IR 05000309/1990010

Insp Rept 50-309/90-10 on 900516-0619.Violation Noted.Major Areas Inspected:Operations,Radiological Controls,Maint/ Surveillance,Security & Engineering/Technical Support

ML20055G601
Person / Time
Site:	Maine Yankee
Issue date:	07/16/1990
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20055G598	List: IR 05000309/1990010 ML20055G597 ML20055G600
References
50-309-90-10, GL-89-10, IEB-85-003, IEB-85-3, IEB-90-001, IEB-90-1, NUDOCS 9007230363
Download: ML20055G601 (18)

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION 1-Report No:

-50-309/90-10 License No.:

DPR-36

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s Licensee:

Maine Yankee Atomic Power Company Inspection At: Maine Yankee Atomic Power Plant Wiscasset, Maine

' Conducted:

May 16 through June 19, 1990 Inspectors:

_ Richard'J.-Freudenberger, Resident Inspector

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James _M. Trapp, Senior Reactor Engineer Roy L. Fuhrmeister, Resident Inspector

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William T; Olsen, Resident-Inspector'

Approved:

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E. C. McCabe, Chief, Readtor. Projects Section 3B Date OVERVIEW 10perations: An: uncontrolled reduction in reactor vessel inventory occurred when the pressurizer was. drained while the plant was shut down.

Otherwise, good operator performance was evident.

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Radiological-Controls: An unplanned exposure was received by; personnel per-

< forming work on valve PCC-A-216. An-NRC radiation specialist inspector reviewed the incident, which is documented in Inspection Report 50-309/90-11.

' Maintenance / Surveillance: A Control Element Assembly Fail'ure was identified.

during surveillance testing on June'7.

Licensee corrective actions' were

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aggressive and thorough. Actions in response toLNRC; Bulletin'90-01 were timely-and well' coordinated. - The " Loss of-AC" test was performed appropriately.

Security: The licensee identified and promptly reported on uncompensated de-gradation of a vital area barrier when a security guard was.found to be-in-

-attentive to duties.

Engineering / Technical Support:

Conservative administrative limits were estab-lished'for Primary to Secondary leakage following the identification of cir-cumferential~ cracking of the steam generator tubes during the refueling outage.

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-The motor operated valve inspection and repair program implemented during the refueling outage was conducted in an acceptable manner.

9007230363 900719

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Persons: Contacted;.'........'.....................-..'..............

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M e;. :InspectioniMeetings' Conducted by' Region-Based Inspectors..........-16;

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DETAILS 1.

Plant Operations During routine daily tours the following were checked: manning, access control, adherence to procedures and Limiting Conditions for Operation, instrumentation, recorder traces, protective systems, control room annun-ciators, radiation monitors, emergency power source operability, operabil-ity of the Saf ety Parameter Display System (SPDS), control room logs, shift supervisor logs, and operating orders.

The condition of plant equipment, radiological controls, security and safety were assessed.

Plant housekeeping and cleanliness were evaluated.

Biweekly, selected Engineered Safety Features (ESF) trains were verified to operable. The inspector reviewed, also biweekly, a safety-related tagout, chemistry sample results, shift turnovers, portions of the containment isolation valve lineup and the posting of notices to workers.

The inspector observed selected phases of plant operations and concluded that the areas inspected and the licensee's actions did not constitute a health and safety hazard to the public or plant personnel.

The following are noteworthy areas the inspector reviewed:

a.

Loss of Reactor Coolant System Level Control (1) Event Description On June 4, 1990, following a refueling outage, Maine Yankee operations personnel were filling and venting the reactor cool-ant system in accordance with Procedure 1-9-1, " Reactor Coolant System Fill and Vent."

Nitrogen was being added to the pres-surizer to pressurize the Reactor Coolant System (RCS) in order to establish conditions under which the reactor coolant pumps could be vented and run.

The reactor coolant pumps are run fcr approximately one minute during the fill and vent procedure to

" sweep" any air trapped in the loops to the reactor vessel head for venting.

At 3:10 p.m. the evolution to pressurize the RCS was begun by increasing nitrogen pressure in the pressurizer in accordance with Proceaure 1-9-1, Step 6.4.

As anticipated, indicated level in the pressurizer decreased due to gases in the reactor vessel head and RCS loops being compressed and the voids being filled by the pressurizer water inventory.

The decrease in pressurizer level was indicated on both the hot-calibrated level indicators (LT-101X and LT-101Y) and the cold-calibrated level indicator (LT-103).

The hot-calibrated level channels read actual level

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when the pressurizer is at operating conditions and must be cor-rected for other pressurizer conditions.

