IR 05000331/1993009

Insp Rept 50-331/93-09 on 930522-0707.Major Areas Inspected:Followup of Events,Operational Safety,Maint, Surveillance,Temporary Instruction & Rept Review

ML20046B083
Person / Time
Site:	Duane Arnold
Issue date:	07/23/1993
From:	Hopkins J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20046B067	List: IR 05000331/1993009 ML20046B066
References
50-331-93-09, 50-331-93-9, NUDOCS 9308030075
Download: ML20046B083 (28)

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U. S. NUCLEAR REGULATORY COMMISSION

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REGION III

Report No. 50-331/93009(DRP)

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

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Licensee:

Iowa Electric Light and Power

Company

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

Duane Arnold Energy Center Inspection At:

Palo, Iowa Inspection Conducted: May 22 through July 7, 1993 Inspectors:

M. Parker C. Miller

Approved:

[.N /

b, 7OD93

iR. D. Lanksbury, Chief Date Reactor Projects Section 3B

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. Inspection Summary

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Inspection on May 22 throuch July 7. 1993 (Report No. 50-331/93009(DRP))

Areas Inspected:

Routine, unannounced inspection by the resident inspectors of followup, followup of events, operational safety, maintenance, surveillance, temporary instruction, and report review.

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Results:

An executive summary follows:

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9308030075 930723 V

PDR ADDCK 05000331 W G

PDR 3d

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EXECUTIVE SUMMARY Operations The plant was operating at 89 percent power at the beginning of the period with power coastdown in progress prior to the refueling ottage scheduled to begin July 29, 1993. The plant operated at or near maximum achievable power during the period with minor down power operations due to surveillance

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testing. The reactor was operating at 78 percent power at the end of the period.

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Several issues have given cause for significant regulatory concern.

For example, the inoperability of the

"A" standby diesel generator (SBDG) in

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excess of the technical specification (TS) limiting condition for operation (LCO) allowances (section 3), the acceptance of " humorous" or gag annunciators on the control room annunciator panels, the acceptance of excessive noise and

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disturbances during the shift briefing process, and the failure of three

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operating crews to recognize that an emergency core cooling system valve (MO-2137) had been deenergized (section 4).

Operators were well informed of the potential response of reactor water level instrumentation to degassing from depressurizations, and thoroughly knew the required actions to take in the event that instrumentation becomes unreliable (section 7).

Maintenance / Surveillance

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Two unresolved items were issued to follow problems with maintenance procedure calculation reviews and unqualified capacitors in the high pressure coolant

injection (HPCI) system (section 5).

Equipment problems continued with "B" control building chiller, reactor recirculation pump speed control, and lightning strike effects on the well water pump controllers.

Efforts to

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troubleshoot and correct a 125 D.C. ground were expedient and effective.

Management support was evident throughout the process.

i Encineerina and Technical Support

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Engineering support and leadership was apparent in the re-installation of new river water breakers, in troubleshooting and corrective actions for a 125 volt D.C. ground, and in troubleshooting the "D" inboard main steam isolation valve

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(MSIV) position indication problem.

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Safety Assessment /0uality Verification

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Tolerance of less than optimal control room turnover conditions and " humorous" annunciators indicated a weakness in licensee self-assessment capability and i

may have fostered a less than rigorous attitude towards conduct of operation.

Management was very supportive of implementing sound corrective actions once the problems with annunciators, crew briefings, missed control room indication, and inoperable SBDG were identified.

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Management support in reducing radiation exposure was evident as a special j

cleanup project in a " dead leg" pipe from the cask pool reduced on-contact dose from 350 roentgen per hour (R/hr) to 15 R/hr and general dose rate on the second floor reactor building from 20 mil 11 roentgen per hour (mr/hr) to

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2 mr/hr.

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DETAILS

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Persons Contacted R. Anderson, Operations Supervisor

• R. Baldyga, Supervisor, Maintenance Engineering

• P. Bessette, Supervisor, Regulatory Communications

• J. Bjorseth, Assistant Operations Supervisor

• D. Blair, Quality Assurance Assessment Supervisor

• C. Bleau, Supervisor, Systems Engineering

• D. Engelhardt, Security Superintendent J. Franz, Vice President Nuclear J. Kinsey, Supervisor, Licensing D. Lausar, Supervisor, Project Engineering M. McDermott, Maintenance Superintendent K. Peveler, Manager, Corporate Quality Assurance K. Putnam, Supervisor, Technical Support

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• 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 End Maintenance T. Wilkerson, Radiation Protection Manager

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

• Denotes presence at the exit interview on July 7,1993.

2.

Followup (92701)

(Closed) Open Item 50-331/91019-03:

Procedure Changes. This item was opened to track the licensee's implementation of procedure 1406.1,

" Procedure Use and Adherence," and documentation of surveillance procedures. -The concerns were that for inoperable equipment, post i

maintenance testing requirements were not adequately spelled out, steps in the procedure which were not fully completed were not properly identified, and that the practice by operations shift supervisors (OSS)

i of voiding procedures steps when equipment was out of service may have eliminated the proper review process. This was especially a problem when redundant equipment was involved.

The licensee's post maintenance testing program had been expanded and proceduralized in maintenance department procedure MD-024, Revision 8,

" Post Maintenance Testing Program." This procedure used a matrix format

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as a guide for appropriate testing requirements based on equipment type.

The procedure also required maintenance personnel to evaluate the post maintenance operability testing to ensure system operability, component function, and technical specification (TS) compliance.

The licensee issued guidance to operators in letter NG-93-2543 on proper actions to take when a procedure step which involved more than one piece of equipment cannot be followed due to inoperable equipment.

Specifically, the guidance directed the plant staff to identify surveillance test procedures (STPs) which involved more than one piece of equipment per procedure step, in order that these STPs might be changed.

It also required that a procedure change be initiated if a piece of equipment in the STP was inoperable. These actions resolved the concerns associated with this open item. This open item is closed.

(Closed) Violation 331/93003-01: Workers did not initiate a Fuel Storage Pool / Cask Pool Storage Permit or cbtain approval prior to storing a stellite bearing from a control blade in the cask pool.

This item was closed in inspection report 50-331/93008(DRSS) but was inadvertently listed as item number 331/93001-01. Violation number 331/93003-01 is the correct number, and the violation is closed.

No violations or deviations were identified in this area.

3.

Followup of Events (93702)

During the inspection period, the licensee experienct several events,

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

May 25, 1993 - PCIS Group III Isolation due to jumper losing contact June 11, 1993

"A" SBDG tripped during a surveillance test start July 1, 1993 - Division 1 125 volt D.C. ground SBDG Start Failure On June 11, 1993, the "A" standby diesel generator (SBDG) failed to start during STP-48A001-SA, " Standby Diesel Generators Semi-Annual j

Operability Test." This STP tested the ability of the SBDG to start and

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reach rated voltage and frequency within 10 seconds.

Following the start signal, the SBDG cranked for about 3 seconds and then tripped, with an overspeed condition annunciated.

Based on operator observation, normal start parameters, and not getting the engine running annunciator,

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the licensee estimated that the SBDG speed reached only about 250 rpm.

The overspeed trip setpoint was 1044 revolutions per minute (rpm).

