IR 05000313/1989028

Insp Repts 50-313/89-28 & 50-368/89-28 on 890601-30. Violations Noted.Major Areas Inspected:Plant Status,Followup of Events,Operational Safety Verification,Followup on Previously Identified Items,Maint & Surveillance

ML20247N662
Person / Time
Site:	Arkansas Nuclear
Issue date:	07/21/1989
From:	Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20247N627	List: IR 05000313/1989028 ML20247N621 ML20247N651
References
50-313-89-28, 50-368-89-28, NUDOCS 8908030099
Download: ML20247N662 (13)

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APPENDIX B.

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'U.SM NUCLEAR REGULATORY COMMISSION

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. REGION IV

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] p Wi : Inspection Report:

50-313/89-28

. Operating Licenses:

DPR-51

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L50-368/89-28

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50-368L

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LLicensee:

Arkansas 1 Power & Light' Company; (AP&L)

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Box 5511..

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.Little Rock,, Arkansas-.72203.

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A g ). Facility Name:. Ark'ansas NuclearL0ne (AN0), Units 1 and 2

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'L Inspection At: *AN0' Site, Russellville,-Arkansas

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Inspection.;Coi1 ducted:

June 1-30, 1989 l

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' Inspectors:j jlW.';D. Johnsoni Senior Resident Inspectors l

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LProject Section A, Division of Reactor j

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sR.!C.' Haag,. Resident Inspector, Project-.

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Section>A, Division'of Reactor Projects

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i Approved:

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D. DL/ Chamberlain, Chief', Project Section A Date

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. Division of.' Reactor Projects I

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Inspection Summary

Inspection Conducted' June 1-30, 1989 (Report 50-313/89-28; 50-368/89 28)

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Areas Inspected:

Routine, unannounced inspection including plant status,

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. followup of events, operational safety verification, followup on previously

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identified items, maintenance, surveillance, and' review of contingency strike (

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, Results:

An open fire door which was observed by the inspector during a plant

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tour is.5a.n apparent violation. The fire door had been intentionally propped open, but1 compensatory measures had not been taken.

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The repair of a leaking-flange on the Unit 2 reactor head vent line identified j

W a weakness;in the maintenance organization when resolving deficiencies that'

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.were discovere'd in the plant.

Management attention is needed to ensure that l

' maintenance personnel obtain adequate and timely engineering support when

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8908030099 890724

PDR ADOCK 05000313

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dealing with deficiencies in'the plant.

In addition, the failure of a reactor coolant pump pressure sensing:line emphasizes the need.for thorough corrective action tn resolve this issue during the upcoming refueling outage.

The failure to promptly perform _ corrective action for level differences from RCS' level indicators is an apparent violation..This apparent violat-ion identified weaknesses:in the licensee's tracking and scheduling of corrective action.

The NRC staff is concerned that this corrective action issue is indicative of a weakness with:the new condition reporting-system. Weaknesses were also identified in the performance of the operations department during the RCS drain down.

Operational weaknesses indicated that additional planning and training is needed prior to the next RCS drain down.

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DETAILS 1.

Persons Contacted

• N. Carns Director, Nuclear Operations C.' Anderson,'In-House Events Analysis Supervisor T. Baker, Technical Support Manager D. Bennett, Mechanical Engineer S. Capehart, I&C Engineer A. Cox, Unit 1 Operations Manager M. Durst, Modifications Engineering Superintendent R. Eddington, Unit 2 Outage Manager

• R. Fenech, Unit 2 Plant Manager J. Gobell, Mechanical Engineer H. Green, Quality Assurance Superintendent L. Gulick, Unit 2 Operations Manager

• G. Jones, Engineering General Manager R. Lane, Engineering Manager

• D. Lomax, Plant Licensing Supervisor R. Lovett, Electrical Engineer

• A. McGregor, Engineering Superintendent J. McWilliams, Maintenance Manager B. Michalk, Mechanical Engineer

• P. Michalk, Nuclear Safety and Licensing Specialist V. Pettus, Mechanical Maintenance Superintendent F. Philpot, Nuclear Engineering Superintendent L. Taylor, Nuclear Safety and Licensing Specialist

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R. Tucker, Electrical Maintenance Superintendent

• J. Vandergrift, Unit 1 Plant Manager J. Waxenfelter,ijnit 2 Maintenance Manager C. Zimmerman, Unit 1 Operations Technical Support Supervisor

• Present at exit interview.

