ML20246K756
| ML20246K756 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 06/27/1989 |
| From: | Robert Carrion, Kellogg P, Schin R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20246K717 | List: |
| References | |
| 50-302-89-14, NUDOCS 8907180255 | |
| Download: ML20246K756 (19) | |
See also: IR 05000302/1989014
Text
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UNITED STATES
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NUCLEAR REGULATORY COMHisSION
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REGION 11
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101 MARIETTA STREET,N.W.
ATLANTA, GEORGf A 30323
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Report No. 50-302/89-14
Licensee:
Florida Power Corporation
3201 34th Street South
St. Petersburg, FL- 33733
Docket No.
50-302
Ucense No. DPR-72
Facility Name: Crystal River 3
Inspection Conducted: May 3 - June 2, 1989
Inspectors:
7b S3 i Wy
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R. 'Schin
Date. Signed
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R. Ca'rrion
Date Sfgned
Approved by: ,
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P. 'Kellogg, Chief
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Operational Programs Section
Operations Branch
Division of Reactor Safety
SUMMARY
Scope:
This was a special announced reactive inspection to review an event of May 29,
1989.
In that event, Emergency Feedwater piping and a containment penetration
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were heated above design limits and unanalyzed thermal stresses were imposed
on the A steam generator.
The event occurred with the plant in Mode 5 on
Decay Heat Removal cooling, and with no reactor coolant pumps operating. The
purpose of this inspection was to assess:
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1.
Potential damage, by physical inspection of affected piping and
equipment and by review of engineering evaluations.
2.
Written procedures for adequacy, by review of operating procedures
and system drawings and by interviewing operators.
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3.
Operator use of procedures, by review of logs and records relating
to the event and by interviewing operators.
4.
Cor.ective actions taken by the licensee.
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Results:
The inspection results are summarized as follows:
1.
There was no apparent damage to safety equipment as a result of this
event.
One incorrect drawing of a pipe support and one improperly
stored. piping swing connection were identified by the inspectors.
Control of pipe support drawings .is an unresolved item.
(paragraph 6.)
2.
Written operating procedures were inadequate to prevent overheating
of the EFW piping and containment penetration, and also to prevent
the imposition of unanalyzed thermal stresses on the A steam
generator.
(paragraph 5.)
3.
Operator use of procedures was also inadequate.
Procedures that did
exist were not-reviewed by the operators.
This was a contributing
factor to the event.
(paragraph 4.)
4.
Corrective actions taken or planned by the licensee at the time of
the inspection were incomplete.
The licensee had not identified the
full scope of weaknesses in operating procedures.
Also, the
licensee had not identified any weaknesses in operator use of
procedures.
(paragraph 8.)
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- Unresolved items are matters where more information is required to determine
whether they are acceptable or may involve violations or deviations.
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REPORT DETAILS
1.
Persons Contacted
Licensee employees
- T. Austin, Principal Mechanical Design Engineer
- W. Bandhauer, Nuclear Operations Superintendent
- R. Fuller, Senior Nuclear Licensing Engineer
- F. Fusick, Supervisor, Mechanical Design
- B. Hickle, Manager, Nuclear Plant Operations
- W. Marshall, Nuclear Operations Superintendent
- W. Rossfeld, Manager, Nuclear Compliance
R. Widell, Director, Nuclear Operations Site Support
- M. Williams, Nuclear Regulatory Specialist
Other licensee employees contacted included operators, engineers, and
office personnel.
NRC Representatives
- P. Holmes-Ray, Senior Resident Inspector
- A Tedrow, Resident Inspector
- Attended exit interview
Acronyms used throughout this report are listed in Attachment 7.
2.
General Description of the Event (93702)
This event occurred with the unit in Mode 5, with a steam bubble in the
pressurizer and no RCPs operating.
Operators were maintaining RCS
pressure at about 160 p(sig (by using pressurizer heaters) and temperature
at about 90 degrees F by using DHR cooling).
Pressurizer level and RCP
seal flows were being maintained by the makeup system.
