IR 05000331/1993010
| ML20149D422 | |
| Person / Time | |
|---|---|
| Site: | Duane Arnold  |
| Issue date: | 09/13/1993 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20149D409 | List: |
| References | |
| 50-331-93-10, NUDOCS 9309210037 | |
| Download: ML20149D422 (24) | |
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t U. S. NUCLEAR REGULATORY COMMISSION
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REGION Ill Report No. 50-331/93010(DRP)
Docket No. 50-331 License No. DPR-49 Licensee:
lowa Electric Light and Power Company IE Towers, P. O. Box 351 Cedar Rapids, IA 52406 Facility Name:
Duane Arnold Energy Center Ins'pection At:
Palo, Iowa Inspection Conducted: July 8 through August 23, 1993 Inspectors:
J. Hopkins C. Miller P. Prescot Approved:
9 13h1 R. D. Lanksbury, Ch,igf; Date Reactor Projects Section 3B Inspection Summary Inspection on July 8 throuch Aunust 23. 1993 (Report No. 50-331/93010(DRP))
Areas inspected:
Routine, unannounced inspection by the resident inspectors of ' followup, followup of events, operational safety, maintenance, surveillance, regional requests, management meetings, and report reviews.
Results:
An executive summary follows:
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EXECUTIVE SUMMARY
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Plant Operations At the beginning of the period, the reactor was operating at about 77 percent power with all rods out, in coastdown prior to refueling outage 12. The main generator was disconrected from the grid on July 29, 1993.
Shutdown and conldown operations went smoothly. The "A" spent fuel pool cooling pump
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tripped due to debris in the pump suction strainer. This event demonstrated the need for the licensee to improve their control of foreign material on the refuel floor. An improvement was observed in the conduct of shift turnovers.
Maintenance / Surveillance
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Outage planning efforts have resulted in good work coordination with a proper emphasis on shutdown risk activities. One unresolved item (331/93010-01) was i
identified due to cleanliness concerns in foreign material exclusion zones (sections 3 and 5). One unresolved item (331/93010-03) was identified due to concerns with personnel errors during maintenance and surveillance activities (sections 5 and 6).
Enaineerina On July 14, 1993, Mr. Michael McDermott, formerly the Maintenance Superintendent, replaced Mr. Michael Flasch (an INP0 (Institute of Nuclear Power Operations) loanee) as Manager of Engineering. Mr. Gary Van Middlesworth, Assistant Plant Superintendent - Operations and Maintenance, assumed responsibility for management of the maintenance department on
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July 14, 1993, following Mr. Michael McDermott's promotion to Manager of Engineering. A permanent replacement for the Maintenance Superintendent was
scheduled to be named after the refueling outage.
Engineering support was continuing in an effort to resolve problems aith main steam isolation valves (MSIVs), high pressure coolant injection (HPCI)
reversing chambers, feedwater stop check valve operator cracking, and feedwater sparger jacking bolt replacement.
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Plant Suonort l
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One unresolved item (331/93010-02) was identified due to concerns with contractor access authorization (section 3). Management oversight and
planning to minimize the effects of the Cedar River flooding were timely and i
effective (section 3).
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DETAILS
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1.
Persons Contacted
- R. Anderson, Operations Supervisor R. Baldyga, Supervisor, Maintenance Engineering l
- P. Bessette, Supervisor, Regulatory Communications 1'
- J. Bjorseth,-Assistant Operations Supervisor
- D. Blair, Quality Assurance Assessment Supervisor
- C. Bleau, Supervisor, Systems Engineering
- D. Engelhardt, Security Superintendent l
J. Franz, Vice President Nuclear
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- R. Hannen, Outage Supervisor
- C. Kardos, Supervisor, Reactor and Computer Performance
- J. Kozman, Supervisor, Engineering
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D. Lausar, Supervisor, Project Engineering
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- J. Loehrlein, Engineering Supervisor e
M. McDermott, Manager, Engineering
- K. Peveler, Manager, Corporate Quality Assurance
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K. Putnam, Supervisor, Technical Support j
- A. Roderick, Supervisor, Testing and Surveillance
.i P. Serra, Manager, Emergency Planning
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- H. 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 i
- T. Wilkerson, Radiation Protection Manager
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- D. Wilson, Plant Superintendent, Nuclear
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- K. Young, Manager, Nuclear Licensing in addition, the inspectors interviewed other licensee personnel
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including operations shift supervisors, control room operators, I
engineering personnel, and contractor personnel (representing the
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licensee).
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- Denotes presence at the exit interview on August 23, 1993.
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2.
Followup (92701)
(Closed) Open item (331/92005-01(DRS)): Delete the vented-flowmeter l
method from the local leak rate testing (LLRT) procedure or provide l
justification for its use in the testing of specific penetrations. The i
inspector reviewed the applicable sections of; surveillance test
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procedure (STP) 47A005, Rev. 29, used for testing the main steam l
isolation valves (MSIVs).
In addition, a meeting was. held at the
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regional office on July 19, 1993, where the licensee presented the methods to be used for testing the MSIVs. The meeting was followed by a
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conference call on July 23, 1993. The proposed methodology was as j
follows:
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A combined test of both MSIVs in each main steam line would be performed using the constant pressure make-up flow method.