Operating procedures used for filling and venting the RCS required that pressurizer level be maintained between 20-25% and the three pressurizer a

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level channels be in agreement, As pressurizer level decreased, operators added inventory to the RCS from the RWST (Refueling Water Storage Tank) via the RHR (Residual Heat Removal). pumps in accordance with Procedure 1-9-1.

However, they were unable to maintain pressurizer level greater than 20%.

LT-103; indication decreased to approximately 11% and LT-101X and LT-101Y decreased.

to approximately 19%. Makeup to the RCS from the RWST was,in-creased and LT-101X and LT-101Y indicated an increase:in pres-surirer level from approximately 19% to. 39%.

LT-103 remained steadyEat 11%. At 4:20 p.m., with approximately 39% level in-dicating on.both LT-101X and LT-101Y, RCS makeup from the RWST was' secured. Nitrogen pressurization of the RCS continued. As expected, indicated pressurizer level resumed a downward trend after securing makeup.

Operations personnel assumed that LT-103 was indicating incor-rectly and requested that an Instrument and Controls (I&C)-tech-nician backfill and vent the transmitter.

Following backfilling and venting of LT-103, its indicated pressurizer level decreased from 11% to 2%.

I&C-personnel stated to operations personnel that they believed-that LT-103 was. accurate, and returned the transmitter to service at 5:30 p.m.

The operators concluded that LT-103 remained inaccurate, based on the fact that.two in-dependent level transmitters (LT-101X and LT-101Y) were tracking together and indicated a level in the pressurizer. The opera-tors requested that I&C calibrate LT-103. That calibration of LT-103 was initiated, but was not completed until after:the pressurizer was drained at 7:10 p.m.

At:4:40 p.m., pressurizer level as indicated by LT-101X and LT-101Y-began trending upward. This unanticipated increase in pressurizer level was identified by the Reactor Operator (RO)

-and discussed with the Shif t Operations Supervisor (SOS).

This increase 'in indicated pressurizer level, instead lof the expected decrease, was assumed to be due to inleakage to the RCS from the RWST. That assumption was not verified.

Pressurization of the RCS continued. The R0 and SOS decided to reduce pressurizer level, by draining the RCS to the RWST, when indicated level-reached approximately 60% on LT-101X and LT-101Y.

The. decision to drain the pressurizer, which was not in accordance with Pro-cedure 1-9-1, was discussed among the senior reactor operators and the. reactor operators present in the control room, but was not conveyed to the Plant Shift Superintendent (PSS). The PSS was outside the conteci room'and engaged in' unrelated activities during this period.

The R0 planned to reduce pressurizer level by using the operat-ing Residual Heat Removal (RHR) pumps discharging to the RWST-through a slipstream demineralization loop.

Initially the slip-stream demineralization loop was placed in service with the dis-

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charge from the demineralizers being returned to the RCS via.-

valve CPU-17 Under these conditions, transfer of RCS inventory H

u to the RWST via the slipstream demineralizers would occur if CPU-17. was shut and Valve CPU-16 (slipstream discharge to RWST)

was then opened. At approximately 7:10 p.m., the RO directed

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the Auxiliary Operator (AO) to transfer the slipstream flow to

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the RWST.

Due to a miscommunication between the R0 and the A0

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performing this evolution, CPU-16 was. opened prior to closing c

CPU-17.

That caused the flow through CPU-17 to reverse, divert--

ing RHR flow-to the RWST through valve CPU-16'in addition to the

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slipstream flow.

This error in valve manipulation ceused a rapid

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decrease in indicated level and a large transfer of RCS inven-

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tory (approximately 6000 gal.) to the RWST. This diversion was i

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terminated when the A0 closed valve CPU-17.

When the transfer. occurred, the control room operator observed I

that RWST level had increased by greater than the anticipated

amount. He then checked the Primary Inventory Tracking System.

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(PITS) indicators, which indicated reactor vessel level.

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. instruments indicated a: substantial gas space in the reactor

. vessel head.

The operators verified that RHR capability had not been affected

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and contacted the Plant Shift Supervisor and the Operations De-partment Manager (who-was not onsite). All three pressurizer

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level ' transmitters (LT-101X, LT-101Y and LT-103) were backfilled and vented.

Backfilling and venting of the level transmitters e'

restored accurate pressurizer level indication.

Filling and venting of the RCS were then resumed to increase the suction pressure to the RHR pumps..There was no'. indication that RHR was

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operating abnormally, but the system'was vented to ensure that-no air entrainment had taken place.

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(2). Inspection Activities A regional specialist inspector and a PWR resident inspector were dispatched to the site to review the event.

The inspectors interviewed Operations personnel and station management; reviewed strip charts from control room recorders, printouts of computer

points, layout of main control board indications, locations of

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valve operator handwheels in the spray buildirg; and held dis-l cussions with personnel performing the Plant Root-Cause Evalu-ation (PRCE).

