-03) pending the inspector's review of..

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the licensee's completed corrective actions and review of the adequacy of h

L instrumentation available to the operator to evaluate termination of dilution.

4.0 Operational Safety Verification (Units 1 and 2)

(71707)

t The inspectors routinely toured the facility during normal: and backshift hours to access general plant'and equipment conditions, housekeeping, and

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L adherence to fire protection, security, and radiological control measures.

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Ongoing work activities were monitored to verify that they were being conducted in accordance with approved administrative and technical u

procedures, and~ that proper communications'with the control room staff had o,

been established. The inspector observed valve, instrument, and electrical

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equipment lineups in the field to ensure that'they were consistent with

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system operability requirements and operating procedures.-

y During tours of the control room, the inspectors verified proper staffing, t

access control, and operator attentiveness. ' Adherence to procedures and i

limiting conditions for operations were evaluated. The inspectors

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examined equipment lineup and operability, instrument traces. and status of control room annunciators. Various control room logs and other available licensee documentation were reviewed.

R The inspector observed and reviewed outage. maintenance, and problem

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L investigation activities to verify compliance with regulations, procedures, codes,'and standards.- Involvement of quality assurance / quality control (QA/QC), safety tag use, personnel qualifications, fire protection

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. precautions,. retest requirements, and reportability were assessed.

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l The inspector observed tests to verify performance in accordance with L

approved procedures and limiting conditions for operation (LCOs),

collection and validation of test results, removal and restoration of e

equipment, and deficiency review and resolution.

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Radiological controls were observed on a routine basis during the reporting period. Standard industry radiological work practices, conformance to radiological control procedures, and 10 CFR Part 20 requirements were observed.

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Y Checks were made_ to determine whether security conditions met regulatory L requirements, the physical security plan, and approved procedures.

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checks included security staffing, protected and vital area barriers.

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L personnel identification, access control badging, and compensatory measures when required.

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'The inspectors walked down the accessible portions of the Unit 2 emergency feedwater (EFW) system te verify operability. The walkdown was conducted b

using the current revision of the valve lineup, Attachment A, to p

Procedure 2106.06, ' Emergency Feedwater System Operations.". The current revision:to Dr6 wings: M-2202, " Lube Oil, Lube Oil Cooling, Electro / Hydraulic E

Controls and; Main Steam," and M-2204, " Emergency Feedwater," were reviewed during the preparation and conduct of the walkdown inspection. While no system misalignment or operability items were identified, the inspector a

identified some minor discrepancies such as valve packing leaks and loose L

electrical conduit. These findings were presented to the licensee for a

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corrective action.

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During the walkdown, which encompassed several rooms in Unit 2, the L

inspector noted the low quality of housekeeping in three rooms. These

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rooms were.the! turbine driven EFW pump room, the upper north piping L-penetration; room and the upper south piping penetration room.

Items such R

as loose insulation, spilled lubrication and excessive miscellaneous

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debris were observed by the inspector. At the exit, when the cleanliness P+

~ issue was discussed, the licensee agreed with the poor housekeeping j

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. assessment of these rooms-and stated that it appears that these rooms have

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' fallen behind the rest of the plant in improving or maintaining the level il cof: housekeeping. Management attention is needed to ensure that the

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e required resources are given to improve the level of housekeeping in. these

rooms.

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. 5.0j Temporary Instruction 2515/104 Fitness-for-Duty (FFD):

Inspection of f

Initial Training Programs

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M The inspectors attended the three phases of the licensee's FFD training a

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. program; FFD Policy Awareness Training for General Employees, FFD Training f

for Supervisors, and FFD Training for Escorts. -

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'The licensee required-all-personnel with access to the protected sree to attend the policy _ awareness and escort training. Supervisory personnel

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also attended the supervisory training. Attendance was recorded et all

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sessions and written examinations were administered.

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The inspectors noted that the content of the training sessions was extensive'and that the, presentations were good. The rule requirements,

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s background information, and licensee program were well explained in the combined sessions which covered the policy awareness and escort training aspects. The supervisory training focused exclusively on the supervisor's role in policy implementation, and extensive role playing and situational training occurred.

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Onn11, the inspectors found the content and quality of the presentations

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to W good.