The downstream side of each valve was to be drained and vented for the test.
e If the combined test exceeded the acceptance criteria, a test of the outboard MSIV using the same test method would be performed, but with no pressure differential across the inboard MSIV.
If the two tests indicated that the inboard MSIV was leaking in
excess of the acceptance criteria, a test of the inboard MSIV in the direction of accident pressure would be performed using the vacuum - flowmeter method.
In this method, a vacuum pump would maintain a vacuum on the test volume and discharge through a fl owmeter.
This would ensure that all the leakage past the inboard MSIV was measured.
The inspector stated that the licensee's proposed methodology was
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acceptable provided that:
The pressure at the test rig was adjusted as required to maintain e
the differential pressure across the valve (s) being tested at a pressure greater than or equal to 24 pounds per square inch (psig).
If a mass flowmeter was used, the licensee was to ensure that the
humidity level in the measured air was below that which would affect the performance of the flow sensor.
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The use of the vented-flowmeter method was also discussed.
The inspector stated the method could be used in place of the vacuum-flowmeter method provided that in addition to the previously stated conditions:
The tubing length between the test volume and the flowmeter should
be kept as short as feasible.
The licensee stated it would be kept to less than or equal to 40 feet.
The test boundary was tested for leakage at 5 psig before and
af ter the main test, using the constant pressure make-up flow method. The 5 psig tests should be performed with the downstream side of each potential leakage path drained and vented.
The highest leakage rate of the two 5 psig tests should be added
to the results of the main test (vented flowmeter method) before determining whether the acceptance criteria was satisfied.
Based on the above understanding, this item is considered closed.
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No violations or deviations were identified in this area.
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3.
Followup of Events (93702)
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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 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:
July 9, 1993
- Reactor recirculation runback to 65 percent power.
August 10, 1993 - Loss of electrical power to the Emergency Operating l
Facility.
I August 13, 1993 - Primary containment isolation.
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"A" spent fuel pool cooling water pump trip.
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- Contract employee's site access revoked.
a.
Loss of Electrical Power to the Emeroency Operatina Facility l
On August 10, 1993, at 3:00 a.m., the Emergency Operating Facility (EOF), located in the Iowa Electric (IE) Tower, an office building
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in downtown Cedar Rapids, Iowa, lost all electrical power.
The cause of the loss of power was an underground electrical fault in the Cedar Rapids electrical distribution system due to heavy rains.
Electrical power at Duane Arnold Energy Center, which was in Cold Shutdown for a refueling outage, was not affected.
Power was restored at 4:40 a.m.
The shift supervisor was informed of the loss of power to the IE Tower at approximately 5:19 a.m.,
and the licensee informed the NRC Operations Center at approximately 5:44 a.m.
The loss of power to the EOF disabled various computer systems, facsimile communications, radio communications, the emergency news center, and IE Tower lighting.
Some of the computer systems affected were the Meteorological Information Data Acquisition System (MIDAS) dose projection model, Safety Parameter Display
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System, and emergency data system.
The EOF still had dose projection capability using MIDAS on lap top computers, and the
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telephones were being powered from a battery source.
The alternate emergency news center, located at the Cedar Rapids airport, was not affected by the underground electrical fault.
The licensee's response to the event was reviewed by the resident inspectors and regional emergency planning specialists and no significant concerns were identified.
b.
Cedar River Flooding Due to continued unseasonably high rainfall, river water flow and level increased significantly.
On April 4, 1993, after significant spring runoff, the river crested at 745.5 feet, as measured at the river water intake structure (see inspection
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report 50-331/93005 for details). On July 11, the river crested at 743.2 feet. There was no localized flooding on the site. The
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licensee continued to monitor river water levels due to local flood warnings.
From July 14 to July 28, 1993, Interstate 380 ano :owa State road
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965, between Cedar Rapids and Iowa City, were closed due to flooding near Iowa City. The licensee evaluated alternate
evacuation routes and assessed the capacity and availability of
emergency facilities and emergency services of the surrounding l
countie.;.
The licensee determined that adaquate capabilities still existed. The licensee discussed these issues with surrounding local county officials, Federal Emergency Management Agency (FEMA) Region VII, the State of Iowa, and the NRC at Region III and the Office of Nuclear Reactor Regulation (NRR).
c.
"A" Soent Fuel Pool Coolina Water Pumo Trio j
On August 13, 1993, at approximately 7:15 p.m., the "A" spent fuel pool (SFP) cooling water pump tripped on low suction pressure.
The reactor was defueled with all fuel assemblies in the SFP.
The SFP temperature was approximately 112 degrees Fahrenheit (F) when the pump tripped. Decay heat was being removed by both trains of SFP cooling prior to the pump trip. The "B" train of SFP cooling was not affected by the
"A" pump trip. The licensee identified a black rubber overshoe in the suction strainer of the "A" SFP cooling water pump.
The overshoe was removed, and the "A" train
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of SFP cooling was restored on August 14 at approximately l
1:25 a.m.
The temperature in the SFP was approximately 119 degrees F when the "A" train of SFP cooling was restored.
At the time of the event, the SFP gates were installed to isolate the SFP from the reactor cavity to simport draining the reactor cavity.