In addition, the-inspectors reviewed the completed

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PRCE.and observed the Plant Operations Review Committee (PORC)

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review of the PRCE. The inspectors independently verified the correlation between pressurizer level indication (in percent)

and PITS indication (elevation referenced to mean sea level)

using plant drawings showing elevations of the various components.

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'(3) Licensee Corrective Actions

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Immediate licensee' action in response to this event was to stabilize the reactor coolant system by returning water from-the.

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RWST to the RCS and venting the gas from the RCS. While this evolution was in progress, an Unusual Occurrence Report (VOR)

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was generated.

Preliminary recommendations for long term cor-

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rective action listed in the UOR included the initiation of a

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Plant Root Cause Evaluation (PRCE).

Licensee management actions while the PRCE was in progress included a section of the June 5-

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Day Orders (the morning af ter the event) devoted to a re'-emphasis

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of. operations department philosophies regarding.be>ieving and

acting _upon instrumentation readings, stopping evolutions when unexpected conditions arise, importance of accurate ~ communication,

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maintenance of a questioning' attitude, teamwork, and--taking the

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time to do it right.- Effective June 7, based on initial review

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E of factors contributing to the event, several changes _were made^

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to the conduct of shift turnovers and duties of the Startup Co-

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.ordinators.

Upon_ completion of. the.PRCE, eight (8) recommenda-

'tions to prevent recurrence were identified and endorsed by the Plant Operations Review Committee (PORC) on June 8.

These follow, o

A task force was established to determine-the cause.of-the l

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simultaneous failure of both pressurizer level safety / con--

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trol channels, and the potential that'any other vital trans-

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mitters may be subject to similar common cause conditions.

A revision to Procedure 1-9-1, " Reactor Coolant System Fill

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and Vent," was completed prior to' reuse of the procedure

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after the Control Element Assembly inspection efforts.

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Provide redundant cold-calibrated pressurizer level indica-

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tion in the control' room, with' trend'and alarm functions,

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using existing Appendix R instrumentation and.the plant computer.

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Provide ailimited flow method for transferring water from

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the RCS to the'RWST during low pressure operations.

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Provide a correction curve for LT-101X and LT-101Y for sub-

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cooled and' low pressure conditions.

Update operator training to reflect the impact of the

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' standpipe design of the reactor vessel level indication (the level instrument indicates 10094 until the standpipe is t

uncovered at approximately 91?4 level).

Provide a warning sign on Valve CPU-16 to direct that it j

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not be opened until Valve CPU-17 is closed.

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f Revise RHR procedures to provide for transferring purified

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water from the RCS to the RWST.

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Prior to reperforming the reactor coolant system fill and vent

.after.the outage was extended.due to Control ElemenJ Assembly failures, Procedure 1-9-1, " Reactor Coolant System Fill arid Vent,"'was revised to incorporate the recommendations of the

PRCE. The-task force identified the cause for the common-fail-ure of both of the pressurizer level instruments and identified y-other< instrumentation that may have been subject to similar cir-m cumstances. The Instrument and Controls (I&C) Section ensured

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that the affected instrumentation systems were adequately back-filled prior to the instrumentation being required to be oper-able.

Provisions to ensure these actions occur in the future are to be permanently incorporated into plant procedures.

The remainder of the corrective actions recommended by the PRCE are-to be: completed following plant startup.

I (4) Assessment'of-Event Based on post-event review of plant data, on June 4,1990, pres-

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surizer level decreased below the bottom of the pressurizer at

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approximately 3:40 p.m. and was not restorea until 7:55 p.m.

l Indicated level on LT-101X and LT-101Y at 3:40 p.m.-inaccurately

indicated 20?4 pressurizer level.and then, with the pressurizer M

empty, trended up to 66'4 indicated level. -After filling and H

venting'LT-103's' variable and reference legs at 5:30 p.m., LT-103 j

was correctly reading offscale low.

However, based on the re-

sponse of two other independent level transmitters, LT-101X and q

LT-101Y,!LT-103 indication was not used by the operators.

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actual RCS level between 3:40.p.m. and 6:40.p.m. was between the L-bottom of-the pressurizer and 91?4 reactor vessel level (PITS L

reactor. vessel level indication is of fscale high: abovel 91% level).

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The exact reactor vessel level at that time is-unknown since

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level indication for this range is not available during the RCS n-fill and vent evolution, i

Post-event review of the PITS recorder charts indicates that I

reactor vessel level had decreased to approximately 91% prior to

the RCS-to-RWST Inventory transfer which occurred at 7:10 p.m.

(A: PITS level of 91?s corresponds to approximately 4 feet above

l the reactor vessel flange.) After the transfer to the RWST,

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PITS level was reduced to 74?f, which corresponds to about 3 feet q

below the reactor vessel ~ flange. This is approximately 2 feet j

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above the top of the hot leg pipe and more than 9 feet above the

core.

