ML20133E780
| ML20133E780 | |
| Person / Time | |
|---|---|
| Site: | Braidwood  |
| Issue date: | 01/03/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20133E763 | List: |
| References | |
| 50-456-96-14, 50-457-96-14, NUDOCS 9701130149 | |
| Download: ML20133E780 (26) | |
See also: IR 05000456/1996014
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,U.S. NUCLEAR REGULATORY COMMISSION
REGION III
l Docket Nos: 50-456. 50-457
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Report No: 50-456/96014: 50-457/96014
1 Licensee: Commonwealth Edison (Comed)
Facility: Braidwood Nuclear Plant Units 1 and 2
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Location: RR #1, 80 ( 79
Braceville. IL 60407
Dates: September 7 - October 18, 1996
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Inspectors: C. Phillias, Senior Resident Inspector
M. Kunowsci, Resident Inspector
J. Adams. Resident Inspector
T. Esper, Illinois Department of Nuclear Safety
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Approved by: R. D. Lanksbury. Chief. Projects Branch 3
Division of Reactor Projects l
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9701130149 970103
PDR ADOCK 05000456
0 PDR
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EXECUTIVE SUMMARY
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Braidwood Nuclear Plant. Units 1 & 2
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NRC Inspection Report 50-456/96014; 50-457/96014 j
This inspection included aspects of licensee operations, engir1eering,
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maintenance, and plant support. The report covers a 6-week period of resident ;
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inspection. l
Operations j
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The inspectors concluded that prom t action by the Unit 1 reactor
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operator prevented a significant p ant transient after a failure of the
l master feedwater pump controller. (Section 01.1) l
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NRC inspectors identified that on September 10, while performing a '
Unit 1 diesel generator monthly operability surveillance, the most
recent revision of the procedure was not used. A Notice of Violation
was issued. (Section 03.1)
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The licensee identified that a non-licensed operator tasked with
securing the 1C condensate booster pump shut the pump suction valve
instead of the discharge valve as required by procedure, damaging the
pump. (Section 04.1)
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The inspectors observed that operations personnel responded tc
unex)ected conditions systematically and efficiently after the failure
6f t1e Unit 1B containment spray to start during a surveillance test.
(Section 04.2)
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The licensee identified that two non-licensed operators failed to follow
a procedure and sprayed about 150 gallons of water into the 18 diesel
oil storage tank room during a fire protection surveillance. This
licensee identified and corrected failure to foilow procedures was a
non-cited violation. (Section 04.3)
Maintenance
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The inspectors observed that 03erators were unable to rack in the
Train 'A' RCactor Trip Bypass areaker during the performance of the bi-
monthly operability survaillance for the Solid State Protection System ,
(SSPC), Reactor Trip Breaker, and Reactor Trip Bypass (BY) Breaker. The l
oaerators emergency exited the surveillance using prescribed sters in
t1e procedure when the problem coulo not be quickly resolved. Clear
procedures, thorough briefings, and recise communications resulted in
an unusual situation being well hand ed. (Section M2.2)
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The licensee identified that two safety injection vent and drain valves
and two local leak rate test connectors were not included in
l surveillance procedure 1(2)Bw0S 6.1.la-1. " Primary Containment Integrity
l Verification Of Isolation Devices Outside Containment." This issue was
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an unresolved item pending a review to determine if there was a
violation of technical specification 4.6.1.1. (Section M2.4)
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The inspectors observed that the 1A motor driven feedwater pump had
severe oil leakage as high as 17 gpm ano concluded that the material
condition of the pump was poor. (Section M2.5) .
Enoineerina
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The licensee identified several roll-up fire doors for rooms that
cor,tained safety-related equi) ment that failed to close when outside air
veni.ilatinn was supplied to tle rooms during surveillance testing. When
the differential pressure across the doors was removed by securing
outside air ventilation, the doors closed normally. The surveillance
procedure did not specify ventilation lineup or acceptance criteria and
was marked as completed satisfactorily. Five days later, a Problem
Identification Form (Ph-) was generated but the required plant barrier
impairment controls were not initiated fcr 2 month:. The licensee also
determined tnat the Unit 1 roll-up fire doors had never been post- ,
modification te-ted. This was an unreso,/ed item pending completion of '
testing of the Unit 1 roll-up fire doors. (Section E2.1)
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The inspectors reviewed the status of temporary alterations. Temporary
, alterations were found to be installed in accordance with plans and no
unauthorized alterations were found. The inspectors concluded that the
number of temporary alterations installed greater than 18 months was
high (14) and that management controls to ensure that plant problems are
4 fixed permanently and in a timely manner were not effective in these
insunces. (Section E2.3)
Plant Sucoort
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Based on observations during this inspection period, the inspectors
concluded that radiological housekeeping and contamination control was
good. No problems were identifiet i. (Section R1.1)
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During this inspection period, security guards were observed performing
their daily rout',es as expected and no problems were identified.
(Section S1.1) l
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Report Details !
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Summarv of Plant Status l
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! Unit 1 entered the period performing a unit shutdown. The unit was shutdown
l on September 7,1996, to repair leaking feedwater drain valves off the 'C' and l
l 'D' steam generators. The valves were repaired and the unit returned to '
l service on September 9, 1996. Unit 1 was returned to 100% power and operated
routinely until October 11, 1996, when the un1! began a ramp down to full <
shutdown at 3:01 a.m. on October 12, 1996, for a scheduled mid-cycle outage.
Unit 2 operated at or about 100% power for the entire period.