The licensee calculated the SFP time to boil was approximately 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br />, assuming one train of SFP cooling remained in service and no other actions were taken.
The licensee reviewed their shutdown risk guidelines and developed contingency plans to reflood the reactor cavity and remove the SFP gates if the
"A" pump could not be restored. Additionally, the "B" train of residual heat removal (RHR) was available to be started in the fuel pool cooling assist mode, had it been needed.
The licensee's initial investigation determined that use of black overshoes was discontinued after the 1990 refueling outage.
However, a few pairs of black overshoes were found in the " dress out" area mixed in with the black rubber boots used for " wet" work. The licensee was unable to determine how long the overshoe was in the SFP cooling system or how the overshoe got into the SFP cooling system.
During the investigation, the licensee determined that the "B" SFP
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cooling pump did not have a suction strainer.
The licensee
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committed to evaluate the need for a pump suction strainer in both
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SFP cooling pumps. Additionally, the "A" pump tripped on low j
suction pressure in the previous two refueling outages due to
foreign material clogging the pump suction strainer.
On August 20, 1993, a conference call was held between the
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licensee, Region III, and NRR to discuss the root causes of the
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event, immediate corrective actions, the results of the licensee's
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actual investigation, and actions planned to prevent recurrence.
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During the conference call, the licensee committed to revise the
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procedures for housekeeping and foreign material exclusion,
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evaluate adding covers or screens to the SFP skimmer intakes, t
examine the screens in the SFP cooling system skimmer surge tanks,
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and perform other actions to reduce the potential for introducing foreign objects into the SFP. Because this issue developed late i
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in the inspection period, additional followup was required. This issue, as well as the other cleanliness control issues discussed
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in section 5.a., will be tracked as an unresolved item j
(331/93010-Ol(DRP)). The inspectors will continue to evaluate the
licensee's actions to improve the control of foreign material on the refuel floor.
d.
Contract Employee's Site Access Revoked On August 13, 1993, the licensee determined that a contract employee had falsified portions of his security application to obtain site access for employment. The licensee made the required
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notifications in accordance with 10 CFR 73.71. The issue of the
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falsified security application and the licensee's program to grant site access was considered an unresolved item (331/93010-02(DRSS)).
No violations or deviations were identified in this area. Two unresolved items were identified.
4.
Operational Safety Verification (71707) (71710)
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The inspectors observed control room operations, reviewed applicable i
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 to service of affected components. Tours of the reactor building and turbine building were conducted to observe plant equipment conditions, 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, 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 i
observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan.
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The inspectors observed plant housekeeping and cleanliness conditions and verified implementation of radiation protection controls.
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the inspection, the inspectors walked down the accessible portions of the high pressure coolant injection (HPCI) system to verify operability by comparing system lineup with plant drawings, as-built configuration or present valve lineup lists; observing equipment conditions that could
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degrade performance; and verifying that instrumentation was properly valved, functioning, and calibrated.
These reviews and observations were conducted to verify that facility
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operations were in conformance with the requirements established under technical specifications, Title 10 of the Code of federal Regulations, and administrative procedures.
a.
Refuelina Outaae Activities
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The inspectors observed preparations for and performance of
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shutdown and cooldown activities leading up to refueling outage i
12.
The activities were performed very professionally and smoothly.
Excellent prior planning and management oversight were evident throughout the process. Shutdown risk planning and i
priorities were clear to operators and maintenance workars. Major testing activities were well scheduled and were observed by
licensee management.
The licensee initiated the shut down on July 28, 1993, and disconnected the generator from the grid and scrammed the reactor on July 29, as scheduled.
In addition to refueling the reactor, major planned activities included modifications to correct instrument inaccuracies as discussed in NRC Bulletin 93-03, " Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in Boiling Water Reactors;" control rod blade replacement; 4160 Vac bus j
refurbishment; containment integrated leak rate test; standby
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diesel generator inspections; and motor operated valve testing.
b.
Control Room Operations The inspectors observed shift turnovers and crew briefings on day shifts, backshifts, and weekends to evaluate the effectiveness of the licensee's corrective actions to improve control room turnovers and professionalism. The licensee's guidelines to j
improve shift turnovers were implemented on June 18, 1993 (see
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Inspection Report (IR) 331/93009 for details).
Crew briefings following this guidance, observed by the inspectors, were less congested, more orderly, and more focused on relevant issues.
In addition, the licensee's upper management was present at most of the shift briefings, including some on the backshifts and weekends.
No violations or deviations were identified in this area.
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5.
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 with technical
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specifications (TS).
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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
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work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibraiions were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by
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qualified personnel; parts and materials used were properly certified; and radiological and fire prevention controls were implemented.
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Work requests were reviewed to determine the status of outstanding jobs
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and 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 reviewed.
- Emergency service water pump "A" replacement
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- Emergency service water strainer "A" refurbishment
- Reactor mode switch replacement
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- Loop "A" and "B" outboard RHR injection valves M0-1904 and M0-2004
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spring pack replacements
- Core off load i
a.