The inspectors also contacted other plant personnel, including operators, technicians, and administrative personnel.

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Plant Status (Units 1 and 2)

Unit I remained shut down for repair of previously identified reactor coolant system (RCS) leaks, until the unit was returned to (,ritical operation on June 3, 1989. The unit reached 80 percent power operation on June 5, 1989, and remained at that power through the end of the inspection period.

Unit 2 operated at 100 percent power until June 23, 1989, when the unit was shut down to investigate an increase in the unidentified RCS leakage.

The unit remained shut down through the end of the ',nspection period to repair an RCS leak and to perform corrective maintenance.

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Followup of' Events (Unit 2)

(93702)

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jFollowihg the"Un11i 2 shutdown on June 23, 1989, to investigate the

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nincrease.in RCS leakage, the Linspector reviewed the-four outage activitic 1 discussed below:

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,a.s Efforts to R'epair a Flance Leak The licensee identified a packing leak on an' isolation valve and a flange leak on the 3/4-inch reactor head vent line as the cause of the increased RCS leakage. The valve was repacked and the gasket was.

replaced ~in_the' flanged joint. On June 27, 1989,. during the plant heatup while in Mode 3, the licensee identified an approximate 6-gallon-per-minute leak from the same flanged joint on the reactor head vent line. While the licensee concluded that a " pinched" gasket caused the second leak, the inspector made the following observations.

when reviewing the earlier repair effort:

A condition report was written the day after the flange was

remade which documented two different styles of mating flanges.

The joint consisted of a male half of a "large tongue and groove" flange pair and a female half of a "large male-female" flange pair. An engineering memorandum, without a signature or documented concurrence, provided the justification for acceptance of this condition. The engineer became aware of the flange mismatch and provided the justification after the joint had been repaired.

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The old gasket was wider than the new replacement gasket. While conducting interviews, the inspector learned that the engineers providing the flange mismatch justification were not aware of the gasket differences until after the second leak of the flanged joint.'

Following the second leak, the licensee conducted a more thorough repair effort. This consisted of replacing one of the flanges to provide two properly matched flange halves, verification that the correct gasket was used, and refining the techniques used to make up the joint.

The inspector's main concern, after performing this review, was that maintenance personnel did not recognize the need to obtain engineering involvement when the flange and gasket problems were first identified. Obtaining this involvement after the work is completed puts engineering at a distinct disadvantage to provide an objective'and accurate resolution. During previous maintenance activities, the inspector has observed the reluctance of the maintenance organization to obtain additional assistance. Management

' attention and guidance is needed to ensure that maintenance personnel

' are aware of the need to obtain engineering and management involvement when deviations or problems in the plant are discovered.

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Failure of Vent Assembly While performing corrective maintenance during the outage, the licensee discovered a vent pipe from a pressure sensing line for the

"C" reactor coolant pump (RCP) had sheared off. Since.the fracture was located at the toe of the socket weld for the second vent valve, the line did not leak due.to the first vent valve providing adequate isolation. - The licensee's investigation indicated that a misaligned hanger at the. top of the vent assembly caused large bending moments in the vent assembly and, when coupled with the vibration of the RCP, resulted.in the failure. Corrective action involved replacing a portion of the vent assembly, examining welds for additional defects,

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realigning the hanger and verifying proper alignment of other hangers associated.with the RCP sensing lines.

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The inspector _ reviewed the design engineering memorandum which addressed the recent failure and the large number of past failures associated with the'RCP sensing lines. On the basis of the historical review, the licensee concluded that each failure, including the recent failure, had two contributing factors.