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The inspectors concluded,. based on PITS data, that a gas bubblef

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existed in the reactor vessel head prior to the discharge of

approximately 6000 gallons of coolant; It further appears that-

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pressurizer level was lost and a gas space may have formed in-

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the reactor vessel head as early as 3:30 p.m. based upon extra-po_lation of PITS data.

M4-The cause of the event was the failure of any pressurizer level instrument to accurately indicate pressurizer level. This was r

compounded by the fact that separate, independent, redundant

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level channels were trending within 2*. indicated level, and were.

both wrong.

That masked the indication problem.

Contributing factors included:

no clear procedural requirement for agreement'

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between Indicators, no specific procedural guidance for actions

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to be taken in the event of indication anomalies; and inadequatei F

procedural ' guidance for preparing instrumentation to begin the t

evolution.

The situation was exacerbated when the operators,

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believing their erroneous indication, rapidly discharged approxi-mately 6000 gallons of reactor coolant due to improper sequencing m

of valve operations which were not authorized for_this plant condition.

The associated lack of' procedural guidance on steps to be.taken to reduce RCS inventory during RCS fill and vent contributed to the improper sequencing.

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The PRCE concluded that the cause of the instrument anomalies

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was the fact that several pressure transmitters are connected to

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each pressurizer level instrument reference leg.

The pressure transmitters were not filled and vented when the level trans-e

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mitters were.. That lef t voids in the-reference leg sensing

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lines. When the system was pressurized,'these voids compressed,

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resulting in a decrease-in the height of the water column in-the

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reference legs. That reduction in the reference legs resulted in an. increase'in indicated _ level, with actual level decreasing or steady.

The' inspectors reviewed the supporting documentation

for this conclusion and found this'to be a reasonable explana-tion of the observed phenomena on.LT-101X and LT-101Y.

As discussed above, contributing factors to this-event included inadequate or inappropriate procedural guidance and actions taken by operations personnel during the conduct of Procedure 1-9-1,

" Reactor Coolant System Fill and Vent."

Procedural deficiencies were identified by NRC instectors and by licensee staff members conducting independent rev ws of this event. The procedure deficiencies noted by the NRC foi Mw.

Procedure 1-9-1 contained a prerequisite to verify the

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operability of the pressurizer level instrumentation, but it did not require backfilling and venting of the pressuri-zer level transmitters.

The operability was verified by

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-I&C personnel through.a paperwork review to verify a cur-e rent calibration and that a backfill and vent had-occurred during the outage, i

Procedure 1-9-1 states that the three pressurizer level-

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transmitters shall be in. reasonable agreement but does.not i

provide an objective criterion for making this determination.

Guidance for draining inventory from the RCS during the RCS

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fill and vent evolution was not included in Procedure 1-9_-1.

Ter.hnical' Data Book Figure 1.3,1,'" Pressurizer Level Cor-

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rections for 0FF: NORMAL pressurizer / containment conditions,"-

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for LT-101X&Y was not adequate for level corrections re-quired when conducting-Procedure 1-9-1.

The f ailure of the procedure to-adequately address preparation of the. instruments, provide objective criteria for the instru-mentation to be in reasonable agreement, and provide direction

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for draining' violates 10 CFR 50, Appendix B, Criterion V (50-309/90-10-01).

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The procedural inadequacies provided above, and others, were

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also identified by the licensee's staff and are documented as

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. recommendations in the licensee's evaluation of this event (PRCE -

172)..The lack of adequate procedural guidance for conducting

'the RCS fill and vent evolution was a contributing factor, but not the prime cause, of this event.

Operator action, based on

.i, available indications and procedures,-could have averted the

reactor-coolant-system inventory reduction which resulted-in an unanticipated entry into a reduced inventory condition, r

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Operations personnel performing this evolution did not strictly adhere to Procedure 1.9.1, " Reactor Coolant System Fill and Vent." Examples are provided below:

Caution statements throughout-RCS Fill and Vent Procedure

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1-9-1 state that LT-103, LT-101X, and LT-101Y are to be in agreement.

The three level transmitters were not in agree-

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ment following the initial pressurization of the pressurizer-and remained out of agreement for the dur: tion of the event..

Operators took a proper action in having I&C backfill LT-103.

However, the RCS pressurization evolution could and should have be(n suspended pending the determination of LT-103 operability.

Procedure 1-9-1, Step 6.4.6, directs maintenance of pres-

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surizer level between 20-25%.

Throughout the RCS fill and vent evolution, this guidance was not followed, m

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In' response to the increasing indicated pressurizer level,

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dural guidance.

During the draining evolution, inadequate

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a communications resulted in an inappropriate valve'manipu-lation.