The licensee inspected the "A" SBDG following the trip. The fuel rack was tripped, and the local overspeed trip annunciator was lit. The fuel rack was designed to trip under two conditions:

a mechanical overspeed trip device and a manual emergency stop push button mounted on the SBDG.

The licensee determined that no one had actuated the push button and that the actuation of the overspeed trip mechanism was not plausible.

After postulating that the reset mechanism may not have been fully reset, the licensee's engineers and mechanics, and a vendor (Colt)

representative, inspected the overspeed trip mechanism visually, including the use of a boroscope. The mechanism appeared to be in good condition, with no defects or excessive tolerances noted.

Numerous attempts to recreate a partially latched reset mechanism using the overspeed reset lever were unsuccessful. The licensee obtained information from the H. B. Robinson plant about a similar event they had experienced but had been able to repeat the partial latching of the reset mechanism. The vendor indicated that the proper way to reset the overspeed trip was to slowly move the overspeed trip lever to the left twice; once to latch and remove the spring tension, and the second time to ensure full engagement, and to verify the lever moves freely. The vendor recommended technique to reset the overspeed trip lever was not discussed in the operating instruction for the SBDG, the SBDG surveillances, or in the Colt technical manual.

The "A" SBDG had previously been run for the SBDG monthly surveillance 48A001-M on May 12,-1993. As part of the surveillance, the overspeed-mechanism was tripped and the SBDG was turned over with air (air barring), to drain oil from the cylinders.

Following this action, the auxiliary operator (AO) reset the overspeed mechanism. This was performed while the SBDG exhaust manifold, located close to the overspeed reset lever, was still hot, causing the A0 to move expeditiously.

Following the overspeed reset, the overspeed trip annunciator was reset, and the A0 had no indication of other than normal conditions.

After the failed start attempt on June 11, 1993, operators immediately declared the "A" SBDG inoperable, and left the SBDG in the tripped -

condition for inspection purposes. The shift supervisors notified the resident inspectors, plant management, and the system engineer shortly

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after the problem occurred. Operators successfully fast started and ran the "B" SBDG on June 11, 1993, thereby complying with TSs and ensuring

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that the "B" SBDG overspeed mechanism had been fully reset.

The licensee began troubleshooting the "A" SBDG immediately, and had completed inspections by June 12, 1993.

Following their inspection, the system engineer, vendor representative, and lead SBDG mechanic all concluded that the overspeed trip mechanism was in good condition, and that the

"A" SBDG was functioning properly.

Operators declared "A" SBDG operable on June 12, 1993.

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Following the event, the licensee gave immediate direction to operators on how to reset the SBDG overspeed trip mechanism using the vendor.'s recommendation. The SBDG STPs and Operating Instruction (OI) 324,

" Standby Diesel Generator System," were also changed to reflect the new reset technique. The licensee planned to include overspeed trip reset training into initial and continuing training for auxiliary operators.

The licensee established a Root Cause Analysis Team for the event. The team consisted of the SBDG system engineer, a mechanical maintenance diesel specialist, a maintenance department senior instructor, an auxiliary operator, the testing and surveillance supervisor, a quality assurance engineer, a Colt representative, and a technical support specialist. Using a fault tree analysis method, the team considered possible failure mechanisms for the various subcomponents involved.

Based on component drawings, operating history, and operator observations, the team was able to rule out an actual engine overspeed condition, a mechanical failure of the overspeed mechanism, and a push button assembly trip. This left the partially latched overspeed trip reset mechanism as the most likely cause. The team recommended corrective actions consisting of: overspeed reset training and procedure changes, periodic operator checks of the overspeed reset lever, delaying air barring until the SBDG has had more time to cool, use of gloves or insulating material on the reset lever, overspeed mechanism and microswitch inspections on the "A" SBDG during refueling outage 12, consideration of overspeed trip microswitch modifications,

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addition of a platform for operators to make reset operation easier, and development of preventive maintenance tasks for various SBDG overspeed trip mechanism components.

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Most of these recommendations had either been implemented or were

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planned at the end of the inspection period. Corrective maintenance action requests for visual overspeed mechanism and microswitch

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inspections during refueling outage 12 were submitted. The licensee planned to provide a temporary or permanent operator platform following refueling outage 12.

Preventive maintenance tasks were planned to be developed following the inspection of the SBDG during refueling outage 12. The licensee.was still considering the need for a microswitch

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modification, and the need for a full disassembly and inspection of the overspeed mechanism.

On July 9, 1993, the licensee submitted licensee event report (LER) 93-04.

In addition, the licensee planned to send an operating experience

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entry to the Network system to notify other utilities of the possibility for failed SBDG starts due to this mechanism.

The licensee's investigation identified the partial latching of the overspeed reset lever as the most likely cause for the "A" SBDG start failure. This partial latching would have been accomplished on

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May 12, 1993, following reset from the monthly SBDG STP. The "A" SBDG was restored to operability on June 12, 1993, 31 days later.

Duane Arnold Energy Center TS 3.5.G.1 stated that during any period when one diesel generator was inoperable, continued reactor operation was

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generator was sooner made operable, provided that the remaining diesel

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generator and all low pressure core and containment cooling subsystems

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requirement could not be met, an orderly reactor shutdown to hot

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supported by the operable diese1' generator were operable.. If Ris shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

is required. Failure to restore the "A" SBDG to an operable status t

within 7 days and failure to shut down the reactor to hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was an apparent violation of TS 3.5.G.I.

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One apparent violation was identified and no deviations were identified.

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4.

Operational Safety Verification (71707) (717101

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 -

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emergency systems, reviewed tagout records, and verified proper' return

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to service of affected components. Tours of the reactor building and

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turbine building were conducted to observe plant equipment conditions,

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including potential fire hazards, fluid leaks,. and excessive: vibrations _

and to verify that maintenance requests had been initiated for equipment

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in need of maintenance.

It was observed that the Plant Superintendent,

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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

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observation and direct interview, verified that the physical. security i

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

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The inspectors observed plant housekeeping and cleanliness conditions i

and verified implementation of radiation protection controls. During

the inspection, the irispectors walked down the accessible portions of the standby diesel generators to verify operability by comparing system l

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lineup with plant drawings, as-built configuration or present valve l

lineup lists; observing equipment conditions that could_ degrade i

performance; and verifying that instrumentation was properly valved, functioning, and calibrated.

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These reviews and observations were conducted to verify _that facility operations were in conformance with the requirements established under

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TS, Title 10 of the Code of Federal Reculations, and administrative

procedures.

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Control Room Operations j

The inspectors observed control room activities during normal-I operations and during shift turnovers. While control room i

demeanor during normal operation was usually acceptable, the

inspectors noted some weaknesses that tended to distract operator.

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attention. -The shift turnover and crew briefings were held in the i

control room. During some of the crew briefings observed, there

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i were several extra personnel in the control room. The shift briefings had no definite order and no specific ending point.

Several non-essential side conversations were taking place in addition to relevant shift turnover information. Phone calls during the briefings tended to distract the operators from participating, or delayed the shift briefing while the matter was being resolved.