Cleanliness Control Proaram The inspectors observed the licensee's cleanliness and tool control program as it applied to foreign material exclusion for critical systems. Cleanliness activities were controlled by Nuclear Generation Division Procedures 1408.11, " Housekeeping i
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Control Procedure, Normal Operations and Maintenance," and 1408.12. " Refuel Floor Housekeeping Control." The inspectors noted that the procedures had some good guidelines and recommendations for foreign material exclusion practices, but very few actual requirements. As a result, some work activities failed
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to provide adequate cleanliness requirements, even though some activities were performed very well.
j The inspectors observed refuel floor activities on several occasions. At the beginning of the refueling outage,.a
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housekeeping zone was established around the spent fuel pool, cask pool, dryer and separator pit, and reactor cavity.
One point of
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entry was established for personnel and tool control, and this area was kept clean on most occasions.
However, some workers on the refuel floor were unclear about requirements for bringing tools and equipment inside the area.
Management expectations for personnel and tool control on the refuel floor were posted in the area, but the requirements for logging and lanyarding tools appeared to conflict with guidelines in procedure 1408.11.
The inspectors pointed out instances where work performed on the refueling bridge could have resulted in tools being dropped into the dryer and separator pit. The licensee was considering procedure revisions for refuel floor activities at the end of the report period.
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The inspectors also noted that some requirements of procedure
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1408.11 for refuel areas were not being carefully followed.
Procedure 1408.11 required an inspection to be performed prior to work in a foreign material exclusion zone. This licensee's inspection activities for the refuel floor did not ideritify several plastic tie wraps and a small piece of wood, which were later found floating in the dryer and separator pit and reactor i
cavity pool areas. The licensee retrieved one tie wrap and the
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wood.
Another tie wrap that was identified on top of a fuel bundle in the reactor core during defueling activities was later retrieved.
The material control log was hard to use and read and did not
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reflect the log sheet requirements of procedure 1408.11.
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licensee revised the log sheet after the inspectors identified the discrepancy. The inspectors also noted two minor instances of personnel not using the entry point for bringing tools in and out of the foreign material exclusion zone.
a Inadequate housekeeping and control of foreign material problems resulted in tie wraps being introduced into the reactor core, the
"A" SFP cooling pump trip due to a rubber boot clogging the suction strainer (see section 3), and a flashlight being dropped into the suppression pool.
In other areas of the plant, the requirements of procedure 1408.11, for posting an area as a foreign material exclusion zone, were not being followed.
For example, the high pressure coolant injection (HPCI) room and the "A" standby diesel generator room did not have housekeeping zone boundaries clearly identified and posted as a foreign material exclusion zone.
In addition, pipe openings were not capped properly in the HPCI room during maintenance and inadequate controls were in place to keep metal chips out of the HPCI condenser vacuum chamber. The inspectors have noted housekeeping discrepancies in other areas, such as the reactor core isolation cooling (RCIC) room.
The inspectors have discussed these discrepancies with licensee management, and will
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continue to evaluate the effectiveness of the licensee's
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corrective actions.
Pending further review by the inspectors and the licensee of these and other refueling outage housekeeping practices, this item will.be followed with the previous items
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identified in section 3.c., above, as unresolved item (331/93010-01(DRP)).
b.
Personnel Errors Three specific examples of personnel errors were identified during
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the conduct of maintenance activities.
"A" Emergency Service Water (ESW) Pump.
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On August 18, 1993, noise and high motor vibrations were identified during post-maintenance testing of the "A" emergency service water (ESW) pump. The licensee's evaluation determined that on August 10, 1993, the upper i
motor bearing he.d been installed upside down. The licensee's immediate corrective action was to determine if
there was any damage to the motor or lower bearing.
Both the upper and lower "A" ESW motor bearing had to be
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replaced.
No other deficiencies were identified.
To prevent recurrence, the maintenance procedure was revised to require a maintenance engineer or supervisor to witness the bearing replacement. The "A" ESW pump was returned to service onAugust 21. This was similar to the bearing failure caused by improper bearing replacement on the
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ESW pump motor during refueling outage 11.
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Reactor Water Cleanup Outboard Isolation Valve (M0-2740)
On August 18, 1993, during post-maintenance testing, valve M0-2730 cycled closed, but did not open. The licensee determined that the clutch tripper fingers for the motor
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operator were installed incorrectly when maintenance was performed earlier in the refueling outage.
- Low Pressure Coolant Injection Loop Select logic Design i
Change Package l
On August 19, 1993, during the performance of maintenance acceptance testing for design change package (DCP-1537) for
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the low pressure coolant injection (LPCI) loop select logic, I
the licensee identified a wire that was connected to the
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wrong termination point.
The inspectors have discussed these concerns with licensee management.
Part of the licensee's immediate corrective actions was to brief the plant supervisors and staff from both the day and night shifts on the seriousness of any
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increasing trend in personnel errors. Additionally, on August 24, the licensee instituted guidelines to immediately stop work if a personnel error occurred, contact the plant superintendent (or designee), and hold an immediate evaluation of the event with the plant superintendent before the work activity was resumed. The inspectors will continue to evaluate the effectiveness of the licensee's corrective l
actions. Due to the number of events that occurred at the end of the inspection period and the serious nature of the
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increase in personnel errors, the review of the licensee's root cause evaluations, immediate corrective actions, and actions to prevent recurrence were considered an unresolved item (331/93010-03(DRP)). An additional example of a personnel error was identified during surveillance observation (section 6) and was considered part of the unresolved item.
