ML17174A885
| ML17174A885 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 09/11/1991 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17174A883 | List: |
| References | |
| 50-237-91-22, 50-249-91-22, NUDOCS 9109190066 | |
| Download: ML17174A885 (21) | |
See also: IR 05000237/1991022
Text
U. S. NUCLEAR REGULATORY COMMISSION
REGION II I
Report Nos.
50-237/91022(DRP); 50-249/91022(DRP)
Docket Nos.
50-237; 50-249
License Nos.
Licensee:
Commonwealth Edison Company
Facility Name:
Dresden Nuclear Power Station, Units 2 and 3
Inspection At:
Dresden Site, Morris, IL
Inspection Conducted:
June 29 through Aug~st 22, 1991
Inspectors:
W. Rogers
D. Hills
M. Peck
R. Greger
P. Rescheske
M. Kunowski
N. Shah
. R. Zuffa, Site Resident Engineer
J?-::fi1nois-E:7'~ment of Nuclear Safety
Approved ~~~~
-/,1/9/
By
pro j ~ c ~ s sect i 0 n ~ B
--'Z'-rrn--..
1
,-,~Ve,.,_e___,__* -
Inspection Summary
from June 29 throu h Au ust 22
1991 (Re ort Nos. 50-237/91022
DRP ;
91
D P .
Areas Inspected: Routine unannounced safety inspection by the resident
inspectors, region based inspectors, and an Illinois Department of ~ucle~r
Safety inspector of licensee acti.on on previously identified items; licensee
event reports; operational safety; monthly maintenance; monthly surveillance;
training effectiveness; Systematic Evaluation Program items; events; safety
assessment and quality verification; and report rev_iew.
Results:
Three cited violations were identified. *One involved the failure of
maintenance workers and their supervision to follow written procedures during
the installation of the steam separator within the reactor vessel.
Another
involved inadequate corrective actions to a previous violatio~ in the area of
NRC reporting.
The third violation dealt with programmatic inadequacies of
the channel check process.
One non-cited violation was identified involving
use of an inadequate procedure by operators while performing radwaste transfer
activities. Five unresolved items and two open items were identified.
One
Systematic Evaluation Program item was closed.
This was Item 14 - Topic*
III-4.5.3 and 2.2.2 (Supp. 1).
9 10919006~ 910912
~DR
ADOC~ 05000237
PDF*<
c
Plant Operations
Management decisions with regard to power ascension and shutdown were
conservative. Operator performance during abnormal and transient conditions *
. was good.
Some weakn~sses were noted in the management directives for
operations regarding NRG reporting, flow control line (FGL) control rod*
- manipulation instructions, and actions for safety related 4160 VAG bus low
voltage conditions. Also, operators failed to stop and receive additional
instructions on two occasions (FGL situation and radwaste transfer activities)
with adverse consequences.
Finally, management exhibited a significant
increase in awareness towards reporting plant events to the NRG.
M~intenance/Surveillance
Findings associated with the steam separator shroud installation were
reflective of personnel performance weaknesses during the last Unit 2 refueling
outage 10 months ago.
Maintenance actions during this inspection period
appeared adequate except in the reactor recirculation discharge valve initial
root cause determination.
W~aknesses in the content of the surveillance
program persisted and expanded from the previous inspection report period.
Safety Assessment and Quality Verification
.
.
A strength was noted in the reviews conducted by Offsite Review Safety Group
with.their findings considered relevant and a worthwhile contribution to safe
operation. Nuclear Quality Program audits were performance based and beneficial
in identifying problems.
The commitment tracking program for licensee event
report (LER) corrective actions appeared to be adequate.
Conversely, some
weaknesses were noted in the scope of safety evaluations being reviewed by
the offsite review group and in the quality of the post scram review report
for June 9, 1991.
2
.
'
DETAILS
1.
Persons Contacted
- commonwealth Edison Company
- Er Eenigenburg, Station Manager
- L. Gerner, Technical Superintendent *
- J. Kotowski, Production Superintendent
E. Mantel, Services Director
D. Van Pelt, Assistant *superintendent - Maintenance
J. Achterberg, Assistant Superintendent - Work Planning
- G. Smith, Assistant Superintendent-Operations
- K. Peterman, Regulatory Assurance Supervisor
M. Korchynsky, Operating Engineer * *
B. Zank, Operating Engineer
J. Williams, Operating Eng~neer
R. Stobert, Operating *Engineer
T. Mohr, Operating Engineer
- M. Strait, Technical Staff Supervisor
L. Cartwright, Q.C. S~pervisor .
J. Mayer, Station Security Administrator
D. Morey, Chemistry Services Supervisor
D. Saccomando, Health Physics Services Supervisor
- B. Viehl, Engineering and Construction
- F. Kanwischer, Services Superintendent
T. Mohr, Operating Engineer
- K. Kociuba, Quality Assurance Superintendent
- D. Lowenstein, Regulatory Assurance Analyst
- Denotes those attending the exit interview conducted on August 2~, 1991,
and at other time$ throughout the inspection period.
The inspectors also talked wit~ and interviewed several other licensee
employees, including members of the technical arid engineering staffs,
reactor and auxiliary operators, shift engineers and foremen, electrical,
mechanical and instrument maintenance personnel, and contract security
personnel.
2.
Previously Identified Inspection Items (92701 and 92702)
(Open) Open Item (50-237/90027~14(DRP)): Perform sample inspection of
Systematic Evaluation Program (SEP) topic resolutions.
An additional SEP
item confirmed completed by the inspectors is listed in paragraph 8. *
This open item will remain open pending completion of licensee
confirmation of topic closures and completion of the NRC sample
inspection.
(Closed) Violation (50-237/91003-0l(DRP)):
The failure of Dresden
Instrument Surveillance (DIS) 500-9 to adequately prescribe steps to
measure the Reactor Protection System response time in accordance with
Technical Specification requirements.
The inspector reviewed the
3
~--------- --------------------------
.
.
licensee's planned corrective action including rev1s1on of DIS 500-9 to
ensure the proper applications of test equipment.
The inspector
determined that removal of.Dobler timer and the addititin of detailed
procedures are contained in the revised DIS 500-09.
This item is closed.
(Closed) Unresolved Item (50-237/91009-04(DRP)):
Evaluate causal factors
for the March .22, 1991, event involving the lifting of the steam separator
assembly on Unit 2.