The inspectors and Region III management discussed these problems with licensee management. They also discussed the improper

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labelling of some control room equipment that had been done humorously. This included two dummy control room annunciator windows with unnecessary and inappropriate engravings, as well as label tape markings which were unnecessary. The annunciator response procedures (ARP)s listed the annunciator windows as spare alarms, but did acknowledge their engraved markings.

These annunciators were also mimicked in the simulator.

Although the annunciators were not wired to annunciate and were marked as spare alarms, they still added unnecessary visual clutter to an important operator aid.

Following the discussions, the licensee immediately removed the

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inappropriate labelling and annunciator windows from the control room and simulator, and the ARPs were changed to reflect the windows as spares with no engraving. The licensee also began an effort to improve control room turnovers and professionalism.

Operations management implemented interim guidelines to reduce control room distractions and improve shift turnovers.

The guidelines which were implemented on June 18, 1993, cautioned operators against non-professional behavior and distracting casual conversation.

In addition, new guidance for the shift turnover included suspension of testing and major activities, eliminating non-operations personnel from the control room, the use of the off-going "B" operations shift supervisor (OSS) to handle phone

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calls during turnover and the on-coming crew brief, direction for the off-going "A" OSS to attend the crew brief led by the on-coming "A" OSS, requirement for a definite crew brief start and end point, and no casual conversation or non-relevant discussions during turnover. The licensee also planned to send operations personnel to other plants to observe their shift turnover process.

Crew briefings observed by the inspector following this guidance

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were less congested, more orderly, and more focused on relevant issues.

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Core Spray Valve Indication On June 30, 1993, during the performance of STP BS-5, " Control Room Plant Shift Check List," a control room operator discovered an abnormal indication for the "B" core spray inboard isolation valve (M0-2137). The green " closed" indication light was not lit,

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and the last known position of the valve was closed. An operator

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dispatched to the motor control center (MCC) for the valve found the breaker in the off position. When the operator returned the breaker to the on position, the green closed indication for valve MO-2137 illuminated. Operators subsequently stroke-timed the valve in the open and closed directions and verified that it was operable.

Further investigation determined that the valve had been deenergized since 5:18 p.m. (CDT) on June 29, 1993. That was.the time the containment isolation monitoring system (CIMS) printer indicated "no power" to valve MO-2137. The inspector and licensee then questioned how the breaker was mispositioned., and why three operating crews had not noticed the indication during their shift, during the previous BS-5, or during shift turnover panel walkdowns.

The licensee had been conducting tactical security drills during the time when the valve was deenergized. A portion of the drill took place near MCC-1844 which housed the breaker for valve MO-2137. The guard involved had been using MCC-1844 for cover, and at one point was counselled by the drill controller to move away.

Neither the guard nor the drill controller were aware of any inadvertent or intentional breaker operation. The breaker handles on this MCC were easy to move and quiet when operated. The guard

had been wearing several articles which could have bumped the breaker to the off position.

Security computer searches showed that no unauthorized access problems existed.

Based on the above, the licensee determined that the incident was most likely caused by the drill players. To prevent further inadvertent actuation of equipment, the licensee suspended all tactical security drills until operations could review their potential impact on plant equipment, briefed security personnel on the need to keep a safe distance from sensitive plant equipment, and was considering installation of barriers in front of sensitive equipment in high traffic areas.

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The inspector interviewed the operating crews who were on shift

when valve M0-2137 had been deenergized. All operators who were questioned indicated that they had performed an informal panel

walkdown prior to assuming the shift, looking for major parameter i

changes, alarms, and tags. Operators also indicated that informal panel walkdowns were performed throughout the course of the shifts-i during the time that valve M0-2137 was deenergized. The extent of detail of the walkdowns appeared to vary by individual. Nuclear Generation Procedure 1410.1, " Shift Organization, Operation and Turnover," stated that a thorough panel check need not be completed prior.to shift turnover but shall be completed as soon as practicable. The Operations Supervisor indicated that BS-5 was the expected mechanism to meet that requirement.

The inspector noted that BS-5 was a very good mechanism to help operators determine the status of major plant systems. However,

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t this event suggested that operators were relying too much on BS-5 and not enough on their own panel checks and walkdowns to keep themselves informed of plant status. Operators had nearly two full shifts of routine panel observations, two sets of off-going and on-coming shift turnover panel walkdowns-, and a shiftly BS-5 STP during which the deenergized valve could have been detected.

The inspector noted this lack of rigor in performing operator duties as a cause for concern.

The inspector interviewed the 11 p.m. to 7 a.m. shift operator who had performed the BS-5 STP while valve M0-2137 was deenergized.

The operator had checked the block on the STP that indicated the valve was in the closed position. The operator later indicated that he believed he had seen the green " closed" light energized when he had performed the STP, even though the light had been off.

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No other unusual personal or plant conditions appeared to have been involved with the error. The operators involved agreed that the error should not have occurred. The routine nature of this STP with over 200 checks, and common interruptions were discussed by operators as possible contributors to the error.

Technical specification 6.8.1 specified that written procedures covering areas of normal startup, operation, and shutdown of systems and procedures be implemented.

Procedure STP BS-5,

" Control Room Panel Shift Check List," required an operating engineer to check and record the status of plant equipment and to

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indicate those components not in their desired position.

Failure to properly indicate the status of valve M0-2137 was considered an apparent violation of TS 6.8.1.

Following recovery from the deenergized breaker, the plant manager convened a meeting of the operators involved, along with other plant management, to determine the causes of the problem and possible corrective actions. Corrective actions for the security event were discussed previously. Disciplinary action was administered to the operator who incorrectly recorded tN status of valve M0-2137 on BS-5.

As part of the licensee's corrective action, a third qualified reactor operator (RO) was added to most of the shifts. That individual was expected to reduce the distractions on operators performing shift surveillances. A third RO was not immediately added to all shifts due to personnel schedule problems. The licensee planned to have the third R0-in place effective July 18, 1993.

(A third R0 had routinely been assigned to the day shift, and the licensee had previously planned to implemented this practice for all shifts.) Operations management was also considering the increased use of the CIMS printer during shift checks as well as other options to improve routine conduct of operations performance.

One apparent violation was identified and no deviations were identified.

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5.

Monthly Maintenance Observation (62703)

Station maintenance activities of safety-related systems and components

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listed below were observed and/or reviewed to ascertain that they were conducted in accordance with approved procedures, re latory guides, and industry codes or standards, and in conformance wit" (S.

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

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to assure that priority was assigned to safety-related equipment maintenance which might affect system performance.

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Portions of the following maintenance activities were observed and/or

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reviewed:

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"A" SBDG overspeed trip mechanism inspection and troubleshooting

- Torus spray valve (M0-2006) operator testing

- Offgas radiation stack monitor

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- RHR heat exchanger throttle valve (M0-1939) inspection and motor change out

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"B" control building chiller repairs

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- River water pump breaker installation

- 125 volt DC ground troubleshooting

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Following completion of maintenance on the "A" SBDG, the inspectors verified that it had been returned to service properly.

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The licensee continued to experience reactor recirculation pump speed

control problems, "B" control building chiller 3-way valve malfunctions, and lightning strike complications with well water pump controllers.

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These were dealt with appropriately in the interim, but still required

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long term corrective action. Reactor building door seals became a concern as painters painted doors without protecting the door seals.

