ML17177A392
| ML17177A392 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 05/06/1992 |
| From: | Hsia A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17177A390 | List: |
| References | |
| 50-237-92-05, 50-237-92-5, 50-249-92-05, 50-249-92-5, NUDOCS 9205150075 | |
| Download: ML17177A392 (23) | |
See also: IR 05000237/1992005
Text
'.'
U; S; N.UCLEAR REGULATORY COMMISSION
REG ION I II
Report No~.
50~237/92005(DRP); 50-249/9?005(DR~)
Docket No.s.
50-237; 50-249.
License Nos.
DPR~2S
Licensee;
Commonweal.th Edison Company
Fac~lityName:. Dresden Nuclear PQwer St~tion, Units 2 and 3
Inspection At:
Dresden Site, .Morris, IL
Inspection Conducted~ March 3 through April
l~, 1992
.. Inspectors:* * . *
W. Rogel'.'S
M.
Peck
K. Shembarger *
D. Liao
A. Madi son
R. Zuffa; Site Resident Engineer
.
Illinois Department of Nuclear Safety" *
Ap-proved .'Bi:
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l.>"'::Z.,. ;/jj 1-:=:f ' , i ' '/,; .* 2- ---
A. H. Hsia/ Actihg Chief .
Project~ Secti6n 18
Inspection Summary
1,' ) /. -. '
c
"' 6 / 'i L. '
I
.
- Date *
Inspection from March 3 through Apr'il fQ,. 1992. (Report Nos. 50:-237 /92005CORP) ;"
.50-249/92005CDRP)).
. .
.*
....
Areas I~spected: .A routine unanno~nced safety inspection was conducted by the
resident inspectorsj and an Illinois Department of Nuclea~ Safety.ins~~ttor .
. lhe inspection reviewed licens~e action on previously ide~tified'.i~ems;
.
bpe~ational safety ind preparation for start up from refueling: Walk do~ns Of
. safety systems were performed and monthly maintenance. and surveillance
'-activities were *fol lowed~ Training effectiveness was evaluated, *as was
.
licensee handlirig of events. The licensee's saf~ty assessment and quality
. veiificati-0n capability was assessed and s~~eral ~anagemeht meetings were
held.
Re~ults: One vibl~tion with multiple*exa~ples of inadequate procedures or
inadequate implementatlon of procedures \\.{as i'1entified. Five unresolved
items~ -0he with multi~le examples~ and one open item was
identified~*
Plant Operations Control room operators were professional.
They were
.
knowledge~ble of annunciator alarms .. Reactor oper~tor log quality continues
to imp-rove .. Some fostances of-'inattentiori were-noted-~outside the control room
and some Technical Spec ifi cation kn owl edge defi ci enci es w_ere *noted.
Operator
identification and resolution of housekeeping deficiencies were not evident
except in the Unit 3 drywell where it was good.
Weaknesse~ were observ~d in
9205150075 920506
ADOCK 05000237
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operator knowledge of administrative controls.*
- Maintenance/Surveillance Maintenance activities appeared to be well performed
except for coordination.and completion of wcirk on the 2/3 di~sel fire pump.
Surveil 1 ance procedure content was a weakness .as was . imp 1 ementat ion of
surveillanc* procedures.
Emergencv Preparedness
Proper activation of the emergency plan was observed.
Safety Assessment and Quality Verification
There was limited mid-level
management presence in the power block. Safety evaluations for temporary
alterations were viewed as a weakness.
Engineering and Technical Support *Significant weaknesses in design basis
information and personnel's grasp of the information were evident.
The
- weaknesses in the design basis information hampered operational dechions and
cost many hours of the licensee staff's time.
-
2
DETAILS
1..
Persons Contacted
Commonwealth Edison C6mpany *
- C. Schroeder, Station.Manager
- L. Gerner~ Technical Superintend~nt
- J. Kotowski, Production Superintendent
D. Van Pelt~ Assistant Superintendent - Miintenance
J. Achterberg, Assist ant Superintendent - *Work Ptanni ng .
G. Smith, Assi.stant Superintendent-Operations
- R. Radtke, Regulatory Assurance Supervisor
M. Korchynsky, Operating Engineer
1. Mohr, Operati~g Engineer *
- M. Strait, Techhical Staff Supervisor
- D. Ambler, Radiatioh* Protection Manager
- K. Kociuba, Quality Assurance Superintendent
- D. Karjala, Performance Improvement Director
- Denotes.those attending-the exit inter~iew conducted on April 10, 1992:
The inspectors also talked with and intervi~wed several other licensee
employees, including ~embers of the te~hnical and engineering staff;
- reactor and auxiliary operators; shift engineers .and .foremen;
elettrical, mechanical, and instrument maintenance petsonnel; and.**
- contr~ct security personnel~
- 2.
. Previously Identified Insp~ction Items {92701. and 92702)
a.
(Closed) Violations (50/237/90023-0la and b(DRP))~ Lack of*
. operations personnel knowledge of Dresden Administrative Procedure
.
(OAP) 7-5, Rev. 8, and Dresden Operating Abnormal (DOA) Procedure ..
902-S G-2, Rev. 3, and lack of technical staff personnel knowledge
regarding recognizing and processing conditions adverse to
qua l it,Y ._
Although this violation i~ considered closed, the corrective
actions to it appeared to have been inadequately implemented
resulting in repetition of similar events, as described iri
sections 2c(l) and 7c(l). The cause for the inadequate corrective
actions is under further review, and is being tracked as an
Unresolved Item (237/92005~0l(DRP)).
b.
(Open) Unresolved Item (50-237/91016-04(DRS)):
Em~rgenty diesel
generators (EDGs) breaker logic design cbnsisterit with existing
regulations.
The ltcensee routinely tests the EDGs loaded and
paralleled to the grid which renders the load shedding feature
nonfunctional. Should a loss of coolant accident coincident with
a loss of offsite power occur during t~e testing,_ rior!ll.aL " .
.
protective features*-would autonratfrallY be -bypas.sed, and the EOG
3
would be overloaded.
Under a*technical assistance request the
Office of Nuclear Reactor Regulation (NRR) reviewed this
situation.
NRR verbally provided the licensee and the inspe*ctors
- with the following.initial conclusions: 1) An EOG is not capable
. of performing its intended function when .being tested in the
licensee's normal manner;
2) The .Technical Specification
requirement t~ demonstrate operabiliti of other EDGs when an IOG
is inoperable can be accomplished without performing a full load
- test.