I Refuelina Outaae Maintenance c.
Outage maintenance activities appeared to have been planned well.
Maintenance planners had contingencies built into the schedule to account for potential problems such as occurred with the outboard MSIVs. Many of the maintenance activities were performed well, with adequate procedure use and supervision.
Some problems were discovered as a result of testing activities or outage inspections which required further resolution:
The "A" and "D" outboard MSIVs failed their LLRT.
The allowable leakage was 5428 standard cubic centimeters per minute (SCCM). The "A" and "D" leakage was 9030 SCCM and
- 0405 SCCM, respectively. Although this MSIV LLRT performance was better than that of previous outages, it continued the lengthy history of MSIV LLRT failures at Duane Arnold Energy Center.
The high pressure coolant injection (HPCI) turbine
inspection revealed cracked reversing chambers and an indication of turbine wheel rubbing on the reversing chambers. This continues a trend of cracked reversing chambers found on eight separate occasions since 1978.
The reactor mode switch was replaced with a new model.
- During post-maintenance testing, a collar on the handle assembly cracked.
The vendor stated that the function of the switch was not affected by the cracked collar.
Jacking bolts and washers, which provided a preload on the
feedwater spargers (during construction), had come loose.
In-vessel repairs were planned to remove these bolts, as well as a bracket assembly, from all the feedwater spargers.
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The feedwater stop check valves M0-4441 and M0-4442 had
cracked operator housings, which indicated that a
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significant over-torque condition occurred.
The safety-related function of the check valves was to maintain primary containment integrity. The manufacturer (Anchor Darling)
determined that the allowed thrust rating on the valve disk was 617,961 pounds of force. Although the nanufacturer stated that this was a conservative value, it was less than the theoretical torque value, which could have been applied at motor stall conditions.
The valves passed their LLRTs following discovery of the over-torque condition. The licensee continued to evaluate the possible effects the over-torque condition had on the valve's disk.
Following completion of maintenance on the reactor protective system, the inspectors verified that this system had been returned to service properly.
No violations or deviations were identified in this area.
One unresolved item and one additional example of an unresolved item were identified.
6, Monthly Surveillance Observation (61726)
The inspectors observed technical specification (TS) required surveil-lance 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 components were accomplished, that test results conformed with TS and procedure requirements and were 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 portions of the following test activities:
l STP-41A006.2 - (Scram) Discharge Volume High Water Level Instrument functional Test / Calibration
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STP-42B027-CY - Safety Valve / Safety Relief Valve Position Indicator Relay Functional Test
STP-45A007
- Annual Core Spray System Simulated Automatic Actuation
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NSO40001
- Functional Test of Essential Bus Degraded Voltage l
Relays NS81001
- Refueling Platform Daily Inspection
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Test / Calibration On August 21, 1993, during the performance of procedure STP-41A006.2, "(Scram) Discharge Volume High Water Level
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Instrument Functional Test / Calibration," a half-scram signal on j
the "B-1" channel of the reactor protection system was received due to a personnel error. The reactor was d2 fueled at the time of the event, and no equipment actuated. as a result of the half-scram signal.
The test was stopped to determine the reat causes for the event.
The STP was successfully completed on August 22.
The licensee's initial investigation determined that section 7.1
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of the STP that tested half-scram channel "A-1" was completed, and no problems were identified. Next, the instrument and control (I&C) technician in the control room proceeded to section 7.2 of the STP to support the test of half-scram channel "A-2."
However, the I&C technician at the local instrument rack attached the calibration unit to level switch LS-18628 for half-scram channel
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"B-1" in accordance with section 7.3 of the STP.
The I&C technician at the local instrument rack continued with section 7.3, and a half-scram signal on the "B-1" channel of the reactor i
protection system was received.
It should be noted that the level
switches for half-scram channels "A-1" and "B-1" were both located on the same instrument rack (10122).
Since this personnel error occurred at the end of the inspection period, the review of the licensee's root cause evaluations, immediate corrective actions, and actions to prevent recurrence will be followed with the previous items identified in section 5
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above, as unresolved item 331/93010-03(DRP).
No violations or deviations were identified in this area.
One example of an unresolved item was identified.
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i 7.
Reaional Reouests (92701)
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a.
Information Notice 93-33 The resident inspectors reviewed the licensee's response to Information Notice (IN) 93-33, " Potential Deficiency of Certain Class IE Instrumentation and Control Cables."
The licensee's review of the IN found no immediate operability l
concerns.
Further evaluation of Firewall III cable and Okonite Okoprene cable would be required if plant life extension efforts were pursued. Maintenance action requests were also submitted to inspect and evaluate the installed condition of seals and other
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items. The licensee planned inspections during refueling outage 12 to further evaluate components potentially affected by IN 93-33 information.
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b.
Dron Oiler Reservoirs
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Based on previous industry problems with bearings lubricated by drop oiler reservoirs, Region III management requested the inspectors to assess operator's familiarity with the operation of drop oiler reservoirs. The inspectors interviewed auxiliary operators and second assistant operating engineers, and accompanied them in the plant to determine their understanding of
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oilers and oil sight glasses for rotating equipment.