The inappropriate valve manipulation caused a

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diversion of approximately 6000 gallons of RCS inventory to-the RWST.

This error resulted-in a further reduction in reactor' vessel level,

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An~ additional. weakness was the failure'to suspend filling and venting of the RCS pending resolution of-the cause for the-un-

anticipated pressurizer level increase.-

Procedure 1-9-11 1ndi--

cates that, on an increase in pressurizer pressure,-indicated'

level in the pressurizer will decrease. _However, indicated'

pressurizer level during this event increased for about 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.

At no time during this 2.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> period was the fill and vent

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evolution su: pended.

The operators were aware of the'unantici-I pated increase in level and discussed potential reasons for the indication.

These discussion did not result-in reaching an understanding of the level increase.

At this point, operators

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performing the evolution considered that continued pressuriza-~

l tion would aid in slowing the indicated rate of level increase n

and chose to continue the pressurization when, upon. review, it appears they should have suspended it, b.

Licensee Event Report Review r

TheLin'spector reviewed Licensee Event Report (LER)90-002, "Inadvert-ent SIAS while Swapping Vital AC Busses," and Plant Root Cause+ Evalu-i ation Number 171, which addressed an_ inadvertent Safety Injection Actuation Signal (SIAS).

This occurrence'was previously reviewed as

described in Region I Inspection Report 50-309/90-06, Detail 1.c.

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Items identified as requiring further review included:'the;LER,mthe M

' Plant Root Cause Evaluation, personnall performance implications,'and-long term' corrective actions.

The LER accurately reflected the event

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as it occurred. The Plant Root Cause Evaluation appropriately ad-dressed the principle contributors which led to the SIAS.

These were: Inadequately human-factored labels associated with the vital'AC'

busses; an insufficiently detailed operating procedure (considering

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that cross-tieing vital busses is a non-routine evolution); and'the e

SIAS actuation relays being operable when'they did not need to be.

Corrective actions included relabeling of the equipment, evaluation of the training prov_ided on the evolution, a rewrite of the procedure governing the evolution and an evaluation of the feasibility of dis-abling the SIAS, Containment Isolation' Signal (CIS), Recirculation Actuation Signal (RAS), and Containment Spray Actuation Signal (CSAS)

actuation systems when in extended shutdown with actuation neither required nor desired, i

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_The equipment had been relabeled at the time of this review.

Long-

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term corrective actions planned by the licensee to address this ' issue were considered appropriate.

The inspector had no further' questions.

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2.

Radiological Controls-Radiological controls _were observed on a routine basis during the report-ts ing period. Areas reviewed included Organization and Management, external radiation exposure control and contamination control.

Standard industry radiological work practices, conformance to radiological control. procedures and 10 CFR Part 20 requirements were observed, a.

Worker Concern-

The NRC was informed of a worker concern regarding the unplanned ex-posure to three workers involved with the repair of valve PCC-A-216.

A specialist inspector reviewed the circumstances of the unplanned exposure during an inspection conducted on June 5 through 7.

The specialist inspector's findings are documented in Region I Inspection Report.50-309/90-11.

'3.

Maintenance /Scrve111ance The' inspector observed and reviewed maintenance and problem-investigation activities _to verify compliance with regulations, administrative and main-tenance procedures, codes and standards, proper QA/QC involvement,, safety tag use, equipment alignment, jumper use, personnel qualifications, radio-logical controls for worker protection, retest. requirements, and report-ability per Technical Specifications.

i Also, the inspector

~ rved parts of surveillance tests.to assess per-I formance in accort r with approved procedures and Limiting Conditions

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for-Operation, te results, removal'and restorationaof equipment, and deficiency review and resolution.

The following activities were; reviewed and considered to be noteworthy:

a, Control Element Assembly Failure On June 7, while performing procedure 3-6.2.1.19, "(Cold) Functional-Check of CEAs," Control Element Drive Mechani.sm (CEDM) 53 had been fully withdrawn and was being driven into the core. The CEDM would not drive in~beyond a height of 38 steps.

The CEDM would move out when pulled but, upon insertion, stopped.at Step 38.

Initial trouble-shooting activities were unsuccessful-in determining the cause. After completing an evaluation on the effect that the stuck CEDM had on the reactor shutdown margin, the licensee made appropriate procedure changes and continued the procedure.

No other problems were en-countered i'n completing the CFA functional checks.

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CEDH 53 is a dual element CEDM in Shutdown Group C.

A dual element CEDM consists of a single drive mechanism which drives two (2) Con-

s trol Element Assemblies (CEAs), in this case CEA D6 and CEA 79.

~ During troubleshooting, the CEAs were unlatched from CEDM 53. CEA D6

fel1~into the core to the full inserted position.