The DHR system
was taking a suction from RCS loop B hot leg (this is the only DHR
suction connection to the RCS) and discharging int'o the reactor vessel
through the core flood nozzles.
The DHR flowpath is shown in Attachment
1, Reactor Coolant drawing and Attachment 2,
DHR drawing.
Steam
generators were in wet layup.
Unit startup was delayed by the
unavailability of auxiliary steam, pending repair and startup of one of
the coal fired power plants on site.
To save time during the forthcoming unit startup, operators began
degassing of the RCS by initiating pressurizer spray from the DHR system.
The spray flowpath is shown in Attachments I and 2.
As a result of this
spray flow, hot water (approximately 350 degrees F) flowed .out of the
pressurizer through the surge line and into the lower part of the hot leg
of the A loop.
This flowpath is shown in Attachment 1.
The hot water
then rose through the stagnant cooler water in the A loop, past the wide
range T hot detector, to the top of the hot leg and the top of the A
The elevations are shown in Attachment 3, Reactor
Coolant Piping Assembly Elevation drawing.
Thus the top of the A steam
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generator was heated.
Operators were not aware of the increasing A loop
hot leg temperature and began recirculating the secondary side of the A
steam generator using a chemical recirculation pump.
Periodic recircula-
tion of steam generators is routinely done for chemistry control when'the
steam generators are in wet 9ayt7. The pump took a suction from the steam
generator blowdown piping and discharged through a spoolpiece connection
to the Emergency Feedwater piping and back into the steam generator.
The flowpath is shown in Attachment 4, Main and Reheat Steam drawing;
Attachment 5, Chemical Cleaning Steam Generators drawing; ond Attachment 6
Feedwater drawing.
Portions of the EFW piping including EFW containment penetration 424 were
heated to 222 degrees F, which is above their design temperature of 150
degrees F.
Also, the A steam generator was subjected to a thermal
gradient of about 270 degrees F, from top to bottom, for which it had not
been analyzed.
A total of approximately 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> elapsed from the time
that pressurizer spray flow was started until it was stopped upon
discovery of the overheating problem.
Three different shift crews of
operators were involved, including a total of six licensed R0s and six
licensed SR0s.
3.
' Detailed Sequence of Events (93702)
Time
Data Source
Item
0000,
SS Log
Shift turnover plant status: Mode 5, RCS at 93
May 28
degrees F and 158 psig, A DHR train operating
0015
R0 Log
Started pressurized spray per EQ 89-1521
0556
R0 Log
Started B OTSG on recirc
0800,
SS Log
Shift turnover plant status: Mode 5, RCS at 90
May 28
degrees F and 167 psig, A DHR train in service
1600,
SS Log
Shift turnover plant status: Mode 5, RCS at 91
May 28
degrees F and 160 psig, A DHR train in service
1650
R0 Log
Started A OTSG on recirc, secured B OTSG
0000,
SS Log
Shift turnover plant status: Mode 5, RCS at 92
May 29
degrees F and 165 psig, A DHR train operating
prior
Interviews
An R0 on shift was performing an instrument
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to 0440
calibration check PT that was required for entry
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into Mode 3.
This lead him to discover that the
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RCS A loop T hot was reading high (approximately
350 degrees F). The licensed operators on shift
(2 SR0s and 2 R0s) were surprised that A loop
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T hot temperature was high.
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0440
R0 Log
Stopped pressurizer spray
0440
Interviews
The SS was concerned about a possible steam
bubble in the top of the A loop hot leg.
Operators increased pressurizer pressure by
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about 20 psig.
Steady levels in the pressurizer
and makeup tank indicated to them that there had
been no steam bubble in the A loop.
.
0500
NCOR 89-124
Containment penetration #424 (EFW) temperature
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and
was found to be 222 degrees F, which exceeded
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Interviews
the design limit of 150 degrees F.
This was
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discovered by an R0, who went out in the plant
to read the local temperature indicator for-
penetration #424. This temperature-instrument
had recently been installed, as a result of-
overheating the B OTSG EFW containment
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penetration last year.
