IR 05000461/1993022
| ML20058M539 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 12/15/1993 |
| From: | Phil Brochman, Hague R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20058M527 | List: |
| References | |
| 50-461-93-22, NUDOCS 9312210022 | |
| Download: ML20058M539 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
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i Report No.
50-461/93022(DRP)
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Docket No.
50-461 License No. NPF-62 I
Licensee:
Illinois Power Company
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500 South 27th Street
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Decatur, IL 62525
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Facility Name:
Clinton Power Station Inspection At:
Clinton Site, Clinton, illinois
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Inspection Conducted: October 26 - November 27, 1993 i
Inspectors:
P. G. Brochman
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F. L. Brush
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R. B. Landsman
.l Approved By:
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A f f ' 'f 3 Itichard L. Hague, Chief Date
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Reactor Projects Section IC
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Inspection Summary
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Inspection froin October 26 throuah November 27. 1993. (Report No.
50-461/93022(DRP))
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Areas inspected:
Routine, unannounced safety inspection by the resident inspectors of licensee actions on operations, maintenance, engineering', and
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plant support.
-l Results: No violations or deviations were identified. One unresolved item i
was identified.
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9312210022 931215 PDR ADOCK 05000461 G
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I EXECUTIVE SUMMARY.
f Operations
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The plant was shut down for the fourth refueling outage for the entire
report period.
Maintenance l
An interruption of shutdown cooling for 36 minutes occurred due to
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personnel error during preparations 4r a surveillance.
Core i
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temperature rose 8 F.
I The alternate rod insertion system actuated when a technician drew an
arc while reinstalling a fuse during a surveillance.
No control rod
motion occurred. (IFI 461/93022-01(DRP))
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A reactor scram occurred during a surveillance due to personnel errors
by licensed operators. No control rod motion occurred.
(IFI 461/93022-
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02(DRP))
Enaineerina
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A jet pump hold down beam was replaced due to indications of possible I
cracking.
Licensee management was very proactive in following-up on
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industry events.
Good progress was made on testing motor operated valves, encompassed by
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the Generic Letter 89-10 program.
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Feedwater check valves were found not in conformance with their design l
requirements. (UNR 461/93022-03(DRP))
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A root cause for the failure of a main power transformer in 1992 could
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not be ascertained.
j Plant Support
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The results of the reactor recirculation and reactor water cleanup
pipings' chemical decontamination exceeded expectations, with an overall decontamination factor of 9.15.
Management's inspection of the drywell's cleanliness and readiness for i
final closecut was not as thorough as it could have been.
Several minor
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items were found by the inspectors.
Declines in plant housekeeping were noted by licensee management and the
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inspectors, during the course of the outage.
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DETAILS 1.
Persons Contacted Illinois Power Company (IP)
- J. Perry, Senior Vice Presideat
- J. Cook, Vice President and M& nager of Clinton Power Station (CPS)
- J. Miller, Manager - Nuclear Station Engineering Department (NSED)
- R. Wyatt, Manager - Quality Assurance
- D. Thompson, Manager - Training
- J. Palchak, Manager - Nuclear Planning and Support
- F. Spangenberg, III, Nuclear Strategic Change leader
- R. Phares, Director - Licensing L. Everman, Director - Radiation Protection P. Yocum, Director - Plant Operations W. Clark, Director - Plant Maintenance K. Moore, Director - Plant Technical j
- W. Bousquet, Director - Plant Support Services
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- C. Elsasser, Director - Planning & Scheduling I
R. Kerestes, Director - Nuclear Safety and Analysis
- D. Korneman, Director - Systems and Reliability, NSED
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- J. Langley, Director - Design and Analysis, NSED
- J. Sipek, Supervisor - Regulatory Interface The inspectors also contacted and interviewed other licensee and contractor personnel during the course of this inspection.
J Denotes those present during the exit interview on November 29, 1993.
- Denotes those present during the management meeting on October-29, 1993.
2.
Operations The unit was shutdown the entire period for its fourth refueling outage (RF-4).
a.
Enaineered Safety Feature Walkdown (712101 The inspectors performed a walkdown of the residual heat cemoval (RHR)
"A" system to verify its status.
The inspectors verified the following attributes during the inspection:
Valves, circuit breakers, and switches were in their correct
position, for existing plant conditions.
Valves did not have excessive packing leakage and local and
remote position indicators were in agreement.