I. Operations
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01 Conduct of Operations
01.1 Unit 1 Master Feedwater Controller Demand Signal Fails to Zero Outout
a. Scone (71707)-
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At approximately 11:00 a.m., on Se)tember 16, 1996. Unit 1 mester l
feedwater pump speed controller (1)K-FW509) demand signal dropped from
78% output to 0% output. As a result, both main feedwater pumps began
slowing to minimum speed for the master feedwater controller (3100 rpm).
Unit 1 was operating at 100% power at the time of the event. The
inspectors interviewed operations, instrument maintenance, and system
engineering personnel involved in the event. I
b. Observations and Findings
The master feedwater pump controller was in manual at the time of the
event because instrument maintenance personnel were performing work on
the main steam header pressure transmitter (1PT-507). Pressure
transmitter 1PT-507 had been in " test" for about 3 minutes when the
output for 1PK-FW509 failed to zero.
At the time of the event, the Unit 1 reactor 03erator (RO) was closely
monitoring the feedwater system due to the worc in progress on 1PT-507.
The first control room indication of a problem was the "STM/FW FLOW
MISMATCH" alarm for all four steam generators. The R0 recognized the
demand signal at zero and took immediate actions to manually restore the
controller output signal. Unit 1 control room personnel also took
immediate actions to notify instrument maintenance personnel working on
1PT-507 to stop work.
The P0 actions to restore the master feedwater output demand signal were
successful and both feed.later pumps returned to the speed recuired for
100% full power operation. Steam generator levels stabilizec and
returned to normal level of about 66% narrow range once master feedwater
demand was returned to normal. The steam generators level dec mase due
to the ecent was about 13%. The Unit 1 reactor trip set point for low
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steam generator level was at 33% narrow range. Unit power output was
not significantly changed during the event.
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The work performed on 1PT-507 should not have affected the master
feedwater controller output. The area where the work on 1PT-507 was
performed had no circuitry or equipment that could change 1PK-FW509
output. The system engineer verified that no circuitry or equipment
around the 1PT-507 work area could have affected 1PK-FW509.
The system engineer believed that a brief failure in an electronic
l control card for 1PK-FW509 caused the event. The control card in
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question was replaced and the master controller functioned properly
following the replacement. Efforts at the site to identify the failure
in the card were unsuccessful and the card was sent to the manufacturer
for evaluation. :
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The system engineer indicated that the rapid speed change had no
apparent adverse affects on the main feedwater pumps / turbines.
Feedwater pump / turbine parameters after the event were essentially the
same as before the event. l
c. Conclusions
Feedwater system monitoring by control room personnel and operations
department response to the loss of demand signal from 1PK-FW509 were
excellent. Prompt actions taken by operating personnel prevented a
large steam generator level and unit power transient.
02 Operational Status of Facilities and Equipment
02.1 Enaineered Safety Feature System Walkdowns (71707)
The inspectors used Inspection Procedure 71707 to walk down accessible
portions of the Residual Heat Removal (RHR) system. Results of the
inspection are discussed in Section E2.2.
03 Operations Procedures and Documentation
03.1 Incorrect Revision Used While Performina Monthly Test on the 18 Diesel l
Generator (DG) '
a. Inspection Scope (61726)
The inspectors identified that a non-licensed operator was not using the ,
most current revision of 18w05 8.1.1.2.a-2. " Unit One 1B Diesel l
Generator Operability Monthly (Staggered) and Semi-annual (Staggered)
Surveillance." Revision 15. The inspectors interviewed the equipment
operator (EO), the RO. and the Unit 1 unit supervisor. l
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b. Observations and Findinas
t On September 10. operations personnel were concurrently performing Bw0P
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DG-11. " Diesel Generator Startup." Revision 11 and 18w0S 8.1.1.2.a-2.
" Unit One 1B Diesel Generator Operability Monthly (Staggered) and Semi-
annual (Staggered) Surveillance." Revision 15. The inspectors observed
that procedural step F1.10 had not been performed; the inspectors
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questioned the non-licensed operator on whether he had performed the
step. In response, the non-licensed operator obtained the copy of the
i surveillance procedure to see if he had signed off that step. Upon
review of his procedure, step F 1.10 was not included in his version of
the procedure.
Procedural step F1.10 had the non-licensed operator verify that service
water was available to the DG by stroking valve. 1SX1698. "DG service
water valve." The non-licensed operator was using 18w0S 8.1.1.2a-2.
Revision 14E1 which was dated June 28. 1996. The most current revision
to the procedure was Revision 15. dated September 9, 1996. The
inspectors requested the non-licensed operator to inform the control
room of the discre)ancy. Immediate corrective action taken by the
licensee included laving control room personnel forward the most current
revision to the operator.
The licensee's investigation into the event indicated that the Unit 1
unit supervisor obtained the co)y of the surveillance from the
controlled file cabinet the nig1t of September 9. reviewed the
procedure, then placed a cover sheet on the surveillance. However, the
new revision was placed in the cabinet the morning of September 10. As
a result, the Unit 1 supervisor was not aware of the new revision. The
licensee determined that there was no adverse impact from not performing
step F1.10.
c. Conclusions
The failure to use the correct procedural revision to test the 1B DG is
a violation of 10 CFR Part 50. Appendix B. Criterion V (50-456/96014-01
(DRP)).