0600
NCOR 89-124
The NCOR was completed and signed by the SS.
and
The SS had &cided that no 10CFR50.72 telephone
Interviews
. report to the NRC was was required and had so
indicated on the NCOR.
about
Interviews
Oncoming SS questioned deportability of the event
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0800
about
Interviews
Penetration #424 temperature was down to about
0830
150 degrees F.
about
Interviews
An ad hoc management group, including Operations
0945
and Compliance, decided that the event was
reportable as a four hour report.
0951
SS Log and
The NRC was notified of the event via ENS phone,
NCOR 89-124
under 10CFR50.72B21.
4.
Operator Use of Procedures (93702)
The inspector asked the licensee to have copies of all operator logs,
procedures, and drawings that related to this event available upon arrival.
With only a few hours of advance notice, the licensee did have most of
these records available when the inspector arrived on site. The Operations
- Superintendent and Principal Mechanical Design Engineer reviewed these
records with the inspector, along with the sequence of events and current
status.
The inspector noted that the R0 Log entry of 0015 on May 28 stated that
operators started pressurizer spray per EQ 89-1521.
EQ 89-1521 was a
question from operators with a written response from Engineering.
The
question was:
Currently the pressurizer temperature is approximately 270 degrees F
higher than the RCS temperature.
Operations would like to initiate
pressurizer spray to assist in the removal of non-condensibles from
the RCS.
Is there any engineering concern with this?
The response addressed the plant heatup procedure limit of 250 degrees F
delta T for use of pressurizer spray.
It also addressed minimum spray
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flow needed to assure that surge line stratification would not occur.
The engineering response concluded that. spray from DHR with the existing
270 degrees F delta T presented no thermal shock concern as long as no
heatup was in progress.
It also concluded that a spray flow of at least
20 gpm was needed .to prevent thermal stratification in the surge line.
The inspector found that EQ 89-1521 provided a good basis for making a
permanent change to plant operating procedures.
But it was not a
procedure:
it did not have the required review and approval, nor was it
written in the required format of a procedure.
Also, it did not contain
adequate action steps, initial conditions, limits, or cautions.
The
inspector's subsequent review of procedures and interviews with operators
revealed that' the operators did not use this EQ to change an operating
procedure.
The inspector concluded that operators had used EQ 89-1521 in
place of a procedure, just as recorded in the R0 Log.
The licensee showed the inspector copies of procedures that they stated
were used during this event.
The inspector noted that all of these
procedures contained signature blanks by each step.
The inspector then
asked for copies of the signed off procedures that were actually used by
the operators to initiate DHR spray flow.
The licensee was unable to
provide the signed off copies, because they did not exist.
In subsequent
interviews, the SS on shift when the spray flow had been initiated stated
that operators had not gotten out any written procedures for initiating
DHR spray flow to degas the RCS.
The SS stated that this was a simple,
routine evolution and as such a written procedure was not required to be
present or to be signed off.
The Operations Superintendent supported
this policy expressed by the SS.
The inspector reviewed the operating
procedures that the SS stated provided authorization for initiating :: pray
from DHR, and cJncluded that if the operators had gotten these procedures
out and read them, they would have been alerted to watch for increasing
temperatures in the A hot leg.
In response to further inspector
questions, the SS stated that he had never before personally degassed the
Also, he did not know anyone who had done
this evolution.
The Operations Superintendent stated that when he had
asked operators to show which procedures they had used te initiate spray
from DHR to degas the RCS, the operators had difficulty in locating such
procedures.
They were surprised to find that the Plant Heatup procedure
did not address initiating spray from DHR.
The inspector concluded that
operator failure to review existing procedures was a contributing factor
to this event.
This failure to have procedures present is an example of
violation 302/89-14-01.
The Operations Superintendent stated that degassing the RCS from DHR
spray was a routine evolution, and had been done many times to expedite
plant heatup.
He stated that a number of operators had done it and knew
from experience that high temperatures in the A loop hot leg were to be
expected.
