IR 05000331/1993007

Insp Rept 50-331/93-07 on 930407-0521.Violation Noted But Not Subj to Enforcement Action.Major Areas Inspected: Licensee Event Rept,Follow Events,Operational Safety, Maint,Surveillance & Lead Test Assembly Insps

ML20045A866
Person / Time
Site:	Duane Arnold
Issue date:	06/02/1993
From:	Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20045A864	List: IR 05000331/1993007 ML20045A863
References
50-331-93-07, 50-331-93-7, NUDOCS 9306150123
Download: ML20045A866 (13)

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.i U. S. NUCLEAR REGULATORY COMMISSION

REGION Ill Report No. 50-331/93007(DRP)

Docket No. 50-331 License No. DPR-49.

Licensee:

lowa Electric Light and Power

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Company

IE Towers, P. O. Box 351 Cedar Rapids, IA 52406

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Facility Name.: Duane Arnold Energy Center l

Inspection At:

Palo, Iowa

Inspection Conducted:

April 7 through May 21, 1993

Inspectors:

M. Parker C. Miller

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hem C7. /Ir#

vb 6 ) '73 Approved:

yCR.D.Lanksbu/y, Chief Date

' Reactor Projects Section 3B

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inspection Summary

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Inspection on April 7 through May 21. 1993 (Report No. 50-331/93007(DRP))

Areas Inspected: Routine, unannounced inspection by the resident inspectors of followup, licensee event reports followup, followup of events, operational safety, maintenance, surveillance, lead test assembly inspections, regional requests, management meetings, and report review.

Results:

An executive summary follows:

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930$150123 930604 l

PDR ADOCK 05000331 O

PDR

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EXECUTIVE SUMMARY

Operations The plant was operating at 100 percent power with all rods out at the beginning of the period.

Reactor power decreased slowly throughout the period, while in coast down prior to the refueling outage scheduled to begin July 29, 1993.

Reactor power was 89 percent at the close of the period.

Operating performance has been good this period, with a plant gross thermal capacity of 92.4 percent for the cycle, and few personnel errors.

Some problems were noted with standby diesel generator (SBDG) annunciators and operator familiarity with them (section 5).

Maintenance / Surveillance 1.

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Maintenance performance has been very good, with few personnel errors, while

the on-line corrective maintenance backlog has decreased well 1,elow 500.

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One non-cited violation was issued for failure to properly test the primary containment personnel air lock (EA No.93-106) (section 7).

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Level switch surveillance failures were responsible for two separate entries into 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> limiting conditions for operation (LCOs) to cold shutdown.

Continuing level switch problems, plus an inability to ensure high pressure coolant injection (HPCI) discharge piping remained full if one of the LC0

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options was taken, have been factors in nearly initiating a plant shutdown on several occasions (section 7).

Enaineerina and Technical Support The licensee completed HPCI and reactor core isolation cooling (RCIC) room door modifications which should enable the doors to remain intact following the peak pressure of a postulated steam line break in either room (section 6).

Safety Assessment /Ouality Verification The licensee received enforcement discretion for delaying testing of primary containment personnel airlock seals, following their discovery that testing had not been accomplished according to technical specification (TS) and Title 10 of the Code of federal Regulatfons (CFR) requirements (section 7).

Shipping activities for the lead test assembly (LTA) project were well planned and executed, with appropriate management oversight (section 8).

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Persons Contacted

• R. Anderson, Msistant Operations Supervisor

• P. Bessette, Supervisor, Regulatory Communications

• J. Bjorseth, Assistant Operations Supervisor

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• D. Blair, Quality Assurance Assessment Supervisor

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• C. Bleau, Supervisor, Systems Engineering

• D. Engelhardt, Security Superintendent

• M. Flasch, Manager, Engineering

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J. Franz, Vice President Nuclear J. Kinsey, Supervisor, Licensing

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D. Lausar, Supervisor, Project Engineering

• M. McDermott, Maintenance Superintendent

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C. Mick, Operations Supervisor

• K. Peveler, Manager, Corporate Quality Assurance

• K. Putnam, Supervisor, Technical Support

• A. Roderick,-Supervisor,' Testing and Surveillance P. Serra, Manager, Emergency Planning

• N. Sikka, Supervisor, ' Electrical Engineering S. Swails, Manager, Nuclear Training J. Thorsteinson, Assistant Plant Superintendent, Operations Support

• G. Van Middlesworth, Assistant Plant Superintendent, Operations and

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Maintenance

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T. Wilkerson, _ Radiation Protection Manager

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• D. Wilson, Plant Superintendent, Nuclear

• K.- Young, Manager, Nuclear Licensing-i In addition, the inspectors interviewed other licensee personnel including operations shift supervisors, control room operators, engineering personnel, and contractor personnel (representing the

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licensee).

