ML20195J656
| ML20195J656 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 11/17/1988 |
| From: | Chamberlain D, Will Smith, Staker T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20195J648 | List: |
| References | |
| 50-382-88-25, NUDOCS 8812020305 | |
| Download: ML20195J656 (16) | |
See also: IR 05000382/1988025
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V. S. flVCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report:
50-382/88-25
Operating License:
Docket:
50-382
Licensee:
Louisiana Power & Light Company (LP&L)
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142 Delaronde Street
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New Orleans, Louisiana
70174
Facility Name: Waterford Steam Electric Station, Unit 3
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Inspection At:
Taf t, Loii::,iana
Inspection Conducted:
September 17 through October 31, 1988
Inspectors:
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W. F. Smith, Senior Resident Inspector
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T. R. St'akerVResident Inspector
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Approved:
D.'D. Thamberlain, Chief, Project Section A
Date
Division of Reactor Projects
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Inspection Summary
Inspection Conducted September 17 through October 31, 1988 (Report 50-382/88-25)
Areas Inspected: Routine, unannounced inspection of: (1) plant status,
(2) onsite followup of events, (3) operational safety verification, (4) monthly
maintenance observation, (5) monthly surveillance observation, (6) followup of
previouslyidentifieditems,(7)licenseeeventreportfollowup,and(8) plant
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status.
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Results:
In the previous inspection period, as discussed in NRC Inspection
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Report 50-382/88-21, the NRC inspectors identified a number of examples which
reflected weaknesses in the licensee's corrective action programs.
This report
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discusses additional problems encountered as a result of inadequate and
untimely corrective action. While it is understood by the NRC staff that this
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is a complex problem that will have a complex and time-consuming solution, the
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licensee should recognize that management emphasis must be placed on a priority
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basis to get this program under control as soon as possible.
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There are also examples where -licensee actions to achieve compliance to, and
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adequacy of, procedures apparently'have not reached all disciplines. There was
one violation identified in this area. The violation involved failure to
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follow procedures. A Safety Injection Containment isolation valve bypass,
required by procedure to be locked closed, was found unlocked.
One new ur. resolved item was identified in paragraph 3.a. requiring further
review to determine whather there was a violation of NRC regulations requiring
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a Notice of Violation to be issued pending review of the Architect-Engineer's
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analysis on whip restraints which did not meet design requirements.
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DETAILS
1.
Persons Contacted
LP&L
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- R. P. Barkhurst, Vice President, Nuclear Operations
- N. S. Carns, Plant Manager, Nuclear
S. A. Alleman, Nuclear Quality Assurance (QA) Manager
P. V. Prasankumar, Assistant Plant Manager, Technical Support
D. F. Packer, Assistant Plant Manager, Operations and Maintenance
J. J. Zabritski, QA Manager
D. E. Baker, Manager, Nuclear Operations Support and Assessments
J. R. McGaha, Manager, Nuclear Operations Engineering
W. T. Labonte, Radiation Protection Superintendent
- G. M. Davis, Manager, Events Analysis Reporting & Responses
- L. W. Laughlin, Onsite Licensing Coordinator
D. W. Vir.ci, Maintenance Superintendent
A. F. Burski, Manager, Nuclear Safety and Regulatory Affairs
R. S. Starkey, Operations Superintendent
- R. L. Azzarello, Modification Control Manager
^Present at exit interview.
In addition to the above personnel, the NRC inspectors held discussions
with various operations, engineering, technical support, maintenance, and
administrative members of the licensee's staff.
2.
Plant Status (71707)
At the start of the inspection period, on September 17, 1988, the plant
was operating at 90 percent power.
This power level was being maintained
in order to minimize possible damage from noise believed to be originating
from the No. 2 Steam Generator.
On September 23, the plant was shut down to hot standby (Mode 3) to
install instrumentation for the No. 2 Steam Generator noise investigation.
The plant was back on the grid by September 25 and at 90 percent power by
September 26.
On September 29, 1988, power was increased to 100 percent
to take noise data and then returned to about 90 percent power.
Thv. No. 2 Turbine Governor Valve failed shut with No. 1 already shut on
October 20, 1988.
Consequently, power was reduced and maintained at
75 percent.
The plant was shut down and cooled down on October 21, 1988, in order to
investigate the No. 2 Steam Generator noise.