Pipe hangers and supports were in their proper
configuration.
Installed instruments were functioning and calibration dates
were current.
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material condition.
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Operational Safety (71707)
The inspectors observed control room operation, reviewed
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applicable logs, and conducted discussions with control room i
operators. During these discussions and observations, the operators were alert, cognizant of plant conditions,. attentive to i
changes in those conditions, and took prompt action when appropriate.
The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified the proper return to service of affected components.
No violations or deviations were identified.
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Maintenance (61726 & 62703)
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a.
Interruotion of Shutdown Coolina (LER 461/93003)
On November 13, 1993, maintenance personnel were installing signal simulators on reactor protection system analog trip modules (ATM).
A personnel error by the maintenance technician resulted in-reactor vessel low level 3 signals on two channels.
This satisfied the coincidence logic and caused a shutdown cooling i
(SDC) isolation and a reactor scram.
The control rods were fully
inserted before this event and did not move. Control room cperators detected the loss of SDC in less than a minute and dispatched operators to vent and refill the RHR piping. The RHR J
system was filled and vented and the pumps restarted.
Reactor.
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coolant temperature rose 8 F, during the 36 minutes that SDC was unavail able, i
The simulator consisted of a variable resistor which was adjusted by a vernier type dial and was lockable. The technician had completed installation of the simulator on Division III.
He subsequently noticed what appeared to be a loose connector, which he attempted to tighten.
The licensee believed that either electrical contact was temporarily interrupted at the_ connector or the vernier adjustment was moved.
In either case, the ATM tripped. Since Division III was not selected, the LED' lights on the ATM did not illuminate to indicate a trin had occurred. When a different technician disconnected the P-2 connector on a Division II ATM, the logic was satisfied and caused the scram ano SDC isolation.
After SDC was lost, the control room crew reviewed heatup curves developed specifically for this outage.
Based on the time since reactor shutdown, the present core temperature, and reactor vessel water level, the crew concluded that boiling would not occur for
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at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. The crew had also reviewed the recovery actions for a loss of SDC before commencement of the simulator installation and consequently knew that-the temporary jumpers and simulators could be removed in less than 45 minutes. The crew's-other concern was Technical Specification 3.4.9.2.a, which would require that the operators demonstrate within I hour at least one alternate method of decay heat removal for each inoperable RHR
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shutdown cooling mode loop. The alternate means that was
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available was _ low pressure core spray (LPCS) injection from the.
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suppression pool with letdown via the safety relief valves.back to
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the suppression pool. As a precaution, the decision was made to j
refill and vent the RHR piping and then restart the nump.
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i The licensee's evaluation of this event was on going and the-
inspectors will perform further reviews after the LER is issued.
The inspectors identified some questions to licensee management relating to how fast the core heated up and what indications were available to the operators.
The licensee was evaluating the.
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physical condition of the simulators and verifying that the verniers' locks worked.
The policy on when to use the verniers'
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locks and where to set the simulators - relative to the ATM trip point - were under review.
The inspectors will perform further
review of the licensee's corrective actions after the LER is issued.
b.
Reactor Scram Due to Electrical Arc r
On November 17, 1993, licensee technicians were performing an ATWS' channel functional test (CPS Procedure 9434.03). When the
technician reinstalled fuse FR1, he drew an' arc and _ simultaneously
alternate rod insertion system (ARI) channel B actuated.
The ARI i
consists of backup solenoid valves which depressurize the scram air header and cause the scram pilot valves to reposition when
actuated. All of the control rods were fully inserted before the test. The reactor operators immediately recognized what had
happened and responded to the scram. There was no impact on the i
plant.
The inspectors will perform further review, after the licensee completes condition report 1-93-11-063. This action will be i
followed as inspection follow-up item (461/93022-Ol(DRP)).
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Reactor Scram Due to Personnel Error (61726)
J On November 19, 1993, a reactor operator (RO) and senior reactor l
(SRO) made a personnel error and deleted a step in a turbine first
stage channel functional surveilltnce which led to a reactor scram. A contributing cause to the scram was that the procedure j
' Anticipated Transient without SCRAM
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was.not user friendly, when performed in the present plant
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conditions.
The plant was in cold shutdown and all the' control
rods were fully inserted before this event.
The reactor operators immediately recognized what had happened and responded to the scram.