Vibration induced from the RCPs was a _ common factor in all the failures. The second factor consisted of various problems such as weld problems, interferences, hanger installation deficiencies, and nonstandard tubing configurations. The licensee's past position has been to correct these varied factors to prevent failure recurrence, however, previously unidentified failures continue to occur. During the next refueling outage, the licensee plans to install flexible hoses in the RCP sensing lines to reduce vibration transmission.

The number of RCPs * hat will receive this modification is currently under review by the licensee. The inspector will review this modification and the justification used in determining the extent of the modification during the upcoming outage, c.

Repair of Leaking Check Valve During the plant heatup, after the initial repair of the reactor head vent line flange, the licensee experienced difficulty in " seating" a i

discharge check valve for a safety injection tank. Valve 2S1-15C required repeated cycling and mechanical agitation prior to reseating. The licensee decided to repair the check valve when the plant was cooled down for the second repair of the vent lim flange.

After disassembly of 2SI-15C, it was identified that the two railpins which maintain alignment of the disc to the disc shaf t were missing.

This allowed the disc to rotate on the disc shaft and prevented proper seating of the disc.

(The valve is designed for the disc and shaft to rotate as an assembly). On the basis of past problems with Check Valve 2SI-15A not properly seating, it was also disassembled.

While both rollpins were installed in 2SI-15A, one rollpin was cracked and had a loose fit in the mating hole. The licensee

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-6-installed new rollpins in 2SI-15C and replaced the one rollpin in 2SI-15A.

Initial investigation results by the licensee indicated that the rollpins may not have been installed in 2SI-15C during valve repair in 1983. The licensee is continuing this investigation for the cause of the missing and cracked rollpins. On th". basis of the lack of seating problems with Valves 2SI-15B and -D and the lack of industry problems with this type of check valve, the licensee decided not to inspect 2SI-158 and -D.

However, the licensee did commit to the inspector during the exit interview that Valves 2SI-158 and -D would be disassembled and inspected during the next refueling outage which is scheduled to start in September 1989, d.

RCS Level Indication Errors During this outage, the licensee partially drained the RCS on two occasions. The first drain down on June 24, 1989, was for support of the reactor head vent line flange repair while the second drain down on June 27, 1989, was for support of the flange rework and Valve 2SI-15C repair. RCS level indication when draining down is provided by a tygon tube stand pipe and a level transmitter which has remote indication in the control room.

For the second drain down the level difference between the tygon tubing and the remote indication varied from 12 to 18 inches with the tygon tubing providing the higher level indication. During the next 2 days, while investigating for the cause of the deviation, the licensee discovered a water pocket in a horizontal section of the tygon tubing between the standpipe and the connection to the top of the pressurizer. This forned a loop seal and caused the erroneous reading. After draining the water pocket, the water level in the tygon tubing was 8 ir.ches less than previous readings.

In August and December 1988, the licensee wrote two condition reports (CR) to document the level deviation between the tygon tubing and the remote indication that had been experienced during previous RCS drain downs. Both CRs provided corrective action to eliminate or reduce the deviation, however, CR 2-88-0367 provided a detailed description of the problem by the operation's department and an engineering evaluation of the problem. One of the corrective actions of the CR was a job order which provided the instructions for the work detailed in the engineering evalmtion.

In addition, the CR assigned the work on the job order tc t.: completed prior to the next drain down of the RCS. This job order was not worked until the second of the RCS drain downs had been completed. Failure to promptly correct the deviation between RCS level indications within an acceptable period as viewed by the inspector and as documented in a licensee's CR is an apparent violation (369/8928-01). While reviewing this event the inspector was unable to find a system or method for scheduling corrective action as a prerequisite to certain evolutions, i.e., prior to RCS draining. An exception is the condition l

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j-7-l reporting system which will track heatup and criticality restraints.

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.In the response to this violation, the licensee should also respond j

to the scheduling concern and determine whether any existing j

corrective actions are prerequisites to key events but are not being

properly tracked.