The inspector found that degassing of the RCS by using DHR
spray is not described in the Plant Heatup procedure, nor in any other of
the licensee's procedures.
Use of DHR spray, for pressure control, is
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addressed in only one general operating procedure, Plant Cooldown.
The
inspector concluded that operators had previously performed this
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evolution without having an adequate procedure.
Other statements were made by the SS and Operations Superintendent that
were of some concern to the inspector, such as:
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Ifjaction steps (such as ' egassing the- RCS using DHR spray) are not
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. included in a procedure (Plant Heatup), but also are not- prohibited
by~ that pro'cedure, it is still allowable for operators to perf orm '
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such. steps on safety equipment.
Individual : procedures do not ' stand on their .own; instead. plant
. conditions flow from one'. procedure (ie. Plant Cooldown) to' the .next
(ie. - Plant. Heatup).
Therefore, while in one general' procedure
-(Plant Heatup), . the operators may' select and perform action steps
z(such as initiating DHR spray) from another . procedure (Plant
Cooldown) even though these steps. are not referenced from the main
(Plant 'Heatup) procedure in use.
The inspector expres,e
a concern about operation of the plaht without .
using approved procs,
He asked to see the licensee's rules on use
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of procedures.
The inspector reviewed administrative instruction'
AI-400E,' Performance and Transmittal of Procedures, Revision 1, and found
that it did address requirements that had to be met before a plant
operation could be performed without having.a procedure present.
The
inspector discussed this further with' the Operations Superintendent, and
the licensee elected to initiate prompt corrective action .for operators
not adequately using procedures.
This corrective action was in the form
of a written Short Term Instruction to operators, which emphasized and
clarified the administrative instruction.
The Short Term Instruction
stated that either the operating procedure must be' present or the-
following conditions must be satisfied:
The steps must be routine procedural action that is frequently
repeated.
Also, the procedure performer must have personally
performed or directly observed the applicable procedure steps within
a reasonable time period.
In addition, the procedure performer must be able to recall from
memory:
the procedure steps, all aplicable limits and precautions,
and plant conditions required by the procedure.
The licensee issued the Short Term Instruction prior to the completion of
.this inspection.
They stated that all operators will be required to read
and sign it as they go on shift.
In addition, shift supervisors will
,
review it in pre-shift briefings to operators.
One violation was identified in this area.
5.
Adequacy of Procedures (93702)
The ,0perations Superintendent stated that the licensee wanted to continue
the practice of degassing the RCS using DHR spray, with the unit in Mode 5.
The inspector reviewed OP-202, Plant Heatup, Rev. 80. The stated purpose
of the procedure is for plant heatup from cold shutdown or refueling
shutdown condition (Mode 5 or 6) to 532 degrees F (Mode 3). OP-202 does
not provide for degassing the RCS by using spray from DHR.
It does address
degassing the RCS in Mode 4 with RCPs operating.
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The SS stated 'that OP-209, Plant Cooldown, Rev. 66 provided authority for-
degassing the RCS by- using spray from DHR while in Mooe 5.
The
inspector found that OP-202 does not refer to 0P-209 for these steps.
The inspector reviewed OP-209 and found that it does - not rddress
degassing the RCS by using DHR spray.
It does address use of DHR spray
for pressure control.
During the plant cooldown, OP-209 directs
operators to align DHR cooling and to start a DHR train per OP-404.
OP-404 Decay Heat Removal System, Rev. 73 aligns pressurizer auxiliary
spray from DHR for operation.
OP-209 then stops RCPs and presents two
notes:
NOTE: RCS pressure control is now through the use of pressurizer
heaters and auxiliary spray valve, RCV-53.
NOTE:
Hot leg flashing may occur due to pressurizer outsurge to hot
leg caused by contraction from cooldown or pressurizer spray.
Neither OP-209 nor 0P-404 contains any conditions, cautions, or limits to
prevent heating the EFW piping and its containment penetration beyond
design limits or to prevent subjecting the A steam generator to
unanalyzed thermal stress.