• Denotes presence at the exit interview on May 21, 1993.

2.

Followuo (92701)

(Closed) Unreso]ved Item 50-331/92006-02(DRP):

Failure of the safety bus fast transfer feature. During testing of 161KV supply breakers "J" and "K", the 4160V safety bus IA4 failed to fast (within several cycles)

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transfer to its standby transformer source. This resulted in several primary containment isolation system (PCIS) isolations and the start of the "B" standby diesel generator (SBDG). The "B" SBDG did not pick up load because the slow (4.5 second) transfer feature occurred as designed and the standby transformer supplied power to the IA4 bus.

The fast transfer feature of the 1A3 and 1A4 safety busses was designed to maintain bus voltage in the absence of a bus fault and prevent needless cycling of safety equipment in the absence of a fault and is a nonsaftey-related plant feature.

The fast transfer was not considered a.

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i safety feature since the slow transfer feature ensured alternate power.

was available even after a fault had occurred and cleared.

The slow transfer feature was tested periodically during surveillance test procedure (STP) 48A002, " Standby Diesel Generators and Emergency Service

Water System Automatic Actuation Test." The licensee did not test the

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fast transfer feature due to the disturbance it could cause on the

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electrical distribution system.

When the testing of the "J" and "K" breakers caused the safety busses to transfer, only the IA3 bus fast transferred. Troubleshooting of the IA4 bus determined that the control logic cable for the "J" breaker had been damaged during installation. This was similar to installation damage which had previously been noted and repaired on the IA3 bus control cable.

Both of these cables were routed through "LB" type condulets which had a tight bend radius.

In addition, excess cable was inappropriately jammed into the condulet, eventually resulting in a ground. The 1A3 bus logic cable was replaced and tested in January 1992 after it had failed. The licensee replaced and tested the IA4 cable in

April 1992, following its failure.

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As part of the corrective action, the licensee was in the process of inspecting and resistance checking the control cables for 14 of the switchyard breakers. Of the breakers checked so far, all had resistance readings of 50 megohms or e eater, well above the 1 megohm minimum.

No other "LB" type condulets.or control cables were found throughout the switchyard. The inspectors compared these results to the failures of switchyard breakers reported in LER 92-06.

The number of failures

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listed in the LER suggested a higher rate of failure than what the current inspection results indicated. The inspectors questioned the

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licensee about the types of failures referred to in LER 92-06. The licensee could not locate actual maintenance history which supported the one failure per year estimated in the LER. The responsible maintenance organization estimated the problems to be much less, possibly limited to

the two failures of safety bus cabling previously mentioned.

The

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inspectors noted the discrepancy in the LER and agreed that based on the low failure rate and the good cable resistance readings, the control cabling appeared to be sound.

Based on the corrective actions taken and results of the resistance checks to date, this unresolved item is closed.

No violations or deviations were identified in this area.

3.

Licensee Event Reports Followup (92700) (90712)

Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective actions were accomplished, and corrective actions to prevent recurrence had been accomplished in accordance with technical specifications.

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l (Closed) Licensee Event Ra.. t (LER)92-006 (331/92006-LL):

Emergency

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Safety Feature Actuations Due to Damaged Switchyard Cable.. This LER documented several PCIS actuations and the automatic start of the "B"-

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standby diesel generator. The corrective actions for this LER are i

documented in this report under unresolved item 50-331/92006-02(DRP).

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This LER is closed.

No violations or deviations were identified in this area.

4.

Followuo of Events (93702)

During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events onsite with licensee and/or

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'i other NRC officials.