This matter rema-ins open pending written confirmation of the NRC
position, re~ponse from the licensee as to their position, and NRC
review of that response.
c.
(Closed) Unresolved Item (237/92002-04(DRP)):
containment isolation valve during VOTES testing~ While
performing VOTES testing on dayshift for Unit.3 isolation
~ondenser valve 1301-1 the operator de-en~rgized open the
isolation condenser valve 1301-1 on Unit 2, rendering it -
inoperable as a containment isolation valve.
Unit 2 was
operating at the time with containment integrity required.
An
oncoming swing shift senior licensed operator identified the
situation and power was immediately restored to the.valve.
.
.
.
.
.
.
.
.
During the-review of the situation the in~pector ascertained:
(1)
(2)
(_3)
Operators were _not cognizant of the administrative controls
associated with routine test activities as -discussed* in .
. OAP 7-32 "Routine Plant Testin~ Activities~. This lack of
knowledge of administrative. controls will be reviewed as
another e~ample of unresolved it~m (237/92005-0l(ORP)), *
inadequate corrective action to violatio~ 237/90023-01. *
.
.
.
.
.
Locks were placed on the electrical breakers although np
equipment control program specified or directed their
installation. Plant staff occasionally placed locks on
electrical equipment for personnel protection;* These locks
are not part of th* equipment out-bf-service system, and are
not acknowledged to exi s.t by management. * No procedure
exists to direct the placement and use of the locks. This
is contrary to the requirements of 10 CFR Part50, Appendix
B, Criterion V and is considered one example of a violation
against that criterion (237/92005-02a(DRP)).
OAP 7-32 did not require specific measures to identify the
valve in test.
10 CFR Part 50, Appendix B, Criterion XIV,
- inspection, Test, and Operating Status," requires in part
that measures be ~stablfshed to indicate the status ~f
testing performed upon individual items of the nuclear power
plant ... This is an example of a violation (237/92005-
02b(DRP)) of 10 CFR Part 50, Appendix B, Criterion V,
"Instructions, -Procedure*s, *and- Drawings," *in that the
4
procedure did not ade~uately prescrib~ activities affecting
quality .. Also, the applicable section of the CECo Quality *
Assur*nce*Manual doe~ not discus~ the application of OAP
7-32 for test control.
Two examples of a violation were identified in this area. Additionally, .
one unresolved item wtth .two examples was discussed,
3.
Operational Safety Verifi~ation (71707 & 717ldl
.
.
.
The inspectors reviewed the facility for conformance with the license
- and with regulatory requirements.
- a.
On a sampling basis the inspectors observed control room
activities* for proper control room staffing and c*oordination of
plant activities.
Operato~ adherence to procedures or Techni~al
Specifications and operator cognizance of plant param*eters and.
alarms was observed.
Electrical ~ower configuration was
.
confirmed and the frequency of plant and control room.visits by
station managers was reviewed.
Various logs and surveillance~
records were reviewed for accuracy and completeness .
. The inspectors noted that the quality of control room operator log
entries tontinued to improve.
The logs were generally ~dequate as
to the content of the entries.
b.
On a routine basi~ the inspectors t9ured accessible areas of the
facility to assess worker adherence to radiation controls and the
.site security.plan, hoOsekeeping or cleanliness, and control of
field activities in progress.
Significant observations were:
The ~~it 3 drywell was exceptionally .clean prior to and at
the time of the drywell close out inspection.*
. '
-Housekeeping in the Unit 2/3 crib house, auxiliary
electrical room. and the 4160 VAC ESF Bus 23 and 24 room was
poor.
Following maintenanc~ of the 2/j diesel fire pump, trash was
left in the area, oil was spilled on the floor, and several
drop lights were strung about.
c.
Walkdowns of *select engineered safety feature~ (ESF) were
performed.
The ESFs were reviewed for proper .valve* and electrical
ali~nments. Components were inspected for leakage, lubrication,
abnormal corrosion, ventilation and cooling water ~upply
availability. Tagouts and jumper records wer~ reviewed for
accuracy where appropriate.
The ESFs reviewed were:
5
Unit 2
Unit 2/3 Standby Gas Treatment System
. *
- Unit 2/3 Diesel Generator
Unit 3
All Main Steam Isolation Valves
Unit 3 Diesel Generator
No violations or deviations ~ere identified in this area.
4.
Preparation for Start Up from Refuel i nq
In preparation for Unit 3 startup *from a scheduled refueling ~utag~, the
inspectors performed a number of administrative control ~dequacy reviews
and physical walkdowns of safety systems for material condition
discrep~ncies and proper valve, switch, and electfic~l alignments.
a.
Admini~ir~tive ~ontrols reviewed were the out-of-servic~ (OOS)
equipment controls, high radiation door access, temporary
alteration implementation, locked cabinets containing necessary
tools for implementation of the emergency dperating or safe
.
- shutdo~n procedures (EOP/SS) and the su~veillance tracking system .
. * Reslil ts were:
- (1) * Out-of-service (OOS) - The program was acceptable.
However,
some OOS tags had been in place for* an excessive period of
.time.
An example was the OOS tag on MOV 2/3-4101, fire pump
discharge valve.
This valve h~d been out~of-service for
approximately 12 ye~rs following the Three Mile Island
(2)
- Action Pl an.
Another example was the OOS tag on the St'andby
Gas.Treatment damper, 7503.
This damper had been
deenergized to preclude a single failure concern.
Use of
..
the out-of-service system as a de facto minor modification
- is considered a weakness in the program .arid i~ an open item.*
(237/92005-03(DRP)) to.follow licensee corrective actions.
High Radiation Door Access - All high radiation doors were.
locked; Two-locations of minor concern were identified:
(1) The fuel pool ~ooling (FPC) area, a high radiation area,
could be reached from the fourth floor via a ladder.* _Access
to the ladder was restricted by a cage which surrounded
. part of the ladder; 'however the cage "was not 1 ong enough to
prevent personnel from using the ladder.
(2)
A fence on
the turbine shield wall west side did nbt have a Tock.
Othef similar fences were secured with chains and locks.
These inspection findings were brought to the licensee's
.*attention. Preliminary corrective actions were in progress .
. (3)
Temporary Alterations (T/A) -
Five T/As were targeted to be
6
(4)
(5)
in place for startup. One dealt with installation of
diagnostic equipment on the isolation condenser.