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This caused the seals to pull away and bind when the paint dried.

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~ Licensee troubleshooting and repair of a ground on the division one 125 volt D.C. system was expeditious and effective, with appropriate l

management oversight.

The troubleshooting identified a short between A.C. power leads to

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drywell cooling motor operated valves, and position indication for "D" inboard MSIV. This resulted in electricians deenergizing

"D" inboard MSIV, and operators closing the valve. The licensee developed

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alternative MSIV position indication for operators and reopened the l

MSIV. This solution properly weighed the safety concerns of potential i

hazard to the 125 Volt D.C. power system, and the needs of the operators for MSIV position indication.

The inspector noted problems with maintenance procedures being

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improperly modified with improperly reviewed calculations..This had

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resulted in an improper motor operated valve testing procedure being used on a torus spray valve (M0-2006) and several other valves.

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integrity was not affected, and the procedure was corrected. The.

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inspector will review further details of this problem and follow it as i

unresolved item 331/93009-01(DRP).

The licensee discovered that several capacitors used in the HPCI system

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were not properly qualified for their application. The issue involved

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parts receipt and a discrepancy in the licensee's understanding of parts documentation. -No equipment operability problems resulted. The parts were eventually qualified for their configuration. The inspector will follow the details of.this concern as unresolved item 331/93009-02(DRP).

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No violations or deviations were identified in this area. Two

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unresolved items were identified.

6.

Monthly Surveillance Observation (61726)

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The inspectors observed TS required surveillance testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for

operation were met, that removal and restoration of the affected _

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components were accomplished, that test results conformed with TS and procedure requirements and were reviewed by personnel other than the j

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 portions of the following' test: activities:

STP-41A008

- Turbine Control Valve EOC RPT Logic and RPS Instrument Functional Test STP-41A010

. Turbine Stop Valve Closure RPS and RPT Functional Test STP-42B017-Q - Recirculation Riser D/P A > B Quarterly Instrument Calibration

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STP-45A001-Q - Core Spray System Quarterly Operability Test STP-45D001-Q - HPCI System Quarterly Operability Test STP-48A001-SA - Standby Diesel Generators Semi-Annual Operability Test STP-BS-5

- Control Room Panel Shift Check List

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No violations or deviations were identified in this area.

7.

Temporary Instruction (TI) 2515/119 Water Level Instrumentation Errors The inspectors performed inspections and interviews in response to TI 2525/119, " Water Level Instrumentation Errors During And After

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Depressurization Transients (GL 92-04)." The objective of the inspection was to verify that DAEC had implemented guidance and training to ensure required operator response following rapid depressurization i

transients, and to ensure that the guidance and training was consistent with DAEC Emergency Operating Procedures (EOPs).

The inspectors found that the licensee had issued guidance to all licensed operators consistent with the Boiling Water Reactor Owner's Group (BWROG) recommendations which were issued in letters dated August 19 and October 16, 1992. The operators were also trained using a

BWROG training video, " General Electric Safety Information Letter 470,"

and E0P specifics using the DAEC E0P Training Techniques guide. The inspectors verified through training records and discussions with the licensee that all licensed operators were trained on the BWROG guidance in the classroom and the simulator. One minor discrepancy with training records of a new license student and one training instructor was eventually resolved to show that these individuals had also received the proper training.

The licensee's simulator scenarios included events where

depressurization occurred either as a result of a leak or as required by the E0Ps. These scenarios force the operators to evaluate the accuracy of their level instrumentation. The inspectors observed operating crews

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response to simulated depressurizations and found them to be very cognizant of potential level inaccuracies and of the recommended methods to verify reactor water level. The simulator used a programmed malfunction which simulated level instrumentation response when

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reference legs would be in the saturation range. This was sufficient to drive the operators to check instrumentation, then go to reactor pressure vessel flooding if it did not respond.

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The simulator did not model the expected effects on water level instrumentation due to off-gassing caused by depressurization, although simulator operators did fail level instruments high to simulate degassing. The Electric Power Research Institute (EPRI) study of non-condensible gases in level instrumentation was expected to result in a

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generic computer model for instrumentation response. The licensee initially expected to receive this model by mid-June 1993 but had not yet received it. This model will then be supplied with plant specific numbers to predict the response of DAEC level instrumentation to non-condensibles. The DAEC training department expected to be able to update their simulator to reflect this expected response once the information is available.

The licensee had been prompt in disseminating the information available on non-condensible gases to the operators in the continuing training program, and had included guidance on dealing with the issue in the E0P Training Techniques guide.

Four previous training cycles had included updates on this subject. The licensee planned to evaluate the need to make permanent additions to their continuing training program once plant response was understood, and reactor vessel water level instrumentation modifications to minimize the effects of the non-condensible gases were in place.

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The licensee evaluated the BWROG guidance for inconsistencies with their E0Ps and found no discrepancies with the actions required by the E0Ps.

The BWROG guidance served as a supplement to the E0Ps in giving

direction on how to verify that level is within a specific range when non-condensibles are present.

i The licensee had performed walkdowns of level instrumentation racks to

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look for leakage, and taken corrective action, including tightening fittings, to stop the minor leakage which they found.

Cyclic preventive maintenance requests were also in place to check for this leakage on a periodic basis.

The licensee had not seen level anomalies during depressurization even after reviewing instrument traces from past shutdowns.

Engineers planned to monitor both channels of reactor vessel narrow range water level with a high speed recorder during the shutdown for the 1993

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refueling outage. This action was expected to help to better characterize level instrumentation response during pressure transients.

In addition, a reactor vessel water level instrument modification was planned for refueling outage 12 to meet the requirements of NRC Bulletin 93-03, " Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs." The inspectors will continue to follow the

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licensee's implementation of modifications, training, and procedures which address the issues of this bulletin.

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No violations or deviations were identified in this area.

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Report Review (90713)

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During the inspection period, the inspectors reviewed the licensee's monthly operating report for May 1993. The inspectors confirmed that t

the information provided met the requirements of TS 6.11.1.C and t

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Regulatory Guide 1.16.

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No violations or deviations were identified in this area.

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Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations.

Two unresolved items disclosed during the inspection were discussed in Section 5.

10.

Exit Interview f30703)

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

on July 7,1993, 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 the inspection.

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M762 Federal Register / Vol. 67. No. u3 / Friday. July to.1992 / Notices ENCLOSURE 2

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n pnor reviews for the YarJce Nuclear guides cumntly being developed or Aocmrzsts: Scad comments to: ne f'ower Station The plar.1 was I; censed improvements in all published guides Secetary of the Nmission. U.S before the requement for issuance of a are encourcred at any time. Wntten Nuclee. Regulatory Commission.

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fmal Environmental Sta tement.

comments may be submitted to the Washerton. DC 20555. ATTN:

Agencies and Persons Co. sulter!

Regulatory Pubhcations Branch.

Docken.ng and Service Branch.

]

D vision of Freedom of Information and Hand deliver comments to: One White

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He NRC staff reviewed the hcensee's Pubhcations Services. Office of Thnt North.11555 Rochille Ake.

nquest and da not consult other Administration. U.S. Nuclear Regulatory Rockde. MD between 7.45 a.m. to 4:15 agencies or persons.