In fact, the A steam generator m6y have been
subjected to such unanalyzed thermal stresses in the past.
Throughout this event, the - applicable general operating . procedure was
OP-202, Plant Heatup, Rev. 80.
Also, that procedure did not adequately
address using DHR pressurizer spray control to degas the RCS while in
Mode 5.
The inadequacy of OP-202 to prevent heating the EFW piping and
containment penetration #424 beyond design limits and to prevent subjecting
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the A steam generator to unanalyzed thermal stresses is identified as as
an example of violation 302/89-14-01,
6.
Physical Inspection of Affected Piping (93702)
Because the portions of the EFW line and the related containment penetra-
,
tion were heated above ' design temperatures, the inspector was concerned
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about possible damage to the piping, its respective supports, and the
Therefore, the inspector performed a physical inspection of
the components that were potentially heated beyond design limits.
These
included' the EFW line inside the Reactor Building from penetration 424 at
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elevation 118'-2" to the vertical run of pipe at elevation 112'-0", where
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pipe supports EFH-118A and EFH-119A attach to the pipe.
In addition to
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the two referenced supports;
the pipe, the inboard portion of the
penetration, and pipe support EFH-115 were visually inspected by the
inspector for evidence of degradation, failure to function as designed,
and any other detrimental effects due to operation at elevated
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tempera tures.
Although minor paint flaking and oxidation were noted on
the penetration and pipe support attachments, the inspector observed no
abnormalities.
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The inspector also visually inspected the EFW line outside the Reactor
Building from the penetration to the first pipe support, EFH-134, located
about 15 feet upstream of penetration 424.
The inspector noted that the
chemical cleanup line, through which the steam generator recirculation
operation was conducted, discharges into the EFW line within two feet of
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penetration 424 via a removable spool piece and that there is a check
valve, FWV-44, immediately upstream to prevent flow from backing up into
the EFW line.
Therefore, essentially the only section of the EFW line
outside the Reactor Building that was exposed to elevated temperatures
was the short length (less than three feet) between the check valve and
the penetration.
As inside the Reactor Building, the inspector noted
similar. minor point flaking and oxidation on the penetration and pipe
support attachment, but no abnormalities.
One questionable practice was observed by the inspector during this
walkdown.
That is, the removable spool piece had been placed onto a
Snistrut frame, CSI 95130, near where-it is normally used.
It was held
in place by being tied to the unistrut by two large-gauge wires. Although
no safety-related equipment or piping was observed in the immediate
vicinity, a falling spool piece could nevertheless cause damage to itself
as well as adjacent piping, which could result in operational delays /
inconveniences.
The' licensee agreed with this assessment and committed
to promptly remove the spoolpiece froth the plant.
In additic
the
licensee stated they would review procedures for spool piece L ,orary
storage requirements while in the plant, and for ensuring timely return
to the warehouse for controlled storage. This information will be reviewed
by the NRC Resident Inspector.
Also, as a result of the walkdown, the inspector noted that support EFH-74,
which appeared on orthographic drawing P-304-091, Revision 1, was not
installed.
Further investigation determined that it had been deleted
per FCN No. 6A, written against MAR 88-07-11-02.
The licensee had
performed the- work in the field, but the information had not been
incorporated into the appropriate orthographic drawing.
The inspector
noted that technically the drawing which was to incorporate the latest
revisions had not been signed off.
However, the licensee engineer
assisting the inspector expressed a high degree of confidence that the
latest drawing revision would show the support as being deleted and was
surprised to find that the deletion had not been incorporated.
The
drawing had already been through several levels of review and the
licensee engineer felt the probability was high that this error would
have remained through final drawing approval and issuance. To assure that
this situation is rectified, the licensee issued FCR 11, written against
the above-referenced MAR and drawing.
To assure that this case is
isolated and not symptomatic of a larger problem with control of design
documents, the licensee committed to reviewing a sample of 10 similar
recent design mo.iifications for piping restraints, to check for
completeness of incorporating new information in plant drawings.