When the
instrumentation was installed, personnel failed to update*
- critical drawing, M-359, wit~in a day of installation as
. required by the T/A procedure, DAP-07-04, *control of
Temporary System Alteratio*n,* step F.l.f(S) .. Failure to
acc6mplish this task as prescribed in the procedure is
considered another example of a 10 CFR Part so, Appendix 8,
Criterion V violation (237/92005-02c(DRP)) *
. EOP/SS Cabinets - All. equipment necessary to perform the
. EOP/SS functions was present in the audited cabin~ts.
Surveillance Tracking System ~ No discrepancies or overdue
surveillances were identified.
b.
- System walkdowns were performed on the following systems:
- * **
- *
- * *
Low Pr~ssure Coolant lnje~tion System
Standby Liquid Control System (SBLC)
Core Spray System
Standby Gas Treatment System* (SGTS) .
One bank of Hydraulic Control Units
- Control Rod Drive System
.containment Cooling Service Water (CCSW) System
Emergency Diesel Generator Cooling Water System
.
Emergency Diesel .Generator Air Start System (Unit 3 .and ,2/3)
.Fire Protection System
Significant observations were:
(1)
On April 1, 1992, the SBLC storage tank air sp~rge in)et
valve 3-1101-36, was found open and unlocked .. The system
valve lineup checklist ;n*oop 0040-M4 required the valve to
- be locked closed and independently verified in that *
position~
The valve was manipulated *on March 20, 1992, to facilitate a
SBLC storage t~nk.air sparging prior to sodium pentaborate
sampling.
OAP 7-14, ~Control and Criteria for Locked
Equipment and Valves", required eit~er an approved procedure
or outage checklist be used to unlock lnd reposition a
locked valve. If a valve was unlocked without a
corresponding procedure' or outage checklist, an operator *was
required to be in continuous attendance~ Final valve
- position was required to be in accordance with the equipment
checklist, independently verified by two individuals, and*
documented in the unit log book.
The. ai-r sparging * ev.olution
was performed without an approved procedure or outage
checklist. Additionally, the locked v~lve was repositioned
without an operato*r in continuous attendance. This
7
personnel failure to understand and execute administrative
requirements is another example of the unresolved item
mentioned in section 2.a (249/92005-0l(DRP)).
(2)
On April* 1, 1992, a wal.kdown of the Unit 2 and Unit 3 SBLC
. * systems was performed.
DOP 0040-M4 required .the f o 11 owing
- valve~ to*be locked in the correct position~
(3)
(4)
(5)
. *
2A-1150, pressure indic~ting root valve
- *
3A-1150, SBLC pump discharge root valve
30..:1150, SBLC pump discharge indicating backfill valve.
The valves were in the correct position with a locked chain ,
draped over the operator. However, the chain did not
restrict operator movement.
OAP 7-27 *independent
.
Verific~tions" states:
"Th~ last.per~on to check a lricked *
valve will also ensure the locking devi~e is installed .
- properly (i.e. the ch~in will not fall off}.
I~ is not the
intent of a locking ~evice to pr~vent movement of a valve
but to serve as a flag to indicate that before this valve is*
manipulated certain precautions or actions may be required".
The practice of draping a lock and chain across a _valve
instead 6f physically securing to prevent movement is
conside*red a weakness in the.conduct of operations.
CCSW pumps A & D leaked.exces~ively thrbugh the packing and
. work request tags identifying the condition were present. ..
The most current ASME inservice tests Qn the pumps met *
required* ~ressures and flows with the A pump in the "Alert~
region.
At the end of the inspection peiiod, Technical
Staff persohnel were determining the priority of a m~nor
modification for installing new CCSW pump shafts.
A minor drawing discrepancy .was identified by the inspectors *
on the Piping and Instrumentation Oiagram (P&ID} for the
.
Standby Gas Treatment System dealingwith the location of a
- lotal temperature indicator on each train. Once identified
to the 1 i censee, a P&ID change request was submitted.
Several di~trepancies ~ere noted between the a~tual fire
protection system and the associated P&ID.
Also
- discrepancies were noted between Dresden Fire Protection
Procedure (DFPP} 4120-Ml, the system's proper alignment -
checklist,- and equipment nameplates.
The discrepancies were
due to a modification to the fir~ protection system to
support the new ~dministrative and service building *
additions.
The fire protection system loop modification was completed
during November/December 1991.
Retagging of the ~qujpme~t
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=-
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--
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- -
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was in progress. The licensee had walked down the*fire
protection system during February and March 1992 and
submitted a P&ID change request.
The discrepancies were
- discussed with the licensee and the correct system lineup
was verified by the inspector and Assistant Fire Marshall.
After the P&ID is changed, the DFPP will be revised and
updated to reflect the modifications.
O~e example of a violation was identified in this area.
One exa~pje of
a previously mentioned unresolved item and one open item are 'discussed
in this section.
5.
Engineered.Safety Feature System Walkdown C71710)
A detailed walkdown of the accessible portions of the Unit 3 Isolation
Condenser System was performed to verify systeni operability. The
lso.lation Condenser i.s relied upon.during implementation of the Dresden*
Emergency Operating Procedures (DEOPs), and is the primary method.of
. *decay heat remo.va 1 in the Dresden Safe Shutdown Procedures (DSSPs).
a..
While reviewing documentation associated with the 'makeup water.
supplies to the isolation condenser, the inspector identified
several issues and discussed them with the licensee. These issues
- .. are unresolved (237/92005~04(DRP)) pending ftirther licensee
evaluation of these concerns and additional NRC review.
.
.
lhe*original fire suppression system hydraulic verification
study performed for the Dresden Station ~ay not have been
based on the most bounding condition.
- *
The DSSPs do not direct operators to .open the crosstie valve
between the IA condensate storage tank (CST) and the 2/3 CST
although the lA.tST water volume is used t6 ensure minimum
safe shutdown water volume availability.
.
.
Discrepancies appear to exist between DSSPs, the Safety
. Evaluation Report (SER) and the Fire Hazard Analysi~ as to
th~ intended isolation condenser makeup sources.
Discrepancies in the hydraulic verification study and the
DSSP requirements for use of water sources challenge the
ability of the Fire Protection System to support both makeup
to the isolation condensers and*suppress a fire.
. .
.
.
-
Attachments to DSSP 100-CR "Control.Room Evacuation/ Safe
Shutdo~n" did not contain some.local operator actions tha~
were specified in the body of the proced.ure.
Additional confirmation of the actual CST useable water
volume was necessary, including confirmation of the accuracy
of the level instrumentation and its presence._i~- a
9
- ,,
.,
calibration program.