04 Operator Knowledge and Performance
04.1 Condensate Pumo Suction Valve Miscositioned
a. Inspection Scooe (71707)
The inspectors interviewed operations department managers, walked down
the location of 1DC0996 1C condensate booster Jump suction valve and
reviewed 18w0P DC/CB2 " Condensate / Condensate 300 ster System Shutdown."
Revision 8.
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b. Observations and Findings
On August 30, 1996, a non-licensed operator mispositioned 1CD099C the
1C condensate booster pump suction valve, during a pum) swap to clean
strainers. The strainer cleaning evolution required t1e shutdown of the
1C condensate booster pump. Bw0P CD/CB-2, " Condensate / Condensate
Booster System Shutdown," Revision 8. Step F.4., required that the
discharge valve of the 1C condensate booster pump be shut prior to
securing the condensate booster pump. Licensee personnel stated that
l prior to securing the booster pump a reactor operator noticed 1C
l condensate booster pump flow go to zero for about 2 minutes and then
l came back to full flcw. The reactor operator called the non-licensed
( operator in the room and asked if he had repositioned any valves. The
l non-licensed operator responded that he had not yet repositioned any
l valves. The evolution was then completed and the 1C condensate booster
pump was secured.
On September 4, 1996, the 1C condensate booster pump was restarted and
Jump output steadily decayed over about 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Another condensate
acoster pump was started and the 1C pump was secured. Maintenance
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trouble-shooting revealed that the pump inboard wearing ring was broken
in several pieces and the pump impeller was worn because of the broken ;
wearing ring.
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Computer point flow data indicated that the 1C condensate booster pump
flow went to zero for about two minutes on August 30. Licensee
personnel stated that according to the pump manufacturer a 2 minute
disruption of flow could only cause the damage found if the suction
valve had been closed because of a loss of cooling medium for the pump.
The licensee conducted awareness briefings for licensed and non-licensed l
operators on September 12 to discuss several recent events concerning ,
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configuration control (discussed in Inspection Report 96012). The '
inspectors attended one awareness briefing, at which
adherence, self-checking, and adherence to operation' procedures department j
standards were discussed.
Licensee personnel stated that the non-licensed operator reported, on .
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September 15. that he had indeed shut the suction valve instead of the
discharge valve but did not think it had caused any damage. The
licensee terminated the employment of the non-licensed operator because
of his failure to initially disclose his mistake. The licensee did not
determine why the non-licensed operator mispositioned the valve, 3rior
to his termination. Licensee management stated that because of tie
previous events, the operators credibility was questionable and saw no
value in further questioning why the valve was mispositioned.
c. Conclusions
The failure to follow the procedure resulted in damage to plant
equipment. However, since the condensate / condensate booster systems are
not safety-related and do not fall under NRC requirements, no notice of i
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violation will be issued. The inspectors concluded that awareness
briefings conducted on September 12. and the employment termination of
the employee were adequate corrective actions.
04.2 Surveillance Run of 18 Containment Soray Pomo
a. Inspection Scone (61726)
On September 16, 1996, the 1B containment spray pump was run during
3erformance of procedure 1BwVS 6.2.1.b-2. "American Society of .
Mechanical Engineers (ASME) Surveillance Requirements for 1B Containment '
Spray Pump and Check Valves 1CS003B and 1CS011B." The inspector
monitored the performance of the test at the 1B containment spray pum)
and interviewed the system engineer acting as the test director and t1e
plant E0 stationed at the containment spray pump during the test. The
inspector also performed a review of procedures 1BwVS 6.2.1.b-2 and Bw0P
CS-5. " Containment Spray System Recirculation to the RWST." for
compliance with Updated Final Safety Analysis Report (UFSAR) assumptions
and technical specification (TS) surveillance requirements.
b. Observations and Findinos
The inspector observed the following:
. The E0 at the pum) utilized three-way communications techniques
every time he talced with the unit R0 in the control room.
. The E0 used self-checking when operating plant equipment.
. Control room personnel made plant-wide announcements prior to
starting or stopping the containment spray pump.
. The system engineer acted as the test director for the
surveillance and was present at the pump during aerformance of the
entire test. The system engineer was knowledgea)le on operation
of the plant equipment and use of test equipment. Test equipment
and instrumentation used in the test were within calibration due
dates.
. An industrial safety representative was present during performance
, of the test to ensure site expectations with respect to personnel
safety were observed.
An unexpected condition occurred during performance of the test. After l
the containment spray system was aligned per Bw0P CS-5. the control room I
operator attempted to start the 1B containment spray pump and it did not I
start. In response to the failure to start, the control room notified
the E0 stationed at the pump. The operators then began troubleshooting i
the failure to start.
Control room personnel sent an E0 to the 1B containment spray pump l
breaker to verify that the breaker was properly racked-in and no signs
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of breaker problems were evident. After racking the associated breaker
out and then in, the operators attempted to start the pump again. It
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failed to start on the second attempt.
Additional trouble shouting by the licensee found the lifting arm on the
valve stem had rotated due to mechanical play and was not making contact
with the limit switch. The operator was able to correct the limit
switch problem and the interlock was satisfied.
The IB containment spray pump was subsequently successfully started and
run. Operations response to the failure to start was systematic and the
operator knowledge of the system provided for quick resolution of the
problem.
c. Conclusions
Operations and system engineering support for performance of the rout ne
surveillance test on 1B containment spray pump was good. The limit I
switch for 1SI001B not being fully engaged because of mechanical play i
only had significance while the Jump was in a test mode. The safety I
features were unaffected. The a)ility of the pump to start in a normal l
configuration was not affected.