In each case, the inspectors verified that the notification was correct and timely, if appropriate, that the licensee was taking prompt and appropriate actions, that activities were

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conducted within regulatory requirements, and that corrective actions would prevent future recurrence. The specific events are as follows:

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May 4, 1993 - 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO to cold shutdown for condensate storage tank-

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level switch LS5219

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May 14, 1993 - 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LC0 to cold shutdown for suppression chamber-level switch LS2319

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May 19, 1993 - One hour security event report No violations or deviations were identified in this area.

5.

Operational Safety Verification (71707) (71710)

The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room operators during the inspection. The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. Tours of the reactor building and turbine building were conducted to observe plant equipment conditions, i

including potential fire hazards, fluid leaks, and excessive vibrations

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and to verify that maintenance requests had been initiated for equipment in need of maintenance.

It was observed that the Plant Superintendent, i

Assistant Plant Superintendent of Operations, and the Operations

Supervisor were well-informed of the overall status of the plant and

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that they made frequent visits to the control room.

The inspectors, by

observation and direct interview, verified that the physical security

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plan was being implemented in accordance with the station security plan.

The inspectors observed plant housekeeping and cleanliness conditions and verified implementation of radiation protection controls. Daring the inspection, the inspectors walked down the accessible portions of

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the HPCI system to verify operability by comparing system lineup with

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plant drawings, as-built configuration or present valve lineup lists;

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observing equipment conditions that could degrade performance; and

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verifying that instrumentation was properly valved, functioning, and

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calibrated.

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

Standby Diesel Generator Alarms

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The inspectors observed operators perform STP-48001-M, " Standby Diesel Generator Monthly Operability Test." While the diesel was loaded, supplying power to the grid, the inspectors noted that the "A" diesel local annunciator panel IC93 windows D-5, " Generator Field Ground," and D-6, " Generator Loss of Field," were lit.

The annunciator response

procedure for the windows required the operator to verify the alarms were valid and that no loss of offsite power existed, then trip the SBDG, and notify the operations shift supervisor. The auxiliary

operator had not taken these actions because the alarm had come in previously as part of the slow SBDG start procedure used in the STP.

The alarms should have been reset after the SBDG field was energized.

This would have then allowed a valid alarm to annunciate should an actual ground or loss of field occur. The auxiliary operator was newly qualified and somewhat unfamiliar with the equipment. The STP which the operator used did not specify that the alarms be reset. After the inspectors questioned the operators, the auxiliary operator cleared the al arm. The inspectors discussed the incident with the operations supervisor who indicated that the operations shift supervisor had informed him of the issue. He also indicated he had counselled the operator involved to reset the alarms, and given training to other

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operators on the issue.

Based on observations of this surveillance both before and after the event, the inspectors concluded this was an isolated event.

The inspectors also discovered that the annunciator windows for the SBDG alarm panels IC93 and IC94 differ in operation from each other and from the control room annunciators.

Various windows on the panels clear either by a button on the panels or on the SBDG gauge board. The-al arms i

I on IC93 and IC94 also have different flashing functions than the control room panel alarms. The initial flash rate is much quicker than control i

room alarms, to the extent that the alarms at times appear to be in i

solid (the " acknowledged" state) when they are, in fact, flashing.

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addition, the IC93 and IC94 alarms do not " slow flash" when the alarming

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condition has cleared. The operations supervisor and the SBDG system engineer were considering possible solutions to these problems, including a flash rate modification and a change to the reset function.

The inspectors will continue to follow the licensee's progress in this area and the operator familiarity with the SBDG operation.

No violations or deviations were identified in this area.

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6.

Monthly Maintenance Observation (62703)

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Station maintenance activities of safety-related systems and components listed below were observed and/or reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, and industry codes or standards, and in conformance crith TS.

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 status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which might affect system performance.

Portions of the following maintenance activities were observed and/or reviewed:

- Drywell H,-0, analyzer repairs

- Condensate storage tank (CST) level switch repairs

- Reactor heat removal service water discharge check valve overhaul

- HPCI and RCIC door modifications

- Kaman radiation monitor repairs

- Zinc injection test skid installation Following completion of maintenance on the CST, the inspectors verified that this system had been returned to service properly.

