ML20249A618
| ML20249A618 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 06/15/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20249A616 | List: |
| References | |
| 50-285-98-09, 50-285-98-9, NUDOCS 9806170151 | |
| Download: ML20249A618 (18) | |
See also: IR 05000285/1998009
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ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.: 50-285 .
License No.: DPR-40
Report No.: 50-285/98-09
Licensee: Omaha Public Power District
Facility: Fort Calhoun Station
Location: Fort Calhoun Station FC-2-4 Adm.
P.O. Box 399, Hwy. 75 - North of Fort Calhoun
Fort Calhoun, Nebraska
Dates: April 12 through May 23,1998
Inspectors: W. Walker, Senior Resident inspector
V. Gaddy, Resident inspector
T. Meadows, Reactor Engineer
Approved By: W. D. Johnson, Chief, Project Branch B l
ATTACHMENTS: Supplemental Information
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9906170151 990615
PDR ADOCK 05000285
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EXECUTIVE SUMMARY
Fort Calhoun Station
NRC Inspection Report 50-285/98-09
Operations
~ a' 'During a refueling outage, operators exhibited quick, decisive cecision making to
- - preclude any inadvertent criticality following an unexpected increase in the count rate on
.the Channel B wide range nuclear instrumentation by emergency borating the reactor
coolant system (Section 01.1).
. The licensee prepared and executed the reduced inventory evolutions in a professional I
manner. The licensee stressed safety over maintaining the outage schedule
- (Section 01.3).
. During emergency diesel generator restoration following maintenance, operators
overlooked the fact that the offsite low signal (Iow bus voltage) would cause the diesel to
start. When operators moved the mode selector switch from off auto to emergency
- standby, the diesel generator started as designed. This was not anticipated by
operations personnel (Section 04.1).
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. - Failure to adhere to 10 CFR Part 50, Appendix B, Criterion 5, resulted in inadequate
procedure guidance during a plant cooldown. This, in conjunction with operations
personnel confusion over wide-range pressure instrumentatic,n inaccuracies, resulted in l
the reactor coolant system pressure being lowered to the point where Reactor Coolant
Pump RC-3C cavitated (Section 08.1). !
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Maintenance
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- . During a refueling outage inspection of containment, the inspectors discussed with the
l licensee the poor material condition of component cooling water piping inside
l' containment. Rust and peeling / flaking paint was evident on the pipes. Pitting was also
occurring on some pipes. Due to the poor condition of the pipes, the licensee performed
an analysis that showed that the structural integrity of the piping was sound and that the
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L . peeling / flaking paint would not affect the recirculation strainers. The licensee removed
L loose paint and rust from the piping (Section M2.1).
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L Engineenng
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- ~ . During the development of a modification package, design engineering personnel
incorrectly interpreted the effect of removing power from certain electrical distribution
panels. When power was removed from Electrical Distribution Panel Al-418, the
diesel-driven fire pump received an inadvertent start signal (Section E1.1).
- The licensee's initial evaluation that allowed a platform to be constructed on a cable tray
was deficient in that it did not consider the additional weight of individuals standing on
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the platform. When questioned by the inspectors, the licensee performed an additional
analysis that concluded that the additional weight did not have an adverse affect on the
cable trays (Section E4.1).
. During initial construction, .the licensee failed to maintain adequate design control
regarding tornado venting and modifications to the auxiliary building. This resulted in
structures being built on top of the vents, which would impede their venting capability.
This nonrepetitive, licensee-identified and corrected violation is being treated _as a ,
. noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy
(Section E8.1).
Plant Support
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The licensee failed to properly label 15 bags of radioactive material in the radioactive
waste building as required by 10 CFR 20.1904. This nonrepetitive, licensee-identified
. and corrected violation is being treated as a noncited violation, consistent with
Section Vll.B.1'of the NRC Enforcement Policy (Section R1.1).