Commie = ion. Wa shington. DC 23555.

p.m Federd workdays.

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f~mdmg of No Significant impact Regulatory guides are available fer Copies of comments may be examined

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inspection at the Commission's Public at the NRC Pubhc Document Room. 2120 The Commission has determined not Document Rwm. n20 L Street A L Street. NW. (lower level).

to prepare an environmental impact ashington. DC. Copies of issued Washic.gton DC j

staternent for the proposed exemption.

guides may be purt:hased from the Based upon the foregoing environmental Government Pnnting Office at the PO* "" ""O**'AN*: coen Act assessment, we conclude that the current CPO price. taformation on James Ueberman. Director. Office of proposed action will not have a

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current GPO prices rusy be obtained by Enforcement. U.S. Nuclear Regula tory significant effect on the quality of the contacting the Superintendent of Commission. Washington. DC 20555

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Docummts.ES GovemnmWnting

@hM j

rf r de a with respect to this action, see the application for exemption Opu. ht Mu Box 282.

may pacentAWc

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% ashington. DC 2031:-7082. telephone dated May 22.1992 which is available (202) 512-2249 or (202) 512-2171. Is sued ckpoun f

bl ic DocIment Room.guides may also be purchased from the The NRC's cu rent pohey on

issio e a atimaNnicalInfonnahm Serme enforce =ent conferences is add essed in

n20 L Street. NW Washmgton. DC n a standing order bas,. Details on Sectio: V of the latest ree ion to the (

q 20555, and at the local pubbc document s

this service may be obtamed by writing.. General Statement of Policy and room at Greenfaeld Community College.

1 College Drive. Green!

e'.d.

NT15. 5285 Port Royal Road Springfield. Proced: e for Enforcement Actions?

A 22161-Massachusetts 01301.

(Enforcement Policy} 20 CFR pa-t 2.

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Auth nry: 5 U.S C. 552lal.

appen:Lx C that was pubbshed on Dated at Rocklie. Marpand. this Od da)

of July 199:

Dated et Rociville. Maryland. this Mth day Februa.y 18.1992 (57 FR 5791) The For the Nuclear Reguin, Comm:ssion

% 2m Edommet Pohcy states dat.

RM F. Dudky, N For the Nutiear Regulatory Commimon.

• 'enfor ement conferences wiU not

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.4ctag Duector.No+Po c Aractors.

Enc S. Bwijord. Director, norma'.y be open to the public.~

Decommissionirs and Erm r.~entalPwjet.

O"s:e cfNucleor RepictoryResearch HOWeTer. the Commission has decided to c,pammt a trial pwpam to D: rector ~te. Dins:ce of Fr:: :- rwjects-f rR Doc. 92-1L:24 Tded 7.M. e 45 am)

deter ~ :e delber to maintain the I

11HIV/V. O"rce t!%cle: Ce::ror ow,,2 m wm Rep!;6on curren* pol. icy with regard to

[FR Dar 9 -18:3 Fded 7 r-41 e 45 am)

enforcement cocierences or to adopt a swuc coot rs.o.c Two-Year Trial Program for new policy that would aUow most

Conclucting Open Enforcement enforcement conferences to be open to Confecences; Poucy Statement attendance by aU members of the pubhc.

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Regu!atory Guides;isscance.

MU h"#

Avaksbtlity A GENcy: Nucleat,1er.datory

hsh The Nuclear Regalat:-. Commission has issued a revision to a pide in its Acwc Policy statement.

The NRC is implementing a tw o. year i

Regulatory Guide Senes This series has trial pvpam to aUow public svuuAny:The N.uclear Regulatory been developed to dest.be end make

observaton of selected enforcement available to the public sd information Commission (NRC) is issuing this policy confere:ces.The NRC wiU monitor the

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as methods acceptable to the NRC staff staummt on de implementatie of a for implernenting speci5: parts of the, two-year trial pregam to aHow selected pro am and determine whether to

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Cco". 2ssion's rerJ' atacnt techniques edemmt contences to be opm to MaM M hU 6

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used b3 the naff m evabng specihc ettendance by all members of the c nducing open enforcement c nien:ces based on an assessment cf l

problems or postulated a ndents. and d p-Mc.This pohcy statement data needed by the staff n its review of cesenbes the two-year trial program the fot:wmg cnteria-appbcations for permits and hcenses and informs the public of how to Fet (1) Wnether the fact that the Regulatory Gutde 87. Emsion 1.

information on upcoming open conference was open impacted the

" Inst uctions for Record.n; and eni reement coninences.

NRC s ability to conduct a meanm.ul e

c nfere ce and/or implement the NRC s Repornng Occupationa! Ea d:ation oarts:This trial program is effective on enf icement pmgram;

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bposure Detal' desenS s an luly 10.1992. while comments on the acceptable propam for ne preparaton propern are being received. Submit (2) Wee 6u 6e open codnene retenuon. and repornn2 c' records of comraents on or before the compleuon impacted the beensee,: pa-ucipanon in

occupa6cnal ra d:eno:. e gos ures It of the tnal progra= scheduled for July the coclerace, hcludes copies of NRC Fc=.s 4 and 5 11.1W2. ' Comments received after tNs (3) Wr. ether the NRC e xpended a and detailed instructions en comp!cteg date wili be considered if it is practv.a!

signifant amount of rmurces in them to do so. but the Commission is ablc to makin; 6e conference public: end Comments and super :.ns in assure corsideration only for comments (4) ne ertent of pubhc interest m i

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connecuen with items fm 2nduwon in recened on or before this date.

openc; the enforcement confere nee

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s Federal Regtster / Vol. 57. No.133 / Friday. July 10.10a2 / Notiws 037G3

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b I. Criteria for Selecting Open three categories of boensees wiu be s ubrect to personnel screening, that

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j Enforcement Confermes commeraal operating reectors, signs. Sanners po6ters,ets not larger p

l hospitala, and othei !scensees, whidi than 1 r tr permitted, and that

i Enforcement conferences wiU not be wW c nsW M the mmainmg Wes M 6mp6e pesons may & rewed y

l open to the pubbc if the enforu:nect Heenseen.

Each agional Ace wW eMnw to y

j ection being comtempleted-

< iduct the enfortement conference

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(1) Would be 1alen again61 an II. Amxmadng Open Enforcement

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1. c ceedings in accordance with regional indindual, or if the action, though not Conferences

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prach h enfwment confennce tzken against an mdmdual. tums on As soon as a.t is determined that en wiu continue to be a meeting between I

whether en indmdual has commmed enforcement conference wul be open to the NRC and the Lcensee.While the wrongdoing; public observation. the NRC will orally enforcement conference is open for

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(2) Involves signincant personnel notify the licensee that the enforcement public observation. it is not open for

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failures where the NRC has requested conference will be open to public public participation.