When DSSPs were .revised in April, 1988, the 10 CFR 50.59
~afety evaluations failed to consider the ~ostulated 10 CFR
Part 50, Appendix R, fire scenarios. as part of the facility
design basi~.
b.
During a physical walkdown of the isolation condenser system,
valves 3-1301-32 and 3-1301-19 were found to be ciosed as
required, but the chains and locks associated with the valves
allowed the valves to be opened without removing the locks. Thi~
finding" was consistent with those presented in sectjon 4.b.2.
After identification.to station personnel, both valves were
adequately locked.
c.
Minor drawing discrepancies*were identified and brought to the
attention of station personnel for resolution including:
Hanger # M-1199D-262 on drawing ISI-206 appeared to be"""'
reversed with its. adjacent snubber ..
Valve 3-1301-10 was identified as being powered from
emergency AC power instead of DC power on drawing M-359.
The primary makeup supply (clean demjneralized water)
connection to the isolation condenser system ~as not
identified on drawing M-359.
- *
d.
bop J300~M1/El "Unit 3 Isolaiion Condenser~ step 39 required valve
- 3-1301~603 to be closed and step 50 required valve 3-4107-50~ to
be open. During performance of the DOP on February 24, 1992, the
checklist performer and idehtifier indicated on the checklist that
the valves were actually locked in their designated positions.
No
documentation to correct the ~hecklist was identified.
The
inspector verifi_ed that both valves were locked in the identifi.ed
positions. These dis~repancies were i~entified to station.
personnel for review and ~esolution.
No violations Or deviations were identified.
One ~nresolved item was
discussed.
6.
Monthly Maintenance Observation (62703~ *
=St~tion maintenance activities affecting the safety-felated arid
- important to safety systems and components listed below were observed
and-reviewed to ascertain th~t they were conducted in accordance with
approved procedures, regulatory guides and industry codes or standards,
and did not cOnfl ict with Techn*ical Specifications.
The following item~ were considered during this review: . ~pprovals were
- obtained prior to initiating the work; functional testing or
10
- * *
.
.
calibrations were performed prior to returning components or systems to
service; quality control records were maintained; activities were
accomplished by qualified personnel; parts and materials used were
properly certified; radiological controls were implemented; and fire
prevention controls were implemented. . *
- The following maintenance activities were observed and reviewed:
Unit 2
Unit 2/38 Standby Gas Treatment charcoal * filter replacement &
repairs
..
Unit 2/3 Diesel Generator rotor p9le bolt re-torque/replacement
Unit 2/3 Diesel Fire Pump repair
lJnH 3
- * **
- *
- * *
- ** * * *
Traversing incore.probe amplifier power supply*repair
Control rod drives P-7 and E-3 replacement
High Pressure Coolant Injection (HPCI) full flow test throttle
valve, 2301-10, replacement
- Core Spray injection valve, 1402-248,'repacking
- 8 Feedwater line containment penetr.ation (X-1078) replacement
Main Steam line penetration (X-1058) bellows repair
.. ,
Emergency Diesel Generator rotor pole bolt re-torque/replacement
West bank scram discharge volume vent isolation valve rebuild .
Reactor building v~ntilation damper air lines seismic support .
installation .
.
- .Stator cooling panel modificati~n
.
Safety relief valves acoustic ~onitor installation
HPCI turning gear motor limit adjustments
.
- EHC and Main Stop.valve pre-operational line up work
.
.
.
Inboard and outboard Main Steam Isolation Valves (MSIV) pilots and *
cylinder operator replacement or repair.*
Electrical penetration (X-202S) repair
Annunciator fuse block replacement
Significant ob~ervations were:
a.
The inspector observed. overall good convnunications between working
individuals with an improved attitude toward procedure usage and
b.
work package guidelines.
During MSIV maintenance activities on March 17, 1992, the
inspector observed *a missing pilot valve terminal junction box .
supporting bracket on the 3~2038 MSIV.
The inspector located the
bracket lying on the structural support ste~l directly above the
valve.
The support bracket's function appears to prevent the
terminal box from pivoting and inducing moment forces .at the pilot
solenoid connection.
The inspector determined from a review of
the valve maintenance history that the latest maintenance acti~i!.Y ..
11
. *-
on the valve operator assembly was perfonned on February 10, 1990.
The support bracket for the other MSIVs was intact. *This matter
is.unresolved (249/92002-0S(DRP)) pending further inspector review
_as to whether the support bracket was essential to the integrity
of the MSIV valve operator.
. .
.
.
.
.
c.
At 1534 on February 28, 1992, the 2/3 Diesel.Ffre Pump *was taken .
out of service for gasket replacement to repair an oil leak.
Removing the 2/3 diesel fire pump from service resulted in entry
into Dresden Administrative Technical Requirement (DATR) limiting
Condition for Operation (LCO) action statement 3.1.2.1.a, which
required the fire pump be rest-0red to _operable status within 7*
days or a deviation report prepared.
On March 6, 1992, at 2030,.
the 2/3 Diesel fire Pump was returned to service, and a deviation
. report was prepared s i nee the *se.ven-day LCO was exceeded. The
deviati.on report did a time study analysis *of the event. *
The inspectors and the licensee agreed on the following sequence
of events:
The diesel fire pump was removed from service two shifts*
priQr to the_start of maintenance activities .. *
Maintenance activities were halted for five shifts due to *
- management request.
.
.
The original replacement gaskets to stop the oil leak.were
th_e wrong material. The work analyst had improperly
classified the gaskets as non-safety related instead of
regulatory re 1 ated. * Therefore, receipt inspection was
minimal and didn't identify the material discrepancy.
It took two *days for the purchase order for the right .
- gaskets to be prepared and issued to the vendor .
Th~ parts were delivered to ~he station two shifts prior t6
di scoverY that they were on s*i te.
Due to a part number discrepancy, there was a one hour delay
during the receipt ~nspection.
The licensee attributed the root cause of exceeding the_L~O to an
expansion of work scope during the fire pump repair. The
inspectors, on the other hand, attributed the root ca~se to the *
six delays discussed above;
The licensee's corrective action was
to discuss the event with personnel to heighten their*awareness. *
The inspectors considered these corrective actions minimal.
d.
While witnessing annunciator troubleshooting and ~ubsequent fuse
block replacement, inspectors observed:
12
A fine layer of dust was on all the control annunciator
circuit boards.
- An operating standard .commercial drinking fountain was** *
located in the auxiliary electriC:al equipment.room,.which
contains numerous safety related equipment.
.
.
. .