On March 22, 1991, Dresden Unit 2 experienced an
unexpected anomaly in electrical power as core flow was increased.
As
coolant flow through the reactor core increased from 72 to 75 ~illiori
pounds per hour, the plant's electrical output increased by 2 megawatts
instead of the anticipated 30 megawatt increase. Also, reactor coolant
temperature .in the annulus region increas~d about 2 degrees Fahrenheit at
the same time the core flow/electrical output anomaly occurred.
Because
the power/flow anomalies were similar to a Vermont Yankee event
associated.with the steam separator lifting. from the seat on the core
shroud in the reactor, the licensee commenced a Unit 2 shutdown on
March 24, 1991, to i~spect the reactor interrials.
An investigation team
comprised of CECo corporate and plant individuals was formed to review
this event, along with other recent maintenance-related problems which
occurred during the Unit 2 refuel outage.
On March 27, 1991, NRC regional _
specialists arrived on site to review the event and licensee actions.
On March 27, 1991, the steam dryer was removed to facilitate the
inspection of the shroud head bolts. With assistance from General
~lectric Company (GE), a detailed inspection plan was initiated and
implemented~ with emphasis placed on verifying if the shroud head bolts
were latched and tightened. Troubleshooting and corrective actions were
performed under work request 000524.
Visual inspections on seven.
accessible shroud head bolts with an underwater camera indicated that the
bolts were latched, but not tightened. Subsequently, all 48 bolts were
verified latched, but not tightened.
In ~dditiqn, several spring
retainers were found to be mis-positioned.
Based on an evaluatton
performed by GE, the loose shroud head bolts would allow the shroud head
and steam separator to lift at high core flow conditions. The GE
analysis for the Vermont Yankee event concluded that no significant
changes in plant safety margins occurred during operation with the steam
separator assembly lifted.
The following conclusions .were based on interviews, observations, and.
document reviews, conducted by NRC regional. inspectors on March 27 -
July 16, 1991:
Steam separator installation was completed during the Unit 2 ~efueling outage
on November 26, 1990, using Work Request 094963 and Dresden Maintenance
Procedure (DMP) 0200-12, "Reactor Shroud Head and Steam Separator
Installation," Revision 7.
A s~cond shift mechanical maintenance crew
-completed the steam separator installation in the reactor cavity, and a third
shift crew (3 maintenance mechanics) completed the latching and
tightening of the separator shroud hold down _bolts.
Based on the signed
steps, in the work package (Steps G.12 and G.15), the third shift foreman
verified the hold down bolts were locked (latched), signed that the hold
down bolt nuts were tightened, independently verified the hold down bolt
4
nuts were tight, and signed that all spring retainers were correctly
positioned up on the nut.
The work crew did not use the procedure wh{le performing the shroud head_
bolt work.
All three mechanics and the foreman indicated that they did
not recall ~eeing the work package during the shift. Workers were not
familiar with having the procedure at the actual job location because
work practices on the refuel floor for mechanical maintenance allowed .the
use of a "clean table for the administrative aspects (signing of steps)
cf the work.
This table was located on the refuel floor; however, away
from the work p.erformed on the refuel bridge.
Review of the procedure by_
the NRC and the licensee indicated that the procedure, although weak, was
adequate and should have resulted in shroud head bolt tightness. Failure
to follow DMP 0200-12 for steam separator shroud bolt locking and
tightening is an example of a violation of 10 CFR Part 50, Appendix B,
Criterion V (50-237/91022-0la(DRS)).
There was no apparent management involvement during the third shift
mechanical maintenance *activities on November 26, 1990.
Because of a
shortage of foremen for that shift, one regular foreman and one upgraded
mechanic were assigned supervisor coverage of the shift's activities.
Normally, three foreman were utilized. Inadequate shift coverage was not
communicated to management.
This lack of supervision resulted in little
observation of maintenance activities on the refuel floor. .Although the
assigned foreman signed the procedure step for tightening the hold down
bolts, he did not observe the work. -The foreman was assigned 5 jobs for
coverage during the shift, with most of his time spent supervising
critical path work performed on the Main Steam Isola_tion Valves.
Dresden
Administrative Procedure. (OAP) 9-11, "Procedure Usage and Adherence,"
Revision 2, Step 0.(3) stated that when a st~p was initialed or signed,
it must be based on either direct observation, er a direct report such as
face to face communication.
If other than direct observation was utiliied,
then the initials of the person performing the observation must be included
with the initials of the person actually initialing the step. Failure to
observe the work or to have any or the three mechanical maintenance crew
members initial the step for the performance of the tightening of the hold
down bolts is an example of a violation of 10 CFR Part 50, Appendix B,
Criterion V (50-237/91022-0lb(DRS)).
All three mechanics had no experience in the hold down bolt tightening,
the proper use of the bolt wrench, or the bolting mechanism.
The 1ead
mechanic recalled experience only with the removal of the separator. The
licensee provided no formal training on th~s bolting process. Training,
usually consisted of "passed down" training from experienced crews.
The
foreman had received informal training as a junior foreman observing the
previous Unit 3 separator installation, but had never actually performed
the work.
Independent verification was not clearly understood by the foreman.
The
cause of this power/flow anomaly clearly indicated that the bolts were
not tightened, or independently verified as tight. After work had been
compl~ted, the lead mechanic and the foreman went to the bridge and the .
foreman "independently verified" the bolt tightness with an underwater
5
telescope.
The tops of the bolts have two flats machined into.them. The
area between the two flats indicated the position of the locking
(latching) T-lugs on the bottom of the bolt assembly.
The foreman
incorrectly used this indication and verified the bolts to be tight.
Bolt tightness could not have been verified in this manner, since the
area in question was located under the shroud lugs.
OAP 9-11,
11Procedure
Usage and Adherencej
11 Revision 2, defined ind~pende~t verification as the
certification of the correctness of an operation or condition based on
eithei first-hand observation or through personally performed
manipulation.
Failure to adequately perform the independent verification
of the shroud head bolt tightness in accordance with OAP 9-11 is an
example of a violation of 10 CFR Part 50, Appendix B, Criterion V
(50-237/91022-0lc(ORS)).
.
The foreman also initialed the procedure step that stated that all spring
- retainers were correctly positioned up to capture the hold down bolt
nuts.