CEA 79 remained at 38 steps withdrawn. The-reactcr was partially disassembled.- CEA 79

was reaoved from the fuel assembly and inspected visually.

The CEAs.have five fingers, arranged as if four were at.the corners:

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of a square and one at the center.

The fingeis are connected _by a

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hub located at their upper ends.

Each finger inserts into a guide tube located in a fuel assembly.

In the originally installed CEAs

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(reference. design), the four outer. fingers have eight-inch silver-

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indium-cadmium ( Ag-7n-Cd) plugs located adjacent to the lower,

-Inconel endcaps, where the center finger has boron carbide pellets.

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That_ difference was due to the dashpot action utilized to arrest rod motion at the end of travel.

The four outer guide tubes utilize a dashpot design, while the center tube does not. Ag-In-Cd plugs were

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originally included.in the design of the outer fingers for structural considerations.

On later designs, all five fingers have the Ag-In-Cd-

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The visual inspection revealed that CEA 79's center finger had an axial crack, approximately four (4)_ inches long, near the tip, and

that its Inconel end cap was was missing.

Through-the crack, the upper spacer and spring were visible.

This indicated that the end-cap, lower _ spacer, and boron carbide pellets _ were missing.

-1 This CEA is one of 23 reference design CEAs (out of a total of 81 in

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the core) which were to remain in the reactor through the upcoming Cycle 12 operation and be replaced during:the next refueling outage.

As a result of the identified _ failure of CEA 79, the licensee in-

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spected the,115 used CEAs onsite.

This population _ included 43 of the i

new design (used for up to five cycles of operation)_ and 72 of the reference design (mainly original equipment and of. various usage his ~

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tories).

The inspections ir.cluded eddy current examination of the full length of all the fingers except those three that would not. fit into the inspection equipment due to failures.

These were the three.

that were missing their endcaps. The results of the inspection were-j as follows:

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Forty-three CEAs of the new design (with Ag-In-Cd plugs in place

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a of the reference design's boron carbide pellets) had no indica-tions.

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Of the 72 reference design CEAs, hree were missing their end-

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caps, one had an axial crack that intersect.ed with a circum-ferential crack in the cladding to endcap tield area and, of the remaining 68, 26 had indications of cr m s.

As the boron carbide pellets are irradiated, they swell due to gas production.

Since the CEAs are operated slightly inserted into the core, the tips are subject to higher radiation than the rest of the assembly.

As the pellets near the tip swell, they strain the Inconel cladding.

In this case, the licensee postulated that SYial Crack formation propagated until it intersected with the cladding to endcap weld area.

The crack then propagated circumferential1y around the weld arta, resulting in the endcap separating from the cladding.

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Destructive examination to validate this postulated failure morte is planned.

The licensee did not reinstall any used CEAs of the reference design for Cycle 12 operation.

The CEA configuration utilized for Cycle 12 included the use of the 43 used CEAs of the new oesign (these were inspected with no defects identified), 37 unused CEAs of the new de-sign, and one unused CEA of the reference design. The licensee plans to use the CEA of the reference design for one cycle only, and to then maintain it as a spare.

Although not prescri:>ed by inservice Inspection (ISI) p.ogram re-quirements, the licensee has routinely inspected the CEAs.

The most extensive of these examinations was conducted in August of 1985, after Cycle 8.

That examination utilized an encircling coil eddy current technique which measured wear, strain and qua;ity of the cladding.

Sixty-one CEAs were examined.

Strain aed/or i< ear were determined to be the life-limiting considerations.

Using r,onservative progression rates based on past experience, acceptance criteria provided by Com-bustion Engineering, and the ceasurements taken in 1985, the licensee projected the remaining useful life of the CEAs. A replacement pro-gram was initia 3d and CEAs were replaced during the refueling out-ages after Cycies 9, 10 and 11.

Twenty-three CEAs of the reference design were to remain in service through the end of Cycle 12, the current cycle.

In general, the cladding cracked with strain values less than the acceptance criterion for strain. As previously stated,

.further evaluation of the failure mode is planned.

Infcrmation on the subject was distributed to other utilities through the Nuclear Network on June 13, 14 and 18. An informational report was made to the NRC Operations Center on June 14.

Combustion Engi-neering (CE) issued an Information Bulletin to all CE plants on June 20.

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L On June 25, the licensee met with the NRC staff in Rockville, Maryland

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to discuss the CEA failure and the licensee's plans for pidnt restart.

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No concerns regarding this issue were "Jentified related ts safe

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operation of the facility during Cyc1x 12.. The NRC staff is evalu-

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ating the generic implications of this issue.

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Rosemount Transmitter Testing

The inspector also reviewed the 1.icensee's program to inspect Rose-l

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mount Transmitters as requested by NRC Bulletin 90-01 dated March 9,

1990.' This bulletin concerned loss of fill oil.in transmitters manu-

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factured by Rosemount.- That could result in eventual failure of the

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measuring instrument.