The plant uses drop oiler reservoirs to maintain oil sump level in a variety
of safety-and nonsafety-related applications. The operators were
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well aware of the oiler function and the relationship between i
oiler level and oil sump level. The operators maintain reservoir oil level for nonsafety-related equipment in the visible range by verifying proper oil requirements, then filling the reservoir with that oil. A work request was written to fill the reservoirs on safety-related equipment.
No violations or deviations were identified in this area.
8.
Manaaement Meetinas (30702)
On July 26, 1993, Mr. Edward Greenman, Director, Division of Reactor Projects and the resident inspector met with Mr. John Franz,
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Vice President, Nuclear Division, and members of his staff to discuss outage safety, recent plant performance, and items of mutual interest.
I During the onsite meeting, Mr. Greenman toured the plant and gave an outage safety presentation to Duane Arnold Energy Center staff.
9.
Report Reviews (90713)
During the inspection period, the inspectors reviewed the licensee's monthly operating reports for June and July 1993. The inspectors j
confirmed that the information provided met the requirements of-1 TS 6. ll.l.C and Regulatory Guide 1.16.
No violations or deviations were identified in this area.
10.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations or deviations. Three unresolved items disclosed during the inspection are discussed in sections 3.c., 5, and 6.
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11.
Exit Interview (30703)
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The inspectors met with licensee representatives (denoted in section 1)
on August 23, 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
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inspection report with regard to documents or processes reviewed by the
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inspectors. The licensee did not identify any such documents or processes as proprietary. The licensee acknowledged the findings of the
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inspection.
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ENCLOSURE 2
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10 CFR 50.59 Inspection l
Licensee: Iowa Electric Light and Power Company IE Towers, P.O. Box 351 l
Cedar Rapids, IA 52406 i
t Facility Name: Duane Arnold Energy Center Inspection at:
Palo, Iowa I
Inspection Conducted: June 7 through June 11, 1993 Inspector:
R. Pulsifer, Licensing Project Manager,- NRR
Areas Inspected:
Routine, announced inspection to evaluate the licensee's
10 CFR 50.59 Safety Evaluation Program. (IP 37001)
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Results: No violations were. identified. An executive summary follows:
The licensee's 10 CFR 50.59 Safety Evaluation Program continued to be good.
The safety evaluations (SE) and' Safety Evaluation Applicability' Reviews (SEAR)
issued in the last 12 months were more comprehensive than those issued previously.
The quality of.the safety determinations was good.
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The training materials were good.
Each individual. preparing or verifying an
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SE or SEAR was given training, and their qualifications were maintained by the
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training department.
Several SEs, SEARS, and the applicable Duane Arnold Energy Center (DAEC)
procedures were reviewed and some inconsistencies were noted. The inconsistencies dealt with the definition of "SAR" (Safety Analysis Report)
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and " basis" of the Technical Specifications (TS) and conflicting requirements
between procedures.
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Details
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Persons Contacted
- W. Aldrich, Electrical Design Engineering Group Leader
- D. Barta, Nuclear Licensing Specialist
- P. Bessette, Supervisor, Regulatory Communications
- J. Bjorseth, Assistant Operations Supervisor
- D. Blair, Supervisor, Quality Assurance
- C. Bleau, Supervisor, Systems Engineering
- T. Browning, Sr. Principal Engineer-Licensing W. Clark, System Engineer-Mechanical
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D. Curtland,' Operations Shift Supervisor B
- M. Flasch, Manager-Engineering
- J. Franz, Vice President-Nuclear
- B. Hopkins, Principal Engineer, Mechanical Engineering
- M. Huting, Supervisor, Quality Control A. Kacere, Training Supervisor
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- J. Kinsey, Supervisor-Licensing l
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- J. Kozman, Supervising Engineer, Configuration Control
- D. Lausar, Supervisor-Project Engineering
- J. Loehrlein, Supervising Engineer-Professional Development and Assessment
- W. Lopkoff, Sr. Training Instructor
- K. Peveler, Manager Corporate Quality Assurance
- R. Potts, Supervisor-Plant Procedures
- K. Putnam, Supervisor, Technical Support
- D. Robinson, Nuclear Licensing Specialist
- A. Roderick, Supervisor, Testing and Surveillance
- N. Sikka, Supervising Engineer, Electrical Engineering
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- M. Stewart, Senior Principal Engineer, Mechanical Engineering
- S. Swails, Manager-Nuclear Training
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B. Taylor, Principal Engineer, Project Engineering
- G. Van Middlesworth, Assistant Superintendent-Operations and
Maintenance
- J. West, Sr. Training Instructor
- D. Wilson, Plant Superintendent-Nuclear
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- M. Wood, Group Leader, Project Engineering
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- K. Young, Manager-Nuclear Licensing U.S. Nuclear Regulatory Commission (US NRC)
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- C. Miller, Resident Inspector
- Denotes those present at the entrance meeting on June 7, 1993, and/or
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the exit meeting on June 11, 1993.
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2.
10 CFR 50.59 SAFETY EVALUATION PROGRAM IP 37001
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The inspector reviewed the licensee's 10 CFR 50.59 safety evaluation (SE) program including the SEAR determination process.