The foreman indicated to both the NRC and the licensee that he did
not know how to actually verify the correct position of the spring
retainers. His visual *verification was based on the fact that the spring
retainers did not appear to be broken and nothing was out of place.
The ~nresolved issue regarding this event is closed; however, one violation
with three examples and no deviations were identified in this area.
3.
Licensee Event Reports Followup (90712 and 92700)
Through direct observations, discussions with licensee personnel, and
revi.ew of records, the following event *report was reviewed to determine
that reportability requirements were fulfilled, immediate corrective
action was accomplished, and corrective action to prevent recurrence had
been accomplished in accordance with Technical Specifications.
(Closed) LER 249i91,;,.004 "Unplanned Standby Gas Treatment System Auto-
start During Calibration
11
(Closed) LER 249/91-003, "Inoperable Torus Wide Range Lever Transmitters.
Due to Unknown Cause".
In addition to the foregoing, the inspector reviewed the licensee's
Deviation reports (OVRsJ generated during the inspection period. This
was done in an effort to monitor the conditions related to plant or
personnel performance, potential trends, etc.
OVRs were also reviewed
for initiation and disposition as required by applicable procedures and
the quality assurance manual.
No violations or deviations were identified except as delineated jn this.
or other reports.
4.
Operational Safety Verification (71707)
During the inspection period the inspectors verified daily, and randomly
during back shift and on weekends, that the facility was being operated
6
. ( c ~ .. ;,: ? .. '
in conformance with the licens*e:and regulatory requirements and that the
licensee
1 s management control<System was effectively carrying out its
responsibilities for safe operation. This was done ori a* sampling basis
through routine direct observation of activities and equipment, tours-of
the facility, interviews and discussions with licensee personnel, reviews
of operating logs, independent verification of safety system status and *
limiting conditiohs for operation action requirements (LCOs), corrective
actiOn, and review of facility records ..
On a sampling basis. the inspectors daily verified proper control .room
staffing and access, operator behavior, and coord.ination of plant *
activities with ongoing control room operations; verified operator
adherence with the latest revisions of procedures for ongoing activities;
verified operation as required by Technical Specifications;
.. :
including compliance with LCOs, with emphasis on engineered safety
features (ESFJ and ESF electrical alignment and valve positions;
monitored instrumentation recorder traces and duplicate channelsfor
abnormalities; verified status of ~arious lit annunciators for operator
understanding, off-normal condition*, and corrective actions being taken;
examined nuclear instr,umentation and other protection channels for
proper operability; reviewed radiation monitors and stack monitors for
abnormal conditions; verified that on~ite and offsite power was available
as required; observed the frequency of plant/control room visits by the *
station manager, superintendents, assistant superintendents, and other
managers; and observed the Safety Parameter Display System for operability.
Iiems for consideration during plant tours included rad1ological controls
adherence, security _plan. implementation, housekeeping controls and
component leakage/lubrication.
As a result of these tours and reviews
these specific occurrences were evaluated:
a.
Torus Widi Range Level Transmitter 3-1641-58 drifted from 14.7 feet
to 13. 5 feet between January 31, 1991 ~ and February 2, 1991. A
similar drop on 3-1641-SA 6ccurred between April .6, 1991, and
May 31, 1991. Operators did not identify these failures until.
June 5, 1991, although the Unit Operator Daily Surveillance Log
(DSL) (Appendix A) required performance of a daily instrument check *
- on these instruments.
By Technical Specifications definition,
11an instrument check is a
qualitative determination of acceptable operability by observation
of instrument behavior during operation. This determination shall
include, where possible, comparison of the instrument with other
independent instruments measuring the same variable". Initial
op~rator training included only the Technical Specifications
definition and on-the-job training for Appendix A completion from*
licensed Nuclear Station Operators (NSO). .
Specific training involving accuracy for specific instruments in
regard to operability determination had not been given. Although
most of the NSOs appeared to be knowledgeable of the correlation
between the narrow range torus level indicator and the two wide
7
range level indicators, i.e. O" on the narrow range indication
corresponds to 15
1-0" on the wide range indications, they did not
necessarily: use this correlation to perform the operability check.
The Unit Operator DSL (Appendix A) did not provide tolerances, thus
making it difficult for the NSO to assess instrument opera.bility by
m~ans of an instrument check~
NSOs also stated that additional
procedural guidance would be beneficial for performing instrument
checks.
The failure of instruction, procedures, or the Unit Operator DSL
(Appendix A) to provide appropriate acceptance criteria for
performing the instrument check is a violation *
(50-249/91022-02(DRP)) of 10 CFR 50, Appendix B, Criterion V.
In
addition, several operators indicated that they would question the .
operability of these instruments and take appropriate action if they
were indicating at least one foot below the normal expected level of
14.7 feet.
However, the one foot drift did occur and went
unidentified for an exten~ed period.
b.
- During th~ performance of Dresden Operating Surveillance (DOS) 1400-
04, "Cold Shutdown Testing of the Core Spray System Check Valves",
on July 11, 1991, the 28 core spray pump ran without a suction
source for a short period due to the condensate storage tank
suction valve, 2-1501~37, being in it's normally locked closed
position. Although high vibration was observed, no pump damage was
identified before the pump was stopped.
The failure to open this *
valve prior to performing the surveillance* was due to a deficiency
in DOS 1400-04 that did not prescribe opening the valve.
In
addition, the applicable piping and instrument drawing M-35,
- Sheet 1, indicated the normal position of this valve as locked open.
Deficiencies regarding the procedure and drawing are considered an
unresolved item (50-237/91022-03(DRP)) pending a review to determine
whether drawing discrepancy was isolated and whether this procedure
had been revised under the procedure upgrade program.
c.
On July 23, 1991, Unit 2 control rods were inserted to reduce the
flow control lin~ (FCL).
The Control Rod Sequence (CRS) for
shutdown enforced by the rod worth minimizer (RWM), did not
correspond to the *first step provided in the* FCL instructions.
Therefore, to use the FCL instructi6ns entailed bypassing the RWM.
Pre~ious management direction had indicated that the RWM would be
left inservice, even at high power levels.
Upon weighin9 the
conflicting directives, the Shift Control Room Engineer (SCRE)
incorrectly instructed the NSO to follow the CRS, resulting in the
insertion of four shaper control rods from step 48 to step 40.