.
Extremely large gauge wire was used for the negativ~ circuit
which may have contiibuted to the loss of ~ll control room
annunciators on Alert of April 4, 1992.
.
. ..
In response to these observations, the licensee vacuumed the
cabinets and was trying to determine whether a periodic
preventative maintenance cleaning was appropriate and, unplugged
.the drinking fountain and tagged it out of service. With regard
to the large gauge wire .the licensee stated they kne~ this and an
- annunciator circuit modification was being contemplated.
No violations or d~viations were identified.
One Unresolved item was .
discussed.
7.
Monthly Su~v~illance Obs~rvation (617~6)
Surveillance testing required by Technical Specifications, the Safety*
Analysis Report, maintenance activities or modification activities w.ere
observed or reviewed.
Areas of consi-deration while performing
.
obsefvations were procedure adherence, calibration.of test equtpment,
identification of test deficiencies, and personnel qualification. Areai *
of considerati6n while reviewing surveillance records were completeness,
pro~er a~thorization and review signatu~es, test results properly*
. dispositioned, and independent verification documented~ *The following
activities were obser~ed or ~eviewed~
Unit
- *
Unit
- * * * * * * * *
2
3
DIS. ~00-2
Control Rod Dri.ve Accumulator Pressure Switch *
Calibration
DIP 700-ll Calibration of the TIP.
DIS 2301-:-03 HPCI High Flow Isolation Calibration
DTS-1600-01 LLRT of Primary Containment Isolation Valves
DTS 1600-04 Local Leak Rate Testing of Elettrical Penetraticins
DTS 7500-07 Standby Gas Treatment System Charcoal Leak test
DTS 7500-11 DOP Testing of 2/3 *SBGT HEPA Filters
1400~01 Core Spray System Pump Test *
DOS 1400-02 Core S~ray System Val~e Operability Check
DOS 1400-05 Quarterly Core Spray System Pump Test
DO~ 1500-06 LPCI System Valve Operabil1ty Ch~ck
DOS 1500-02 .Containment Cooling Service Water Pump Test
13
.
. ' :*
DOS 1500-10 Quarterly LPCI System Pump Test
DOS 6600~03 Bus Undervoltage and ECCS Integrated .Functional Test
for Unit 2/3 Diesel Generator
DOS 6600-04 Bus Undervoltage and ECCS Integrated Functional Test
for Unit 3 Diesel Generator .
- SP 92-3-57 Bus Undervoltage*and ECCS Integrated Functional Test
for Unit 2/3 Diesel Generator
.
DIS. 600-2
Narrow Range Reactor Pressure Calibration
DIS 600-3
Reactor-Vessel Narro~ Range Level _
.
DIS 1400-06 Core Spray Flow Transmitter FT 1461A(B) Calibration
and Maintenance Inspection
DIS 1400-07 Core Spray Pump Minimum Flow Valve Analog Trip Unit
Calibration
DIS 1400-01 Core Spray Header Differential Pressure
Instrumentation Calibration
DIS 1500-19.LPCI System Pressure Transmitters and IST Pump Suction
- Discharge .Pressure Indicators. Ca 1 i brat ion
- .
DMP ll00-1 * Standby Liquid Control Squib Valve Inspection
Sighificant observations ~~re:*
a.
Drywell Air Sample
On March 8, 199~, station personnel did ~ot complete the Unit 2
Reactor Coolant System (RCS) leakage T/S Surveillance (4.6.d)
within its normal time interv~l. The previous s~rveillance was
- completed at 11:45 A.H. on Ma~ch 7, 1992.
The next surveillance
was not completed until 4:13 A.H. on March 9, 1992 .
. Technical Specifi~atio~ surveillance requirement 4.6.d delineates
t_hat. a drywell air sample will be taken daily and analyzed to
determine whether the reactor coolant leakage is within acceptable*
limits.
- A series of events contributed .to the missed surveillance when at *
- 9:20 a.m. on the 8th, the health physics (HP) technician retrieved
the* drywell air samples from the continuous air monitor (CAM) and *
determin*ed the sample was invalid since .the CAM was not runnin*g~ *
A second sample .was taken from an alternate. sample point and ..
delivered to Chemistry Department.
At 2:51 .P.H. the chemist
completed the sample count but failed to communicate the results
- to the control room.
At 11:00 P.M. the d~parting SCRE reviewed .
and initialed Appendix A, Unit Operator~ Daily Surveillance Log,
indicating that all of the shift operational ~urveillan~es were
successfully completed.
However, the block for T/S 4.6.d was left
blank.
The SCRE and the reactor operator recognized the drywe11*
. air sample results were not completed.
However, they failed t~
recqgnize the sample analysis was required to meet the RCS .leakage
surveillance. The operations personnel incorrectly beli~ved the
samples were only needed for the drywell venting procedure .. At
4:13 A.H. on March 9th the reactor operator decided to vent the
~ . *- -
.. :: -
14
Unit 2 drywell .. This decision prompted the Chemistry* Department
to ~ommunicate the sampl~ results to the reactor operator.and the
appropriate log entries were made.
The midnight operations crew
also failed to recognize the sample analysis was required to meet
the RCS leakage T /S requirement.
From this chronology*and a*review of the surveillance procedure
the inspector determined:
(1)
(2)
The RCS l~akage surveillance procedure; part of the Unit
Oper~tors Daily Survei.llance Log (Appendix A), nomenclat4re
was inconsistent with T/S 4.6.d.
The procedure step was
labeled"Drywell CAM Filter Readings, 6-hour BETA GAMMA
Micro Ci/2cc from Chemistry Department".
This nomenclature
did not agree with the T/S requirement, "Reactor coolant
system leakage shall be checked daily by the sump and a.ir
sampling system
11
Appendix A required the reactor operator to record "N/A"
.following successful completion of the surveillance each
day.
Use of
11 N/A
11 was misleading indicating the requirement *
was not applicable.
(3)
The survei~lance procedure;~ acce~t~nce criteria shown in
the U~it Operators Daily Surveillance Log (Appendix A) was
based upon drywell venting not reactor coolant leakage. *
This is another example of an activity affecting quality not
being covered by a procedure, and.is another example of the
previous violation (237/92005-02d(DRP)) ..
( 4.)
(5)
(6)
The inspectors determin~d that several SEs and SCREs failed
to recognize that failure to meet T/S surveillance
requirements constituted a failure to meet the Limiting
Condition for Operation (LCO).