The plant entered Mode 5 on
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October 22, 1988, and remained in Mode 5 while finding and correcting the
source of the noise in No. 2 Steam Generator.
See paragraph 3.b of this
report.
Preparations for startup were underway at the end of the inspection
period; however, preparations were halted when Reactor Coolant Pump 28
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shaft seal exhibited staging problems and had to be replaced.
This will
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be discussed in the next resident inspectors' report.
No violations or deviations were identified.
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3.
Onsite Followup of Events (93702)
a.
Missing Seismic Restraints in CPC Panels
During an exit interview conducted by the resident inspectors on
September 23, 1988, the NRC inspectors reiterated earlier concerns
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over the licensee's failure to implement timely corrective action
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after a nonconforming condition was identified on safety-related
equipment.
The details of these concerns were documented in NRC
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Inspection Report 50-382/88-21.
In response, the licensee conducted
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reviews of all open nonconformance condition identification (NCI)
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reports to ensure that there were no other problems that should have
been corrected earlier.
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On September 29, 1988, the licensee found NCI-256700, dated June 15,
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1988, which identified missing seismic restraints on the fixed incore
amplifier (FICA) drawers located in Bays A, B, C, and D of Core
Protection Calculator (CPC) Panel CP-22 in the control room.
Upon
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reviewing available documentation related to the restraints and
discussing the problem with the NSSS contractor, Combustion
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Engineering Corporation, the licensee concluded that the restraints
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must be installed, and without them, the CPCs might not function as
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designed in the event of a seismic event.
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At 6:20 p.m., the shift supervisor was informed of the problem.
Technical Specification (TS) 3.3.1 requires at least two CPC channels
to be operable when the plant is in Modes 1 or 2 (reactor critical
and/or at power).
The other two channels must be in bypass and
tripped respectively.
This action statement could not be met.
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6:20 p.m., the licensee entered TS 3.0.3 which required shutdown of
the reactor to be commenced within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
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The NPC senior resident inspector was onsite and was kept informed by
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the licensee as the problem developed.
At about 7 p.m., the licensee
held a conference telephone call with NRC Region IV management and
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requested enforcement discretion to allow continued operation of the
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plant while installing the required seismic restraints.
Briefly, the
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basis of the request was that: (1) it would take about the same
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amount of time to restore the CPC cabinets to a qualified state as it
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would to shut down the plant; (2) the licensee would take
compensatory measures to manually trip the reactor should a seismic
event occur; and (3) the probability of an earthquake was about
2 x 10E-6 in a 24-hour period based on the analysis in
Section 2.5.2.7 of the FSAR.
The request was granted at about 7:15 p.m. for a period not to exceed
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
By 2:40 a.m. on September 30, 1988, the missing seismic
restraints were installed in two CPC cabinets, thus enabling the
licensee to have the minimum two operable CPC channels required by
By 10:30 a.m. the same day, the seismic restraints were
installed in all four CPC cabinets. The licensee was then able to
exit the TS 3.3.1 Action Statements and resume. normal operation.
The licensee determined that on October 21,1982,(about2 years
prior to initial fuel load) the seismic restraints were installed,
inspected, and accepted in accordance with Field Change
Request E-2759, Revision 1.
However, the licensee noted that the
Plant Monitoring Computer / Auxiliary Protective Cabinet
Multiplexer (MUX) drawers were installed just below the FICA drawers
on November 1,1984.
It was apparent that in order to facilitate
installation of the MUX drawers, the seismic restraints on at least
two of the FICA drawers would have been removed. There was no record
of removal or reinstallation. On June 7, 1988, the licensee noted
the missing restraints and by June 14 had determined that they were
required. On June 15, NCI-256700 was initiated.
The control room
supervisor, who reviewed the hCI at the time, apparently did not
recognize the impact of the nonconformance on the operability o# the
CPC cabinets.
On October 13, 1988, the licensee completed an engineering evaluation
which documented the chronology of events and included a new analysis
and calculation performed by Combustion Engineering.
The evaluation
shoted that without the seismic restraints installed on the back and
with the drawer front retaining hardware installed, the FICA drawers
would not have become a missile hazard in the CPC cabinets during a
seismic event. Thus, it was determined that the CPC channels were
never rendered inoperable by the missing FICA drawer seismic
restraints.