There was no impact upon the plant.
At'approximately 1:00 a.m. on November 19, 1993, the control room _
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SRO and R0 reviewed procedure CPS 9030.01, checklist 24, " Turbine
First Stage Pressure Channel Functional Checklist." They-determined that with the phnt in cold shutdown and the reactor ~
f recirculation pumps' breakers racked out, certain steps need not-l be performed. One of the deleted steps also reset the reactor
protection system (RPS) half-scram.
With this action omitted'and
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a second channel taken to the trip condition, the RPS logic was i
satisfied and a reactor scram occurred.
The test was satisfactorily reperformed. The licensee concluded that while the procedure was clear, it was less than user
friendly.
Step 8.1.35.b combined returning the RPT' bypass
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switches to normal with resetting the RPS system. This step also contained an independent verification.
However, the ability of
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the independent verifier to prevent a scram was also removed when i
the step was deleted.
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The licensee concluded that this event was not reportable under j
the requirements of 10 CFR 50.72 and 50.73 based on the fact that the safety function was already completed - since the _ control _ rods:
were already fully in the core - and the process parameter of a reactor trip caused by turbine trip above 40% reactor power was
invalid.
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o The inspectors reviewed the licensee's rational and agree with it.
The inspectors will perform further review after the corrective actions from condition report 1-93-11-064 are completed.
This action will be tracked as inspection follow-up item (461/93022-02(DRP)).
d.
Observations Of Work Activities The inspectors observed maintenance and surveillance activities of both safety-related and nonsafety-related systems and components listed below.
These activities were reviewed to ascertain that I
they were conducted in accordance with approved procedures, regulatory guides, industry codes or standards, and in conformance with technical specifications.
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' Recirculation Pump Trip
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Document Activity l
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D35179 1E51F063 - MOV
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D32243 lE51F063 - Packing
l D19319 1FW021 - MOV D25349 Div II Battery replacement No violations or deviations were identified.
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Enaineerina i
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Jet Pump Hold Down Beam Inspection
The licensee inspected all of the jet pump hold down beams (JPHDB)
i for indications of cracks. An indication of a cracked JPHDB was found on beam #7 and a loose' tack weld on beam #8's anti-rotation collar was also found. This action was in response to a JPHDB i
failure at the Grand Gulf nuclear power plant in September. The
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JPHDBs at Clinton and Grand Gulf were very similar; the same
material, heat treatment, and reduced preload. The preload on the-
JPHDB bolts was reduced in 1980 by GE SIL 330.'
Before the event at Grand Gulf, the licensee visually inspected t
1/3 of the beams every other refueling outage.
No inspections
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were scheduled for RF-4.
Based on the information from Grand
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Gulf, the licensee decided to perform a visual and ultrasonic inspection of all 20 JPHDBs.
Based on the inspection, beam'#7 was
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replaced with a new beam, utilizing the improved heat treatment, i
During power operation, jet pump operability will be checked
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daily.
General Electric intended to issue an additional SIL on
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this issue.
The licensee will perform further review of this
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issue after the SIL is issued.
Pending completion of the licensee's review, the inspectors have no further_ concerns.
The inspectors concluded that engineering management's inwolvement in this issue was excellent. The follow-up of industry events and
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the decision to perform a 100 percent inspection demonstrated good.
judgment.
b.
RF-4 Motor Operated Valve Work
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The schedule for motor operated valve (MOV) work during the fourth refueling outage was very aggressive.
A total of 93
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(safety-related and nonsafety-related) MOVs were completed. This
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included 67 static and 6 dynamic tests, modifications to
't actuators, valve replacements, and preventative maintenance. A management initiative to improve work performance involved forming teams consisting of maintenance, quality, and engineering
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personnel to work on the MOVs.
This contributed significantly to the successful completion of the scheduled work as well as addressing emergent issues.
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t There were 230 motor operated valves (MOVs) in the Generic Letter (GL) 89-10 program. Testing of 35 MOVs was _ completed before RF-4.
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During RF-4, a total of 44 GL 89-10 MOVs were worked, 4 of which
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were GL 89-10, Supplement 3 valves. There were 31 modifications installed and 38 static and 6 dynamic tests performed.
There were
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an additional 70 valves in the GL 89-10 program that will not be completed by June 1994.
In the near future, the licensee intends to submit an extension request to the NRC.