04.3 Miscositioned Valve Caused Water Release to the 1B Diesel Oil
Storage Tank Room
a. Insoection Scope
On September ll, during performance of surveillance test procedure
OBw05 FP.3.1.0-1, " Diesel Generator Fuel Oil Storage Tank Rooms
Foam Systems Main Drain and Alarm Test Quarterly Surveillance," an
E0 opened 1FP258. the deluge isolation valve. instead of the
adjacent 1FP371. system main drain valve. The valve was opened
about 48 seconds before the operator realized that he opened the
wrong valve. About 150 gallons of fire protection water sprayed
into the 18 diesel oil storage tank room. The licensee
subsequently removed the water, verified the operability of
electrical equipment in the room, and began an investigation. The
inspectors reviewed the valve arrangement and the results of the
investigation,
b. Observations and Findings
The E0 was working with an ecuipment attendant (EA) during the
surveillance. The licensee cetermined that the EA had read the
procedure, but the E0 had not. During the surveillance, the EA
pointed in the vicinity of the 1FP371 valve and directed the E0 to
o)en it, but did not identify the valve by name or number. The E0
t1en opened the 1FP258 valve without checking the valve tag or
verifying valve identification with the EA. The workers realized
their mistake when no water flowed out the drain hose they had
connected near the 1FP371 valve.
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For the failures to meet management expectations regarding
procedure use, communichtions, and self-checking, the operators
were given time off from work. In addition, the station
. temporarily halted non-licensed operator work, while non-licensed
operators, their immediate supervisors, and shift engineers
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attended a discussion session on the personnel performance
problems manifested in this event and two other recent valve
mispositioning events (involving a boric acid tank valve and a
diesel oil storage tank valve, discussed in Inspection Report
96012) on September 12.
c, Conclusions
The licensee's investigation of the valve mispositioning was
prompt and thorough; however, the three recent events involving ,
valve mispositioning by non-licensed operators were indicative of !
a weakness in plant configuration control. l
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TS 6.8.la required that written procedures be established, implemented,
and maintained covering activities recommended in Regulatory Guide 1.33, ,
Revision 2, Appendix A. TS 6.8.la applies to 0Bw0S FP.3.1.0-1 and I
therefore. the failure to follow OBwCS FP.3.1.0-1 was a violation of
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by the licensee were adequate. This licensee-identified and corrected
violation is being treated as a non-cited violation consistent with
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Section VII.B1 of the NRC Enforcement Policy (50-456/96014-02 (DRP)).
08 Hiscellaneous Operations Issues (92901) l
08.1 (Closed) Insoection Followuo Item (IFI) 95017-04: Inspectors to
review surveillance revision for the post-accident neutron
monitoring system. The licensee added a quarterly verification of i
calibration to the surveillance which had consisted of only en
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18-month calibration. In addition. a system training module was
developed and presented to licensed operators earlier in 1996 during
requalification training. The training will be repeated again in '
2 years. The inspectors had no further concerns and this item is
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closed.
II. Maintenance
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H2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Susoected Lubrication Problem with Westinghouse Series DS 480-Volt
Breakers
a. InsDection ScoDe
On September 24 the IC Reactor Containment Fan Cooling (RCFC) fan
failed to automatically start in slow speed during surveillance
18w0S 6.2.3.A-1, "RCFC Monthly Surveillance," and also did not
start when the control room control switch for the fan's low speed
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breaker was manually taken to "close." The inspectors observed
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the performance of the surveillance and the subsequent attemated
manual start. The licensee declared the fan inoperable and )egan
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On October 10, the Ty)e DS safety-related breaker for the supply
ventilation fan for tle Unit 1 1B DG room failed to close during a
surveillance run of the diesel.
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After the RCFC breaker failure, the resident inspectors and
Region III electrical specialists followed the licensee's investigation.
i On October 10 and 11. a telephone conference was held with the NRC
4 headcuarters personnel, Regional III electrical specialists, the
- resicent inspectors, and the licensee to discuss the NRC concerns about
the operability of the other safety-related breakers.
j b. Observations and Findings
Both breakers were Westinghouse series DS 480-volt circuit breaker. The
j licensee had 12 of the type 416 DS breakers, used as reactor trip and
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reactor trip bypass breakers, and about 320 of the type 206 DS breakers,
60 of which were safety-related. Of these 60 breakers, there were 12
I Unit 1 breakers and 10 Unit 2 breakers that were required to close in an
i accident scenario.
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A licensee investigation found that the RCFC breaker had a failed
1 charging motor cutoff switch, and the DG su) ply fan breaker had an over i
j heated and failed spring release coil. Bot 1 of these breakers plus
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others had been onsite since initial startup.
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- In addition, the licensee found that the Westinghouse breaker operations
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and maintenance manual did not address lubrication of the operating
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mechanism in these breakers. These along with other breakers had not
I had the operating mechanisms lubricated at Byron and Braidwood,
i The RCFC and the DG supply fan breakers along with others were submitted
- to Westinghouse for a detailed failure analysis. The results of that
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investigation is an inspection followup item for possible generic
- applications (50-456/457/96014-03(DRS)).
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Similar issues related to 4.16 kilovolt breakers and some 480 volt
i breakers were addressed in inspection report 95016. As a result,
i recently Byron shipped several non-safety related breakers to
Westinghouse for refurbishment. Braidwood contracted with Westinghouse
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to overhaul some breakers onsite and train maintenance personnel on the
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issues not addressed in the maintenance manual. The licensee has also
i committed to revise procedures as necessary and train personnel,
c. Conclusions
l The inspectors concluded control room personnel responded well to
j the breaker problem on September 24. The results of the failure
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analysis of the two breakers and the operability assessment of the
remaining breakers will be followed up on by the Division of
Reactor Safety as an Inspection Followup Item.