The inspector made the following observations on operations performance during the RCS' drain down:

Procedure 2103.11, Revision 11. " Draining the Reactor Coolant System," has a step which verifies the condition of the tygon tubing by ensuring that no leaks, kinks, air bubbles, or loop seals exist and that the tubing is properly secured. This signoff was made prior to the RCS drain down. Because a tygon tube loop seal was subsequently discovered, this inspection was either not properly performed or needed to be performed at a given frequency to ensure proper condition of the tygon tubing.

Procedure 2103.11 also requires that the cause of deviations between the RCS level indicators, when greater than 10 inches, be determined prior to draining below 90 inches of the bottom of the RCS hot leg. The level transmitter was calibrated prior to draining below 90 inches; however, the deviation remained greater than 10 inches. The inspector was informed that RCS draining continued because the operators believed that the deviation was caused by an error in the remote indication.

The remote level indication was the conservative indication;

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however, operations used the tygon tubing for actual level indication.

The RCS was drained down to elevation 375 mean sea level (MSL)

feet which is approximately 6 inches above the " reduced inventory level" as defined by Generic Letter 88-17 " Loss of Decay Heat Removal." Procedure 2103.11 requires that additional steps be taken when draining below the reduced inventory level.

These steps were not completed. When the loop seal was removed from the tygon tubing the indicated RCS level, as indicated by the tygon tube level detection system, fell 2 inches below the reduced f nventory level.

These observations highlight the fact that improvements by the operations department in establishing the RCS level indication systems and resolving level indication problems are needed prior to any futare RCS drain downs. This event did not affect shutdown cooling since RCS level was being maintained at approximately 4 feet above the hot leg midloop level. However, if the RCS had been drained down to midloop level while using the nonconservative tygon tubing indication, shutdown cooling could have been impacted.

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Operational Safety Verification (Units 1 and 2)

(71707)

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The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators. The inspectors verified the operability of selected emergency systems, reviewed tag-out records and verified proper return to service of affected components, and ensured that maintenance requests had been initiated for equipment in need of maintenance. The inspectors made spot checks to verify that the physical security plan was being implemented in accordance with the station security plan. The inspectors verified implementation of radiation protection controls during observation of plant activities.

The inspectors toured accessible areas of both units to observe ;, ant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibration. The inspectors also observed plant housekeeping and cleanliness conditions during the tours.

During a tour of the plant, the inspector noted that Fire Door 375 was propped fully open. This fire door is located in the corridor between the Unit 1 and Unit 2 auxiliary buildings on Elevation 354 and is normally closed. A fire watch was not assigned to the area to compensate for the open fire door.

It was apparent that the door was intentionally opened since a lead brick was maintaining the door open. While no work was being perfonned in the area, an adjacent watertight door had recently been repainted. The licensee's failure to maintain Fire Door 375 shut is an apparent violation of Unit 1 Technical Specification 3.21.1, which requires fire barriers protecting safety-related areas to be intact at all times or that compensatory measures be taken.

(313/8928-01)

Unexpected actuations of the control room emergency ventilation system continue to be an unresolved problem.

Following corrective action on the Unit 2 control room radiation monitor in early May 1988, the licensee had experienced only one actuation of the control room emergency ventilation system until June 25, 1989. From June 26 to July 2, 1989, however, four actuations have occurred. The licensee has made a preliminary assessment of the cause of the control room radiation monitor spiking which initiated these recent ventilation actuations; however, corrective action to prevent recurrence has not been identified. Further management attention is needed to provide a timely and permanent resolution to this issue. The inspector will continue to monitor the licensee's actions.

These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under Technical Specifications, 10 CFR, and administrative procedures.

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Followup on Previously Identified items (Units I and 2)

(92702)

(Closed) Violation 313/8820-02: Design basis for a plant change not correctly incorporated into work instruction.

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The licensee has attributed this violation to'an engineering oversight ~

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' :when preparing the instructions for-the plant ^ change in which insufficient details were provided.

Recent' plant changes reviewed by the inspector i

have provided adequate ~ detailed instructions to ensure'the design basis requirements are implemented..This item is closed.