Utilizing the data from the completed individual plant examination
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(IPE), 50 valves were identified as being significant contributors
to core damage or containment release frequencies.
Twenty-six of-j these valves required a plant outage to perform the work. They i
were all completed during RF-4.
Thirteen valves were completed prior to RF-4 and the remaining 11 were scheduled to be finished by June 1994.
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The inspectors observed valve work, reviewed maintenance work
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packages, and interviewed personnel involved in the effort.
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t inspectors concluded that licensee's efforts should have a very positive effect on improving the reliability of these MOVs.
Based
on these reviews, the inspectors identified no concerns.
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c.
Desian Problem with Feedwater Check Valves The local leak rate tests (LLRT) on the feedwater outboard
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containment isolation valves (1FWF032A&B) identified. unacceptable
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leakage rates. The licensee's investigation determined that an
incorrect design on the air assist actuator caused the excess seat
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leakage. A contributing factor was the licensee's failure to understand the actuator's purpose. The actuator's function was to
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drive the valve disk-into the seat during a design basis loss of coolant accident when there is no feedwater. flow rather than
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assisting the disk into the flow stream and then letting the reverse flow close the valve. The installed configuration on both valves was incapable of providing a closing force on the disk to drive the disk firmly into its seat. A new problem identified in i
RF-4 was lateral movement of the disks due to the dynamic forces
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of feedwater flow. With the incorrect configuration, the force
necessary to move the disk sideways into its seat might not be present.
.i The actuators were redesigned and the valves stroked with the
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disks misaligned. The licensee exper N that the proper operation
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of the actuator or reverse flow will cause the valves to seat.
The LLRT was reperformed and leakage rates decreased.
Inspection of the valve seats had shown that they were in excellent
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condition. The inspectors will further review whether these i
valves were in conformance with their design requirements and if
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L problems with the FW32B actuator discovered in RF-3 should have
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resulted in identification of similar problems in FW32A.
This
review will be tracked as unresolved item (461/93022-03(DRP)).
e d.
Control of Scaffoldina
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During a review of site requirements for erecting scaffolding, the
inspector determined that the site was not adequately addressing
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seismic requirements for scaffWing in safety-related applications, i.e. adjacent or over operating or operable safety-related equipment. Although, from visual inspection and discussions with site personnel, the site had good general practices of erecting scaffolding; the process was not formalized in site procedures. The inspector noted that the licensee had-already started a project to provide improved scaffold erection procedures for safety considerations, i.e. OSHA' requirements.
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The licensee agreed to also address and incorporate general seismic concerns in its overall scaffolding process.
i Areas discussed with the licensee included:
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Providing scaffolding configurations and requirements that l
have been analyzed to withstand seismic loadings.
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Providing more guidance in procedures on what was required
to make scaffolding seismically qualified, e.g. diagonals, cross bracing, lashing, rigid standoffs.
A lack of formal training of personnel in seismic
requirements (both licensee and contractor personnel responsible for erecting scaffolding).
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Following scaffold erection, adding an inspection of the
scaffolding for structural (seismic) attributes and a
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signoff on the Completed Scaffold Tag.
The inspector noted that the licensee already had a good training program for licensee personnel in the OSHA considerations for j
scaffolding erection. The inspector discussed his concerns with
- i licensee management and based on the proposed actions has no further issues for follow-up.
e.
Evaluation of the Failure of B Main Power Transformer On January 4, 1992, the B phase main power _ transformer (MPT)
tripped due to an internal fault (Inspection Report 461/91026).
The MPT consists of three 345 kV to 22 kV single phase transformers. The transformer was shipped to the manufacture's facility in Texas for disassembly and inspection. The inspection indicated that the failure initiated in the inner high voltage winding and arced to the grounded center core.
The gasses produced by the arcing reduced the transformer oil's dielectric constant and the low voltage windings grounded.
Significant localized melting of copper windings and damage to the steel core
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i constant and the low' voltage windings grounded.. Significant
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localized melting'of copper windings and damage.to the steel core j
occurred. The transformer was repaired, returned to the station, and stored as a spare.
J The cause of the initiating.short could not be determined.
The
licensee concluded that this event was a random failure.
Consequently, no corrective actions to prevent this type of
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failure were defined. The licensee did identify several I
parameters which will be monitored as part of its equipment
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reliability program including:
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Increasing the oil sampling frequency.