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Reoort Details
Summarv of Plant Status l
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The Fort Calhoun Station was in its 17th refueling outage during this inspection period. Several I
of the major activities completed during the outage included the replacement of all sixth stage
extraction steam piping, removal of steam generator flow orifices, and modification of the
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Another major activity was the replacement of all failed fuel. The licensee determined that there
was a total of 69 leaking fuel pins in 38 fuel assemblies. All of the leaking fuel assemblies were j
replaced with either new fuel assemblies or previously bumed fuel assemblies. j
l. Operations
01 Conduct of Operations
01.1 General Comments (71707)
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The inspectors frequently observed ongoing plant operations. In general, the conduct of l
operations was professional and safety-conscious. The inspectors noted effective
implementation of management expectations during most observations.
01.2 Unexoected Increase on Counts on Channel B Wide-Ranae Nuclear Instrumentation
a. Insoection Scooe (71707)
The inspectors followed up on the unexpected increase in counts on the Channel B
wide-range nuclear instrumentation.
b. Observations and Findinas
On May 14,1998, radiation protection personnel were cleaning the reactor cavity. At
approximately 1:30 p.m., Channel B of the wide range nuclear instrumentation
experienced a sustained increasing count rate for no apparent reason. The reactor
vessel head was in place, but was not tensioned. The count rate increased from less
than 5 counts per second to approximately 200 counts per second. The remaining three
channels of wide-range nuclear instrumentation did not show an increase in counts.
Based on the increase in count rate, control room operators entered Abnormal Operating
Procedure AOP-03, * Emergency Boration," and evacuated containment.
Operators emergency borated the reactor coolant systen. ~Nith approximately 600 gallons
of concentrated boric acid and the counts on Channel B of the wide-range nuclear
instrumentation decreased to less than 10 counts per second.
Following emergency boration, operators assessed the situation and declared Channel B
inoperable and exited the abnormal operating procedure based on the following:
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. Approximately 600 gallons of concentrated boric acid was injected into the
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Approximately 1500 gallons per minute of shutdown cooling flow was available
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. There was no increase in counts on the remaining three wide-range nuclear
instrumentation channels.
Operations also venfied shutdown margin. Following the emergency boration, reactor -
coolant system boron concentration was 2372 ppm. The core operating limits report
required a boron concentration greater than 1900 ppm.
The licensee believed the cause of the increase in counts was an electrical transient.
During troubleshooting, the licensee determined the cause of the increase in count rate
to be a bad detector cable connector in a junction box. The ennnector was repaired and
no further anomalous indications were observed.
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c. Conclusions
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' During a refueling outage, operators exhibited quick, decisive decision making to
preclude any inadvertent criticality following an unexpected increase in the count rate on
the Channel B wide-range nuclear instrumentation by emergency borating the reactor
coolant system.
01.3 Sustained Control Room and Plant Operations
a. Insnachon Scoon (71715)
The inspectors performed extended periods of observation of control room and plant
activities during the period of April 9-12,1998, while the reactor coolant system was
being drained to a midloop condition. The inspectors assessed licensed operators'
attentiveness, plant awareness, communications skills, manipulations, and use of
procedures. The inspectors also assessed shift management supervision and
. involvement.
b. Observat: ens and Findinos
During the period of April 9-12,1998, the inspectors observed approximately 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> of
p_ control room and plant activities. The inspectors observed three different crews and
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l three shift tumovers during this period. -The inspector observed the shift briefing
conducted using Standing Order SO G-92, " Draining of RCS to Mid-Loop." The following
documents were reviewed:
. Operating instruction, Ol-RC-2A, "RCS Fill and Drain Operations";
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. . Technical Data Book, TDB-lli.20, "RCS Elevations VS. LI-106. LI-199, and
LIS-119";
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' Abnormal Operating Procedure, AOP-19, " Loss of Shutdown Cooling"; and
.- OP&S-SDS-0002, " Shutdown Cooling and LTOP Control Plan."