6.0 No_ntM y b !ntenance Observation (Units 1 and 2)

(62703)

Station maintenance activities for the safety-related systems and components listed below were observed to ascertain that they were conducted in accottlance with approved procedures, regulatory guides, and

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industry codes or standards and in conformance with the TS.

The following items were considered during this review: the limiting

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conditions for operation were met while components or systems were removed from service, ap~pecvals were obtained prior to initiating the work,

activities were accomplished using approved procedures and were inspected as applicable, functional testing and/or calibrations were performed prior to returning components or systems to service, quality control records were maintained, activities were accomplished by qualified personnel, parts and materials used were properly certifier', and radiological and fire prevention controls were implemented.

Work requests were reviewed to determine the status of outstanding jobs and to ensure that priority is assigned to safety-related equipment maintenance which may affect system performance.

The following maintenance activities were observed:

Testing the LPI Flow Transmitter PDT-1402 (Job Order 795817). This

work was performed to verify the correct flow input signal to the safety parameter display system (SPDS) computers, which had been earlier reported as being erroneous. The initial portion of the testing involved a string check of the loop to the SPDS input.

During this check. the output leads from the transmitter (PDT-1402)

were lifted. When the connections were remade, the output leads were reversed.

It was not until testing was performed by the night crew that this error was discovered and the leads were installed correctly. Subsequent testing identified no additional problems with the LPI flow signal. During the recent Unit 1 midcycle outage, the flow signal to both SPOS computers was accurate.

The work package for troubleshooting Transmitter PDT-1402 did not contain a " lifted lead signoff sheet." Nor was there any indication that the leads had been marked when they were removel or that an

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independent verification was performed during retennination. This 4 an additional example of the violation regarding failure to perform work (liftedelectricalleads)inaccordancewithprocedural

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reouirements of Administrative Procedure 10.25.003, " Conduct of Maintenance" (313/8945-02; 368/8945-02),

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i As left MOVATS test of High Pressure Injection (HPI) Valve CV-1220

(Procedure 1403.39, "MOVATS Testing and Maintenance of Limitorque

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SMB-00 Actuators " Job Order 797157). During the test, excessive

movenent was discovered at the housing gear assembly of the valve r

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operator. Corrective action to reduce the movement involved

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disassembly of.the operator and installing a thinrier housing gasket.

While observing reassembly of the operator, the inspector noted that the lif ted lead data of the Procedure 1403.39 sheet had been only

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partially completed.

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i The electrical leads that had been disconnected and were in the process of being reconnected at the time of the in.ipector's observation had been identified on the lifted lead sheet. However,

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the signoffs for the leads being removed and reconnected were not completed. When questioned by the inspector, the electrician stated

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that the signoffs were not made due to the valve being located in a contaminated area and that all the signoffs (removal, reconnection, i

and second verification) would be completed back in the office after i

the work is completed.

The inspector does not consider the practice of completing all signoffs for the lifting and reterminating of electrical leads after the work has been completed as meeting the intent of Procedure 1403.39.

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The lifted lead data sheet of this procedure requires a signoff for

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the removal and restoration of each lead and verification signoff for l-both steps.

In addition, Procedure 1025.003 " Conduct of Maintenance "

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contains instructions for maintaining a procedure and making signoffs l

while working in a contaminated area. This is a third example of the E

licensee's failure to follow procedural requirements relating to L

liftedelectricalleads(313/8945-02;368/8945-02).

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Backflushing the' lube oil cooler for Resctor Building Spray

Pump P-35A.

The service water side of the cooler was cleaned by alternating a reverse flow of damineralized water and service air through the cooler to remove the corrosion and sediment deposits.-

L The need to periodically clean this cooler and the coolers for the

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p low pressure injection pumps was identified during the last Unit 1

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refueling outage when the as-found service water flow through the I

l cooler was less than the minimum requirements. During the outage, the coolers were cleaned using the backflush method with subsequent'

flows exceeding the minimum requirement. At that time, the licensee decided that periodic cleaning of the cooler was needed to ensure l

that minimum service water flow through the cooler would be

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L, maintained, i

The scheduling of the cleaning and the verification that it is completed has not been imolemented into the surveillance or preventive maintenance programs and currently is the responsibility of the system engineer. The inspector noted that the most recent cleaning of the coolers had been delayed several mor.ths due to scheduling and workload difficulties.