Actions taken by the licensee were prompt and appropriate once this
NCI was resurfaced, and the licensee has been in the process of
making programmatic changes to provide responsive and timely
corrective action when appropriate.
Included in the licensee's
short-term corrective action was a comprehensive review of all open
NCIs. As a result of this review, three other examples of
nonconforming conditions not corrected in a timely manner were
identified as discussed below:
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NCI-255471, dated May 2, 1988, (during the second refueling outage)
identified a bent strut on rigid 12-inch safety injection system pipe
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restraint RCRR-133.
Apparently this NCI was given a 1-week priority
for correction, which would have been adequate because plant startup
was nearly a month away. However, the work did not get done nor was
it flagged as a startup constraint. The licensee conducted an
engineering evaluation on or about October 8,1988, and determined,
based on the engineer's recollection of the condition and a
photograph taken during the outage, that the pipe could not have been
overstressed with the bent strut connected.
The evaluation also
showed that the remaining support would be adequate to carry all
design operation and seismic loads if the load carrying capability of
the nonconforming restraint was not there. The restraint was
replaced during the October 21, 1988, outage.
NCI-258220, dated September 16, 1988, identified several pipe whip
restraints on the Reactor Coolant, .ceedwater, and Main Steam Systems
in the Reactor Containment Building which were too close to the
piping to allow the design thickness of insulation to be installed.
Apparently the plant had been operating in this condition since
construction.
The licensee made an operability call on October 1,
1988, stating that continued operation of the plant was acceptable.
This was based on the logical assumption that if the restraints were
closer to the pipe, the pipe could not reach the whip velocities
anticipated by design.
This was balanced against the minor
degradation in physical properties of the restraints due to the
higher temperatures they)would have at closer proximity to the pipe
(which was not insulated .
The Architect-Engineer has been
contracted to provide a detailed followup analysis to support the
licensee's position. As such, this issue shall be an unresolved item
(382/8825-01) pending review of the followup analysis and its
conclusions.
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On October 28, 1988, while reviewing an 1CI-252577 related to level
instrument tubing supports on the boric acid makeup tanks, the
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licensee noted that the drawings called for ASME Class 7 piping on
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the level indicators when it appeared that Class 3 should have been
installed.
This was previously identified on March 25, 1985, and
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accepted as is by engineering on the basis that if the piping broke
off the tanks when boration was called for, there was sufficient
volume below the tank connections to achieve the required reactor
shut down conditions. One of the assumptions included the boric acid
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concentration being in accordance with the T5. On October 28, 1988,
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the licensee noted that Amendment 10 of the TS, dated January 8,
1987, reduced the concentration, rendering the basis for acceptance
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invalid.
The licensee was in the process of promptly replacing all
of the piping at the end of this inspection period.
In addition,
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records are being received to determine if the actual boric acid
concentration in the tanks were low enough since January 8, 1987, to
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have caused an unreviewed safety question. The licensee has
comitted to provide the results to the resiMnt inspectors during
the next inspection period.
Since the issue of inadequate corrective uccon programs implemented
by the licensee are the subject of discussion in NRC Inspection
Reports 50-382/88-16 and 50-382/88-21, no purpose will be served in
additional enforcement actions or tracking mechanisms. The NRC
inspectors will continue to monitor licensee actions in this area.
b.
Determination of Source of Metallic Noise in Steam Generator No. 2
In NRC Inspection Report 50-382/88-21, the NRC inspectors documented
licensee effnrts to determine the source of a noise that appeared to
be coming from Steam Generator No. 2.
The noise was first identified
on August 30, 1988, by an operator while conducting his rounds near
the Main Feedwater 1 solation Valve on the +46 elevation. At the
time, the plant was at full power, and the noise resembled a loose
part hitting against the feedwater piping or something in the steam
generator. By September 16, 1988, the licensee had concluded that
the noise was coming from the steam generator based upon sound
testing of the accessible feedwater piping. Assistance was obtained
f rom Technology for Energy Corporation (TEC), Combustion
Engineering (CE), and Anchor-Darling Valve Compan
Later,
assistance was obtained from Babcock and Wilcox (y.B&W)whohad
previous experience with a similar problem at another plant.
The licensee found that reducing power to about 90 percent
significantly reduced the noise.
Except when taking sound data, the
plant was run at 90 percent to minimize possible damage by the
unknown source.