-(Closed)' Violation 368/8832-01:

Use of safety-related piping to support

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The procedures governing th'e conduct of maintenance and the control of construction / modification.were revised to prohibitothe use of

safety-related piping or. components to support ~ rigging.

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' engineering approval'is obtained prior to,using rigging...The inspector

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also verified that maintenance personnel received training on the procedure changes.

This item is closed.

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. '6 Monthly Maintenance Observation (Units l'and 2) (62703)

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Station maintenance. activities for the safety-related systems. and components. listed below were observed,to ascertain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and in conformance with the Technical-Specifications.

.The following items were considered during this review:

the limiting conditions for. operation were met while components or systems._were removed from service, approvals 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 certified, radiological controls were implemented, 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:

Inspecting and flushing the seal water system for Charging Pump 2P36C (Job Order 787484)

Testing, cleaning, and inspection of protective relays associated with Circuit Breaker A-410 (Tie between 4160 Voltage Bus A-4 and A-2)

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(Procedure 14112.017, Job Order 787323).

This work consisted of the biennial preventive maintenance of the relays.

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Installation of caulking in the seismic gap between the outer containment wall and the floor in the Unit 1 lower south electrical (

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penetration room. During a plant tour, the inspector noted the seismic gap had several locatfons where the caulking was missing or had become loose. While this joint does not constitute a fire barrier, the inspector questioned the license to determine if the joint integrity was required to separate the electrical penetration room from the room below, which is a high energy line break area.

The licensee wrote a condition report to address the concerns of the joint integrity and the qualification of the electrical equipment located in the penetration w om. This issue will remain unresolved pending completion of the corrective action identified on the condition re ort and review of these items by the inspector (313/8928-02.

Weekly lubrication of stems for High Pressure Injection Valves

CV-1227 and CV-1228 and Decay Heat Removal Vaive CV-1404 (Job Order 786099). Because of the failure of Valve CV-1227 to stroke during a surveillance test, the licensee initiated an interim program to weekly lubricate the stem of valves that may be susceptible to the same type of failure. Long-term action consists of installing new motor operators and approving i new improved stem lubricant. Because of the limited number of cycles allowed for some of the valve operators, the valves were manually stroked then torqued closed with a spring scale and a known force. The instructions state to attach the spring scale to the handwheel spinner and pull tangential to the handwheel. The inspector questioned the definition of a " handwheel s ainner." The inspector observed the spring scale being attached to tie handwheel spoke and for one application in the middle at the spoke. This valve was later reclosed with the spring scale attached to'the spoke at the outer rim of the handwheel. On the basis of these observations and the wording in the instructions, the inspector did not consider this a completely reliable method of torquing valves closed.

In addition, the inspector noted the valve stem cover for CV-1228 was missing. Since the failure of CV-1227 was attributed to dry and ineffective stem lubricant, the use of a stem cover is important for maintaining the integrity of the lubricant. The

?icensee stated that the installation of stem covers is being reviewed. Subsequent to the end of this inspection period, the licensee informed the inspector that they were going to a monthly schedule for lubricating these valve stems and they would no longer manually stroke these valves closed with the use of a spring scale.

Reassembly of Unit 1 Service Water Pump P-4A (Procedure 1402.061, Job

Order 784458)

Semiannual preventive maintenance on the fire pump diesel

(Procedure 1306.027, Job Order 784910)

Lubrication and reassembly in the gearbox to pump coupling for High

Pressure Injection Pump P-36A (Procedure 1402.010, Job Order 785728)

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Replacement of carbon steel parts with stainless steel parts in a

service water pump discharge check valve (Plant Chenge 86-3351, Job Order 735351). The inspector noted that the carbon steel parts being replaced were severely corroded, including the valve body which required weld buildup and machining prior to reassembly. Check Valve 25W-2B was the last of the three identical valves to be repaired by. the plant change. The licensee informed the inspector that an additional plant change is being planned to replace the existing valve bodies with stainless steel bodies.