The inspector is concerned

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that future delays may result in inadequate flow to the coolers, which

15 a critical element for maintaining the operability of safety-related equipment unless controls are in place to ensure proper implementation. The licensee has plans to proceduralize the

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scheduling and cleaning of the coolers, but no date has been given for the completion of this task.

Licensee actions on this matter

will be tracked as an inspector followup item (313/8945-04).

Troubleshooting the periodic increase in the output signal from the middle chamber of Unit 2 excore detector Channel "D" (Job Order 802287).

Replacenent of a switch in the channel test circuit l

corrected the problem.

Replacement of emergency diesel generator jacket coolant circulation i

Pump 2P-167A (Procedure 6402.056, Job Order 801135).

This pump is part of the diesel standby heating system and runs continuously whenever the diesel is shut down to ensure that jacket water is circulated.

Earlier, the pump motor had tripped the thermal overload

and allowed the jacket coolant temperature to decrease to the low

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temperature alarm setpoint. Troubleshooting revealed a high running amperage on "C" phase of the motor, therefore, the pump and motor

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unit was replaced.

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The inspector reviewed the maintenance history and planned repair

efforts for Cooling Units 2VUC-19A and -19B. These two cooling units provide cooling for Electrical Equipment Room 2091 which contains safety-related inverters and a motor control center.

Coil leaks, in March 1988 for 2VUC-19B and February 1989 for 2VUC-19A rendered both

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units inoperable. The licensee justified that this condition was acceptable based on two redundant ventilation fans in the room which

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receive a start signal at 120"F room temperature. During tours in the plant, the inspector has observed one or both of these fans running continuously. The licensee stated that the fans are routinely

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started to maintain a comfortable room temperature.

The licensee has reviewed the temperature considerations of using only the ventilation fans and has concluded that the cooling units, 2YUC-19A and -B, are not required. However, based on noise and normal temperature considerations, the cooling units are the preferred method for room cooling.

Both cooling units being out of service for this extended period of time is an example of licensee-

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willingness to tolerate known equipment problems. Recently, the licensee has increased ef forts to repair the cooling units.

The inspector will monitor the licensee's repair efforts.

E 6.1 Improper Splicing of Electrical Connections in response to en NRC conrnitment, AP&L evaluated the tape splice configuration used to replace nylon crimp connectors in Limitorque dual voltage motor operators.

(SeeNRCInspectionsReports 50-313/88-29; 50-368/88-29 and 50-313/89-37; 50-368/89-37 for amplification).

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s The configuration under review consisted of a V-type splice using bolted l

compression lugs wrapped with Okonite T-95 tape with a jacketing overlay t

of Scotch 33 tape. The licensee's position that the installed configuration is qualified under the mquirenents of 10 CFR 50.49(1) is currently under review by NRC. NRC's concern that the Scotch 33 tape used i

at ANO was not part of the environmentally tested splice, which used Okonite 35 for the jacketing overlay, was addressed for MOVs by the

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licensee's commitment to replace the Scotch 33 with Okonite 35. The

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licensee pursued the replacement of the Scotch 33 tape on 27 motor operated

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valve (MOV) operators on Unit 1 prior to restart from the midcycle outage.

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The replacement work received 100 percent quality control inspector i

coverage end was performed to the requirements of AP&L Drawing E-2052,

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Sheet 37E. During the tape replacement effort, the licensee identified

two instances where no Okunite T-95/35 tape had been installed. Licensee Drawing E-2052, which establishes acceptable configurations for

environmentally qualified taped splices requires the use of Okonite i

T-95/35 tape..The failure to tape in the two instances identified where

no Okonite T-95/35 tape was used is a violation of the drawing requirements

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(313/8945-01).

The licensee's documentation for the two motor operators

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involved, CV-2680 and CV-2630, indicate that the motor leads were disassembled and improperly reassembled at an offsite motor repair r

facility.

Inspection of other motors that had been repaired by the same vendor were performed in response to the noted deficiency. No additional i

problems were identified as a result of the additional inspection effort.