On September 23, 1938, the plant was shut down to Hot Standby
(Mode 3) so that the steam generator could be instrumented in an
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effort to locate the source of the noise. On September 25, 1988, the
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plant was returned to power and data was taken.
By Septerter 30,
1988, the licensee informed the NRC that preliminary results
indicated that the source of the noise was in the area of the
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feedwater inlet into the steam generator.
On October 5,1988, a CE preliminary technical evaluation suggested
four candidates for the noise source:
(1) a loose part in the
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feedwater distribution box; (2) a loose thermal sleeve at the
feedwater inlet to the steam generator; (3) a loose seal ring on the
feedwater distribution box; and (4) a loose feed ring discharge elbow
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in the immediate vicinity of the feedwater distribution box.
In
their final evaluation dated October 13, 1988, CE confirmed the above
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possibilities to the extent practicable and recomended a visual
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inspection of the steam generator internals including the thermal
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sleeve to be conducted at the first convenient opportunity but not
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beyond January 1989.
The report also recommended operation at a
reduced power level, i.e., about 96 percent maximum, where the
100 percent noise amplitude would be reduced by at least one half.
On October 14, 1988, the licensee increased power from about
90 percent to 96 percent.
During a conference call between Region IV, f4RR, and the licensee'on
October 14, 1988, the staff expressed concern about the licensee's
decision to operate above 90 percent and emphasized particular
concern that the licensee was considering operation as late as
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mid-flovember 1988 without knowing what kind of damage might be
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occurring in the steam generator.
Following the conference call,-the
licensee reduced power back to 90 percent and committed to shut down
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and inspect the steam generator no later than October 29, 1988.
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On October 21, 1988, the plant was shut down, and by the evening of
October 24, 1988, the steam generator internal inspection was
underway. The feed ring, distribution box, thermal sleeve, and
moisture separators showed no sign of damage or loose parts.
Inspection of the distribution box revealed an unexpected bracket
welded in place which was apparently used as a fabrication aid. The
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bracket did not appear on the drawing. CE will provide the licensee
with the appropriate justification for the extra part being in the
steam generator. The resident fiRC inspectors will follow up to
verify this does not create a safety issue.
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On October 26, 1988, after finding no condition in the steam
generator that would explain the noise, the licensee proceeded to
remove the cap from a check valve that is located about 13 feet of
piping upttream of the steam generator feedwater inlet.
This was to
obtain a better view of the feedwater piping irmiediately upstream of
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the steam generator. The 20-inch swing check valve was supposed to
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have had the internals permanently removed in 1982 prior to initial
startup due to a design change. The reason for the design change was
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documented on December 21, 1982, under Significant Construction
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Deficiency fio. 43, pursuant to 10 CFR 50.55(e). Up to this point.
therefore, the empty check valve was not considered to be a possible
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source of the noise. When the cap was removed, the licensee found
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that only the valve disc was removed.
The swing arm and pin were
still installed. There was significant wear on the end of the arm
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indicating it had been impacting the top inside surface of the valve
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body for some time.
It is believed that this was the source of the
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noise.
The licensee went on to drain the steam generator and inspect
the secondary side of the tube sheet for foreign or loose parts that
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could cause the noise and found none.
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The swing arm and pin were removed from Check Valve V8268 on
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October 26, 1988. On October 27, 1988, the licensee removed the cap
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on the similar check valve (V825A) from Steam Generator fio.1 and
removed the swing arm and pin. The swing arm in V826B exhibited
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much more wear than the arm in V825A, which might explain why the
noise could only be heard on the Stean Generator No. 2 side.
The licensee's representatives comented that they heard faint and
infrequent, but similar sounds on the Steam Generator No.1 side
while at full power, but they had to listen intently for at least
30 minutes. At the time, it was explained away by the noisa experts
as noise from No. 2 being transmitted through piping and structure.
Once it was determined that the check valve swing arms were still
installed on both sides, it became evident that the lesser sounds on
the No. 1 side were probably coming from V825A.
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The NRC inspectors questioned why the internals were only partiall-
removed. Upon review of the construction documents and quality
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inspection reports, the NRC inspectors noted in several places there
was direction and confirmation stating "check valve internals
removed" or "remove internals from check valves " but no where did
the documentation specify that all internal parts were to be removed.