HPCI and RCIC Door Modifications The licensee completed HPCI and RCIC room door modifications which strengthened the doors, frames, and haraware of the three doors to enable them to withstand the maximum postulated steam line break in either room.

Inspection report 50-331/92022(DRP) documented the licensee's Non-Conformance Report (NCR)92-133 determination that the doors had not been analyzed to withstand the maximum pressure of a steam line break. This determination had put into question the condition of various electrical and control equipment in the reactor building.

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On. November 23, 1992, the licensee determined that the reactor building

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equipment would be operable in the event of a HPCI and RCIC steam line break, but determined that a modification to enhance the door strength should be accomplished to resolve the NCR.

Engineers designed and installed a short term modification in December 1992, which barricaded the doors with removable steel bars.

The licensee minimized the time the barricades were removed by implementing a temporary operating order

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limiting access to the HPCI and RCIC rooms to all but operators on

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shiftly rounds, except by permission of the plant manager.

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On May 15, 1993, the licensee completed a permanent modification to the

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HPCI and RCIC doors which enabled them to withstand at least a 4 psid differential pressure; well above the approximate 3 psid spike which was postulated for a steam line break in the rooms.

Completion of the new door and hardware installation allowed the licensee to restore normal access to the HPCI and RCIC rooms.

No violations or deviations were identified in this area.

7.

Monthly Surveillance Observation (61726)

i The inspectors observed TS required surveillance testing and verified

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that testing was performed in accordance with adequate procedures, that

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test instrumentation was calibrated, that limiting conditions for-operation were met, that rcmovr.1 and restoration of the affected components were accomplished. that test results conformed with TS and procedure requirements and vare reviewed by personnel other than the

individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.

The inspectors also witnessed or reviewed portions of the following test activities:

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t STP-428014-M - Core Spray Pump and Residual Heat Removal Pump Discharge Monthly Functional Test STP-428019-Q - Condensate Storage Tank Low Water Level Quarterly Calibration Test STP-428020-Q - Suppression Chamber High Water Level Functional / Calibration Test STP-42B025-Q - HPCI Steam Line High DP Instrument Functional Test / Calibration

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STP-47A004

- Airlock local Leak Rate Test

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STP-48A001-M - Standby Diesel Generators Monthly Operability Test

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STP-48C001-Q - Emergency Service Water Quarterly Operability Test l

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Drvwell Airlock Testino (EA No. 93-1061

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On April 27, 1993, the licensee informed the resident inspectors

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of a discrepancy in the performance of surveillance testing for the drywell personnel airlock. The concern was identified as a result of a review of lessons learned and good practices

identified from the previous refueling outage. This review consisted of evaluating and resolving previously identified action items prior to the upcoming refueling outage, scheduled for July 29, 1993. The concern involved whether or not TS required a leak test of the drywell personnel airlock following the _400 psig drywell inspection if a leak test had been performed within 3 days

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prior to the drywell entry.

The inspectors noted that 10 CFR Part 50, Appendix J, Ill.0.2 (b)(iii) stated:

" Air locks opened during periods when -

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containment integrity is required by the plant's Technical

Specifications shall be tested within 3 days after being opened.

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For air lock doors opened more frequently than once every 3 days, the air lock shall be tested at least once every 3 days during the

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period of frequent openings." Further, Duane Arnold's TS section 4.7.A.2.d.2)c) states "Within three (3) days after securing the airlock when containment integrity is required, _the airlock gaskets shall be leak tested at a pressure of Pa."

i The licensee's past practice had been to ensure that a valid test of the drywell airlock had been performed within 3 days of the last drywell entry (versus 3 days after the opening).

As such, the licensee verified that the drywell airlock had been tested within the last 3 days.

In addition, if the airlock had not been tested within 3 days of the last entry, the licensee performed a leak test of the drywell personnel airlock.

In reviewing the leak test licensing history, the inspectors noted that the licensee had applied for a TS amendment (RTS-112), dated

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August 29, 1978, and an exemption request to 10 CFR Part 50,

Appendix J, dated November 5,1981, for drywell airlock testing.