The.RCS Leakage T/S LCO
Action required ~n orderly shutdown to be initiated and the
reactor shall be in a cold shutdo~n condition within 24*
hours. *The operato'rs concluded the LCO action was not *.
applicable even when the surveillance requirements are:not
met (excluding the 25% surveillance interval ma*ximum
allowable ~~tension): This is considered a weakness in the*
conduct of shift operations.
The licensee's surveillance program is based on a daily
versus 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> routine, however, the policy regarding
11Daily
11 has not been clearly stated.
The licensee indicated
such a policy would be written.
The HP technician's acti.on to resample upon discovery of the
- inoperable CAM,- and the associated log entries,* indicated a
positive, questioning attitude.
b.
On March 11, 1992 the inspector observed the HR.Cl High Flow
15
Isolation Calibration per DIS 2301-03: After the HPCI steam
valves were i~olated, the LPCI minimum flow valve 2-1501-138
clo~ed automatically.
The analog trip unit (ATU) for the HPCI
high flow transmitter was located adjacent to the LPCI minimum
flow ATU.
The instrument mechanic indicated that he had selected
the correct ATU on the master calibration unit. * Through
subsequent discussions and a review of the~ircumstances, the
inspector concluded the wrong ATU was inadvertently selected on
the master calibration uni.t.
c.
On March 7, 1992, the licensee performed DOS 6600.:.03. * During a
record review of the completed procedure, the *fo 11 owing
observations were made:
(1)
During the test, the 2/3 Diesel Generator ~ent fan and fu~l
oil transfer pump fajled to transfer to Unit 3 power when
expected.
( 2) .
OAP 9-11, "Procedure Usage and Adhetence" Rev. 3, requires a
Procedural Comment Supplement, Form*9-11A, be completed if
unexpected responses occur.
The form is to be used to
document information such as the destription of the. problem, :
the basis for continuing or discontinuing the procedure, the
steps or prcicedures fcillowed to return the line-up to
normal, and .the names of p~rsonnel contacted as part of the
decision making pro~ess.
.
.
.
.
The licensee did not document the unexpe~ted responses to
the test fo the manner prescri b.ed by admi ni strati ve .
.
procedures (no Form 9~11A wa~ com~leted).
Also~ based upon
interviews, the test leader and a technical support staff
group leader involved in the test were riot aware of Form
9~11A or the procedural* requirement, and did not recall.
receiving training on OAP 9~11. This is another item to be
- reviewed under Unresolved Item {237/92005-0l(DRP));
During the test, sever:a 1 steps were performed locally by
station pe~sonnel, under the dire~tion of the test leader in
the control room.
OAP 9-11 required initialing or signing of a step be based
on either direct observation, or a direct report (a.g.,
telephone call, face-to-face communication) from the person
- making the observation.
It further states that if other
than direct observation is utilized, then the initials of
the person performing the observation must be included with
the initia*ls of the person actually initialing the step.
Severa 1 of the steps performed locally by station per.sonne 1
were signed with only the test leader's initials, although
direct observation of step p~rformance was not utilized .
The failure of key personnel ~o:~e ~ognizant of-applicable
16
administrative procedure will be a reviewed as another
example of unresolved item (237/92005-0l(DRP)) of 10 CFR 50
Appendix B, Criterion XVI, Corrective Action in. that the
corrective action to violation 237/90023-0l(DRP)*was not
adequate to preclude this situatiori~
(3) *
Two of the acceptance criteria for DOS 6600-03 are .
verification that the diesel generator operates with the
emergency 1 oads 1 oaded for greater than five minutes and for
the 2/3 di~sel generator auxiliary equipment feeds to
- automatically transfer.to Unit 3.
The documehtation for loaded diesel generator operation was
inconclusive as to.whether the five minute requirement was
met.
Therefore~ process computer data was reviewed and
confirmed that the emergency loads had been unloaded from
the emergency bus prior to completion of the minimum five
minute run of the loaded diesel generator.
The failure to
run the EOG in a loaded condition for five minutes in
accordance"wi th step I. 7. a of Dos* 6600-03 is another example
of a 10 CFR Part 50, Appendix B, Criterion V, violation
(249/92005-02e(DRP)) for failure to follow established
proc.edures.
- Also, the documentation was uncle~r as to whether the 2/3 *
- diesel generator *auxiliary equipment automatic transfer to
Unit 3 w~s verified .. A butned cable prevented the
ventilation fan from transferring and an i~properly
installed relay cover inhibiting the movement of a relay
, prevented the fuel oil transfer pump from transferring.
It
was subsequently confirmed that, following replacement of
the burned cable and removal of the relay covet, the vent
faD and fuel oil. transfet pump were loc~lly st~rted fro~
Unit 3 power.
Therefore, automatic transfer of all 2/3
diesel generator auxiliary equipment was not verified d~ring
performance of the survei Hance procedur.e.
After bein~ informed that the acceptance criteria had not
been met, the licen~ee successfully performed Special.
Procedure (SP) 92-3-57, "Bus Undervoltage Arid ECCS
Integrated Functional Test For Unit 2/3 Diesel Generator
{Unit 3 Test Only)", on M~rch 21, 1992, and verified the
diesel generator operated for greater than five minutes
while it was loaded with the emer~ency loads and the 2/3
.diesel generator auxiliary equipment feeds transferred to
Unit 3 .. The inspector observed test performance and.
reviewed the completed test procedure and verified the
established acceptance criteria were satisfied.
A further_example of a violation was identified.
Two examples of ~n
unresol.ved item were discussed .
. 17
y
8.
Training Effectiveness {41400, 41701)
The effectiveness of training programs for licensed and non-11censed
personnel was reviewed by the inspectors during the witnessing of the
licensee~~ perform~nce of ro~tine ~urveillance,. m~intenance, and
- . operati6nal activities, and during the review of the licensee's response
to events which occurred during the inspection period.
Plant personnel
exhibited. weaknesses in knowledge of the reactor coolant leakage
Technical Specification requirements and knowledge of administrative
procedures for testing.
No violations or deviations wer~ identified.
9.
Events Followup {93702*).
During the inspection p~riod, several events occurred, some of which
required prompt notific~tion of the NRC pursuant to 10 CFR 50.72.
The
inspectors pursued the events onsite with the licensee and with NRC
~fficials. In each case, the inspectors reviewed the accuracy and
tim~iness of the licensee notification, the licensee's corrective*
actions and that activities were conducted within regulatory
requirements.
The specific ~vents reviewed w~re:
a.