The
results of this review will be shown to the NRC Resident Inspector.
Pending completion of this review, this item is identified as
UNR 50-302/89-14-02.
7.
Review of Engineering Evaluations (93702)
The inspector reviewed licensee engineering evaluations concerning the
affect of operating the EFW line at elevated temperatures and its
potential
for system deg radation.
He reviewed Calculation
No. 5510-716-PAC-2, which is part of the "EFW System Thermal Upgrade
Analysis", which assumes operating temperatures of 600 degrees F at the
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top of the steam generator to 200 degrees F at the inboard side of penetra-
tion'No. 424.
The penetration consists of a 14" sleeve and 2" thick end
plate inside the Reactor Building. A 6" Schedule 160 process pipe passes
through the center of the sleeve and end plate.
Welded lugs secure the
sleeve to the concrete containment wall.
A 3/4" plate is welded on the
sleeve to provide a closure plate to facilitate testing of the penetration.
The 3/4" plate is not considered part of the containment boundary, and is
not -credited as a pipe support in the piping analysis.
The analysis
included the supports for the EFW line inside the Reactor Building and the
calculations for the three supports inspected during the walkdown.
The inspector also reviewed calculation No. DC-5510-707.19.2, Revision 1,
entitled, " Penetration X-109 Investigation - Stress Evaluation," which
evaluated the structural effects on the penetration due to a temperature
gradient of 300 degrees F imposed on the process pipe.
This calculation
was chosen for review by the inspector because this penetration is
identical to Penetration No. 424 and the temperature differential is much
more severe,
It concluded that the 3/4" thick closure plate located on
the outboard end of penetration 109 was stressed beyond its elastic limit
into the plastic range.
This mechanical behavior thereby relieved the-
thermal loads while assuring containment isolation via the 2" thick
plate, which remained in the elastic range.
The inspector reviewed two
additional calculations, DC-5515-704.7,0-SE, Revision 0,
entitled,
" Penetration No. 424 Elevated Temperatu re" and DC-5515-704. 7,0-P E,
Revision 0, entitled, " Penetration No. 424 Temperature Analysis."
These
two calculations were initiated specifically to evaluate the high
temperature event identified on May 29, 1989.
The logic used for these
two calculations is the same as that used for DC-5510-7/ 7.19.2, for
/
penetration 109.
The calculations concluded that the 3/4' thick closure
plate of Penetration No. 424 was stressed into the plastic range by the
elevated temperatures, allowing relief of the thermal stresses, while the
2" thick plate remained in the elastic range and continued to assure
containment isolation.
The concrete adjacent to the penetration was not
adversely affected because the penetration temperature did not exceed the
guidelines of the American Concrete Institute as outlined in Appendix A
of ACI 349/359, which allows localized concrete temperatures adjacent to
penetrations to be 200 degrees F for long time periods and 350 degrees F
for short emergency periods.
The calculations all appeared to be professionally done, utilizing
applicable codes and standards, reasonable assumptions, and conservative
judgment.
They concluded that no damage was done to the EFW piping, pipe
supports, or containment penetration 424.
FPC asked Babcock and Wilcox (B&W) to conduct an analysis regarding the
effects of the differential temperature on the "A"
0TSG.
Specifically,
B&W was asked:
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Is there a differential growth between the
"A" hot leg and the
OTSG/Rx Vessel that would cause any concern?
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Is there a delta T concern across the OTSG axially or tube to shell
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that is considered detrimental?
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When secondary recirculation was in progress and downcomer
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temperature was at 240 degrees F, was there a problem ecross the
lower tube sheet?
B&W responded verbally via telecom that due to the low power / temperature
levels at the time of the excursion, there were no detrimental effects.
However, they requested more time to undertake a more detailed evaluation
of the event.
The licensee stated that they would review the
forth-coming information with the NRC Resident Inspector.
No violations or deviations were identified in this area.
8.
Reporting of the Event (93702)
The inspector reviewed the licensee's reporting of this event to the NRC
for timeliness and adequacy.