The objective was to prevent the check valves from trapping pressure
in the steam generator during a feedwater line break accident. The
objective was accomplished by removing the valve disc only, thus
there was no safety significance to leaving the remaini19 parts in
the valve.
The licensee plans to continue noise monitoring of the steam
generator and feedwater check valves during unit startup to assure
that the problem is corrected. The resident inspectors will continue
to monitor licensee actions.
c.
QA Audit of Jamesbury Corporation
During the period of August 9-11, 1988, the licensee conducted a
vendor plant audit of Jamesbury Corporation, a division of Combustion
Engineering.
The findings were satisfactory in all areas, except the
auditors noted that two purchase orders (L-106184-W and L-96954-P)
were filled through the vendor's comercial quality program when the
purchase orders specified nuclear quality by imposing such documents
as the LP&L approved Jamesbury QA Manual,10 CFR 21, Appendix B to
10 CFR 50, ANSI N45.2-1971 and ANSI N45.2.9.
The purchase orders
were delivered to the site with Certificates of Compliance stating
conformance with all of the above nuclear requirements.
The licensee
did not request corrective action from Jamesbury until September 2,
1988, when a corrective action report was issued to the vendor. At
the time, LP&L indicated that this was not potentially reportable
pursuant to 10 CFR 21.
Jamesbury responded on September 21, 1988,
stating that the particular parts furnished have always been
processed in accordance with their commercial quality program and
acknewledged that they should have noted an exception on the
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certificates of compliance. Jamesbury comitted to ensure that if
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commercial quality parts were quoted but the purchase orders call for
nuclear quality, the disparity would be resolved in writing before
the order was entered.
The licensee reviewed all previous Jamesbury orders and showed the
NRC inspectors that earlier purchase orders called for the same
quality requirements as was imposed on the original components.
In
the case of noncode, nonpressure boundary parts, Jamesbury Cways
applied the commercial quality program. This appeared appropriate,
and the Certificates of Compliance correctly reflected what wa.9
specified.
The disparity emerged when LP&!. changed the
specifications in recent purchase orders to require nuclear quality
for all parts, which was not necesr,ary for noncode, nonpressure
boundary parts. Conducting business as usual, Jamesbury supplied the
same parts as before, not realizing the purchase orders no longer
specified original component quality requirements.
The only apparent safety issue here is the lack of timeliness on the
part of the licensee to recognize the implications of the vendor
supplying commercial grade material when nuclear grade was specified.
As it turned out, the hardware was correct, thus there was no impact
on plant safety; however, this is another indication of weaknesses in
the licensee's corrective action program which have been addressed in
previous inspection reports. Since the licensee is already taking
actions to improve the timeliness and effectiveness of its corrective
action programs, there will be no purpose served in issuing an
additional Notice of Violation at this time.
Region IV staff and the
resident inspectors are monitoring licensee progress in this area.
4.
Operational Safety Verification (71707)
The objectives of this inspection were: (1) to ensure that this facility
was being operated safely and in confonnance with regulatory requirements;
(2) to ensure that the licensee's management controls were effectively
discharging the licensee's responsibilities for continued safe operation;
(3) to assure that selected activities of the licensee's radiological
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protection programs were implemented in conformance with plant policies
and procedures, and in compliance with regulatory require <nents; and (4) to
inspect the licensee's compliance with the approved physical security
plan.
During the outage of October 21, 1988, the NRC inspectors toured the
containment building and observed maintenance activities, implementation
of radiological controls, housekeeping, and equipment condition. The NRC
inspectors observed the following conditions and noted that no Condition
Identification (CI) tags were in place, and thus they were identified to
the licensee for correction:
The cover on safety-related Conduit Box B30705A was ajar and hanging
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from one bolt.
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b.
The face of the thermometer installed on cabinet C-6B was shattered,
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The pipe whip restraint at Valve SI-332A was not installed properly.
A retaining nut was loosened and approximately 1 inch from the stop
bracket.
d.
Boric acid deposits at a vent on Reactor Coolant System Pressure
Transmitter RC-IDPT-0124 indicated leakage during plant operation,
e.
A rope was hanging from the snubber attached to the safety injection
system piping near Valve SI-302. Also, in the vicinity of SI-302, a
cable was hanging freely from a pipe whip restrain +.