M2.2 Observation of 2Bw0S 3.1.1-20. " Unit Two SSPS. Reactor Trio Breaker.
and Reactor Trio Bypass Breaker Bi-Monthly (Staqqered) Surveillance
(Train A)"
a. Insoection Scone
The inspectors reviewed the 3rocedure and observed the performance of
2Bw0S 3.1.1-20, " Unit Two SS3S. Reactor Trip Breaker, and Reactor Trip
Bypass Breaker Bi-Monthly (Staggered) Surveillance (Train A)" on
September 27 and September 30, 1996. The activities were also reviewed
against the UFSAR
b. Observations and Findings
Prior to the commencement of the surveillance on September 27. the
ins]ector observed a tailgate meeting conducted by the unit supervisor
wit 1 personnel involved in the performance of the surveillance. The
meeting reviewed recent problems that had been encountered with racking
in the Unit 2 reactor trip bypass breaker A (BYA) and what action would
be taken in the event similar problems were encountered during the
performance of the surveillance.
The licensee personnel experienced more resistance than normal on
several attempts at racking in the breakers. As authorized by the I
procedure, an emergency exit was conducted from the procedure. l
On September 30 the ins]ectors observed the successful performance of I
2Bw0S 3.1.1-20. No pro]lems were encountered during the performance of '
this surveillance and the operators completed the surveillance well
within the 2-hour time requirement that started with the racking in of
the Train A Reactor Trip Bypass Breaker.
The inspectors observed the following good work practices during the
performance of this surveillance: 1) the unit supervisor anticipated
the 30ssibility for additional BYA breaker problems and briefed the crew
on t1e action to be taken in the event they recurred and the R0s
consistently checked each other's action prior to performing the action;
2) the R0s and EOs demonstrated good communication skills by using the
phonetic alphabet and three way repeatbacks. The inspectors also noted
that the surveillance procedure was well written and provided clear
directions to the operators. The operators were able to use the
procedure to perform the emergency exit (a non-routine evolution) and
system restoration without confusion or delay.
c. Conclusion
The inspectors concluded that the pre-surveillance preparation was good,
that control room crews demonstrated govd team work and good
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communication. The inspectors also concluded that the procedure was
well written and provided clear guidance for backing out of the process.
M2.3 Safety Iniection Motor Operated Valve (SI-8804B) Stroke Test Failure
a. Inspection Scoce
During the performance of 2Bw0S 0.5.SI.l. " Safety Injection System Valve
Stroke Quarterly Surveillance." Revision 1E2, on September 25, 1996, the
licensee observed that motor operated valve (MOV) 2SI8804B failed to
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stroke fully open. Licensee personnel locally verified valve position
I at 90% open. As a result, the "B" Emergency Core Cooling System (ECCS)
I train was declared inoperable and a 7-day time clock was started per TS
l Limiting Condition for Operation 3/4.5.2. The inspectors interviewed
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the Unit 2 unit supervisor and site engineering staff, and reviewed the
following documentation: 1) Unit 2 Control Room Log (9/25/96): 2) 2Bw0S
0.5.SI.1. " Safety Injection System Valve Stroke Quarterly Surveillance."
Revision 1E2: 3) BwAP 330-10. Attachment B. Revision 2. " Operability
Justification:" and 4) Work Package WR 96009031101.
" Troubleshoot / Repair. Open Stroke Circuitry For 2SI88048-L05." ,
b. Observations and Findinas
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The inspector found that the Unit 2 operators had observed simultaneous
open and closed indications on 2SI8804B position indicating lights
during the performance of the open stroke test and the B Train of ECCS
was appropriately declared inoperable. The valve was then stroked
closed and a fully closed indication was received by the operators.
2SI8804B was then stroked open by the operators. The valve opened and
the proper position indication was observed. A stroke time of 14.05
seconds was measured and verified to be less than the operability limit
of 15 seconds. The valve was closed and the open stroke time test
repeated. A 14.05 seconds opening time was again measured and 2SI8804B
was declared operable. The inspectors considered the re-stroking of the
valve without conducting an investigation to determine the cause of the
problem a poor work practice that could mask the problem.
The inspector reviewed surveillance procedure 2Bw0S 0.5.SI.1.
Section E. and found that it provided direction to the shift engineer to
declare the valve inoperable and initiate corrective action in the event
that the valve failed to change position. This section of the procedure
further stipulated that for any valve declared inoperable, acceptable
operation must be demonstrated after the required corrective action had
been performed but before returning the valve to service. However, the
problem was vague on what corrective actions should be taken.
The licensee based their operability of 2SI8804B on the postulated cause
of oxidized switch contacts in the control circuit the valve's initial
opening to a position of 90% which meets MOV setup guidelines, and the
l valve's capability to fully open within the required time during
i subsequent valve stroke test. The licensee concluded that there was
l reasonable assurance that 2SI8804B would open and close as required and
13
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.