However, the SCRE and NSO did not recognize the possible power
shaping/fuel integrity problems associated with inserting rods per
CRS without first reducing recirculation flow as prescribed in the *
shutdown procedure.
The on-call Qualified Nuclear Engineer (QNE)
was not consulted by the operating crew.
Upon inspection the
following morning, a QNE noted the unexpected rod pattern.
8
Subsequent analysis by the QNE indicated that in this particular case,
power shaping/preconditioning envelope problems did not result. The
operator training program did not specifically ~ddress the importance
and possible adverse reactions to not following the FCL_ instructions.
The day before the event, a licensee initiated reactivity assessment
team had identified .this particular weakness and the ramifications.
This is considered an unresolved item (50-237/91022-04(DRP)) pending
review of the documentation of a licensee reactivity assessment
completed just prior to this event.
d.
On July 23, 1991, large areas of the Unit z and Unit 3 reactor
buildings became contaminated, primarily with Co-60, Mn-54, and Fe-
59, at a maximum of 150,000 disintegrations per minute/100 cm2.
The
contamination was identified after four workers, who had completed
the transfer of spent resin from the Unit 2 fuel pool demineralizer
to a tank in the radwas.te building, alarmed the personnel
contamination monitors.at the main access point to the turbine
building.
Contamination was mainly on their sho~s. Minor
contamination was also found in the turbine building along the path
the worker£ took after exiting the Unit 2 reactor building. Access
to the reactor buildings was restricted during the subsequent
cleanup activities. In addition, an investigation team was formed
by the licensee to determine the cause of the contamination.
Whole-
body counts of personnel who were in the reactor buildings at the
time of the resin transfer identified only one worker with
detectable internal contamination.
The whole-body count for this
individual, who was involved in the transfer~ identified the presence
of 7 nanbcuries of Co-60, a level indicating an exposure to airborne
radioactivity well below regulatory limits.
The licensee's investigation indicated that the fuel pool demineralizer
had not been vented properly prior to backflushing the resin transfer
line after the-resin transfer was completed. Air pressure from the
demineralizer vented via the demineralizer's freeboard drain line
and expelled contamination out of a sample sink drain line, which
- drained to a common dra i r'I 1 i ne utilized by the demi nera 1 i zer. Spread
of contamination from the sample sink drain to the two reactor building~
was exacerbated because the normal reactor building ventilation was
secured and the lower volume standby gas treatment system was in operation
at the time.
The licensee stated that a similar resin transfer and backflushing
had been done quarterly for several years without similar problems,
but that this time the auxiliary operator did not vent the
demineralizer to atmospheric pressure as had been _done in the past.
The procedure used to transfer resin and backflush, Dresden
Operating Procedure (DOP) 1900-8, Revision 2, "Fuel Pool
Deminer-alizer Resin Transfer,
11 did not contain specific instructions
for venting the demineralizer prior to backflushing. The licensee
indicated that the procedure will be revised to include this
information.
In addition, the licensee indicated that the revised
procedure would prohibit transfers during standby gas treatment
9
operation and that the drain line on the sample sink, which was not
in use, would be sealed. The failure of DOP 1900-8 to adequately
prescribe steps to vent the demineralizer prior to backflushing is
considered to be a violation (50-237/91022-0S(DRSS)) of 10 CFR 50,
Appendix B, Criterion V; however, in accordance with 10 CFR 2,
- Appendix C,Section V.A., a Notice of Violation is not being issued~
The procedure revisions and modifications to the sink drain line
will be review~d during a future inspection and is an open item
(50-237/91022-06(bRSS)).
During the review of this incident by the'NRC radiation spectalist,
several minor problems were noted with the ~ont~ol of access to.the
~ontaminated reactor buildings, Although a "contaminated are~" sign
was posted at the double step-off-pad area set up in the narrow
hallway leading into the Unit 2 reactor building, it was not readily
visible. Also survey maps had not *been updated by the start of the
- day work shift on July 24, 1991, to indicate the-change in
contamination levels in the r~actor buildings.
One individual
entering the reactor building during the day shift on July 24, 1991,
received low level shoe contamination when the step-off-pads were
crossed without recognizing the need for protective clothing. These
matters were discussed with the licensee who agreed to develop a
checklist for use in future contamination events to ensure that all
access control measures are established pro~ptly and adequately.
This checklist will be reviewed during a future inspection and is an
open item (50-237/91022-07(DRSS)).
One cited violation, one non-cited violation and no deviations were
identified in. this area.
5.
Monthly Maintenance Observation (62703)
- station maintenance activities affecting the safety-related systems_and
components listed below were observed/reviewed to ascertain that they
were conducted in accordance with approved procedures, regulatory guides,
and industry codes or standards and in conformance with Technical
Specifications.
The following items were considered during this review:
the Limiting
. Conditions for Operation were met while components or systems were
removed from service; approvals were obtained prior to initiating the
work; activities were accomplished using approved procedures and were
inspected as applicable; functional testing and/or calibrations were
.
performed- prior to returning components or systems to service; quality
control.records were maintained; activities were accomplished by
qualified personnel; parts and materials used were properly certified;
radiological controls were implemented; ~nd, fire prevention .controls
.were implemented.
Work requests were reviewed to determine status of
outstanding jobs and to assure that priority is assigned to safety- .
related equipment maintenance which may affect system performance .
10
The inspectors monitored the lic~nsee's work in progress and verified
that it was being performed in accordance with proper procedures, and
approved work packages, that applicable drawing updates were made and/or
planned, and that operator training was conducted in a reasonable period
of time.
The following maintenance activities were observed and reviewed:
Unit 2
Recirculation System Sample Valve 220-44 Repair
Shutdown Cooling Loop 2A Suction Valve Control Circuitry Repair
Unit 28 Shutdown Cooling Pump Dtscharge Isolation Valve and Logic Repair
Unit 28 Instrument Air Compressor Overhaul
Unit 3
On1t 3A/3B Hydrogen/Oxygen Monitor Repair
3A Core Spray (CS) Pump Maintenance
3A CS Isolation Valve Rotor Modifi~ations
3A CS Valve Breaker Maintenance
3A & B Post-LOCA Hydrogen/Oxygen Monitor Repair
On Augu~t 6, 1991, the Nuclear Station Operator (NSO) observed the 2A
reactor recirculation pump indicated speed increase to 100%. * While .the
operator was manually reducing pump flow, the 2A pump motor tripped and*
locked out as result of over excitation. Following the pump trip, the
CRAM arrays were inserted to exit from the power/flow instability region.