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Caps were not installed on safety injection system test
Valves $1-2361 and SI-2391.
g.
Yalve SI-2421 (Safety Injection to Loop 18 Containment Isolation
Check Valve SI-242 Bypass) at containment penetration No. 56 was
closed, but no locking device was installed.
Procedure OP-100,009,
Revision 8. "Control of Valves and Breakers," required this
containment isolation valve to be locked in the closed position. The
NRC inspectors noted that the last time these valves were checked in
accordance with OP-100-009 was in April 1988 during the early stages
of the second refueling outage.
It appeared that later during the
outage the lock was removed.
Section 5.1.2.1 of OP-100-009 requires
documentation when the status of a locked valve is changed. None
could be produced by the licensee.
The NRC inspectors concluded,
based on the unexplained missing lock, that the controls required by
OP-100-009 were not implemented.
Failure to comply with OP-100-009
is an apparent violation of NRC regulations (382/8825-02).
The licensee promptly corrected the above items.
The NRC inspectors observed boric acid deposits from leaking safety
injection system Check Valve SI-512B on conduit, cable trays, firewrap,
ducting pipe supports, snubbers and component cooling w0ter system piping,
and valves. The leaking valve was repaired and the boric acid deposits
were cleaned up.
The licensee analyzed the effects of the boric acid on
the above enuipment and found no problems.
The NRC inspectors visited the control room at least once each day when on
site, and verified that proper control room staffing was maintained,
operator behavior was professional r.d commensurate with plant conditions,
and that approved procedures were utilized and complied with.
The panels
were inspected for anomolies and when found were satisfactorily explained
by the operators.
In addition to the reactor containment tours above, the NRC inspectors
toured accessible interior and exterior areas of the plant and noted no
significant deficiencies in housekeeping, radiological work practices and
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equipment condition. The NRC inspectors noted a continuing effort to
paint components and structures, thus protecting surfaces and facilitating
easy cleanup. The overall appearance of the plant I; excellent.
The NRC inspectors attended daily plan-of-the-day meetings to kt ep abreast
of problems and to observe the licensee's identification and manv;;r.g of
corrective maintenance issues.
The implementation of the licensee's security program was specifically
observed at least once each week during this inspection period, with
emphasis on personnel plant identification badges, vital area portals
being kept locked, and processing of personnel through the primary access
point. No deficiencies were noted.
5.
Monthly Maintenance Ooservation (62703)
The below listed station maintenance activities affecting safety-related
systems and components were observed and documentation reviewed to
ascertain that the activities were conducted in accordance with approved
procedures, technical specifications, and appropriate industry codes or
standards,
a.
Work Authorization 01025389. The NRC inspectors observed the
inspection of the high pressure safety injection (HPSI) pump A/B
motor heater and power supply cable terminations. The inspection was
performed to verify that the splices were in confonnance with
Drawing LOV-1564-B-288, "Cable & Conduit List and Installation
Details." Verification of the HPSI pump termination splices was
performed after charging pump motor heater splices were found in
nonconformance with the above drawing and subsequently replaced.
The
HPSI pump motor heater cables were landed en terminal blocks so no
splices were required. The HPSI pump motor power supply cables were
not found in the expected configuration per Drawing LOV-1564-B-288,
but the power supply cable splices were of the same configuration as
the emergency feedwater pump cables depicted in the same drawing and
thus were considered acceptable by the licensee.
Because of the
observed inconsistencies in pump motor cable tennination splices, the
licensee performed additional verifications.
During the subsequent verifications, the licensee determined that
several V-type Okonite splices used on safety equipmant inside
containment and shown on Drawing LOV-1564-B-288 were not consistent
with the documented environmentally qualified (EQ) configurations.
Drawing LOV-1564-B-288 did not require filling of the area between
the cable legs on all V-type splices with insulation tape.
The
qualified configuration required filling of this area with insulation
tape.
The licensee obtained a letter from Wyle Laboratories stating that
these splices can be qurlified for a minimum of 5.9 years, which
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means some splices may have to be replaced as early as 1990.
The
licensee is currently determining the lifetime based on plant
specific parameters which may turn out to be longer than 5.9 years.
Once the plant-specific qualification lifetime is determined, the
licensee has coranitted to implement a program for splice replacement
(if required). The licensee indicated that this will take place in
the next few weeks.