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The inspectors found that these procedures and instructions provided adequate
j guidance and expectations to operations personnel for reduced inventory operations,
including requiring two independent reactor pressure vessel level instruments (LI-199
l- sightglass and LIS-119-Control Room - Narrow Range), establishing vortexing limits for
shutdown cooling (4 - 7 inches below centerline of the hot leg), recuiring two
independent temperature indicators (core exit thermocouple G3 e nd T8), time to boil
calculations, and time to fuel uncovery calculations. In addition, licensee mana0ement
required a continuous watch on Sightglass LI-199 inside containment during reduced
inventory operations; an additional control room wide-range reactor vessel level
Indicator, LI-197, was utilized; an additional licensed operator was assigned to monitor
reactor vessel level in the control room; and low pressure safety injection pump
performance was continuously monitored with a remote alarming chart recorder in the
control room. The inspectors determined that operations personnel were familiar with
these procedures and followed management expectations.
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The inspectors monitored and observed the following evolutions from the control room:
. . 4/9/98, commencement of reactor pressure vessel draining;
.. . 4/10/98, draining reactor coolant system level to reactor vessel flange (1013');
- 4/11/98, reactor pressure vessel head detensioned;
. . 4/11/98, draining reactor coolant system level to midioop (stopped at 1007 feet
6 inches);
. 4/11/98, steam generator primary manways removed and loop air purge to
reduce radiation levels;
. 4/12/98, loop nozzle dams installed; and
i . 4/12/98, flooded reactor pressure vessel to near top of flange (1012 feet).
The inspectors observed that operations personnel performed these evolutions in a
- professional manner with good communications and self-checking practices, while
j maintaining good plant awareness. The control room was quiet and professional with
minimum traffic and riistractions. The inspectors observed close operations supervision
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as well as continuous operations department management coverage. Management
stressed that safety considerations took pnonty to maintaining the outage schedule.
c. Conclusions
- The licensee prepared and executed the reduced inventory evolutions iri , ofessional
manner. The licensee stressed safety over maintaining the outage - Aule.
04 Operator K. c M-y and Performance
04.1 Unplanned Diesel Start of Diesel Generator
a. Inspachon Scope (71707)
The inspector reviewed the activities associated with an unplanned start of a diesel
generator,
b. Observations and Findings
On April 25,1998, Diesel Generator 2 was tagged out for maintenance. Its associated
vital 4160 volt bus was also deenergized and tagged out of service. Following
maintenance on the diesel generator, tags were cleared and a system alignment was
being performed in accordance with Operating instruction OI-DG-3, " Diesel Generator
Normal Operation." During this alignment, the operating instruction instructed operators
to move the mode selector switch from off auto to emergency standby. At this point,
operators questioned whether placing the switch in emergency standby would cause the
diesel generators to start. During this discussion, operators discussed the emergency
safety features actuation circuitry that would start the diesel generator and concluded
that, in the present condition, the diesel generator would not start. When operators
moved the mode selector switch from off auto to emergency standby, the diesel
generator started. Operators shut down the diesel generator and the mode selector was
moved back to off auto.
During the discussions prior to placing the mode selector switch in emergency standby,
operators failed to consider that there was additional circuitry that would also start the
diesel generator. The offsite power low signal starts the diesel on a low bus voltage.
When the mode selector switch was placed in emergency standby, low bus voltage was
sensed and the diesel generator started as designed.
c. Conclusion
During their discussion of circuitry that would cause the diesel generator to start,
operators overlooked the fact that the offsite low signal (Iow bus voltage) would cause
the diesel to start. During restoration following maintenance, operators moved the mode
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- . selector switch from off auto to emergency standby. When this occurred the diesel
generator started as designed. However, this we not anticipated by operations
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07 Quality Assurance in Operations
07.1 Licensee Operational Experience Review Activities
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During the inspection period, the inspectors frequently attended licensee moming plant
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~status meetings which were used to discuss current plant conditions and planned
p activities for the day. The shift manager chaired these meetings and all managers were -
E present, including the plant manager. The inspectors observed that a good exchange of
L information regarding plant operations was provided during this meeting.