The Instr'umentation and Controls (I&C) Section developed a procedure i

to test all series 1153B,1153D and 1154 Rosemount transmitters during

- r the-outage. -The procedure was developed based on guidance provided

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by Rosemount. in. Technical Bulletin humber 4 dated December 22, 1989.

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All transmitters were tested and found to be free of defects, except one.

That transmitter was repaired.and satisfactorily tested. A

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second transmitter.was discovered to be from a suspect lot and was i

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replaced with a transmitter from stock which was also satisfactorily.

tested.

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The licensee's actions to. respond to the bulletin were found to be J

well coordinated, timely and well documented.

NRC Bulletin 90-01 is-

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therefore closed.

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Loss of AC Test l

On June 2, the licensee performed the refueling frequency " Loss of AC

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Test." The test was conducted in accordance with Procedure 3.1.148,',

"B" Train EDG/ECCS Cold Shutdown Test.

That test verifiesiproper i

operation of the automatic start of the emergency diesel generators,-

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emergency bus load shedding and loading, all Train "B" automatically

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actuated emergency core cooling system valves, and the degraded grid i

voltage scheme.

The starting system for the diesel consists of two sets 'of two air j

start motors.. Upon receipt of a start signal, one set of air start

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motors is actuated.

If the diesel fails-to start, both sets are ac-l

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tuated by the start control circuitry. The acceptance criterion for

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B the. time from when the bus is deenergized to the closure of the diesel

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generator ~ output breaker is ten seconds.

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During the test on June 2, the diesel generator failed to start when the first set of air start motors was actuated.

Both sets were actu-

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ated andLthe diesel generator started.

Due to the time delay 'n

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starting, the output breaker closed in 10.7 secords after the start

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'l signal verses the 10 second time limit established as an acceptance

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criteria. No other significant deficiencies were identified,

.j Troubleshooting, including the performance of Procedure 5-78-1,

" Diesel Gener. tor Redundant Systems Check " verified the proper

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operetion of the start control circuitry. A retest of the "B" diesel

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. generator start sequence was performed on June 3.

The diesel genera-

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d tor started using the first set of motors'and its output breaker

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closed in 6,9 seconds.

The' licensee plans to perform further evalu-

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ation of the basis for the ten-second acceptance criterion.

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Physical Security Checks were made to determine whether security conditions met regulatory-requirements, the physicci security plan, and approved procedures. Those

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checks included security st.3fing, protected and vital area barriers,

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vehicle searches and personnel Mentification, access control, badging,

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and compensatory measures when required, l

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-On May.24, at 2:07 a.m. the licensee identified an uncompensated loss of security access contrul when a security guard was inattentive to duties.

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The guard was stationed at a temporary post %;211shed for the refueling

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L outage.

Upon discovery, a replacement ge:.rd was sutioned and a security guard and an auxiliary operator were dispatched to search the area, and a report to the NRC Operation *, center was made, The. search identified no l

indication of unauthorized access,.The security guard involved, a tem-l

'porary employee hired for the outage, was fired, j

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No unacceptable conditions were identified.

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5, E_ngineering/ Technical-Supyort

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Primary to Secondary Leakage Criteria ~

t As described in Region I Inspection Report 53-309/90-06, Detail'5,a.,

i the licensee identified circumferential cracking in a small number of steam generator tubes. On May 23, a meeting between the NRC and Maine.

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.. Yankee was held to discuss the'results of the steam 90nerator tube-e inspections, the methods available for primary to secondary leak de+

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tection, and the revised administrative controls to be implemMyed

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for operation during the upcoming cycle, At the meeting, Maine Yankee-i proposed conservative administrative controls for plant operation a

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during Cycle-12, These controls included: at a measured primary to

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. secondary leakage of fifteen gallons per day, increased surveillance-i

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and a special Plant Operations Review Committee meeting will-be in-itiated; at a measured primary to secondary leakage of fifty gallons..

i r day, a controlled plant shutdown will be accomplished within six a

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hours; at a measured primary to secondary leakage of 100 gallons per i

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l day a rapid plant shutdown will be accomplished within two hours.

After such a shutdown, the plant will not be restarted until the l

leakage source has been identified and repaired.

In a letter dated I

June 6 1990, Maine Yankee formally committed to implement these ad-

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ministrat_ive controls prior to plant startup for Cycle 12 operation.

The inspector reviewed Abnormal Operating Procedure (AOP) 2-25, "High Radiation Levels." -The above commitments were-incorporated into the procedure.

The licensee's actions to address this issue were assessed l

as comprehensive and conservative, and reflected positively on the j

technical capability of Maine Yankee's staff.