I that the individualls) involved be observation as part of the agency's trial Persons attending open enforcement

present at the conference, program and send the licensee a copy of conferences are reminded that (1) the (3)Is based on the find ngs of an NRC this Feideral Register notice that outimes apparent violations discussed at open i

Office of Invesngations I g report. or the program. Licensees will be asked to enforcement mnferences are subject to I

(4) Involves safeguards mformation.

estimate the uumber of participants it funber review and may be subject to

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Privacy Act information. or other will bring to the enforcement conference change prior to any resulting information which could be considered so that the NRC can schedule an enfortement action and (2) the

i Pmprietarb appropriately sized conference room.

stat:ments of views or expressions of

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Enforcernent conferences involving The NRC will also notify appropriate opinion made by NRC employees at medical mn idministrations or State liaison officers that an open enforcement conferences or the i

overexposures will be cpen assumm.g enforcement conference has been lack thereof, are not intended to

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the conference can be conducted scheduled and that it is open to public re resent final determinations or beliefs.

without disclosing the exposed b[*at

individuaTo name. In ad6 tion.

C intends to announce o n the agencys trial program an accordance

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enforcement conferences wi11 not be enforcement conferences to the public with the guidance in this notice, persons E

open to the pubhc if the conference w ll normally at least to working days in attendmg open enforcement conferences I'

i be conducted by telephone or the advance of the enforcement conference wiU be provided an opportunity to conference will be conducted at a through the followmg mechanisms:

submit written comments anonymously s

relatively smalllicensee o tacihty.

(1) Notices posted in the Public to the regional ofLce.These comments d

Finally, with the approvd of the Document Room; will subsequently be forwarded to the j

Executive Director for Operations.

(2) Toll-free telephone messages; and Director of the O! Lee of Enforcement for

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enforcement conferences wd! not be (3) ToU-free electronic baUetm board review and considerat. ion.

open to the pubhc in special cases messages.

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where good cause has b< en shown after Pendmg establishment of the toll free Dated at RockrGa. MD. thus 7th day of J4

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I balancmg the beneht of ;.ublic message systems, the pubhc may call 1992-

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observation against the potential impact (301) 492-4737 to obtain a recording of for the Nuclear Regulatory Coc.cussion.

on the agency's enforcement sction in a upcoming open enforcement Samuel 1. ChiIk.

j particular case.

conferences. The NRC will ireue another secrera y cf the commission.

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The NRC will sinve to conduct cpen Federal Register notice after the toU-free (FR Doc. Mc 33 Fded 7+92; E45 a.m.)

enforcement conferences dunng the message systems are catablished.

m m 7-two-year tnal picpam e accordance To assist the NRC in making with the followc; three goals:

appropriate arrangements to support (1) Approumately 25 ;.ercent of all public observation of enfortement OFFICE OF PERSONNEL

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eligibk enforcecert conferences conferences. individ uals interested in MANAGEMENT conducted by the NRC wd] be open for attending a particular enforcement public observenon:

conference should notry the individual Request for Clearance of a Revised

'i (2) At least one open enforcement identified in the meeting notice Information Colkretkm to Add Form RI conference wdl be condected m esch of announcing the open enforcement 36-7 to CMB Clearance Number 3206-l the reponal chces; anc conference no later than fne business 0128

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(3) Open enf orternent conferenas days prior to the enforcement

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wdl be conducted with a vanety cf the conference.

acuecy: Office of Personnel

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types of hcensees

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!!I. Conduct of Open Enfo cement To avoid potenta! bias m the geno,e: Notice.

Conferences

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I selection process and to attempt to meet l

the three goa!s s eted hve. cre v in accordance with cur ent practice.

suwAstr In accordance with the I

fourth ehyble. nforteme nt conference enforcement conferences wdl contmue paperwori Reduction Act of 1900 (title mvolvmg one c *ee ccegones cf to normaUy be held at the NRC reg.ional 44. U.S. Code. chapter 35) this notice heensees wdl *. mally t-open te be ofhces Members of the pcbhc will be announces a request for clearance of a pubbcdunnga tnal prx am.

allowed access to the NRC reponal reviced information collection, to add

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However.m cases w here there is en off ces to artend open enfmment form R136-7 to the Application for ongome adjudic atarv pweeding with conferences in accord mce with the Refund of Retuement Deductwns one or more inte venors. enforcement

" Standard Operating prtedures for (CSRS). OPM must have SF 2ic2 conferences im o!ving issues related to Providmg Security Suppo-t For NRC comp letely LUed out and signed before the subject rna"er of the ongoing Hearings And Meetmgs"pubbshed paymg a refund of retirement adjud cetion n.y also14 opened for November t.1971156171 Sc:M) These contnbunons SF 2 srb muet also be the pu* poses cf 1:s trid program. the procedures provide that vasito s raay be complete i! there are spouse (s) or forn.cr

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Enclosure 3 Safety Assessment /0uality Verification Inspection Licensee:

Iowa Electric Light and Power Company IE Towers, P.O. Box 351 Cedar Rapids, la 52406 Facility Name: Duane Arnold Energy Center Inspection At:

Palo, Iowa Inspection Conducted: April 5-9, and May 3-7, 1993 Inspectors: Robert M. Pulsifer, Project Manager, NRR/DRPW

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Beth Korona, NRR/DRPW Areas Insp_ected: Routine, announced inspection to evaluate the licensee's quality assurance program implementation and self-assessment capability.

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Results: No violations were identifie,1.

An executive summary follows.

Safety Assessment /Ouality Verification The licensee's self-assessment programs continued to be good.

Safety Committee and Operations Committee meetings were frequent and conducted with good participation and open discussions by most members.

Followup of actions requested by the committees were generally timely and responsive.

Training of the committee members and alternates were found to be good.

The licensee's Quality Assurance (QA) organization continued to improve through a reorganization and the establishment of functional area teams. The QA audits were complete, comprehensive, and generally followed up on previous findings. There was an example of a finding that wasn't completed by an established commitment date because of communications brealdown between QA and the responsible group.

Overall, the strong support for tte QA organization by management has made QA more effective.

Through the tracking of various commitments; i.e. audit findings, agency commitments, etc., the licensee's management was kept informed to determine I

where management attention was required.

i The temporary modification control program has improved.

However, modifications that extend more than 6 months should be resolved in a more timely manner.

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A new corrective action program called the Quality Deficiency Report -(QDR)

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System has just been initiated to consolidate the several separate older l

reporting programs.

This system should provide easier reporting and tracking

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of deficiencies.