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In March 1998, the licensee began providing industry operational experience information
during the moming plant status meeting. The inspectors found that this information was
thorough and gave the licensee valuable insight regarding industry events and
E notifications. The inspectors determined that the licensee was evaluating and prioritizing
t: industry operating experience information for possible applicability to the Fort Calhoun
Ii Station. The inspectors concluded that the industry operational experience review
L activities observed were effective.
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l 08 Miscellaneous Operations issues (92901)
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08.1 (Closed) Unresolved item (URI) 50-285/9802-02 cavitation of Reactor Coolant
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Pump RC-3C. On April 2,1998, the inspectors observed operations personnel perform
activities related to plant cooldown. Operations personnel were using Operations
Procedure 'OP-3A, " Plant Shutdown," Revision 19, to cool down the plant. -This
l- procedure directed operations personnel to use pressurizer steam temperature to
L determine actual pressurizer pressure by correlating the pressurizer steam space
l. temperature to a pressure using steam tables. Operations personnel were using this
- . method to determine reactor coolant system pressure to ensure that they maintained net
L positive suction head for operating Reactor Coolant Pump RC-3C. Reactor coolant
pressure was determined to be 225 psia using the steam tables.
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During shift tumover, the oncoming shift manager questioned whether the reactor
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. coolant system pressure was actually 225 psig, since wide-range pressure
instrumentation was indicating reactor coolant system pressure was 100 psig.- The j
oncoming operations personnel determined that reactor coolant system pressure was j
actually 100 psig and promptly raised the reactor coolant system pressure to 275 psig. i
The inspectors reviewed the licensee's root cause analysis which was used to determine
why the reactor coolant system pressure was lowered to a point below the required net ,
positive suction head of the reactor coolant pump during plant cooldown. The licensee ;
determined the following: ;
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. Operations Procedure OP-3A, ' Plant Shutdown," Revision 19, contained a nota
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which directed operations personnel to monitor reactor coolant system cooldown )
utilizing pressurizer steam space temperature.- This was determined to be a {
typographic! error. The previous revisions to the operations procedure specified I
that pressurizeriiquid space temperature was to be used;
. Sinct, NCE Procedure OP-3A contained a note which discussed the
inacmnscies in wide-range piessure indication. However, over the years,
' informahon concerning the range of error had been misunderstood, resulting in
operators having less confidence in wKle-range pressure indications;
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Operations personnel on shift during the event understood that the pressure
difference between Wide-Range Pressure Indicator P105 and Wide-Range .
Pressure Indicator P115 could be anywhere from 30 to 70 psi. Design '
enginwing personnel confirmed that the largest difference would be only 7 to
10 psi and, as verified by training personnel on the simulator, P105/P115
appeared to be the most accurate means of pressure indication;
Due to a lack of trendable vibration data regarding the reactor coolant pump, it
was difficult for operations personnel to identify that cavitation of the reactor
coolant pump was in progress; and
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A lack of a policy for providing continuous engineering support during system
specific, critical evolutions.
The root cause of the event was determined to be inadequate procedural guidance. The
operations procedure directed operators to use pressurizer steam space temperature ;
i' rather_ than the liquid space temperature indication. Also, a note in the operations
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procedure stated that, when the reactor coolant system pressure is <425 psia, the
pressurizer pressure indication was less accurate.- The term "less accurate" was never
L quantitatively defined and resulted in operations personnel having differing opinions on
the' amount of difference that could be seen between Wide-Range Pressure
indicators P105 and P115. The failure to provide adequate procedural guidance for
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ensuring proper cooldown of the plant is a violation (50-285/9809-01).
The inspectors determined that the oncoming operations personnel exhibited an
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excellent questioning attitude and attention to detail in identifying the reactor coolant
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pump cavitation. However, the inspectors identified that the oncoming crew was not
, _ timely in their documentation of the reactor coolant pump cavitation in the control room
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logs in that the pump cavitation occurred at approximately 6 p.m. on April 2,1998, and
was not properly logged until April 3. The inspectors discussed the timeliness of the log
entry with the operations supervisor and shift manager and were informed that this did
not meet operations management's expectation for control room documentation and
would be discussed with all operations personnel.