.-
no operability concern existed. Diagnostic testing and limit switch
maintenance was performed subsequently on October 8 per Work Request
(WR) 96009031101. " Troubleshoot / Repair: Open Stroke Circuitry For
2SI8804B-L05." The contact wipe pressure was found to be minimal and
l was adjusted per the MOV Coordinator's direction. Valve operation,
testing, and evaluation system (VOTES) testing was performed and the
valve stroked satisfactorily.
c. Conclusion
l
The ins)ectors concluded that 2SI8804B was appropriately declared !
inoperaale when the valve failed to change positions correctly, but j
l
considered the subsequent re-stroke of valve as a poor operating
practice. Retesting of a system or com3onent without conducting an
investigation for the cause could possi)1y mask the conditions
responsible for the failure and allow for a future recurrence.
2Bw0S 0.5.SI.1. Section E, was vague as to what constituted a
corrective action and does not provide what actions to take. ppropriate
M2.4 Missed Surveillance on Containment Isolation Valves
a. Insoection Scooe
On October 4. 1996, the licensee determined that the instrument vent and
drain valves for 1(2)PI-929 (Safety Injection) were not included on
1(2)Bw0S 6.1.1.a-1. " Unit One (Two) Primary Containment Integrity
Verification Of Isolation Devices Outside Containment." The inspectors
reviewed the licensee's immediate corrective action and subsequent
follow up actions. ,
l
b. Observations and Findinas )
The insSectors found that on October 4, 1996, the licensee entered and l
exited imiting Condition for Operation 4.0.3 on both units when it was i
learned that the instrument vent and drain valves for 1(2)PI-929 were
missing from 1(2)Bw0S 6.1.1.a-1, " Unit One (Two) Primary Containment
Integrity Verification Of Isolation Devices Outside Containment." The
licensee verified the vent and drain valves were closed and capped, hung
administrative control tags on all valves, and submitted ]rocedure
revisions to include the valves in 1(2)Bw0S 6.1.1.a-1. T1e licensee
also conducted a review of all containment piping penetrations to ensure
no other valves had been missed. The review identified two local leak
rate test (LLRT) test connections which were not being checked. The
licensee took the same immediate corrective actions for the LLRT test
valves as they did for the instrument vent and drains. The licensee
also commenced a review to determine what the surveillance requirements
were on the valves in question since the Byron Station's equivalent
procedure did contain these valves for testing. The inspectors believed
that these valves were required to be tested in accordance with the
technical specifications. Region III requested the Office of Nuclear
Reactor Regulations (NRR) to review this concern.
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c. Conclusion
This is an Unresolved Item (50-456/457/96014-04(DRP)) pending a review
-
i by NRR of the valves surveillance requirements provided by the licensee.
l
l M2.5 Material Condition of 1A Motor Driven Feedwater Pumo
a. Inspection scone
l
1
1 The 1A motor driven feedwater pump was placed in service on Se)tember 23
to perform repairs to the 1C turbine driven feedwater pump. T1e
'
inspectors interviewed control room operators and walked down the 1A
motor driven feedwater pump.
b. Observations and Findinas
The licensee identified that the 1A motor driven feedwater Jump
develo]ed a lube oil leak of about 30 gallons per shift. T1e licensee
went t1 rough several 55 gallon drums of lubricating oil before a
recycling method was established. The day before the 1C turbine driven
feedwater pump was restored to service the lube oil leak had increased
to about 17 gallons per hour.
Licensee personnel stated that the 1A motor driven feedwater pump had
not been run for several years due to a combination of the good
reliability of the turbine driven pumps and the amount of vibration that
resulted in the shift engineers office when the motor driven pump was
run.
c. Conclusions
The inspectors concluded that the material condition of the 1A motor
driven feedwater pump was poor.
M8 Hiscellaneous Maintenance Issues (92902)
M8.1 1 Closed) Licensee Event ReDort (LER) 50-456/96002:
Loss of Operability of Both Trains of Control Room Ventilation due to a
Personnel Error. On January 29. 1996, the "B" train of control room
ventilation was momentarily rendered inoperable when an electrician
inadvertently grounded the 120-volt feed breaker while replacing an
indicator light socket on a ventilation local control panel. At the
time, the "A" train was technically inoperable, awaiting a post-
maintenance test. During the subsequent assessment of B train
operability by control room personnel, the breaker was opened twice,
again rendering the B train inoperable. With both trains of control
room ventilation inoperable. TS 3.0.3 applied. However, B train
operability was re.tored before the TS 6-hour limit to reactor shutdown
was reached. The licensee's investigation determined that the
l electrician had not discussed the work with control room personnel
i because he considered it minor. This failure to discuss the job with
l control room personnel was contrary to BwAP 1600-10. " Minor Maintenance
,
i 15
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Procedure." The electrician was counselled on the need to follow the
procedure and discuss all work with control room personnel. The event
-
and the procedure requirements were also discussed with other electrical
maintenance personnel.
TS 6.8.la requires that written procedures be established,
implemented, and maintained covering activities recommended in
Regulatory Guide 1.33, Revision 2 Appendix A. TS 6.8.la applies
to BwAP 1600-10 and therefore this event was a violation of TS 6.0.la. The inspectors concluded that the corrective actions as
described in the LER were adequate. This licensee-identified and
corrected violation is being treated as a non-cited violation,
consistent with Section VII.B.1 of the NRC Enforcement Policy (50-
456/96014-05 (DRP)). The inspectors noted, however, that the
cover letter for the LER incorrectly listed 10 CFR 73.71(a)(2)(ii)
as the reporting basis for the event. The text of the LER
correctly listed 10 CFR 50.73(a)(2)(1) as the basis. In addition,
the text referred to two different motor control centers as the
location of the breaker. These two minor errors indicated that
the quality control of the LER could have been improved.