Both of these documents requested the NRC to grant an exemption from the testing requirements of Appendix J and to incorporate the following testing requirement in lieu of the Appendix J requirements:

"The personnel airlock shall be pressurized to 54 psig and leak tested at an interval no longer than one operating cycle. Whenever the airlock is opened during the operating cycle, and containment integrity is required, and it has been greater than three (3) days since the last leakage test, the airlock gasket shall be leak tested at 54 psig following airlock closure."

The proposed wording would have allowed the licensee the latitude to test the airlock within 3 days of an airlock opening (i.e. +/-

3 days). Although the final approved wording in the TS amendment differed from the original proposal, the inspectors were unable to

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determine through documented correspondence, the basis for the

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change. Due to the subtlety of the word change and the wording of the response to the submittals, the licensee did not fully appreciate the full difference in the testing requirements. As a result, the licensee apparently had not changed the testing program from the original proposal.

In reviewing this refueling outage action item, the licensee i

determined that they had not been complying with 10 CFR Part 50, i

Appendix J, and TS 4.7.A.2.d.2)c) in performing a leak test of the drywell personnel airlock within 3 days after opening the airlock j

to perform the 400 psig drywell inspection.

The licensee apparently had not been conducting a leak test following the 400 i

psig drywell inspection, since receipt of TS Amendment No. 106,.

dated August 24, 1984, which incorporated the current wording for the drywell airlock testing.

Most recently, the licensee conducted a plant startup on January 29, 1993, and a drywell entry was conducted to perform a drywell inspection. Again, as a result of the licensee's interpretation of ensuring that a leak test had been performed within the last 3 days, the licensee did not perform a leak test following the January 29, 1993, drywell airlock opening. The failure to perform a leak test of the drywell airlock within j

3 days after the opening is considered a violation of both 10 CFR Part 50, Appendix J, III.D.2.(b)(iii) and TS 4.7.A.2.d.2)c)

(EA No.93-106).

This violation was not be cited because the i

licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the " General i

Statement of Policy and Procedure for NRC Enforcement Actions,"

(Enforcement Policy, 10 CFR Part 2, Appendix C).

As a result of determining that the licensee was not in compliance with 10 CFR Part 50, Appendix J, nor TS airlock testing requirements, conference calls were held between the licensee and the NRC on April 27 and 28, 1993.

In the concluding call, the licensee requested Enforcement Discretion and a Temporary i

Exemption Request from 10 CFR Part 50, Appendix J, leakage testing requirements for the primary containment airlock. The licensee was verbally granted a Notice of Enforcement Discretion (N0ED)

from NRR on April 28, 1993. The licensee subsequently docketed their request for an N0ED in a letter from John Franz to Thomas Murley, dated April 29, 1993. On April 30, 1993, the licensee was formally granted an N0ED from Appendix J airlock testing until a temporary exemption request could be acted upon by the NRC. The

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requested exemption would provide temporary relief from the

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Appendix J requirements until the next shutdown, but no later than the scheduled refueling outage on July 30, 1993.

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b.

Level Switch Calibration Failures During the performance of STP 42-B019 " Condensate Storage Tank Low Water Level Quarterly Calibratior", licensee technicians found that level switch LS5219 " CST IT-5B level switch" was inoperable.

The purpose of level switch LS5219 was to transfer the HPCI and RCIC suction paths from the CST to the torus on iow CST level.

Level switch LS5219 was one of the two switches required by TS to perform this function, and both were required to be operable. The action statement for one inoperable switch was to place the trip system in the tripped condition or to place the reactor into the cold shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Placing either CST low level switch in the tripped position would have caused RCIC and HPCI suction paths to transfer to the torus. This would have taken away the immediate availability of the clean CST water supply.

If the water supply was switched to the torus, the licensee could no longer have ensured that the discharge piping would remain full after 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> since there was no keep-fill system. This would then place the licensee in a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to hot shutdown LC0 due to declaring HPCI and RCIC inoperable.

The licensee chose to enter the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LC0 rather than to place the LS5219 output in the tripped condition.

Instrument and control technicians investigated the limit switch problem and found that the junction box seals for LS5219 were degraded, and the junction boxes were full of water. The junction boxes-are located outside and are exposed to the weather. At the time of this problem the weather conditions were rainy. After draining and drying out the boxes, the technicians reperformed the STP for LS5219, which functioned properly. The licensee declared the level switch operable after about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of the LCO's 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> had expired.