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c. Conclusson
Failure to adhere to 10 CFR Part 50, Appendix B,' Criterion 5, resulted in inadequate
procedure guidance during a plant cooldown This, in conjunction with operations
personnel confusion over wide-range pressure instrumentation inaccuracies, resulted in
the reactor coolant system pressure being lowered to the point where Reactor Coolant
Pump RC-3C cavitated.
II. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (62707)
The inspectors observed portions of the following work activities:
. Control element assembly coupling;
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Installation of new bellows for main steamline penetrations;
. Installation of reactor coolant pump lube oil collection system;
. Safety injection high point vent valve installation
.. Component cooling water relief valve work;
. Replacement of main steamline radiation monitor isolation Valves MS-921 and
922;
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Replacement of raw water component cooling water interface valve seat;
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Replacement of sixth stage extraction steam piping;
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. Calibration and inspection of Inverter D;
. MOVATS testing of safety injection loop injection Valve HCV 327;
- Turbine-driven auxiliary feedwater pump oil change and oil sump cleaning;
. . Replacement of Manual Transfer Switch 183A-4A-MTS; and
. Rebuilding Feedwater Isolation Valve FCV-1103.
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b. Observahons and Findings
The inspectors found the work perfurmed under these activities to be professional and
thorough . All work observed was performed with the work package present and in achve
use. Maintenance technicians were experienced and knowledgeable of their assigned
tasks. The inspectors frequently observed supervisors and system engineers
monitoring job progress, and quality control personnel were present when required by
procedure.
c. Conclusions
The mantenance activities observed wem conducted in a controlled and professional
manner.
M1.2- Surveillance Tests
a. Inspechon Scope (61726)
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OP-ST-AFW-0007, " Auxiliary Feedwater Pump FW-6 Operability Test,"
Revision 0;
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SE-ST-AFW-3002, " Auxiliary Feedwater Piping Forty Month inservice Test,"
Revision 6;
. OP-ST-RW-3002B, " Raw Water Category A and B Valve Exercios Test,"
Revision 1; and
. IC-ST-RPS-0018, " Quarterly Functional Test of Steam Generator Low Pressure
and Asymmetnc Steam Generator Transient RPS Bistable Trip Unit," Revision 2.
. b. Observahons and Findings
Surveillance activities were generally completed thoroughly and professionally.
c. Conclusions
The surveillance activities observed by the inspectors were completed in a controlled
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- M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 u*dal Cond4n of Comoonent Coolina Water Pioina
a. Insoection Scone (62707)
At the beginning of the refueling outage, the inspectors made a tour of containment to
assess housekeeping and material condition of the component cooling water piping.
b. Observations and Findinas
During the walkdown, the inspectors noted that several component cooling water pipes
were corroded, with significant paint peeling and flaking. Similar conditions were
identified in April 1997 and discussed in NRC Inspection Report 50-285/97-06.= In that
report, the inspection team noted that the licensee was developing a protective coating
plan to cure the problem. This plan has not yet been fully developed and implemented.
The inspectors also noted paint peeling and flaking on the walls of containment. In
addition to rust and corrosion, pitting had occurred on some component coolant water
small bore pipes supplying the safety injection leakage coolers and large bore pipes
supplying the containment air coolers. A flange across Flow Element FE-435 was
completely covered with corrosion. Peeling, flaking paint and rust was also evident on
other component cooling water piping. From this assessment, the inspectors identified
two concerns. The first involved the potential for paint and corrosion products to clog the
containment strainer. The second was the structural integrity of the component cooling
water pipes.
b.1 Containment Sorav Recirculation System
The issue of loose paint potentially clogging the recirculation system strainers
was previously evaluated by the NRC in Inspection Reports 50-285/95-07 and
50-285/95-09. The licensee prepared Engineering Analysis93-023 to address
paint peeling identified by the NRC in 1995. In 1995, the inspectors specifically
- questioned the peeling paint on the containment walls. The analysis concluded
that loose paint would not have a deleterious effect on safety-related equipment,
including the containment spray-recirculation system.' in this inspection period,
the inspectors questioned the engineers regarding the impact of the peeling paint
on safety-related equipment. The licensee informed the inspectors that the
component cooling water piping was also bounded by Engineering
Analysis93-023. !