The discovery that EFW containment
penet ration 424 had been heated beyond its design temperature occurred at
0500 en May 29.
The NRC was notified at 0951, four hours and fifty one
minutes later.
The event was reported under the requirements of
10 CFR 50.72(b)(2)(1), which requires reporting within four hours.
The
SS had completed the NCOR form on the event at 0600. He had decided that
no telephone report to the NRC was required, and had so indicated on the
NCOR.
Later, at about 0945, a group of licensee management personnel
decided that the event was reportable and the 0951 phonecall to the NRC
was made.
The inspector concluded that, since deportability requirements
for this event were not immediately clear and obvious, the timeliness of
the licensee's reporting was adequate.
The event was reported under 10 CFR 50.72(b)(2)(1), which requires the
reporting of:
Any event, found while the reactor is shut down, that, had it been
found while the reactor was in operation, would have resulted in the
nuclear power plant, including its principal safety barriers, being
seriously degraded or being in an unanalyzed condition that
significantly compromises plant safety.
The licensee's management group decided the event was reportable, because
it could have gone undetected.
No plant procedures would have assured
the detection of the overheating of the EFW piping or the imposition of
unanalyzed thermal stresses on the A steam generator.
The high RCS A
loop T hot reading was discovered by luck:
an R0 was performing a PT
ahead of schedule.
Thus the licensee could have potentially subsequently
operated the unit at power in an unanalyzed condition, without knowing
that possible damage or weakening had been done to the EFW piping,
containment penetration 424, or the A steam generator.
Based on this
I
conservative evaluation of the event, the licensee correctly classified
and reported it to the NRC.
No violations or deviations were identified in this area.
l
_ ______ _ _-
_ _ ___ - _-__.
_ _
- _ _ _ _ _ _ _ _ _ _
_ _ _ _ _ _ _ _ _
__
_
_
._
_ _ _ - . _ _ - _ _ _ _ - - -
.
.- . . .
10
9.
Corrective Actions (93702)
The inspector assessed the corrective actions taken or planned by the
licensee at the time of this . inspection.
The licensee had begun to
assess damages:
they had performed a physical inspection of the
affected equipment and had initiated engineering evaluations for the
containment penetration and steam generator.
The licensee's identification of the root cause of the event, however,
was incomplete.
They had determined that a problem existed with
operating procedures, but only for the unique situation of degassing the
RCS using DHR sprey while at the same time recirculating the secondary
side of the A steam generator.
They had not identified the lack of
procedures for degassing the RCS using DHR spray nor the fact that this
evolution, and resultant unanalyzed thermal stresses on the A steam
generator, may have occurred previously.
The licensee also had not
identified any weaknesses in operator use'of procedures in this event.
Insufficient time had elapsed for the licensee to complete a formal
investigation of the event.
Nonetheless, the inspector found that the
licensee's initial investigation into the root cause of this event was
weak.
No violations or deviations were identified in this area.
10.
Exit Interview (30703)
The inspection scope and findings were summarized on June 2,1989, with
those persons indicated in paragraph I above.
The team described the
areas inspected and -discussed in detail the inspection results listed
below.
Item Number
Status
Description / Reference Paragraph
302/89-14-01
OPEN
VIOLATION - Inadequate procedures and
failure to follow procedures, paragraphs
4. and 5.
302/89-14-02
OPEN
UNRESOLVED - Control of drawings for pipe
supports, paragraph 6.
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,,
-
ATTACHMENT 7
ACRONYMS-
- American Concrete Institute
- Design Calculations
- Emergency Feedwater
- Emergency Notification System
- Engineering Question
F
- Farenheit
- Field Change Notice
FCR
- Field Change Request
- Florida Power Company
- Modification Approval Record
NCOR - Non Conformance Operating Report
NRC
- Nuclear Regulatory Commission
OTSG - Once Through Steam Generator
- Performance Test
- Reactor Coolant Pump
R0
- Reactor Operator
- Shift Supervisor
T
- Temperature
.
1
- _ - _ _ _ _ _
_
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