Ori April 2, 1992, the Unit 3 reactor operator started the 3C ~nd
- 3D c6ntainm~nt cooling.service water (CCSW) pumps iTI parallel to
assist pump packing adjustments by maintenance personnel.* Th_e
reactor operator observed 5600 g~llons per minute (GPM) total
flow.
Subsequently, the reactor operatot started the JA and the
38 CCSW pumps in parall~l and observed 5300 gpm.
These flow rates
were tonsiderably less than the 7000 gpm specified in DOP 1500-2, *
"Torus Water Cooling Mode of Low Pressure Coolant Injection
. System," for such pump configurations.
The condition was reported
to shift management, appropriate log entries were made ~nd a**
significance condition adverse to quality report was
i~itiated.
Subsequent testing of-the Unit 2 pumps reveal~d 7000 gpm could not
be achieved for those applicable pump combinations.
C~rtain portions of design basis documents i~fer the *need for 7000
gpm CCSW flow to.maintain an acc~pt~ble torus water temperatur~.
These include Final Safety Analysis Report (FSAR) Table 6.2.4-1
"LPCI/Containmerit Cooling Equipment Specifications" and FSAR
Section 5.2.3.2 "Containment Response to a -Loss of Coolant
Accident." Another design basis documents, General Electric
drawing 729E583 "LPCI containment cooling system process flow
diagram", completed "in 1969, reflected 7000 gpm ccsw flow in a
particular operational mode.
Other sections of d~si~n bas~s_
documents indicate only 3500 gpm is needed which correlates to one
CCSW pump in operation to maintain acceptable torus water
temperature. The need of one CCSW pump is consistent with
emergency diesel generator electrical loading capacity.
Also, in 1988 the licensee completed a safety e.valuation-:and* *
18
modification package to replace the copper nickel LPCI heat
exchanger tubes with stainless steel. Tube replacement resulted
in ~n approximate 10% degradation in the overall heat transfer
coefficient for the heat exchanger.* Calculations supporting the
safety evaluation were based 6n a 2-LPCI pump 2-CCSW pump
capability.
Since Unit 2 was operating and Unit 3 was in cold shutdown, an
operability evaluation was conducted for Unit 2 and completed on
April 4, 1992.
This evaluation coricluded that the CCSW system ~as
c~pable of performing its*safety*function in a one CCSW pump (3500
gpm)/one LPCI pump configuration. A safety evaluation was
performed prior to restarting Unit 3 and reached the same
conclusion -for that unit.
This isiue is ccinsidered unresolved (2~7}9200~-06(DRP)) pending
further NRC evaluation of the li~ensee's HPCI heat exchanger duty**
and suppression pool temper~ture calculation to support operation
of both ~nits, the 10 CFR 50.59 safety evaluation for the 1988 .
heat exchanger tube change out, and th~ original General Electric
design* calculation to support the process flow diagram.
.
.
'
. .
b.
On April
2~ 1992, while Unit 2 was at 98% power, .the licensee.
identified the post-atcid~nt in~trumentation Technical
Specification surveillance requirement for daily source range
- monitor instrument checks and quarterly calibration checks-may not:
ha~e been performed as required. The apparent ca~se was *
misinterpretation of the Technical Specifi~ation requir~ments.
This issue is considered.unresolved (237/92005-0?(DRP)) p_ending *
further evaluation PY the NRC.
c.
On~March 19, 1992, the licensee informed the NRC that a licens~d
operator tested positive for marijua.na iff a random fitness-for..:.
duty te~t. The individual was_ suspended for 14 days acco~ding t~
the.licensee's Fitness-For-Duty p~ogram and referred to the :
, Employee Assistance Program for assessment.
This matter h-as been
- directed to the Operator Licensing section at the NRC Regional
office. -*
.
.
d. * * On April 4, 1992, with Unit-3 in ~old shutdown, the licensee
- declared an Alert du~ to the loss of Unit 3 control room
The loss of the annunciators was. caused by a loose
wire on the negative side of one of the control room panels.
However, due to the design of circuits all th~ control room panel *
- negative circuits were "daisy-chained" together. Therefore, by
losing continuity of one circuit, all the circuits failed.
The
licensee properly classified the event and manned appiopriate
command centers. The event was terminated with the restoration of*
the .anh~nciator system on April 5, 1992.
e;
On March 14, 1992, the high pressure coolant injection (HPCI)
suction valve (MOV 3-2301-6) unexpectedly opened duriri~ the Unit 3
19
.*
integrated .leak rate test {ILRT) .. The MOV opened during ILRT *
pressurization when the high drywell pressure setpoint was reached
providing an engineered safety features {ESF) actuation signal to
the HPCI system.
No othei valves or devices in the HPCI -system*
changed state.
Station personnel intended to remove the MOV from service.prior to
pressurization.
In prepatation for the llRT, el~ctricians were to
disable the actuation signals to all ESF equipment.
For the MOV
this was to be accompli~hed by lifting two wires in the MOV
control circuit. However, the electrician removed the wires from
the corresponding terminal block and taped them together
maintaining the ESF actuation circuit in service. *
.
.
Onshift operations management failed to recognize the opening of
. the MOV wa~ an unplanned ESF actuation and did not report the
event within four hours vi'a the emergency not ifi cation system
{ENS) per 10 CFR 50.72(b){2)(ii).
Following.NRC inspectof
. inquiries, th~ next day off-shift management reviewed the event
and determined a 10 CFR 50,72 report was appropriate.
The report
was made on March lB, 1992.
This is the- third time in less than eighteen months that the
licensee failed to make an ENS report due to an unplanned ESF
actuation .. Two previous violations associated with 10 CFR 50.72
were. issued for failure to make the required NRC notifications*
- following ESF actuation on December 8, 1990 and July 4, 1991. ,
In response to the first violation the ~jc~n~ee issued a
memorandum to the operations personnel to provide guidance on the -
defi~ition of an ESF actuation.
Th~ gtiidance defined an ESF
actuation to include ~ny non-planned or unknown occurrence
invblving the actuation of an ESF train, which results in the *
completion of the desired re~positioning of any piece of
equipment.
Following the July 4, 1991, failure t~ report, the NRC issued a*
violation of 10 CFR 50, Appendix B, Criter~a XVI, Corrective
Actions, for the ineffective corrective actions from the previous
violation.
In response to the second.violation the licensee
committed to:
e
Provide training to the shift engineers (SE) and shift
contiol room engineers {SCRE)~
Clarify the guidance provided operations personnel.