Investigation determined the pump trip was the result of a failed resistor
in the recirculation motor generator voltage ~egulator circuit.
In
attempting to close the pump discharge valve 2-202-5A to facilitate
returning the idle loop to service, the valve failed to close until the
electrical contactors, at the breaker cubical~ were manually held in. A
drywell entry was made to facilitate a temporary alteration to bypass the
large loading conditions encountered by the valve during a portibr. of the
closing cycle such that the valve could perform its design functfon. *
Further engineering review indicated that the valve torque switch setting
was incorrect and another drywell entry was made to change the setting.
The incorrect setting resulted from valve operation test and evaluation
system (VOTES) testing problems encountered on the valve during the
previous refueling outage. This is considered an unresolved item
(50-237/91022-0B(DRS)) pending further review of the adequacy*of previous
VOTtS testing and the resulting torque switch setting.
No violations or deviations were identified.
6.
Monthly Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical
Specifications during the inspection period and verified.that testing was
performed in accordance with adequate procedures, that test
instrumentation was calibrated, that LCOs were met, that removal and
restoration of the affected components were accomplished, tha*t results
11 .
c6nformed with Tethnical Specifications and procedure requirements were
reviewed by personnel other than the individual directing the test, and
that any deficiencies identified during the testing were properly
reviewed and resolved by appropriate management personnel.
The*inspectors witnessed portions of the following test activities:
Unit. 2
.
Dos 2300-1,
11HPCI Motor-Operated Valve Operability Verification
11
DOS 2300-3,
11 HPCI System Operability Verification
11
DOS 660.0~2,
11 Unit 2 Diesel Generator Monthly Operability Test
11
Unit 3.
DOS 500-3,
11APRM Rod Block and Scram Functional Test
11
DOS 5600-2,
11Monthly and Weekly Turbine Checks"
The following items*were evaluated:
a.
Technical Specifitation Surveillance 4.7.C.a requires the secondary
containment integrity be demonstrated by drawing a 1/4 inch vacuum
with the standby gas treatment system at each refueling outage.*
During surveillance testing, the secondary containment integrity
acceptance criteria was verified by the averaging of four
different1al pressure (DP) indicators located at the refuel floor.
The inspector identified the calibration of these DP instruments
(DPI-2/3-5741-517, -518~ -519 and -520) was performed without an
approved procedure or specified. acceptance criteria. However, the
inspectors noted that this could be considered another example of a
recent violation (50-237/91016-02(DRP)) and therefore, may be
encompassed by the corrective action regarding that violation.
Subsequent review of the violation response identified that'the
response was not broad enough.
This was discussed in the NRC
response to the licensee's corrective actions and will be pursued
following resolution of the previous violation.
b.
On July 8, 1991, an automatic standby gas treatment system start anp
reactor building v.enti lat ion system i sol at ion inadvertently occurred
during a surveillance on the isolation condenser area radiation
monitor.
Upon identifying the correct cable for the radiation
monitor power supply inside a main control room panel, the
.
instrument technician laid down the procedure.
Upon turning back to
the panel; the technician inadvertently disconnected the cable for
the reactor building fuel pool channel
11A
11 process radiation monitor *
power supply in the same location in the adjacent panel section.
This caused the engineered safety features actuation and was of no
safety consequence.
The technician appeared knowledgeable of the
. procedure and had a momentary lapse of attention to detail and self-
checking.
The instrument technician was counseled and this event
was revi~wed with instrument maintenance department personnel.
The
licensee reviewed component labeling and determined this not to be a
contributing cause .
12
The inspector noted that the ind1vidual involved was not listed on*
the job assignment matrix for this task.
The inspector did*not,
however, consider this a contributing factor to the event.
The
technician had been tr~ined for the task but had not received an on-
the-job training evaluation. This wa~ in accordance with a
- maintenance department memorandum that allows this if the technician
works under the direct supervision of *the supervisor. The
memorandum defined direct supervision as .observing the critical work
steps as defined by the supervisor.
In this case, no critical steps
were designated due to the supervisor's belief that none existed in
this procedure~ (Only monitors with an alarm and no automatic
actuation function were covered by. this procedure.) The licensee
indicated that a specific definition of critical steps had not been
given in order to give the supervisor more latitud~ based upon
personnel *knowledge of tne technician's abilities. However, the.
licensee did subsequently issue Instrument Department Memorandum 8,
which formalized the determination of critical steps to ensure that
both technician and supervisor were agreed on critical ~tep identification
prior to work performance. Therefore, the inspector has no further
concerns in this area~
.
c.
On August 12, 1990; the licerisee identified deficiencies in Dresden
Instrument Surveillance (DIS) 700-4, "Intermediate Ra~ge Monitor
.
(IRM) Rod Block/Scram Calibration Test", Revision 7, in that th~ IRM
. Hi-Hi and* INOP. functions were not tested adequately to meet
.
- Technical Specification Table 4.1.1 requirements.
Due to the IRM
Hi-Hi Scram.S.ignal being bypassed when the mode switch was in RUN
and reactor power greater than five percent, the actuation circuitry
was not tested all the way to the scram (107) relays when in this
condition.
In addition, the procedure required the IRM being tested
to be bypassed such that the circuitry would also not be tested to *
the scram (107) relays.
(This was not an immediate safety concern
since these scram functions were automatically bypassed* at the power
conditions the 1.1nits were in at the time of discovery.) The licensee
later discovered similar problems with the source range monitors.* The
liten~ee planned to properly test these functions as soon as appropriat~
conditions were reached. This.is conside~ed an unresolved item
(50-237/91022~09(DRP)) pending revie~ of the test results when the*
circuits are properly tested and, an understanding of hew this
problem was originally discovered.
No violations or deviations were identified.
7.
Training Effectiveness (41400, 41701)
The effectiveness of training programs for licensed and non-licensed
personnel was reviewed by the inspectors during the witnessing of th~
licensee's performante of routine surveillance, maintenance, and
operational activities and during the revie~ of the licensee's response
to events which.*occurred during the inspection period. Except as
indicat~d in paragraph 4.c, personnel appeared to be kn9wledgeable of the
tasks being performed, arid nothing was observed which indicated any
ineffectiveness of training.