This evaluation i
included interviews with personnel involved with SE/ SEAR training and
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individuals qualified to prepare and verify SE/ SEARS.
Procedures and training material developed by the licensee were also reviewed.
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inspector reviewed change packages that involved just SEARS and packages that required SEs. An operations committee meeting was observed where an SE was reviewed by the committee. This inspection concentrated on 10 CFR 50.59 safety evaluations and applicability reviews written in 1992 and early 1993 with emphasis on SE assessments, SEAR reviews, and adequacy of procedures and the training program.
A list of documents reviewed is contained in the Attachment.
3.
10 CFR 50.59 Program
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The inspector found that the DAEC program for reviewing changes, tests,
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and experiments that were used in the performance of safety evaluations, for changes to the facility was good. The program for safety evaluations included consideration of licensing basis documentation such as the Final Safety Analysis Report (FSAR) and documents incorporated into the Updated FSAR (UFSAR) by reference.
It included safety evaluation reports (SER) such as the original SER with the operating license and SERs associated with license amendments or other docketed SERs. Other commitments on the docket were also considered.
The DAEC program does reference Nuclear Safety Analysis Center (NSAC)-125,
" Guideline for 10 CFR 50.59 Safety Evaluations." These NSAC guidelines had not been fully endorsed by the NRC staff.
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The DAEC program inchded Nuclear Generation Division procedure 103.3,
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" Safety Evaluation Process," which was used to describe the responsibilities, requirements, and instructions for performing 10 CFR 50.59 safety evaluations. The plant processes, including Plant Procedure Changes, Temporary Modifications (TMs), Plant Modification
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Process (PMP), and Design Document Changes (DDCs) required an SE if i
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directed by procedure 103.2, " Safety Evaluation Applicability Review Process." Changes controlled by the Design Change Process (DCP) and Conditional Releases (CR) for Operation required a Safety Evaluation.
The program also included procedure 103.2, " Safety Evaluation Applicability Review Process." This procedure was used by the licensee to determine if a 10 CFR 50.59 Safety Evaluation was required for plant
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procedures or hardware chanles.
The following items required this review:
1) Procedure changes 2) Temporary Modifications (TMs)
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Engineered Maintenance Actions (EMAs)
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Plant Modification Process (PMPs)
5) New and Revised Software 6) Conditional Releases (CRs)
7) Quality Deficiency Reports (QDRs)
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r 3.1 Procedure Inconsistencies
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Several areas of inconsistency, which are programmatic in nature, were
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found during this inspection.
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Procedure 103.2, Revision 2, stated for the SEAR process that the i
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Operations Committre reviews extended Temporary Modifications (TMs).
Procedure 1410.6, " Temporary Modification Control," eliminated i
extended TMs.in December 1992 in revision 2 of that document. The instructor guide and student guide for the Safety Evaluation Training course (60030) also addressed extended TMs. The inspector l
found that there was no formal process to assure that when one i
procedure was changed that all other affected procedures or training i
material would also be changed.
2)
Procedure 103.3, Revision 2, stated; "A written SE shall be prepared i
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for conditional releases for operation." Procedure 112.2, Revision
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2, " Conditional Releases," stated;
"A documented determination of the need to perform a safety analysis shall be performed in accordance with 103.2 to ensure there is no USQ."
Procedure 103.3
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required an SE be written while procedure 112.2 required a review be
performed to determine whether an SE was needed.
In May 1993, Procedure 112.2 and Quality Assurance Procedure (QAP) 112.2,
" Quality Assurance Approval of Conditional Releases," were revised to indicate that an SEAR was needed to determine the 10 CFR 50.59 applicability. As above, there was no formal. process to assure that i
when a procedure was revised, that any affected procedures would
also be reviewed for changes.
I Quality Deficiency Report (QDR)93-014 was initiated during this
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inspection period to change procedure 103.2 to reflect the requirements j
in procedure 112.2 and revision 7 of the Quality Assurance manual.
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QDR also recommended, "that the procedural change process be reviewed to assure an effective system is in place so that all affected procedures are also changed."
3.2 SE and SEAR Reviews
i Several SEs and SEARS were reviewed for DCPs, PMPs, EMAs, TMs, and CRs.
The inspector noted that the evaluations completed in 1993 were more comprehensive than the older SEs and SEARS. The quality was good and appropriate determinations were made.
Procedures 103.2 and 103.3 gave guidance in the SE and SEAR process by providing examples with sample ~
questions to investigate in order to reach a resolution.
For each of the seven questions developed to determine whether 10 CFR 50.59 applied, i
example inquiries were provided.
The inspector also noted throughout these SEs and SEARS that it was not clear to some preparers and verifiers what was meant by Safety Analysis Report (SAR) and basis.
10 CFR 50.59 addresses the Margin of Safety as defined in the " basis" of the TS.
Procedure 103.3 stated that the basis may be included in the SAR or in the " bases" of the TS.
Several of the
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SEs stated that the TS bases were reviewed while others referenced only the FSAR.
However, procedure 103.3 clearly stated that the SAR not only
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included the FSAR and/or UFSAR but also SEs for license amendments, the original SER for the license, documents incorporated in the UFSAR by reference, and other commitments on the docket. Therefore, procedure 103.3 made it clear what was meant by SAR and basis.