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Motor-operated Valve Program y

The' inspector reviewed the licensee's program for the testing of

motor-operated valves (MOVs) in response to NRC Generic Letter 89-10

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dated 6/28/89, NRC Bulletin 85-03 dated 11/15/85, and Bulletin 85-03

Supplement I dated 4/22/h8. The licensee instituted a program to l

comply with Bulletin.85-03 and Supplement I by identifying the valves covered by the bulletin, establishing the design basis of those valves, developing a valve operator switch setting program, stroke testing the valves to verify their operability, and establishing pro-

cedures for the development and maintenance of switch settings for

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L the valves. Generic Letter 89-10 dated 6/28/89 expanded the. scope of

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a valves covered by Bulletin number 85-03 to include additional safety-l-

class valves, positior-changeable valves and some support system valves.

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- In response to Generic Letter 89-10, Maine Yankee plans to identify

the affected valves by.0ctober 1, 1990 and to' document the design i

basis of the identified valves by December 1,1990.

The valves which U

are identified shall be added to the MOV_ program on a case-by-case l'

basis, depending on valve capabilities and safety function (s). This

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is to be completed by startup from the 1991 refueling shutdown.

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The licensee's personnel responsible for conducting the MOV program

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- appeared to be very knowledgeable, highly motivated, and aware of past industry MOV problems and the need to improve MOV performance and reliability.

The licensee has assigned a full time engineer to K

oversee the program and provide the required engineering assistance.

During the refueling outage a maintenance department electrician was

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assigned to the MOV program with the sole task of overseeing the

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day-to-day performance of MOV repair and testing by contractors.

• Ouring this outage approximately thirty valves were diagnostica11y I

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tested as part of the MOV program, and the data was entered into the equipment history records.

In addition, approximately 150 other MOVs

had preventive maintenance performed on them and were inspected and j

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repaired as necessary.

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While performing work on or functional testing of a number of the

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.MOVs.. difficulties encountered in some cases damaged the valve or its i

i motor-operator.

The licensee generated an Unusual Occurrence Report

(VOR) to delineate each such problem and bring it to plant manage-

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p ment's attention.

Early in the outage, the.use of the VORs resulted-

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in the assignment of a technical staff member to oversee and coordin-

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ate the MOV oroject. Also the Quality Programs Department (QPD)

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increased its surveillance of the MOV project activities. The in-spector reviewed the incidents individually and the corrective ac-i

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tions taken to return.the motor-operated valves to operable status.

L Corrective actions were considered appropriate.

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The Quality Programs Department has not completed its evaluation of

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the UORs or provided recommendations for long-term actions to prevent.

i similar problems. The inspector will review the results'when' avail-

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able in.accordance with the NRC routine inspection program, c.

Unaccounted-For Debris in the Reactor Coolant System i

Item 50-309/90-06-02 was unresolved pending inspector review of an i

evaluation of the effect of the unaccounted-for debris in the reactor-

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coolant system identified during the thermal shield inspection during i

the Cycle 11/12 refueling outage.

That evaluation was performed by the Yankee Atomic Electric Company and was dated 5-22-90.

It con-

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cluded that the debris resulted in an extremely low failure probabil-

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ity that was comparable to previous cycles, This conclusion was.sup-ported by the fact that the debris was mest likely generated during

.the last few operating cycles (since the last thermal shield inspec-

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tion in 1985) and those operating cycles had virtually no fuel fail-

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ures.

Item 50-309/90-06-02 is therefore. closed.

6.

Administrative a.-

Persons Contacted

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Within this report period, inter / %t; and discussions were conducted

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with various 1.icensee personnel, including plant operators, mainten-

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ance technicians and the licensee's management staff, b.

Summary of Facility Activities

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The plant was in.a refueling shutdown for the duration of the report period, c.

Interface with the State of Maine n

Periodically, the resident inspectors and the onsite representative of the State of Maine discussed findings and activities of their cor-(

responding organizations.

No unacceptable plant conditions were

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identified.

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t Meetings _were' periodically held with senior facility. management to

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' discuss'the' inspection scope and findings. ~A summary of findings for

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the' report period was also discussed at the conclusion of the inspec-

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tion.

During one of the routine meetings the contents of~a February-n"

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- 2, 1990 memo authored by the NRR Director and entitled " Temporary

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- was1provided a copy. That memo is available in the Public Document Waivers of Compliance" were discussed with the Plant: Manager and he

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fX Inspection Meetings Conducted by Region Based Inspectors-.'(30703)

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Inspection Reporting.

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Subject Report ho.

Inspector Dates

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i 6/7/90.

Radiation Protection 90-11 Nimitz

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-6/15/90-RETS/REMp 90-12 Jang h

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Inspection Hours This-inspect 1.on involved 205 inspection hours, including 22 backshift-

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