13
8.
No violations or devi~tions were identified except as indicated in
paragraph 4. c.
Systematic Evaluation Program (SEP) Items (92701)
NUREG 1403., "Safety Evaluation Report Related to the Full-term Operating
License for Dresden Nuclear Power Station, "Table 2.1, identified 22 SEP
Integrated Plant Safety Assessment Report topic resolutions to be
confirmed by the NRC Region III office.
The following item in that report was confirmed as closed by the
i nsp_ectors:
Item 14 - Topic III-4.5.3 and 2.2.2 (Supp. 1)
Th~ completion for Item 2 for Topic II-3.b.l/4.l.4 is being tracked as
Open Item 50-237/89019-04.
In addition to Item 2, the following two
items remain to be verified as closed by the licensee and confirmed by
the NRC.
Item 13 - Topic III-2/2.2.2 (Supp. 1)
Item 16 - Topic VI-4/4.18.2; Topic VI-6/4.19
Each of these items was in some stage of verification review by the
licensee .
9.
Events Followup (93702)
a.
On July 10, 1991, radiation protection personnel discovered a steam
leak in the reactor water cleanup heat exchanger room in a reactor
recirculati.on sample line. Closure of the recirculation sample line
containment isolation valves (2-220-44 and 45) failed to stop the
leakage.
The leakage path was subsequently isolated by the closure
of a down stream manual valve.
An Unusual Event was declared as
Unit 2 was shutdown due to the containment isolation valve leakage.
The sample line containment isolation valves had previously failed
on March 4, 1990, and February 21, 1991.
The unit was restarted on
July 14, 1991, following repair of the sample line containment
isolation valves.
As-found leakage testing following the shutdown
determined that the total type B and C leakage did not exceed
Technical Specification limits. The vast majority of the leakage
was from the inboard (44) valve due to galling along the seating
surface of the valve plug and seat.
The licensee believed the
galling was caused by maintenance activities while setting the stem
travel or adjusting the valve to reduce its leakage.
Post-
maintenance local leak rate testing did not identify the excessive
leakage since leakage changed with the variation in seating from one
closure to another, depsnding upon how the galled imperfections
happened to align.
Following lapping of the valve seat and
_
machining of the valve plug, special care was taken during valve
reassembly to avoid rotating the plug while it was in contact with
the seat.
The cause of the small amount of outboard (45) valve
leakage was believed to be small surface imperfections on the
seating surface.
14
b.
During the shutdown 6n July 10, 1991, while Unit 2 was. at approximately
300 degrees F and 80 psig, the operator was unable to establish
shutdown cooling (SDC) due to the suction valve cycling closed after
opening the valve.
The SDC valve logic was repaired and shutdown
cooling was established.
The failure was contributed to a poor
wiring connection on the SOC isolation relay. *A second SDC train
was lined up to the fuel pool cooling system and was undergoing heat
exchanger repairs, the third train was unavailable due to the
overhaul of the discharge valve awaiting repair parts. A more
detailed evaluation of licensee shutdown risk management is planned
to be completed during the next inspection period.
c.
At 0116 on August 17, 1991, Unit 3 scrammed during main turbine stop
valve testing.
When opening the number 2 stop valve all six
combined intercept valves closed. Closure of the .combined intercept
valves reduced generator power from 394 MWe (47%) to 25 MWe with
reactor power still at 47%.
Eventually, the reverse power relay
tripped the generator, the turbine ~nd a reactor scram ensued~
The cause of th~ combined intercept valves' closure was a sluggish
fast acting solenoid. valve, which significantly reduced EHC header
pressure. This reduction in header pressure was repeated while
shutdown in special troubleshooting activities. Subsequently, the
- malfunctioning component was. replaced with acceptable testing
results achieved *
During the scram response operators did not observe the alarm typer
print two seconds after the scram that a *safety related 41.60 volt bus
had low voltage (apprqximately 4000). This was only an alarm typer
alarm without an accompanying annunciator or acknowledgement capability.
The ~pproximately 4000 volt alarm was to trigger operator response to
a recent Electrical Distribution Funcitonal Inspection finding on the
inability of safety related equipment to respond to a degraded grid
condition above the degraded grid relay setting of 3708 volts.
The
operators were to turn on the swing emergency diesel generator
cooling water pump and contact the load dispatcher to increase voltage.
The low voltage condition existed for approximately 1 1/2 hours
before identified by operators and the appropriate actions taken.
The low voltaoe condition was coincident with transfer from the
auxiliary unit transformer to the reserve unit transformer. Also,
at the time of the scram the swing diesel's water pump was being
powered from the Unit 2 power distr.ibution system, which does not
appear to suffer from this same low voltage condition when
transferring to its reserve unit transformer.
The original directive to the operators on this matter did not
consider transient conditions and was inadequate in this respect.
Subsequently, adequate instruction was placed in the scram response
procedure as an operator action to check 4160 bus voltage *
No violations or deviations were identified.
-
15
10.
Safety Assessment and Quality Verification (35502 and 40500)
a.
The inspectots reviewed the post trip investigatiori (PT!) report,
conducted per OAP 7-15, "Scram/Engineered Safety Features (ESF)
Actuation Investigation Program", Revision 3; following the June 9,
1991, reactor scram.
The reactor scram was the direct result of a
high reactor pressure condition following a turbine trip at 42%
power.
The turbine tripped during a test of the thrust bearing wear
- detector. Following the turbine trip there was an approximate two
minute window, prior to the reactor trip, during which the operator
inserted control rod HB to reduce reactor power and pressure. After
the root cause determination was completed by the licensee, the
inspector interviewed the investigation chairman, participating
operations engirieer, the reactor engineer, and the on-shift NSOs and
SCRE.
The PTI data indicated reactor power was approximately 42% prior to
- the turbine trip.
The plant has a bypass valve capability of 40%
load, plus an addttional 5% for station loads. After the turbine
trip all' the bypass valves opened fully. A loss of feedwater
heating resulted in a positive reactivity insertion and.an increase
in reactor pressure.
In this configuration, the plant was *operating
slightly above the bypass valve capability. After the high pressure
annunciation~ the SCRE directed the NSO to insert control rods.
The
NSO asked the SCRE whether he should use the CRAM arrays or reverse
sequence.
The SCRE directed him to use reverse sequence.
the next rod to be inserted per.the control rod sequence.