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Performing double tests on each MPT transformer every other
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refueling outage.
Thoroughly cleaning all MPT fans and radiators each
refueling outage.
Based on a review of the licensee's actions the inspectors have no i
further concerns.
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Follow-uo of Previous Inspection Findinos i
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(Closed) Unresolved Item (461/93013-02(DRP)): Missing flood.
barrier in emergency service water (SX) pump room. On July 27, 1993, the inspectors identified that a hatch in the floor of the Division II SX pump room was not installed and this appeared to be a missing flood barrier. Two questions were identified: (1) Was the plant in conformance with its design basis, with the hatch removed? and (2) Did previous corrective actions fail?
With respect to question (1), the licensee analyzed flooding of the SX pump room from two aspects; (1) a design basis external flood and (2) a pipe break in the Division I SX piping in the SX pipe tunnel.
Modification A-073, issued in 1986, changed the
definition of what was a finad.arrier in the screen house. The exterior of the SX pipe tunnel and the exterior of the Division 11 SX pump room'were defined as flood barriers.
Since the hatch connects two flood-free zones, it was not a flood barrier.for a design basis flood.
Since the SX system was a moderate energy system, only
controlled cracking was postulated in the USAR'.
This was in conformance with NRC guidelines.
Consequently, the maximum postulated crack would be
'Clinton Updated Safety Analysis Report
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i equivalent to -a 2.8 in' hole. Thel flow rate through l
that hole would be 1174 gpm which would take 11.2 l
hours to. fill the SX pipe tunnel.
Since this area would be toured by auxiliary operators every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />,
the licensee believed that flooding, caused by a pipe
crack in the Division I SX piping, was not a credible-l threat against Division II. 'The licensee intended to
revise drawing M22-1001-00-BC to indicate the hatch l
was not a flood barrier.
With respect to question (2), in response to'a notice of
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violation in report 461/86048, the licensee revised the
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flood barrier design in modification A-073. This design
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change deleted the hatch as a flood barrier; however, i
drawing M22-1001-00-BC was not correctly updated.
Since the
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hatch was not needed after the design change, the corrective _
i actions for the 1986 violation were still effective.
Based on this review, the inspectors have no further l
questions.
This issue is considered closed.
i HPCS,n) Unresolved Item (461/93019-02(DRP)): Operability of
(2)
(Ope Injection Valve (lE22F004). Upon ' disassembly of the.
l M0V's actuator, it was. discovered that the motor pinion gear i
key was broken. This allowed the gear to rotate on the
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shaft.
The probable cause of the key failure was an over l
torquing of the valve during a MOVATS test in 1989.
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The licensee's analysis determined that the gear _ had rotated
on the shaft only once or twice before the key' pieces t
engaged each other and the set screw on the pinion gear
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reseated.
The analysis also stated that there was enough i
mechanical coupling, even with the broken key, for the valve
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to perform its safety function.
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During the IPE", the failure of HPCS injection valve was determined to have a more than minor impact on the core
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damage frequency (CDF). The base CDF was 6.73 x 10-' per
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reactor year.
If valve 1E22F004 was inoperable, and hence HPCS inoperable, the CDF increased to 2.50 x 10~'.
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licensee's analysis of the valve's operability is under
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review by the NRC, and this item will remain open.
t No violations or deviations were identified. One unresolved item was identified.
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" Individual Plant Examination
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Plant Supoort
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Source Term Reduction Activities
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The inspectors reviewed the status of the source term reduction
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(STR) program with the cognizant supervisor.
The STR program had
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To achieve dose rates of 300 mrem per hour on reactor
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recirculation piping by 1996.
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To achieve dose rates of 185 mrem per hour by RF-9 and i
without the aid of chemical decontamination by RF-8.
The major projects in the STR program were:
A partial chemical decontamination of reactor recirculation
(RR) and reactor water cleanup (RWCU) piping in RF-4
A full core off-load, chemical decon of the entire RR
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system, and replacement of control rod blade rollers and
pins made from stellite.
A condensate filtration system.
- Improved monitoring and trending of plant chemistry.
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Feedwater system oxygen injection to inhibit piping
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corrosion.
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Modification of steam plant lay-up methods.
- Using cobalt-free replacement parts.
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Changes to operating techniques, such as soft shutdowns and
improving RWCU system availability.