• Replacement of a circuit board in the Unit I hot leg level narrow range instrument display (Job Order 787101)

No violations or deviations were identified.

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Monthly Surveillance Observation (Units 'I and 2)

(61726)

The inspector observed the Technical Specification required surveillance testing on the various components listed below and verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operation were met, removal and restoration of the affected components were accomplished, test results conformed with Technical Specifications and 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 inspector witnessed portions of the following test activities:

Monthly test of Unit 1 Emergency) Diesel Generator K48

(Procedure 1104.36, Supplement 2 Quarterly calibration of hydrogen purge system Analyzer 2C-128B

(Procedure 2304.29, Job Order 786154). The inspector noted that the cover for an electrical terminal box located in the analyzer cabinet was missing. The I&C technicians performing the calibration were not aware of when the cover was removed. A job request was submitted by the licensee to install a new cover. The inspector also identified to the licensee that a sample valve located inside the cabinet that was labeled as "2HPA-18, Gas Supp Inside Panel" was referenced in the procedure as the " Span Calibration Gas Valve." Since this valve is positioned during the calibration, a labeling error has the potential to-compromise the calibration results. The licensee stated the procedures for calibration of both analyzers will be reviewed and corrected to ensure consistent referencing of valves.

Monthly test of Unit 2 Emergency) Diesel Generator 2K4BThe inspector obse

(Procedure 2140.36, Supplement 2.

exhaust smoke leaking f rom several exhaust header joints similar to conditions of recent monthly runs; however, no exhaust fires were noted. After approximately 7 minutes of operation, the oil and smoke

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leakage stopped. The inspector will continue to monitor the.

licensee's corrective actions, including modifications planned for the upcoming refueling outage to reduce the amount of exhaust header leakage.

Calibration of reactor building Radiation Monitor 2RE-8233 (Job

Order 768837).

Postmaintenance surveillance test of High Pressure Injection

Pump P-36A (Procedure 1104.02 Supplement 3). The test was performed to demonstrate operability of the pump following preventive and corrective maintenance. A leak from a threaded joint on the discharge drain line stopped the surveillance test. This joint had been worked during the earlier maintenance. The joint was subsequently repaired and the surveillance test was successfully performed.

Local leak rate. test of Unit 2 Containment Purge Valve 2CV-8284-2

(Procedure 2304.022,' Job Order 789211).

Monthly and quarterly testing of the Unit 2 steam driven emergency

feedwater pump-(Procedure 2106.06, Supplement 1).

Station Battery 2D11 quarterly surveillance (Procedure 2403.024,

. Job Order 786673).

_ Monthly test of Unit 2 Emergency) Diesel Generator 2K4A (Procedure 2104.36, Supplement 1.

Air particulate detector functional test (Procedure 2304.26,

Job Order 785591).

No violations or deviations were identified.

8.

Review of Contingency Strike Plans (Units 1 and 2)

(92709)

The inspector performed this review to ascertain whether the licensee had prepared contingency plans for coping with a possible upcoming strike.

The licensee's strike contingency plan was reviewed and the inspector determined that sufficient personnel were available to meet the minimum requirement for onsite staffing for Plan "A," which uses the normal three l

shifts to maintain 24-hour continuous coverage. Additional training would be required for the staffing allocation of Plan "B," which uses 12-hour shifts and houses personnel onsite. The licensee stated that implementation of Plan "B," if required, would be in the later stages of a strike and that sufficient time would be available to perform the required training. Plant security is addressed in the contingency plans and is deened not to be significantly affected by the current union negotiation since the security force is not represented by the union and there is a

"no-strike" clause in their contract.

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-13-On June 23, 1989, the expiration date of the. union contract, the proposed union contract was defeated by a union vote.

However, the licensee did not implement the initial phase of the strike plan due to the. current

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contract being extended until June 30, 1989.

The union contract was renegotiated on June 30, 1989, with the current contract being extended until July 30, 1989, which is the date that voting results are due.

The inspector will contiere to monitor the potential for a strike and the licensee's implementation of contingency plans.

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Exit Intersiew

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

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