The licensee's quality control inspector also questioned the adequacy of the T-95 installation on one motor, CV-1220. The leads to CV-1220 were also retaped.

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The licensee is currently reviewing maintenance records to identify any

additional applications of Scotch 33 tape in environmentally qualified

splices while awaiting NRC review.

t 7.0 Monthly Surveillance Observation (Units 1 and 2) (61726)

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The inspector observed the TS required surveillance testing on the various components listed below and verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated,

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limiting conditions for operation were met, removal and restoration of the affected components were accomplished, test results conformed with TS and

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procedure requirements, test results were reviewed by_ personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.

The NRC inspector witnessed portions of the following test activities:

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Monthly test of Unit 2 Emergency) Diesel Generator 2K4A

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(Procedure 2104.36, Supplement 1. Approximately halfway through

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the 1-hour run of the diesel, the inspector noticed fuel oil leaking at a fuel line connection at the No. 3 fuel injector. The operator that was observing the test and taking data wiped up the

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i fuel oil which stopped the smoldering of the oil that had collected

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on the diesel. The licensee continued with the diesel test while

mechanics tightened the fuel line connection, which stopped the leak.

i Several other fuel line connections were checked and verified to be

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properly tightened. Based on the design of the connection and that only one leak occurred, the licensee concluded that the leaking connection was not vibration induced but' resulted from improper alignment and makeup of the connection during recent 18-month maintenance. The licensee plans to emphasize the importance of

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proper reassembly of the fuel line connections for future maintenance

activities and the need for early ioentification and correction of

fuel leaks during future diesel operation, j

Eighteen-month calibration of Channel "A" of the energency feedwater I

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initiation and control system (Procedure 1304.098).

• Emergency Diesel Generator K4A 18-month operational test (Procedure 1104.36, Supplement 9). The inspector observed data collection, remote diesel operation from the control room, and actual

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diesel operation during'the 24-hour endurance run.

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FunctionaltestofEFWPumpP-7A(Procedure 1106.06, Supplement 8).

• The test satisfied TS 3.4.1 which requires the turbine driven EFW pump to be operable prior to heating the reactor above 280*F. At this low reactor temperature and corresponding low steam pressure, a

nonnal' surveillance test cannot be perfonned, therefore, the i

functional test is run with the turbine uncoupled. During the later stages of the plant heatup and prior to criticality, the pump

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surveillance test is perfonned which verifies minimum discharge

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Load rejection test and functional capability test of Emergency Diesel Generator K4B (Procedure 1104.36, Supplenent 10). Both of r

these tests are completed at the end of the 24-hour endurance run

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with the functional capability test, proving that the diesel can be l

fullyloaded(2750kw)within30 seconds.

j Calibration of RCS Pressure Transmitter PT-1040, which inputs into

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L analog Channel "C" of the engineered safeguards actuation system

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(Procedure 1304.56, Job Order 795729).

No violations or deviations were identified.

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8.0 Unit 1 Outage Activities (71707)

L 8.1 Overview L

During the inspection period, Unit I was shut down for a scheduled 19-day midcycle outage.. Major goals of the outage were to repair oil leaks on b

two reactor coolant pump (RCP) motors to allow fobr-pump operations,

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installation of a cavitating flow venturi in each HPI line, and D -

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installation of nozzle dam retention rings in the once-through steam generators.

Because of the excessive vibration of the flow venturis

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i during flow and hydrostatic testing, the licensee elected to remove the

flow venturis and return the piping to the original configuration.

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inspection results of the HPI flow venturi modification, including test l

results, are provided in NRC Inspection Report 50-313/89-44;50-368/89-44.

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During the outage, the licensee performed a comprehensive review of previous secondary plant operational and equipment problems. This review provided a list of short-term and long-term problems which, if complete,

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would improve secondary plant operations. Short-term items, such as

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correction of tank level controllers and installation of new valves in

steam lines to allow securing of steam loads while shut down, were.

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completed during the outage.

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The overall conduct of the outage was good. Successful aspects of the j

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recent Unit 2 outage were used during the Unit 1 outage.

It was apparent that lessons learned from problems encountered during previous outages were incorporated in outage planning.

Examples of this included the successful hydrogen peroxide flush of the RCS and the increased attention

given to RCS level indication and reduced RCS inventory operations.