Followup on the licensee's actions for program
implementation shall be tracked as an open item (382/8825-03).
b.
Work Authorization 01018979.
The NRC inspectors witnessed the
hydrostatic test of the welded pipe joints associated with the
replacement of Main Steam t.ine No. 2 Orain Isolation Valve MS-10518.
The hydrostatic test was conducted in accordance with Maintenance
Departmental Procedure MM-7-007, Revision 3, "Hydrostatic Pump Unit
Setup and Operation for Testing." The test was completed
satisfactorily in the presence of the authorized nuclear
inservice (ANI) inspector and a plant quality inspector.
However,
there was one problem identified by the plant quality inspector prior
to startir.g the test.
Procedure MM-7-007 had a prerequisite
(Step 3.2) requiring the test gauges to be calibrated within 2 weeks
prior to the test. Only one of the two test gauges met this
requirement.
This delayed the test for about i hour until a properly
calibrated test gauge was connected.
This was indicative of
inattention to procedure requirenants by the maintenance personnel
conducting the test.
The NRC inspectors expressed concern to the
licensee that plant management efforts to ensure procedure compliance
are not yet fully effective.
The maintenance supervisor initiated a
change to the procedure to require a specific signoff of the test
gauge calibration requirement,
c.
Work Authorization 01025932.
The NRC inspectors observed the removal
of the swing arm and hinge pin from main feed system Check
Valve 2FW-V826B. The reason for this work is discussed in
paragraph 3.b of this report.
The documentation appeared to be in
order, and no problems were encountered during the work,
d.
Work Authorization 0109107.
The NRC inspectors observed portions of
the installation of a new motor in containment fan cooler "C" and
noted the following:
(1) The old fan motor was removed at the end of the refueling outage
in May 1988.
A note was written on the work site copy of the
work authorization stating that electrical tools and parts were
stored in Cabinet C-8.
The NRC inspectors observed tools and
copies of pages from the work package in Cabinet C-8.
The tools
were apparently stored in Cabinet C-8. which contains engineered
safety features system transmitters (safety injection tank level
and pressure) since May 1988.
This was identified to the
licensee and the tools were removed. All other instrument
cabinets ir the reactor containment building were checked orior
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to containment closure, and no other tools or parts were found.
- This appears to be an isolated case and not normal practice by
maintenance personnel.
(2) While the technicians were rigging the fan in place, the NRC
inspectors observed spare bolts and washers in the fan assembly
resting adjacent to the blades.
Because of the potential for
jamming the fan blades, this was identified to technicians
performing the work, and the spare bolts and washers were
removed. Plant management was informed of this poor work
practice.
(3) Splicing of the fan motor power supply leads was performed per
Procedure ME-4-809, Revision 4. "Low Voltage (600 Volts and
Less) Power and Control Cable / Conductor Terminations and
Splices," in conjunction with Drawing LOV-1564-B-288, "Cable and
Conduit List Installation Details." The technicians perfonning
the work had a copy of the proper detail from
Drawing LOU-1564-B-288 but did not have the sheet containing the
applicable notes at the work site. As discussed in
paragraph 5.a above, the drawing detail did not provide for a
splice configuration that was supported by EQ documentation.
The electricians made the splices in accordance with ME-4-809
and added sufficient insulating tape between the legs of the
conductors such that the work was supported by EQ documentation.
The NRC inspectors expressed concern that the licensee's failure
to correct the disparities between ME-4-809 and the drawings was
placing the electricians in a difficult position. Actions taken
to solve this problem, as identified previously in NRC
Inspection Reports 50-382/87-31 and 50-382/88-21 have been
unacceptable to date. The licensee's representatives met with
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the NRC inspectors on October 27, 1988, and presented what
appeared to be an acceptable revision to both the drawings and
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the procedure. This action continues to be tracked under
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violation 382/8731-03 and is another indicator of poor and
untimely corrective action.
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No violations or deviations were identified.
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6.
Monthly Surveillance Observation (61726)
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The NRC inspectors observed the below listed surveillance testing of
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safety-related systems and components to verify that the activities were
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being performed in accordance with the technical specifications.
The
applicable procedures were reviewed for adequacy, test instrumentation was
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verified to be in calibration, and test data was reviewed for accuracy and
completeness. The inspectors ascertained that any deficiencies identified
were properly reviewed and resolved.