The licensee had experienced problems with these level switches several times in the past; mostly due to tangling of the sensor cables. These problems have resulted in similar equipment operability concerns.

On May 14, 1993, during the performance of STP 428020-Q,

" Suppression Chamber High Water Level Functional / Calibration Test," torus level switch LS2319 failed its calibration.

The LC0 for this condition was identical to that required for LS5219 since it was intended to transfer HPCI suction to the torus.

The licensee again was forced to enter a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to cold shutdown LCO.

In this instance, calibration of LS2319 was completed in less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and the licensee exited the LC0.

The licensee planned to address this problem in several ways. The junction boxes will be checked periodically for seal degradation,

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holes will be drilled in conduit line low points to allow for

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draining if water does accumulate, the junction box splices will be improved to be water resistant, and spacers will be added to the CST level switch sensor cables to prevent tangling. Technical specification amendment number 193 had been approved, and will' be implemented, allowing additional time for testing prior to entering the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO. The licensee was also evaluating various methods to verify that the HPCI discharge piping was full when taking suction from the torus. The inspectors will continue to follow the licensee's progress in resolving these issues.

No deviations were identified in this area. One non-cited violation was

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identified.

8.

Lead Test Assembly (LTA) Inspections (60705)

During the inspection period the inspectors observed the licensee's actions associated with shipment to General Electric (GE) of 38 fuel pin segments (4 segments per fuel pin) from a specially designed LTA.

During the previous inspection period (see IR 50-331/93005(DRP)), the licensee had completed inspection, collection, and movement of the fuel pins to a shipping cask liner.

The inspectors observed all major activities associated with the loading of the shipping cask including lowering the shipping cask into the cask pool, transfer of the shipping cask liner with fuel pins into the shipping cask, withdrawal of the cask to the washdown area, and loading of the shipping cask into the overpack container.

Prior to shipment, the inspectors observed the licensee perform a final contamination and radiation survey of the cask. The inspectors independently verified

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selected survey points. The survey was found to be well within the limits of Title 49 of the Code of Federal Regulations.

The inspectors noted that the licensee assigned the necessary resources to the project to ensure that the project proceeded without incident.

The overall project was well planned and executed. The inspectors were particularly impressed with the' ALARA group and management involvement throughout the project.

No violations or deviations were identified in this area.

9.

Reaional Reouests (92701)

The inspectors responded to regional requests for information in two areas, significant event reporting and vital area barriers. The information was researched, compared to the appropriate references, and sent to Region III for further evaluation.

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Manaaement Meetinas (30702)

On April 20, 1993, representatives of Iowa Electric Light and Power and the NRC held a management meeting at the Region III office. The purpose

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of the meeting was to discuss recent plant operations and maintenance

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issues, outage plans, licensing activities, motor cperated valve

program, and other items of mutual interest.

11.

BeDort Review (90713)

During the inspection period, the inspectors reviewed the licensee's monthly operating reports for March and April 1993. The inspectors confirmed that the information provided met the requirements of TS 6.11.1.C and Regulatory Guide 1.16.

No violations or deviations were identified in this area.

12.

Violations For Which A " Notice of Violation" Will Not Be Issued The NRC uses the Notice of Violation to formally document the failure to meet a legally binding requirement. However, because'the NRC wants to encourage and support licensee initiatives for self-identification and correction of problems, the NRC will not issue a Notice of Violation if the criteria set forth in Section VII.B of the " General Statement of

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Policy and Procedure for NRC Enforcement Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C) are met. Violations of regulatory requirements identified during the inspection for which a Notice of

Violation will not be issued are discussed in paragraph 7.

13.

Exit Interview (30703)

The inspectors met with licensee representatives (denoted in Section 1)

on May 21, 1993, and informally throughout the inspection period and summarized the scope and findings of the inspection activities. The inspectors also discussed the likely information content of the inspection report with regard to documents or processes reviewed by the inspectors. The licensee did not identify any such documents or processes as proprietary. The licensee acknowledged the findings of

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the inspection.

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