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8.2 Reactor Coolant System Flush The inspector observed portions of the RCS hydrogen peroxide flush. This was the second attempt by the licensee to perform a RCS flush for Unit 1.

Based on the overall success of the cleaning effort, the licensee appeared to have. resolved many problems that were experienced during the first

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cleaning effort of the-last refueling outage. The operations and chemistry

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department procedures were well coordinated, with adequate levels of

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detailed instructions provided. The licensee estimates that 450 curies of activity were removed from the RCS during the flush while only 160 curies were removed during the first flush. The licensee's current plans include continued refinement of the hydrogen peroxide flush process and performing

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the RCS flush during upcoming scheduled outages.

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8.3. Repair of Reactor Coolant System During the Unit I shutdown for the midcycle outa e, a visual inspection of t.

the reactor vessel level detector probe (rad cal identified RCS leakage.

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In May 1989, the unit was shut down due to excessive RCS leakage, with later inspections identifying the rad cal as leaking. Several repair attempts were made before the leakage was corrected. Due to the buildup of boron crystals on the rad cal, the source of the most recent leakage (flange leakage or leakage by the probes) could not be determined.

Since the initial repairs did not provide long-term correction of the rad

~ cal leakage, the licensee contracted with Babcock and Wilcox (B&W) to

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develop an improved repair method and to perform the actual repair work.

The repair effort involved replacing the dual o-ring seal between the closure assembly and the adapter flange with a metallic gasket and seal i

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welding the gap between the closure assembly and the probes in lieu of

using a c-ring arrangement. During the plant heatup and at elevated RCS pressure, visual inspection of the rad cal verified no leakage. The Itcensee indicated that, during the next Unit I shutdown, a visual i

inspection of the rad cal would be performed to detect any leakage or

' signs of previous leakage.

In addition, the licensee stated that the i

installation of a new design reactor vessel level detector probe is being

investigated. While reviewing this matter, the licensee identified leakage on control rod drive flanges also.

NRC review of licensee i

actions on these leaks is documented in NRC Inspection Report 50-313/89-44;

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50-37/89-44.

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8.4 -Reduced Reactor Coolant System Inventory Operation To support modifications and maintenance activities during the Unit 1

midcycle outage, the RCS was placed in reduced inventory. With the

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increased attention given to reduced RCS inventory operation by the NRC, the problems Unit I has experienced with inconsistent RCS level indication, and the loss of decay heat removal, the licensee has provided increased controls for this operation.

Procedure 1103.11. " Drain the Reactor Coolant System," was recently changed to limit the deviation between any of the three level indications to 0.5 feet. The three indications used to nonitor RCS lesels are the wide-range and narrow-range remote level indication for Loop "B" and tygon tubing. The inspector observed the initial portion of the RCS draindewn and found the evolution well controlled with all operators being highly attentive to the operation. When RCS level reached 376 feet, the difference between the wide-range and narrow-range indications was slightly. greater than 0.5 feet. The RCS draindown was stopped and the instrunentation was recalibrated. Based on the recent observation of Unit 2 during reduced RCS inventory operations and the observation of Unit 1, the' licensee appears to have made significant improvement in RCS level monitoring and in the overall awareness of reduced RCS inventory operation.

9.0 Personnel Errors (Unit 1)

(93702)

Personnel errors continue to be an area of concern. Compensating for known plant problems and inattention to detail on the part of facility personnel are areas of weakness that have been extensively documented.

Licensee management has initiated development of a long-term program to reduce personnel errors and the inspectors will closely monitor the results of these efforts.

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9.1 Interruption of Decay Heat Removal Flow With the plant in reduced RCS inventory to facilitate steam generator (SG)

nozzle dam installation, the operating decay heat removal pump (P34A)

tripped and remained out of service for approximately 9 minute._

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The pump trip occurred as the result of sustained undervoltage on 480v i

Bus B-5, which caused an automatic trip of 4160v Bus A-3.

The undervoltage was the result of personnel error while returning Bus B-5

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to its normal lineup after it had been crosstied with 480v Bus B-6.