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The inspectors also asked if rust from the piping could potentially clog the l
L recirculation system strainers. In response, the licensee provided the inspectors
L with Memorandum EOS-DEN-97-0445 dated November 19,1997. This .
memorandum summarized a safety assessment performed to evaluate the effect
that suspended rust would have on the recirculation system. The licensee ,l
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concluded that the amount of component cooling water piping rust particles that
could potentially be transported to the strainers was small, and the not effect on
strainer head loss was minimal. This safety assessment was sufficient to resolve
the inspector's concern.
L b.2 Structural intagnty
The licensee performed ultrasonic testing on 27 pipe locations on April 22 to
determine the wall thickness of the affected pipe. This work was performed in
accordance with Maintenarne Work Order 972797. The licensee chose piping
l from each level in containment and also piping from each reactor coolant pump
bay. Piping examined included 1.5-inch (10 locations), 2-inch (12 locatens),
4-inch (2 locations), 6-inch (2 locatens), and 10-inch (1 location) nominal pipe
i sizes. Pits had formed at some of the locations tested The worst case pit was
0.045 inch deep. This depth was subtracted from the as-found wall thickness
The worst case wall thickness locations are summarized in Table 1.
Table 1. Summary of Worst Case Ultrasonic Wall Thickness Checks
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Containment Nominal Pipe Nominal Pipe As Found UT Worst Case ANSI /ASME
, Location Size Wall Wall Pit Applied B31.1
Thickness Thickness '(0.045 in) Allowable
Minimum
RCP 3D Bay 1.5 inch 0.145 inch 0.144 inch 0.099 inch 0.010 inch
SG 2A 2 inch 0.154 inch 0.149 inch 0.104 inch 0.012 inch
Basement
L PAL Door . 4 inch 0.237 inch 0.263 inch - 0.218 inch 0.023 inch
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Between 6 inch 0.280 inch 0.265 inch 0.220 inch 0.033 inch
VA-15 and .
Outer Wall
Near 10 inch 0.365 inch 0.355 inch 0.310 inch 0.054 inch
Containment
Tool Room
Ultrasc'ic testing indicated that the worst case locations were still well above
acceptable ANSI /ASME B31.1 allowable wall thickness.
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The contractor used to evaluate the condition of the component cooling water
piping concluded in Letter 97-14.1-19, dated May 12,1998, that the degradation
- was due to oxygen attack and appeared to be primarily cosmetic with no
significant wall loss due to rusting and that the rate of increase in pit depth would 1
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remain approximately constant. The contractor summarized the analysis by
stating that the worst case pipes have approximately 10 years of remaining life.
b.3 Peelina/Flakina Paint Removal
On May 13, the licensee began removing peeling paint from the component
coolant water piping inside containment. Additionally, accessible peeling paint
on the containment liner was also to be removed. Paint was removed from
approximately 1000 linear feet of component cooling water piping. Although the
paint was removed, engineering personnel indicated the pipes would not be
repainted during this refueling outage. Engineering personnel were still
evaluating when to repaint the pipes. Engineering personnel stated that, in areas
where pitting had occurred, the corrosion would not be removed.
c. Conclusions
During a refueling outage inspection of containment, the inspectors discussed with the
licensee the poor material condition of component cooling water piping inside
containment. Rust and peeling / flaking paint was evident on the pipes. Pitting was also
occurring on some pipes. Due to the poor condition of the pipes, the licensee performed
an analysis that showed that the structural integrity of the piping was sound and that the -
peeling / flaking paint would not affect the recirculation strainers. The licensee removed
loose paint and rust from the piping.