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a.
Procedure OP-903-024, Revision 6, "Reactor Coolant System Water
Inventory Balance." On October 31, 1988, the NRC inspectors observed
the performance of the reactor coolant system (RCS) inventory balance
prior to entering Mode 4.
The results indicated that RCS
unidentified leak rate was 1.59 gallons per minute (gpm).
Because
the plant was in Mode 5, no action was required.
Since no other
indications of leakage were present and a large RCS temperature
change occurred during the test (1.2*F with RCS at 190'F), the
inventory balance was reperformed with more attention on maintaining
satisfying the TS requirement (less than 1 gpm)gpm was measured,
RCS temperature.
Unidentified leakage of 0.96
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No violations or deviations were identified.
7.
Followup of Previously Identified Items
(92701)
(Closed) Issue on Main Feedwater Isolation Valves (MFIVs).
Paragraph 2 of
NRC Inspection Report 50-382/88-15 identified a need to perfonn an
additional inspection on the review of the licensee's Potentially
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Reportable Event (PRE) Report 88-053.
On May 13, 1988, the PRE reported,
in short, that MFIVs FW-184A & B may not have met TS Table 3.3-5 minimum
response times under full flow conditions.
FSAR Section 6.2.1.4 assumes
100 percent feedwater flow for 5 seconds for the limiting accident for
peak containment pressure (main steam line break) with a concurrent
failure of one containment cooling train. The valves were tested in the
past to prove that they could close in not more than 5 seconds, but the
test was done at zero flow conditions.
The licensee determined that
5 seconds under zero flow conditions corresponded to 7 to 9 seconds under
full flow conditions.
Initially, this appeared to be a potential
unreviewed safety question until the licensee noted that the FSAR took
credit for the feedwater regulating valves as a backup that would close on
the same signal (Main Steam Isolation Signal) in not greater than
5 seconds, under full flow conditions.
Thus, the plant was not in an
unanalyzed condition due to the slower settings on the MFIVs.
The
licensee reset the MFIVs to close in 3 seconds under zero flow conditions,
which correspondad to five seconds full flow.
This was completed on
May 13, 1988, before the plant was restarted from the second refueling
outage.
The licensee determined that this issue was not reportable under
10 CFR 50.73, which appeared to be a correct decision.
This issue is
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closed.
No violations or deviations were identified.
8.
Licensee Even_t Report (LER) Followup
(92712)
The following LER was reviewed and closed. The NRC inspectors verified
that reporting requirements had been met, causes had been identified,
corrective actions appeared appropriate, generic applicability had been
considered, and that the LER form was complete.
The NRC inspectors
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confirmed that unreviewed safety questions and violations of TS, if cense
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conditions, or other regulatory requirements had been adequately
described.
(Closed) LER 88-022 (Revision 1), Missed Penetrant Test on Two Welds Due
to Personnel Error. When Revision 0 of LER 88-022 was published, the NRC
inspectors noted that the licensee had listed the event date as August 2,
1988, when in fact, as described in the text, the problem was found on
June 20, 1988. The NRC inspectors expressed concern to the licensee that
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it was inappropriate to wait until September 1,1988, to issue the LER
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when the problem was identified over 2 months earlier. The text explained
the licensee's actions in detail which eventually led to the LER; however,
it illustrated the lack of promptness built into the licensee's corrective
action program. This issue has been addressed in previous NRC inspection
reports and the licensee has already been tasked to improve its corrective
action program. The LER indicated that it would take a plant cooldown to
facilitate a penetrant test. On September 24, 1988, the licensee
performed the test while shutdown in hot standby for other reasons.
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NRC inspectors reviewed the test documentation and found the piping
temperature was verified at 111*F. Thus, it was not necessary to cool
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down to correct the deficiency. All seven of the joints in the new piping
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were tested or retested at that time.
The LER was revised on October 19,
1988, reflecting the actual event date and completion of the penetrant
test.
This LER is closed.
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No violations or deviations were identified.
9.
Exit Interview (30703)
The inspection scope and findings were summarized on November 4,1988,
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with those persons indicated in paragraph 1 above.
The licensee
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acknowledged the NRC inspectors' findings. The licensee did not identify
as proprietary any of the material provided to or reviewed by the NRC
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inspectors during this inspection.
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