Preventive maintenance work on 4160v to 480v Transfomer X-5, the normal i

supply to B-5, required that B-5 and B-6 be crosstied. Although Unit 1 management had made the decision during dayshift on December 6,1989, not to perfom the work on Transformer X-5, because of the potential for

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~ losing 4160v Bus A-3, the night shift perfomea the worc.

The management decision not to perfom the X-5 work while in reduced inventory was prudent and showed good safety perspective, however, that decision was not adequately communicated to oncoming personnel.

When power was lost to B-5, the feeder breaker to Bus A-3 tripped as designed. Since P-34A is powered from Bus A-3, the pump was deenergized until the electrical lineup was restored.

Prompt action by the control room operators restored DHR within 9 minutes; however, due to reduced RCS i

inventory operation, temperature increased from 103'F to 122*F.

9.2 Emergency Feedwater (EFW) Actuation While performing a plant heatup, in preparation for plant restart, the EFW system actuated automatically on low SG level. The actuation occurred at 1:40 a.m. (CST) December 21, 1989, and was the result of feedwater flow

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being diverted to the main condenser via Startup Recirculation Valves FWBA and FW88.

During heatup at ANO-1, feedwater is supplied to the SG by a low capacity,

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electric driven, auxiliary feedwater pump with SG level being controlled by Startup Feedwater Regulating Valves CV-2623 and CV-2673. Because of the high leakage rate of CV-2623 and CV-2673, when the valves were on their

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closed seats, the control room operators decided to divert some FW flow

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to the main condenser via FW8A and FW8B. The manually operated FW8A and FW8B were opened enough to allow the startup feedwater regulating valves to operate automatically at approximately one-half demand. As SG

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temperature, pressure, and steam flow were increased during the startup.

CV-2623 and CV-2673 continued to open to maintain SG 1evel until they reached full open.

FWBA and FW8B remained in their open position, however, allowing more flow to divert to the condenser. As SG pressure continued to increase, the auxiliary feedwater pump could no longer maintain SG level. When the EFW actuation setpoint was reached on low SG level, both EFW Pumps P-7A and P-7B started and fed water to the SG. After level was restored, the operators stopped turbine driven EFW Pump P7A, closed FW8A and FW8B. and returned the feedwater system to its normal lineup.

This event could have been avoidad had the licensee decided to repair CV-2623 and CV-2673 prior to proceeding with the startup or if the changing plant conditions had been more closely monitored during heatup.

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9.3 Unit 1 Reactor Trip Due to Total loss of Feedwater Flow

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On December 28, 1989, at 3:30 p.m., the Unit 1 "B" main feedwater

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pump (MFP) was manually tripped at the turbine front standard. The

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operator had been directed to trip the "A" MFP to support-ongoing

l troubleshooting on the "A" MFP oil trip sensing circuitry.

Loss of the

L operating "B" MFP caused the reactor protection system to sense a complete loss of FW flow and tripped the plant.

The EFW system automatically

started on the loss of both MFPs and the operations staff maintained SG t

level within the normal band. All plant systems responded as designed and the plant was stabilized in hot standby.

l The licenses has conducted a review of this event and has concluded that l

the root cause was personnel error. Consnunication between the control

room and the operator at the front standard of the MFP turbine was poor and

.the evolution had not been adequately briefed prior to perfonnance.

9.4 Licensee Actions l

In response to the significant personnel errors which have recently

occurred on Unit 1, licensee management has initiated a number of actions to improve performance of Unit 1 personnel. An oversite group composed of r

site management personnel will monitor onshift performance for adverse traits and report those observations to the Unit 1 plant manager and the i

site director. Operations personnel from other utilities will be on site

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l to evaluate control room activities and conduct. The licensee will also

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be sending operations personnel to other sites with the intention of gaining insights in personnel error reduction methods. While these efforts have just been initiated, it appears that licensee management is taking an aggressive approach bward the reduction of personnel errors.

l The effectiveness of-these actions will be monitored during future NRC

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l inspections.

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10.0 Exit Interview j

The inspectors met with Mr. N. S. Carns Director, Nuclear Operations and

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other members of the AP&L staff at the end of the inspection. At this meeting, the inspectors summarized the scope of the inspection and the findings. The licensee did not identify as proprietary any of the l-material provided to, or reviewed by, the inspectors during this l

inspection.

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