lli. Enaineerina
E1 Conduct of Engineering
E1.1 Inadvertent Diesel Fire Pumo Start
a. Insoection Scooe (37551)
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The inspectors reviewed an inadvertent start of the diesel-driven fire pump.
b. Observations and Findinas
During troubleshooting to determine why diesel-driven Fire Pump FP-1B inadvertently !
started on April 23, system engineering and maintenance personnel identified that the
pump started when power was removed from Electrical Distribution Panel Al-418. Power
was removed during the performance of Modification MR-FC-95-018. The purpose of
this modification was to replace obsolete Molded Case Switches EE-8F-CB20 and ,
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EE-8G-CB22, replace 300 amp fuses fed from obsolete Molded Case
Switches EE-8F-CB20 and EE-8G-CB22 in the DC switchboards with fuses of smaller
current rating, and replace obsolete molded case switches / circuit breakers at the
electri;al distribution panels in the control roorn.
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The inspectors asked design engineering personnel if they considered what effect
removing power from the electrical distribution panels would have on the loads fed by the
panels - Design engineering personnel stated that they reviewed the electrical load a
distnbution list during modification package development. Design engineering personnel
stated that they had overlooked the fact that the diesel-driven fire pump would receive a
start signal when power was removed from the panels. : Design engineering personnel
reexamined the electrical load distribution list and did not identify any other
discrepancies.
c. - Conclusions
During the development of a modification package,~ design engineering personnel-
misinterpreted the effect of removing power from certain electrical distribution panels.
When power was removed from Electrical Distribution Panel Al-41B, the diesel-driven
fire pump received an inadvertent start signal.
E4 ! Engineering Staff Knowledge and Performance
. E4.1 Scaffolding Erection to Support Snubber inspections
a. Inspection Scope (37551)
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The licensee erected a platform on top of a cable tray in the turbine building. The
L ' inspectors followed up to determine what effect this had on the cable tray.
b; Observations and Findings
Prior to beginning the refueling outage, contract personnel erected scaffolding
- throughout the plant. In the turbine building, the inspectors noted that a platform was
y erected such that portions of it rested on a cable tray. This platform was constructed to
support snubber inspections. The inspectors asked what effect the plat'orm would have
on the cable tray and the cables inside the tray. The licensee stated that an evaluation
had concluded that erecting the platform on top of the cable tray would not affect the
cable in the tray;
l Several days later, the inspectors noticed two individuals working on top of the platform.
The inspectors asked if the earlier evaluation included the weight of the individuals
- standing on the platform. The licensee stated that their eeriier evaluation did not include
theweight of the workers standing on the platform.' Following this question, the licensee
performed an evaluation that concluded that the ' additional weight of the individuals
standing on the platform did not have an adverse effect on the cable tray.
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c. Conclusens
The licensee's initial evaluation that allowed a platform to be constructed on a cable tray 3
was deficent, in that it did not censider the additional weight of individuals standing on j
the platform. When questioned by the inspectors, the licensee performed an additional
analysis that concluded that the additional weight did not have an adverse effect on the
. cable trays.
E8- Miscellaneous Engineering issues (92700)
E8.1 (Closed) Licensee Event Report (LER) 50-285/96-08: Inadequate initial construction of
, tomado venting in safety-related areas. On June 15,1996, the licensee determined that
the tomado venting panels in the auxiliary building were encumbered by various
attachments which made the panels incapable of performing their design function.
. Subsequently, the licensee performed a safety analysis for operability and took the
following compensatory measures:
. Removal of all the encumbrances over the tomado vents;
. Revisions to Abnormal Operating Procedure-01, ' Acts of Nature," to open specific
doors in the auxiliary building and post appropriate fire watches when a tomado
has been sighted or is expected. Additional analysis was completed and ,
determined that these compensatory actions were not necessary; and I
- Additional modifications were made to some removable block walls to prevent
potential adverse interactions with safety equipment.