The
clarified guidance defined an ESF actuation as:
"Unplanned
actuation of ESF systems ot compon~nts thereof {e.g.,_valve
movement, pump starts) are expected to be reported
tegardless of what caused the actuation, even if the
actuation was unnecessary or was not directly initiated by
20
- .. *.-
..
ESF actuation signals."
Develop a flow chart to aid in ascerta.ining reportability
requirements and provide it by early first quarter, I992.
. Tp place a copy of NUREG I022, Licensee Event Reporting*
.System, in the control room to aid in reportability
determinations.
The reasons why the corrective actions to prevent recurrence of
the previous violations were not effective will be further
reviewed by the NRC.
This is considered another example of the
unresolved item di~cussed in section 2.a (237/g2005~0I(DRP)).
.
'
No violations or deviations were identified; however, twb new unresol~ed .
items and another example of a previously identified unresolved item was
discussed.
IO.
- Safety Assessment and Quality Verifi~ation (40500)
ai
Mid-l~vel Management Presence
The inspector rioted the presence of mid-level management at
"Vision through Quality" sessions and tailgate meetings .. However,
minimal interaction betweeh mid-level management and Dresden
personnel at th~ actual job-site or duty station was not~d. *
b.
B.us 34-:-2 Temporary Alteration
On March I9, 1992, temporary alteration (T/A) III-7-92 installed
-measuring and test equipment (M&TE) on the auxiliary compart~ent
of ESF 4I60-volt AC Bus 34-1 to monitor voltage. This T/A
provided an indirect interface between Class IE safety related
electrical equipment and non-safety equipment.
The IO CFR 50.59 .
safety evaluation concluded the change would not affect any .
operating modes or eq~ipment failures.
The technical e~aluation
concluded safety related equipment was affected by the T/A.
However, *the safety evaluation did Tiot address the probability or
consequences of malfunctioning M&TE or how the Class IE circuit
would be protected followihg a malfun~tion of the M&TE .
. A previous rion-cit~d:violation (50-237/910I6-0I(DRP)) was issued
for the failure t6 adequately considered the effect rif a
malfunction of non"".safety equipment on a safety related syste*m.
In this tase a T/A
(TA"".II-7~091) on the Unit 2 high.pressure
coolant injection (HPCI) system provided an interface between
cl.ass IE safety related electrical equipment and non-safety M&TE.
The current Dresden licensing bases included a Systematic
Evaluation Program (SEP) commitment to incorporate the electtical
isolation philosophy of IEEE 384 and Regulatory Guide 1.75 fot
plant modifications whenever practical (1985 CECo letter from B.
21.
.
.
Rybak to R. Gilbert (NRR)).
The commitment to IEEE 384 and
potential failure modes of the M&TE,_ and the effect of those .
failure modes, should have been considered in the safety
~valuation process.
To-.address the violation, OAP I0-02, "IO CFR 50.59 Saf~ty
Evaluation/Scre~riing", was revised to incorporate a safety
evaluation screening review worksheet.
The work sheet asks if
safety-~elated class IE Bus integrity is maintained and if safety-
.* related circuits are isolated ~nd separated from non-safety~
related circuits. The safety evaluation preparer or reviewer did
not use the checklist and were not aware of the commitment t6 IEEE 384.
The reason why the corrective actions were not adequ~te* to
prevent recurrerice will be reviewed as yet another example .of
unresolved item (t37/92005-0I(DRP)).
c.
The inspector met wit~ the* orisite quality as~uranc~ g~oup and
discusied two performance based initiatives t~ determine present
p~rformance and the effectiveriess of recent management corrective
~ctions tb:station performance.
One of the initiatives involved
using senicir licensed personnel from other facilities to revie~
operator performance on a periodic basis.
The oth~r initiati~e
involved a soft-side evaluation of the most retent management
corrective action~. *Both initiatives tesulted in soft-side
- assessments which support the inspector's observations outlined in
section 10.~ above.
.
.
No violations -or deviations ~ere identified; however another example of
~previously discussed unresolved-item was. mentibned.
ll~ . Mee~inqs and cith~r Activiti~s (36702)
-a.
On March'I9; I992, the Regional Administrator and st~ff met with *
CECo senior management at corporate headquarters in Downers Grove,
Illinois. *The meeting agenda included the licensee's *"Vision .
. through Quality" program, plant material cbnditions, engineering,
future "oldu plant (Dresden, Quad Cities and Zion) initiatives and.
design basis retri evabi 1 itf.
b~
On March 30, I992, a management me~ting was held iri the NRC
regional office. Attending the meeting wer~ mid-level NRC *
regional management, NRR project and IO CFR 50.59 technical
representatives and key CECo management personnel involved i~
training and approving 10 CFR 50.59 safety evaluati-0ns.
The
subject of the meeting was a safety evaluation performed by the
licensee to support control room habitability when discrepancies
in a past habitability ~ere discovered.
See unresolved item.
.
- 237/90022-02 discussed in inspection reports 237/90022, 9I031, and
91039 for further details.
At the conclusion of the meeting the licensee acknowledged that
the NRC should have been contacted regarding the change in
22
. 12.
c.
assumptions associated with the most recent habitability an.alysis.
'
.
'
O~ March 30, 1992, the Division Director of Reactor Projetts ~et
with the.licensee's operations improvement team and select members
6f oper~tion~ ~anagement. *The meeting_entailed a dialogue from**
the director on safe operating philosophy and questions from the
team to the director on points of interest;
Unre~olved Ite~s .-
Unresolved items ~re matters about which more information is req~ired in
order to ascertain whether.they ar~ acceptable items, open* items,
violations, pr deviations. Unresolved items disclosed during this
inspection are discussed in sections 2.a, *2.c(l}, 4.b.l, 5.a, 6.b,.
7 .c(l), 7 .c(2), 9.a, 9.b~ 9.e and 10.b.
- -
13.'
Open Items
Open items are matters which have been discussed with the licensee;
which will be r~vi~wed further by the inspector; and which involve some*
action on the part of the NRC, the licens~e. or both.
An Open item
disclosed d~ring this* inspection is discussed in Section 4.a.l.
14.
Exit Interview
The inspecto~s met with lic~nsee reptesentatives (denoted in section 1)
during th~ inspection period and at the conclusio~ of the inspectioh
period on April 10,. 1992 .. The inspectors summarized the scope and
- re~ults of the insp~ction and. discussed the.likely content of this
inspection report.
The license~ acknowledged the.information and did
- not indic~te that any of the information disclosed during the inspection
could be considered proprietary in nature.
.
.
23