But the interchanging of the words FSAR and UFSAR for SAR and bases for basis
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inSEs and SEARS makes the evaluations appear incomplete. -The licensee stated that procedures will be revised to reflect the use of these documents.
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One temporary modification (TM) package included a SEAR (TM 93-042) that did not provide a description for the reason for a Yes or No answer to the questions required to determine whether_a safety evaluation was needed as required by procedure 103.2.
This discrepancy was also found in the recent DAEC TS required Offsite Safety Committee audit and a Quality Deficiency Report (QDR) was written to address this issue.
3.3 Trainina
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i The Safety Evaluation training course (60030) appears to be a good introductory course. The Instructor and Student Guides were satisfactory, and adequately covered procedures 103.2 and 103.3.
However, as mentioned earlier, they were not revised when the TM procedure was changed. This was a result of not having effective means to assure materials affected by a change were reviewed and changed where v
appropriate. The engineering department did provide extra training and
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a mentor to new engineering personnel to reinforce 10 CFR 50.59 training and provide counsel. Every individual involved in the preparation or verification of an SE or SEAR was required to go through training on the
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10 CFR 50.59 process. The training department had been tasked to
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maintain training records of qualified individuals.
There was no refresher training or continuing training for qualified preparers or verifiers. This periodic training might sharpen the skills
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of those who don't regularly get involved with this process as well as highlight concerns that had developed over this period.
The licensee committed to develop a refresher course.
3.4 Operations Committee Review The inspector observed an Operations Committee review for SE-93-17 for UFSAR change 93-13 and found that appropriate questions were raised. It was evident that each member had reviewed the SE before the meeting.
3.5 Temporary Modification Loa During the Safety Assessment and Quality Verification (SA/QV) inspection conducted in early May 1993, i question was raised as to why procedure 1410.6, Revision 1, was in the Operations Shift Supervisor's (OSS's)
Temporary Modification log when revision 2 was issued.
It was found that when revision 2 was issued, a memo was also issued which stated
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that all old TMs were " grandfathered" under the old revision and that
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revision 1 is to be placed in the log book.
Both revisions were in i
effect at the same time.
The memo was placed in the log book for
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information.
During this inspection, it was noted by the inspector that
revision 1 was missing. The licensee had not determined why it was missing, however revision 1 was placed back into the log book.
3.6 Conclusions The licensee had a comprehensive 10 CFR 50.59 process. The process identified the steps required and qualifications needed to implement the DAEC 50.59 program.
The inconsistencies between applicable procedures, the use of the words SAR and basis, and the apparent lack of a method to
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revise documentation that had been affected by a previous document change were considered a weakness.
The review of the noted
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documentation did show, however, that the DAEC program had improved and
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the inconsistencies were a lapse in an otherwise improving program.
4.
Exit Interview The NRC inspectors met with the licensee representatives on June 11,
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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.
Attachment:
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Documents Reviewed List
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ATTACHMENT l '.
DOCUMENTS REVIEWED LIST
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i Plant Modification Process (PMP)
PMP-39, Replace MSIV N-2 piping-PMP-73, SFR steam tunnel cooling PMP-74, EDG neutral grounding transformer PMP-75, Non-essential load center breaker
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l PMP-76, Zinc injection point extension PMP-76, Telephone switch installation l
Desian Chance Packaae (DCP)
DCP-1512, Scram relay replacement I
DCP-1523, RPS power supply upgrade DCP-1537, MO 1904/2004 time delay override
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DCP-1540, HPC1/RCIC door modification DCP-1542, SRV lifting lug Non-Conformance Report (NCR)
NCR 93-006, Limitorque teflon leads NCR 93-020, Uninterruptible instrument PCB capacitors l
Special Test Procedure (STP)
STP-174, Cardox demo test STP-184 and 185, RHR GL 89-10 valve testing l
STP-186, RCIC MO-2511 GL 89-10 valve testing L
l Safety Evaluation (SE)
l SE 93-17, UFSAR change 93-13: Containment gross and free volume Enaineered Maintenance Action (EMA)
EMA A11898G, Static Switch automatic setpoint and time constant change OSS Temporary Modification too Procedures 102.10, R1 & PCN A,B & C, Preparation, Review, and Processing of UFSAR Change Requests l
103.2 R0, R1 & PCN A & B, Safety Evaluation Applicability Review Process
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103.3 R0,1, & R2 & PCN A, Safety Evaluation Process l
106.3 R5 & Draft R6, Procedure Change, Revision and Cancellation -
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106.11, R2 & Draft R3, Review Record I
112.2, R0,1 & 2, Conditional Releases
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1112.2 R8, PCN A & B, Quality Assurance Approval of Conditional Releases 1203.60 R2 & PCN A, Plant Modification
1206.7 R2, Control of Design Document Changes (DDC)
1208.1 R3 & PCN A & B, Engineered Maintenance Action Support 1402.5 RO & PCN A, Operations Committee Review of 10 CFR 50.59 Safety Evaluations 1406.3 R9 & PCN A, B, C, D, & E, Revisions of Procedures and Instructions 1410.6 R2 & PCN A, B, C, & 0, Temporary Modification Control 1603.1 R1 & PCN B, Nuclear Licensing Department Safety Evaluation Reviews
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