III. Enaineerina
E2 Engineering Support of Facilities and Equipment
E2.1 Roll-Up Fire Doors Fail to Close
<
a. LnSoection Scooe (37551)
On July 3. mechanical maintenance performed surveillance BwMS 3350-001.
" Fire and Security Door Semi-Annual Inspection," Revision 0, and several
roll-up fire doors did not go closed as expected with outside air
ventilation supplied to the room.
The inspectors reviewed BwMS 3350-001: BwAP 1110-3, " Plant Barrier
Impairment Program," Revision 3: BwAP 1100-8, " Fire Protection Program
System Recuirements." Revision 5: Problem Identification Forms 456-120-
96-011 anc 450-201-96-2158: and Calculation 3C8-0691-001. In addition,
the inspectors interviewed the mechanical maintenance worker that
performed the surveillance, the mechanical maintenance first-line
supervisor, the fire marshall, and several system and site engineers.
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b. Observations and Findin.q.ji
l
l BwMS 3350-001 tests the following 12 roll-up fire doors:
l
1A & 18 diesel generator rooms
- 2A & 28 diesel generator rooms
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Unit 1 Division 11 & 12 ESF switchgear rooms
Unit 2 Division 21 & 22 ESF switchgear rooms
Unit 1 non-ESF switchgear rooms
l Unit 2 non-ESF switchgear rooms
Unit 1 miscellaneous electric equipment rooms
1 Unit 2 miscellaneous electric equipment rooms
BwMS 3350-001 did not specify what the ventilation status of the room l
should have been and did not require that it be documented. l
During the performance of BwMS 3350-001 on July 2.1996, the 2A Diesel
Generator roll-up fira door failed to close when the electro th'ermal
linkage was removed with the outside air ventilation supplied to the
room. This was due to the high differential air pressure across the
l
door. During the performance of BwMS 3350-001 on July 3. 1996, the i
doors to the Unit 1 and Unit 2 non-engineered safeguard feature (ESF) '
switchgear rooms and the Unit 2 Division 21 ESF switchgear rooms also
did not go shut with ouLside ventilation supplied to the room.
On September 3 the licensee determined that a high energy line break I
analysis (calcul3 tion 3C8-0691-001) for U1e turbine building assumed !
that the roll-up doors would go shut. The licensee closed all 12 roll- 3
up doors in order to ensure the plants would be in an analyzed l
U,ndition.
l
The licensee 31anned to test the Unit 1 doors under full ventilation
flow during tie Unit 1 mid-cycle outage scheduled to start October 12.
c. Conclusions
Followup results on this issue by the Region III Division of Reactor l
Safety (DRS) had not been completed at the end of this inspection The l
results of this ins)ection are an Unresolved Item pending the completion '
of the testing of t1e Unit 1 fire doors during the Unit 1 mid-cycle
om age and e followup inspection by a DRS fire protection specialist ;
which wil. La documented in inspection report 96016 (50-456/96014-06 ;
(DRS)). j
E2.2 Residual Heat Removal (RHR) System
a. Insnection Scone (71707)
l
The inspectors reviewed the RHR system design bases i. the UFSAR and RHR )
- system lineups and drawings
- performed a walkdown of accessible portions !
l of the RHR system for proper system configuration and material l
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condition; and performed a review of the following completed l
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surveillance procedures for proper completion and to ensure TS
requirements were satisfied:
. 1BwVS 5.2.f.3-1 --
Last four completed surveillances
. 2BwVS 5.2.f.3-2 --
Last four completed surveillances
. 1Bw0S 5.2.b-2 --
Last completed surveillance
. 2Bw0S 5.2.b-2 --
Last completed surveillance
The inspector also interviewed the RHR system engineer, system
engineering primary group leader, procedures group supervisor, and plant
operating personnel.
b. Observations U 1 Findinos
The following items were observed during walkdown of accessible portions
of the residual heat removal system:
. The condition of the RHR heat exchanger rooms was good. Rooms l
were found clean with only small localized contaminated areas.
. Pressure indication on 2PI-RH028. RH Pump 2A Suction Pressure, was
found at approximately 10 psig while the other suction pressure
gauges for Unit 1 and Unit 2 Sumps all indicated approximately
45 psig. Pressure gauge 2PI-RH028 was a low range pressure gauge
and was normally isolated. However, it was unlikely that the
actual suction pressure was 10 psia when the gauge was isolated.
The gauge was routinely aligned fv service while doing
surveillance tests. After the @ le was placed in service and
subsequently isolated, the inspector monitored the pressure l
indication for several days. The pressure indication began to I
decrease. indicating a small leak. Upon close inspection of the l
isolation valve for 2PI-RH028 (2RH032A). boron crystals were ;
observed on the valve body. This indicated a small leak. The l
condition was reported to the system engineer and an Action
- Request (AR) was generated.
. The material condition of RHR Jump rooms was generally good. AR
tags were hung to identify pro)lems.