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l DETAILS

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Persons Contacted

• D. Barta, Licensing Specialist

• P. Bessette, Supervisor, Regulatory Communications

• D. Blair, Supervisor, Quality Assurance

• C. Bleau, Supervisor, Systems Engineering T. Browning, Licensing Engineer i

W. Clark, Engineer - Mechanical

• G. Coil, Group Leader, Quality Assuranca

• C. Crew, Operations Comittee Engineer

• D. Engelhardt, Security Superintendent M. Everhart, Technical Specialist A

• M. Flasch, Manager, Engineering J. Fosdick, Principal Engineer R. Fowler, Operations Shift Supervisor A

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J. Gushue, Principal Specialist - Quality

• L. Heckart, Licensing Engineer

• M. Huting, Supervisor, Quality Control

• J. Kinsey, Supervisor, Licensing

• B. Klotz, Group Leader, Quality Assurance

• J. Kozman, Supervising Engineer, Systems Engineering

• D. Lausar, Supervising Engineer, Systems Engineering

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• J. Loehrlein, Supervising Engineer, Systems Engineering D. Mankin, Operations Shift Supervisor B R. McGaughy, Safety Committee Chairman

• C. Mick, Operations Superintendent

• 0. Olson, Group Leader, Electrical Engineering

• K. Peveler, Manager, Quality Assurance L. Robinson, Senior Quality Assurance Specialist

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• A. Roderick, Supervisor, Testing and Surveillance

• W. Rose, Safety Committee Engineer

• C. Rushworth, Licensing Engineer

• H. Sikka, Supervising Engineer, Systems Engineering

• S. Swails, Manager, Nuclear Training

• J. Thorsteinson, Assistant Plant Superintendent - Operations Support

• G. Van Middlesworth, Assistant Plant Superintendent - Operations and Maintenance E. Wienola, Senior Quality Assurance Specialist

• D. Wilson, Plant Superintendent, Nuclear P. Wojtkiewicz, Senior Engineer - Mechanical Maintenance

• K. Young, Manager, Nuclear Licensing

• Denotes those present at the entrance meeting on April 5, 1993, and/or the exit meeting on May 7, 1993.

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2.

Followup of Specific Issues

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a.

0perations Committeel0C) Commitments As documented in inspection report (IR) 50-331/92003, "The Operations Committee (OC) agreed that a formal method for ensuring that all comments had been satisfactorily resolved was a good idea and took this item for action."

This item was not added as a

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commitment to track and no formal method had been actively pursued

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by the OC to resolve this issue. The OC felt this was how the

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system worked and it was working then and now.

Procedure 106.11, " Review Record," was being revised and it will formally require a satisfactory resolution of comments with the reviewer. Procedure 106.2, " Review and Approval of Divisional and

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Departmental Procedures," was also revised in December 1992 to l

require formal discussions with the reviewer on unresolved

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comments. Although these revisions were the result of a formal j

review of procedures for acceptability and not the direct result

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of the commitments in IR 50-331/92003, the issuance of revised procedure 106.11 would resolve this concern.

b.

Inadecuacy of Drawinas and Valve Labelina As documented in IR 50-331/92003, " Completion of the valve walkdown and labeling effort is encouraged to prevent future events stemming from valve labeling problems."

This concern dates back to IR 50-331/90016. The IR stated that the licensee committed to place a higher priority on completing its efforts to label, document, and proceduralize all plant valves and components.

It was again referenced in IR 50-331/91017.

Licensee audit report I-93-03 followed up on a finding and found that the walkdown and labeling had been completed, but the drawing discrepancy changes still needed to be completed. Additionally, report I-93-03 noted that drawing changes were progressing well.

These drawing changes were now scheduled to be complete in January

1994.

This item will be followed at a later date.

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c.

Resolution of Corrective Actions and Commitments As documented in IR 50-331/92003, the inspector stated, "Since it appears that the percentage of items listed in NRC Inspection Reports that subsequently assume considerable importance either operationally or in the enforcement arena is quite high, DAEC may do well to decide, based on past history, whether the commitment of resources in this area would be cost effective.'

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Both numbered and unnumbered NRC IR items, were tracked by licensing to work and followup. The numbered items were on a computerized tracking system and the unnumbered items were tracked

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d.

Audit Status Report

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As documented in IR 50-331/92003, the inspector stated, "To obtain a true comparison of the licensee's progress in clearing audit items, the audit status report should again be reviewed next year."

The resolution of overdue audit findings has greatly reduced the number that are overdue. Over the last 12 to 14 months the number of overdue findings has been near zero.

The most significant overdue items identified in IR 50-331/92003 were from Audit Report I-90-25.

Audit Report I-90-25 was reviewed and found to be

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closed.

Internal audit findings commitment dates are now tracked

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by management and get high visibility.

This reflects a stronger management commitment to assure internal audit findings will be

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resolved on a timely basis.

3.

Evaluation of Licensee Self-Assessment Capability (40500)

The inspectors reviewed the licensee's overall self-assessment

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capability. This review included observing several technical

specification (TS) required Operations Committee (Onsite Review

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Committee) and Safety Committee (Offsite Review Committee) meetings.

In addition, the inspectors reviewed the tracking systems the licensee utilizes for tracking internal and agency commitments.

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a.

Safety Committee (SC) Meetinas

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The minutes from the SC meeting for the last 6 months were reviewed. They were found to be thorough and provided sufficient detail to get a clear understanding of the subjects discussed. A plant status briefing was provided at each of the two scheduled monthly meetings. These bi-monthly SC meetings were more frequent than the bi-annual requirement of the TS. Discussions in the two SC meetings that were observed were open and responsive. There was good participation by the members, and items for further discussion by the committee were freely raised.

In order to assure good input from the SC to meet TS requirements on internal audit development and execution, the SC had assigned SC members to the audit teams.

Presentations and discussion on (1) the NOV program, (2) shroud access hole cover inspection, (3) circulation water pump bolt failure, and (4) Washington Nuclear Plant-2 power oscillations were held at the two meetings attended. The committee reviewed and discussed important issues that may affect DAEC. Several of the members were consultants outside Iowa Electric, and they add depth and expertise to the committee. The

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SC open item list was included with the minutes. Status of these open items were not generally discussed at each meeting, but the

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responses to the items were addressed at the next appropriate

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meeting. The issues were generally resolved on a timely basis and

were responsive. Training was adequate, with all members and alternates provided with requalification training on an annual basis. The Eafety Committee Engineer reviewed major plant and

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industry items for interest and applicability, and presented them to the SC for their future interest or review.

b)

Operations Committee (OC) Meetinas Two meetings of the OC were attended and the OC minutes were

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reviewed for the last 3 months.

The levels of discussion were appropriate for the items on the agenda. There was a good discussion on the high water level of the Cedar River including DAEC contingency plans and lessons learned.

There was also a good overview on the reactor mode switch replacement, and the interfaces DAEC had with the Boiling Water Reactor Owner's Group (BWROG), General Electric, and the Monticello facility.

Alternates were rarely used in the OC.

Members and alternates were annually requalified and nad the expertise to provide good OC accountability.

Based on the inspector's observations at the two OC meetings and interviews with OC members, most procedures and requests for technical specification changes were not read in detail by each of the members.

However, there seemed to be sufficient review to determine the safety significance of the change and the 50.59 applicability. The TS requirements for the

OC were being addressed.

Procedures were not generally provided in pre-route meeting packages, however, each procedure change form was read for the required action and reason for the change.

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will be followed up in a subsequent inspection to assure that procedures were getting an appropriate independent review.

c)

Commitment Trackinc The Commitment Control Tracking System (CCTS) was used to track-commitments made to the NRC, Institute of Nuclear Power Operations (INPO), and other agencies as well as internal commitments made between licensee departments. The NRC items tracked by this

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method were responses to Hotices of Violations and Licensee Event Reports.

Weekly reports were distributed as part of the package assembled by the Corrective Action Program Advocate.

These reports were distributed to the appropriate supervisors with all open items listed.

There was a formal monthly agency commitment status report issued, which listed all open agency commitments, clearly identified all overdue agency commitments, and similarly identified those due within the next 45 days.

This report was distributed to the assigned supervisors.