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By the end of RF-4, the licensee had installed an oxygen injection l
capability, modified steam plant lay-up methods and operating
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techniques, completed the design work for a condensate filtration
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system (scheduled to be installed beginning in March 1994), and
performed a partial chemical decon.
Replacement of control rod
blades and valves with cobalt-free components was only being done l
as those components wore out.
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The inspectors observed installation and operation of the chemical
decontamination equipment.
Two different processes were used. A i
LOMI' process was used on the RR and RWCU ring header piping. A
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CITR0X' process was used on the rest of the RWCU piping, pumps,
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and heat exchangers. The actual decontamination went very well though problems were encountered in running the decon hoses and t
connecting the equipment to the plant.
The results indicated that j
the licensee exceeded its goals for decontamination factors (DF).
The LOMI process achieved a DF of 5.8.
The CITROX process i
achieved a DF of 10.5.
The overall DF was 9.15.
Approximately 25 l
Curies of activity were removed from the plant.
In some areas '
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dose rate reductions were very good, changing from 100-200 mrem i
per hour to 2-12 mrem per hour. Overall, the licensee's efforts
have resulted in reductions in the source term.
Future actions
beyond installation of a condensate filtration capability will be
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reviewed as part of the ongoing STR program.
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Drywell closecut Inspection (71707)
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'On Novemoer 27, 1993, the inspector performed a closeout
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L inspection of the drywell with a licensee management a
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representative. The housekeeping conditions were mixed.
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Licensee management had previously comrieted its closecut.
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l-inspection and concluded that the drywell was satisfactory for power' operations. However, the inspector noted trash in the i
basement of the drywell, items such as plastic tie-wraps, pieces:
of tape, a maratuff, pieces of wire, metal shavings, and a broken
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light bulb. Most of this debris was behind or on top of the i
L drywell cooler units. Other pieces were in readily visible areas l
l near tra reactor water cleanup piping, which had high radiation ~
l fields and poor lighting, due to burned out light bulbs. Open or
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I easily accessible areas were quite clean.
J The middle, omni, and upper elevations of the drywell were very clean and only two small pieces of tape were found. The licensee
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immediately sent cleanup crews into the drywell to clean up j
required areas. Overall, the inspectors concluded that management
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involvement in ensuring drywell cleanliness was adequate.
Management has improved the cleanliness of accessible areas and j
needs to put additional attention on difficult to reach areas.
j b.
Housekeepina (71707)
Tours of the circulating water screen house.and auxiliary,
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containment, control, diesel, fuel handling, rad-waste, and
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turbine buildings were conducted to observe plant equipment -
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conditions, including potential fire hazards, fluid leaks,
excessive vibrations, housekeeping, cleanliness conditions, and to l
verify that maintenance requests had been initiated for equipment in need of maintenance. The inspectors verified implementation of radiation protection controls and physical security plan.
Housekeeping conditions declined over the course of RF-4.
Licensee management recognized this in the middle of the outage
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and initiated remedial actions. The licensee needs to evaluate its housekeeping policies to prevent the recurrence of conditions reached in RF-4 during future refueling outages.
,
Ho violations or deviations were identified.
6.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations. An unresolved item disclosed during the-inspection-is discussed in paragraph 4.c.
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.7.
Inspection Follow-up Items
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Inspection follow-up items are matters which have been discussed with
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the-licensee, will be reviewed further by the inspector, and involve
some action on the part'of the NRC or licensee or both. The two
Inspection follow-up items that are disclosed during this inspection
are discussed in Paragraphs 3.b and 3.c.
8.
Meetinal l
a.
Manaaement Meetina (30702)
On October 29, 1993, Mr. E. Greenman, Director, Division of
Reacter Projects, and members of his staff met at Clinton Station l
with Mr. J. Cook, Vice President and Plant Manager, and members of
.
his staff.
Other individuals in attendance are indicated in
[
paragraph 1.
Topics included:
Comparisons of cycle 3 to cycle 4
performance, an overview of RF-4 activities, and specific problems i
which occurred in RF-4.
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b.
Exit Interview j
The inspectors met with licensee representatives denoted in
.:
paragraph I at the conclusion of the inspection on i
November 29, 1993.
The inspectors summarized the purpose and
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scope of the inspection and the findings. The inspectors also
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discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify
any such documents or processes as proprietary.
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