. During initial construction, _the licensee failed to maintain adequate design control
regarding tomado venting and modifications to the auxiliary building. This resulted in
structures being built on top of the vents which would impede their venting capability. s
This nonrepetitive, licensee-identified and corrected violation is being treated as a
noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy
'(50-285/9809-02).
IV. Plant Support
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, R1 Radiological Protection and Chemistry Controls
' R1.1 Failure to Label Bags of Radcactive Waste
a. Insoection Scone (71750)
The inspectors followed up on the removal of 15 bags containing radioactive waste from
the containment to the radioactive waste building.
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b. Observahons and Findings
On May 5,1998, during a tour of the radioactive waste building, a' radiation protection
techmcsan observed 15 bags of radioactive material without proper labeling. The bags -
were immediately surveyed and labeled. All of the bags had radiation levels less than
2 mrom/hr.
The heensee determined that the bage had been surveyed inside containment and
determined to be less than 2 mrom/hr, however the bags were then removed from
containment as directed by a radiation protection technician without proper labeling.
10 CFR 20.1904(a) states, in part, that the licensee shall label each container of .
'
radioachve material with sufficent information, such as the highest contact dose rate, so
that individuals in the vicinity of the radioactive material can take precautions to minimize {
! exposures. Failure to label 15 bags of radioactive waste is a violation of 10 CFR l
. 20.1904(a). This nonrepetitive, licensee-identified and corrected violabon is being . I
treated as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement
Policy (50-285/9809-03). ,
r - As corrective action, the licensee performed the following actions:
- Surveyed and escorted the bags to a proper storage location;
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.~ Walked down the entire plant to look for unmarked bags;
. Briefed the radiation protection technicians in shift tumover meetings;
.- Put requirements on the plant information system for plant staff review; and
.
. Briefed the plant management of expectations.
!
Conclusion
The licensee failed to properly label 15 bags of radioactive material in the radioactive
. waste building as required by 10 CFR 20.1904(a). This nonrepetitive, licensee-identified
and corrected violation is being treated as a noncited violation, consistent with
l- Section Vll.B.1 of the NRC Enforcement Policy (50-285/9809-03).
!
lL V. Management Meetings
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'X1 Exit Meeting Summary
The inspectors presented the inspection results to the mambers of licensee management
at the exit meeting on May 26,1998. The licensee ackriowledged the findings
presented.
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The inspectors asked the licensee whether any materiais examined during the inspection
should be considered proprietary. No proprietary information was identWied.
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ATTACHMENT 1
SUPPLEMENTAL INFORMATION
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
J. Chase, Plant Manager
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R. Conner, Manager, Training
S. Gambhir, Division Manager, Engineering and Operations Support
J. Gasper, Manager, Nuclear Projects ,
S. Gebers, Manager, Radiation Protection l '
R. Jaworski, Manager, Design Engineering
R. Phelps, Manager, Station Engineering ,
R. Ridenours, Supervisor, Station Licensing j
INSPECTION PROCEDURES USED
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IP37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
! IP 71707: Plant Operations j
IP 71750: Plant Support Activities
IP 92901 Followup Operations
IP 92700 Onsite LER Review
ITEMS OPENED. CLOSED. AND DISCUSSED j
Opened
50-285/9809-01 VIO Cavitation of a Reactor Coolant Pump (Section 08.1) i
!
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! Closed
50-285/9802-02 URI Cavitation of a Reactor Coolant Pump (Section 08.1) !
50-285/96-008 LER Inadequate initial Construction of Tornado Venting
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(Section E8.1)
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Opened and
Closed
50-285/9809-02 NCV Failure to Maintain Adequate Design Control Regarding
Tornado Venting (Section E8.1)
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50-285/9809-03 NCV Failure to Property Label Radioactive Waste (Section R1.1)
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