However,
the reactor scrammed prior to the full insertion of HB.
The PTI contributed the root cause of the event to instrument drift
of the thrust bearing wear detector.
The PTI indicated the scram
could have been prevented if the reactor power was lower
(approximately 300 Mwe).
The PTI did not consider the potential
effect of the use of £RAM arrays or reduction of recirculation flow
as a method to reduce power and avoid the scram.
The omission of
the potential use of CRAM array or recirculation flow reduction in
the PTI root cause investigation is considered a weakness in the trip
investigation report.
In a subsequent interview with operating authority management, the
inspector was informed that another r*eport was to be issued by
September discussing these aspects of the scram.
b.
On July 4, 1991, an automatic closure of two reactor water cleanup
(RWCU) Group III primary containment isolation valves (PCIV)
occurr-ed on Unit 2.
The isolation resulted from a RWCU non-
regenerative heat exchanger high pressure signal following ~ RWCU
pump trip caused by an electrical perturbation while changing the
open position indicating light bulb at the local control station for
the RWCU return valve.
On July 5, 1991~ after senior station
m~nagement reviewed the event during a routine planning meeting, the
determination was m~de that the automatic closure of the PCIVs did
. 16
constitute an ESF actuation.
The station subsequently made the
required NRC notification about 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> after the event.
actuations are required to be reported to the NRC within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
per. 10 CFR 50.72(b)(2){ii).
A previous violation of 10 CFR 50.72(b)(2)(ii) was issued
(50-237/90027-06(DRP)) for failure to make the four hour NRC
notification following an unplanned automatic clos~re of eight PCIVs
on December 8, 1990.
In response to the Notice of Violation, the
licensee issued a memorandum to the on-shift operating authority to
provide guidance on the definition of an ESF actuation. The
guidance defined an ESF actuation to fnclude any unplanned or
unknown occurrence involving the actuation of an ESF train~ which
results in the completion of desired repositioning of any pieces of
equipment.
However, in neither the December 8, 1990, nor the *
July 4, 1991, events, did the PCIV logic initiate. Both events
involved only the actuation of the end device.
NUREG-1022, Licensee
Event Report System, Supplement No. 1,Section II.6, clarified that
an ESF actuation includes any automatic, spurious, or manual *action
that results in the actuation of the device to perform its intended
function.
In both events, the intended ESF safety function was the
automatic closure of the PC!Vs.
.
'
Th~ inspector's interview determined.that the SCRE believed the
closure of the PCIVs did constitute ~n valid ESF actuation signal at
the time of the event. However, after consulting with off-shift
management, the decision was made. not to make the NRC notification.
This decision was based upon th~ closure initiation signal not
driven by the primary containment isolation system .. The SCRE was
unaware of the guidance provided in NUREG-1022 or the operations
memorandum *. Additionally, the SCRE had not receive any additiona 1
training on reportability and was unfamiliar with the December 8,
1990, event.
The Shift Engineer (SE) did review the operations
memorandum during the reportability evaluation process.
However,
the "guidance~ provided in the memorandum was confusing and the SE
concluded an ESF actuation did not occur *
. The failure to provide adequate corrective actions to prevent
recurrence of the previous violation is considered a violation of
(50-237/91022-lO(DRP)) 10 CFR 50, Appendix B, Criteria XVI.
c. *The inspectors performed an evaluation of the licensee's quality
assurance program implementation. This involved a review of the
licensee's Nuclear Quality Program (NQP) assessments and
surveillances, and Offsite Nuclear Safety Group functions. A
similar review of Onsite Nuclear Safety Group functions was
described in Inspection Report 50-237/91016(DRP);
~0-249/91016(DRP}.
The inspector reviewed NQP audit reports and verified that
~ppropriate corrective actions to findings were delineated and were
being tracked by both NQP and the plant Nuclear Tracking System (NTS).
17
Findings were assigned a status level that would change to ensure
greater management scrutiny if adequate corrective action *
implementation progres~ was not being accomplished. *In addition,
items greater than 60 days old were flagged in a special report.
Previous finding_s were also .incorporated into subsequent audits to
evaluate the effectiveness of completed corrective actions. Audit
planning was considered good in that related documents events and
personnel were reviewed and/or interviewed to identify specific
audit items.
In.addition, problems identified at other plants were
reviewed for inclusicin such as the Zion Diagnostic Evaluation Team
issues.
The inspector's review of specific findings determined the
licensee's shift to performance based audits to be beneficial in
identifying implementation problems.
Recent improvements in
tracking capabilities were also being utilized to identify problem
areas and to redirect resources. In addition to scheduled audits, *
special audits were performed.in suspect areas. The inspector noted
that team assessments previously conducted in different area~ at
various times during the year, were combined into one large yearly
assessment of a 11 areas conducted in January 1991.
Staffing levels
for the on~ite NQP group appeared adequate with individual
backgrounds from varying areas to ensure the ability _to provide
informed coverage of many disciplines.
Two of the thirteen onsite
NQP personnel were Seriior Reactor Operator (SRO) licensed and two
were SRO certified.
The Offsite Nuclear Safety Group (OFSG) responsibilitie_s were
delineated in Technical Specification 6.1.G.
The inspector regarded
recent OFSG findings and issues to be both relevant and a worthwhile
contribution toward safe plant operation.
However, the inspector
noted that safety evaluations for certain classes of procedures were
not being routed to the OFSG for review in accordance with the
requirements of Dresden Administrative Procedure (OAP) 9-02),
"Procedure and Revision Processing
11
, Revision 24, Step F.7.c.(4).
This.OAP had been previously changed in response to an early 1990
NQP finding of a similar nature, to require procedures which have a
completed Safety Evaluation Form 10-2C to be transmitted to OFSG.
In addition, the inspector noted that an OFSG review dated
October 1, 199Q, (OFSG Tracking No. 12-90-204) indicated that the
Unit 2 high pressure coolant injection (HPCI) steam line high flow
isolation differential pressure transmitter had not been calibrated
in two years and that no surveillance requirement existed.
The OFSG
participant for Dresden indicated that a review had been conducted for
similar instrument calibration problems but that none were identified.
Suggested corrective actions appeared specific to this type instrument.
A more generic issue* involving numerous instruments inappropriately
omitted from periodic surveillance calibration requtrements was
subsequently identified by the NRC and was the subject of a previous
vi6lation (50-237/91016-02(DRP)). Actions in response to the
previous OFSG issue did not identify the generic nature of the
18.