If an agency commitment was overdue on the report, the Nuclear Licensing Manager issued a reminder notice to the responsible supervisor.

If the item was not closed within 2 weeks, a memo from the Vice president-Nuclear Division would have been issued requesting an immediate written

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explanation. The latter notice had never been issued.

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process gave DAEC commitments high visibility with plant t

management.

As shown by the reduction of overdue commitments since the

inception of this program, this was an effective system.

Licensee management used the system and understood the process.

4.

Evaluation of Licensee Quality Assurance Program Implementation L3_55021 i

An evaluation of portions of the licensee's implementation of its quality assurance program was performed. This evaluation includec

review of the licensee's internal audit program and the corrective action program.

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Internal Audit Program i

The inspector obtained a list of all TS required audits for which reports had been issued since January 1992.

Several of these audits, including previous referenced audits, were selected for detail review:

Audit Reports I-93-03, I-92-04, and I-91-07, Conformance of Facility Operations to Technical Specification and License

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Conditions.

Audit Reports I-92-19 and I-92-05, Results of Corrective Actions.

Audit Report I-90-11, Fire Protection Audit, and Audit Reports I-92-18 and I-91-13, Design Control, Modification Activities and Safety Evaluation Audit.

The inspector found the audits to be complete and comprehensive.

Audit findings were followed up and closed in a timely manner.

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Findings from previous audits were usually followed up in tre next

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audit. The audits were developed and planned using NRC and INP0 references.

Planning meeting were held to secure input fron people outside of Quality Assurance (0A) to determine items :o be audited.

Experts from other licensees occasionally participted in audits to enhance their effectiveness. Through interviews with selected lead auditors, the inspectors found them to be well trained and knowledgeable about their specific audit responsibilities.

Several monthly internal audit status reports were reviewed. The reports indicated that overdue audit findings.were generril.s beinc closed by established commitment dates.

These reports provMed good visibility to the management on all outstanding internai

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audit findings.

This report had blank dates for items that *ere i

resolved but not verified by QA.

The April 1993 report star ed i

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placing commitments by QA on the items needing verification, so that management could focus on the actua'. riosure of the finding.

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This report provided a good summary of finding status, responses due within 30 days, and audit schedules.

Finding 2, in audit report I-92-04, did not meet the commitment date because the scope of the finding was not clear to the responsible organization.

It appeared that QA could assist DAEC by assuring that the responsible organization fully understood the entire scope of each finding and that the status was periodically checked before the commitment due date was reached.

It was recognized that this was only 1 of 42 outstanding findings.

However, this misunderstanding provided a false status to management on the final resolution of this item.

Audit report I-92-18, finding 4, addressed a TS requirement where proposed changes or modifications that affect nuclear safety was to be reviewed by the Operations Committee (OC).

The inspectors reviewed this finding and plant followup activities concerning the

Temporary Modification (TM) procedure ACP 1410.6.

This procedure was revised (Revision 2) on December 31, 1992, to streamline the procedure to make it user friendly and to resolve a QA audit

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finding and an NRC inspection report concern.

Before the revision, the TM could be extended beycad 6 months.

The February 1993 quarterly report to the OC, which was a requirement of ACP 1410.6,- indicated there were 44 open TMs, of which 27 were extended. Two of the items dated back to 1989 and three have estimated removal dates in 1995. The April quarterly report identified 35 open TMs; however, there were several TMs in the control room log not on this report. All new TMs installed since-

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the procedure revision had estimated removal dates in 1993. The revised procedure did not allow for extensions.

Revision 2 required that (1) TMs are expected to be installed for 6 nonths or less, (2) they will be in effect for a short duration, and (3) TMs be corrected in a timely manner. The procedure should

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reflect the need for longer than 6 months if needed or otherwise make a permanent change. Changes were still being authorized for greater than 6 months; however, the average age of all TMs was decreasing.

According to an internal memo dated December 23, 1992, all TMs initiated prior to December 31, 1992, would be

" grandfathered" under the old procedure (Revision 1) and this revision was to be kept in the Operations Shift Supervisors (OSS)

TM binder.

An old TM,92-715 was not extended.

Paperwork was initiated in late February to effectively get TM 92-715 the required signatures to meet the intent of Revision 2 instead of using the extension process of Revision 1.

As of May 7, 1993, this had not been completed.

Review of the OSS TM binder indicated that progress was being made to reduce the age as well as the number of long term temporary modifications.

The inspectors will continue to monitor the TM process to assure that the TM procedure only provided for TMs and was not used as a substitute for permanent changes.

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b)

Corrective Action Program

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The Duane Arnold corrective action program utilized several mechanisms to identify and correct conditions adverse to quality.

On May 3,1993, a new process was implemented to consolidate the reporting of deficiencies. The Quality Deficiency Report replaced the Corrective Action Report (CAR), Nonconformance Report (NCR), Audit Findings (AF), and Surveillance Deficiency Report (QSD). This system of reporting was expected to provide a

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single point of contact for status and followup of deficiencies

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The Quality Assurance organization was assigned to distribute and track all QDRs. Overall, the QDR process should make the reporting and tracking of nonconformance items easier.

The NRC will review this process in the future.

There were a few observations noted by the inspector.

The QDR tags were not available on the date the procedure became effective.

(A last minute revision was made to the heading on the tag due to a similarity in the acronym to another tag used in the

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pl ant. ) Also, the database which will be used to track these

items was still under development. This may lead to inaccuracies in status tracking until the method is formalized. The procedure was implemented at a time relatively close to the July 1993 refueling outage.

The licensee had planned to implement the

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procedure earlier, but various personnel delays prevented it. The licensee explained that all QDRs would go through one of two QA/QC l

members, thereby ensuring consistent use of the process.

A la ge percentage of the workforce had been trained on this system, including management. This should greatly aid in the smooth

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transition to this process.

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5.

Quality Assurance

The Quality Assurance organization was evaluated to determine its

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effectiveness. The inspector reviewed the QA Department and QA

Assessment Group goals. The goals established were realistic and t

achievable. They were developed with input from the QA staff to provide ownership of the goals by the whole group.

The Quality Assessment

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organization had monthly planning meetings to determine if any non-T5 driven inspections should be performed. Much of this input was gathered from " functional area" teams made up of both auditors and "surveillers."

These additional inspection items may also be identified by the safety l

committee or plant personnel.

All suggested items were placed in an

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internal tracking system and discussed at the planning meeting.

When an inspection was needed, a surveillance plan was written and performed.

A recent request was made by the VP-Nuclear to review current TS

" interpretations" in an effort to find more " questionable" LCO readirgs similar to the personnel airlock surveillance requirement which has

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recently been granted a Notice of Enforcement Discretion by NRC.

To help foster the relationship between QA and operations, a Temporary Operations Shift Supervisor has been assigned to the QA organization on a rotation basis. This has been a benefit to both organizations by

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getting an operational perspective in QA and providing a QA viewpoint to operations.

6.

Exit Interview

The NRC inspectors met with the licensee representatives on May 7,1993, to address the scope and findings of the inspection. The licensee acknowledged the statements made by the inspector with respect to the items discussed in this report. The inspector discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection and the

licensee did not identify any such documents or processes as proprietary.

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