. .
'*
d.
.,
- i .*.
finding.
Both these issues are considered to be an unresolved item
(50-237/91022-ll(DRP)) pending completion and review of the
licensee
1 s. root cause analysis of the first corrective action
deficiency and further review of licensee actions regarding the
second.
The inspector noted that coordination of improvement fnitiatives
improved by the addition of an individual reporting directly to the
Jechnical Superintendent. This individual was responsible for
.development of the Dresden Management Action Plan including ensu~ing
timely implem~ntation of planned activitiei.
The inspector reviewed the licensee's tracking and resolution-of LER
actions *to *ass~ss managements effectiveness in this area.
The LERs
were reviewed for the nature of the event, the proposed corrective
action, the assignment qf .NTS.corrective action numbers, and the
overall abilityto consistently track.and update the status of
corrective action items.
Additional reviews included evaluation of
the adequacy of periodic updates on outstanding corrective actions
along with the length of time that specific corrective action items
- .remained open* or unresolved.
Of the seventy-one items reviewed, two
. ~ -
problems were noted:
LER 237/83-062 involved th~ Unit 2 HPCI motor gear unit (MGU)
which was observed to have been oscillating between the high
and low speed stops without operator action during a scheduled
HPCI surveillance test. Corrective action delineated in the LER
was tq modify the HPCI control system (Modification M12-2-83-54).,
which would replace the MGU signal converter containing a sensitive
operational amplifier and move the new amplifier to a less harsh
environment.
Latest up-dated corrective action as reported under
the NTS corrective action summary indicated that the modification
for replacement and relocation of the MGU signal conv~rter had
been canceled.
Nb notification to the NRC had been made in
regard to the change in LER corrective action commitme~ts.
Once identified to the licensee, the licensee stated that. a
r~vised LER would be submitted discussing the rational for
cancellation.of the modifi~ation.
An excessive implementation period was ideniified for the
corrective action itefus asso~iated with LER 237/88~013. LER
(237/88-013) resulted from a loss of power to an Analog Trip
System M~ster Trip Unit.
An outstanding commitment, resulting* .
from the corrective actions, involved the development of a
refetence guide.in order to determine the components affected
when fuses were removed from circuit panels.
The guide would
be an instructional tool for removing fuses *
Once identified to the l~censee, th~ guide w~s completed and
was in the procedure review cycle by the end of the inspection
period.
One viola.tion .and no deviations. were identified in this area.
19
11 *. Report Review
During the inspection period, the inspector reviewed the licensee's
Monthly Operating Report for July 1991. The inspector confirmed that the
information provided met the requirements of Technical Sp~cification
6.6.A.3 and Regulatory Guide 1.16. The inspector also reviewed the
Dresden Nuclear Power Station Monthly Plant Status Report for June 1991.
No* violation$ or deviations were identified.
12 *. Violations For Which A "Notice of Violation" Wi 11 Not Be Issued
The NRC uses the Notice of Violation as a standard method for formalizing
the existence of a violation of a legally binding requirement.
However,
because the NRC wants to encourage and support licensee's initiative~ for*
self-identification and correction of problems, the NRC will not
generally issue a Notice of Violation for a violation that meets the
requirements set forth in 10 CFR 2~ Appendix C,Section V.A.
A violation
of regulatory requirements identified during the inspection for which a
Notice of Violation will not be issued is discussed in paragraph 4.d.
13.
Unresolved Items
Unresolved items are m~tters which require more information in order to
ascertain whether it is an acceptable item, an open item, a deviation or
a violation. Unresolved items disclosed during this inspection are.
discussed in paragraphs 4.b., 4.c., 5, 6.c., and 10.c.
14.
Open Items
Open items are matters which: have been discussed with the licensee;
will be further reviewed by the inspector; and whiCh involved some actions
on the part of the NRC, licensee, or both.
Two open items disclosed
during th inspection are discussed in paragraph 4.d.
15.
Exit Interview
lhe inspectors m~t with licensee representatives (denoted in paragraph 1)
during the inspection period and at the conclusion of the inspection
period .on August 22, 1991.
The inspectors summarized the scope and
results of the inspection and discussed the likely content of this
inspection report.
The licensee acknowledged the information and did not
indicate that any of the information disclosed during the inspection
could be considered proprietary in natur~.
20
Docket No. 50-237
Docket No. 50-249
Commonwealth Edison Company
ATTN:
Mr. Cordell Reed
Senior Vice President
Opus West II I
1400 Opus Place
Downers Grove, IL
60515 *
Dear Mr *. Reed:
This refers to the routine safety inspection conducted by W. Rogers, D. Hills
M. Peck, R. Greger, P. Rescheske, M. Kunowski and N. Shah of this office and
assisted by R. Zuffa of the Illinois Department of Nuclear Safety on June 29
through August 22, 1991, of activities at Dresden Nuclear Power Station, Units
2 *and 3 authorized by NRC Operating License Nos. DPR-19 and DPR-25 and to the*
discussion of our findings with Mr. E. Eenigenburg and others at the
conclusion of the inspection.
The enclosed copy of our inspection report identifies areas examined during
the inspection. Within these areas, the inspection consisted of a selective
examination of procedures and representative records, observations, and
interviews wtth personnel.
During this inspection, certain of your activities appeared to be in violation
of NRC requirements, as described in the enclosed Notice. A *written response
is required.
However, because the NRC wants to encourage and support
licensee's initiatives for self-i~entification and correction of problems, the
NRC will not gen~rally issue a Notice of Violation for a violation that meets
the requirements of 10 CFR 2, Appendix C, Section V.A.
This is the case with
the violation discussed in paragraph 4.d of the enclpsed inspection report.
If you do not agree with our statement of your corrective actions, you are
requested to inform us, in writing, within 30 days of the date of th.is le.tter.
Otherwise, no reply to the violation is required and we have no further
questions regarding this matter at this time.
In accordance with 10 CFR 2.790, of the Commission's regulations, a copy of
this letter and the enclosure(s) will be placed in the NRC Public Document
Room.*
The responses directed by this letter (and the accompanying Notice) are not
. subject to the clearance procedures of the Office of Management and Budget as
required by the Paperwork Reduction Act of 1980, PL 96-511.