The following completed surveillance procedures were reviewed and found
complete with proper data recorded and all applicable steps completed:
. 1Bw05 5.2.b-2 performed on 8/23/96
e 2Bw0S 5.2.b-2 performed on 8/2'//96
l a 18wVS 5.2.f.3-1 performed on 5/14/96. 6/13/96. 8/5/96, and 9/5/96
. 2BwVS 5.2.f.3-2 performed on 11/9/95. 2/3/96 and 7/16/96
The completed procedure for 2BwVS 5.2.f.3-2. "ASME Surveillance
Requirements for RHR Pump 2RH01PB." performed on April 1. 1996 had ome
inconsistencies. Step f.1.7 of the procedure recorded the idle suction
pressure for the RHR pump. This step was identified as an acce)tance
criteria step. The acceptance criteria was listed as greater tlan
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( 24 psig (> 24 psig). The recorded value for the suction pressure was
l 24 psig. Therefore, the as found suction pressure did not satisfy tne i
-
listed acceptance criteria.
l There was no indication in the completed procedure that any actions were .
l taken at the time to address the acceptance criteria not being l
l satisfied. The test was completed and sent to engineering for review. !
l On A)ril 3. 1996, temporary procedure change (TPC) 7369 was generated
i
to clange the acceptance criteria to greater than or equal to 24 psig !
(a 24 psig). In accor~ 'ce with BwAP 1300-3 " Preparation and Approvc.1
of Temporary Procedure, and Temporary changes to Permanent Procedures.
TPC 7369 was processed as an " intent change" to the procedure and was
reviewed by engineering and operations (senior reactor operator). TPC
7369 also was screened for 10 CFR 50.59 changes and was reviewed by the
onsite review committee and station manager prior to implementation.
Based ca the new acceptance criteria incorporated by TPC 7369, the ;
surveillance test was signed off as complete.
The reason for the acceptance criteria change on TPC 7369 was listed as
" typographical error." However, the same step for tests of other RHR
pumps also had acceptance criteria listed as > 24 psig.
The inspector interviewed system engineering personnel and the in-
service test coordinator as to the ' oases for calling the change a
typographical error correction. The system engineer stated that the
required suction pressure was 16 psig and the change had no effect on
the pump operation.
However, the reason for calling the change a typographical correction
could not be identified by engineering personnel.
The same acceptance criteria change was incorporated into 1BwVS 5.2.f.3-
2. ASME Surveillance Requirements for RHR Pump 1RH01PA on July 16, 1996
usirig BwAP 1300-8 Minor Corrections of Approved Station Procedures.
BwAP 1300-8 allowed for typographical corrections to procedures and
specific'lly prohibited changes that would alter the technical content
of a prc. iure. Procedures changed with BwAP 1300-8 do not undergo a
thorough echnical review. The change incor) orated into 1BwVS 5.2.f.3-2
altered acceptance criteria and should have 3een considered a change to
the technical content of the procedure and, thereby, not been
incorporated using BwAP 1300-8.
c. Conclusions
The inspectors concluded that overall material condition of the residual I
heat removal system was good. Items requiring maintenance on the system ]
were identified by AR tags with the exception of a small leak on l
l 2RH032A, indicating that operations and engineering personnel were ,
l monitoring the system adequately. j
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The inspectors also concluded that the acceptance criteria change to the
1A RHR pump surveillance procedure (18wVS 5.2.f.3-1) that was
incorporated using BwAP 1300-8. did not provide for a thorough
engineering review. The acceptance criteria change made to 2BwVS
5.2.f.3-2 was not incorporated into all the procedures that were
6ffected by the change. The inspectors concluded that not changing all
the affected procedures at the same time was a poor engineering
practice. All procedures relating to the RHR pumps had been corrected
and had been reviewed in accordance with BwAP 1300-3.
Technical Specification (TS) 6.8.1.a recuired that written procedures be
established, implemented, and maintainec covering activities recommended
in Regulatory Guide 1.33. Revision 2, Appendix A. TS 6.8.1.a ap)1ied to
BwAP 1300-3 and BwAP 1300-8 and therefore the failure to follow 3wAP
1300-8 was a violation. This violation however, was of minor safety
consequence and is being treated as a non-cited violation consistent
with Section IV of the NRC Enforcement Policy (50-456/96014-07 (DRP)).
E2.3 Temocrary Alterations on Plant Systems
a. Insoection Scope (37550)
The inspectors continued a review of the temporary alteration process
that was started in the previous inspection period. The inspectors
reviewed paperwork for several temporary alterations and performed piant
walkdowns of several temporary alterations. Temporary alterations were
reviewed for compliance with UFSAR and TS requirements. The inspectors
also reviewed 10 CFR 50.59 safety evaluations on a sample of temporary
alterations.
b. 0.b.servations and Findinas
The inspectors review of the historical status of temporary alterations
revealed the following information:
. On January 1. 1996, a total of 43 temporary alterations were
installed and 21 had been in place for greater than 18 months.
. On September 30, 1996, a total of 28 temporary alterations were i
installed and 14 had been in place for greater thcn 18 months. !
Procedure BwAP 2321. Step C.1 defined a temporary alteration as a
change to the plant that was " generally expected to be installed for a
specified short duration." Station management had expanded on the
definition of '"short duration" as one fuel cycle (18 months) or less.
Each temporary alteration package had an entry for expected removal
date. For the temporary alterations older than 18 months, the expected
removal date/ event had not been met.
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Problems found with temporary alterations include:
- Review of the tem]orary alteration log and temporary alteration
paperwork in the Work Execution Center (WEC) revealed two versions
of temporary alteration 92-0-001 were filed in the WEC. One
version a)peared to be the original and the other appeared to be a
copy of t1e original. The copy had some items lined out and
initialed while the original did not. It could not be determined
which version of the paperwork was correct. The inspector
notified the associated system engineer of this condition and the
paperwork was corrected.
- Licensee personnel identified that original paperwork for
temporary alteration 96-1-007, which included removal signatures,
was not in the WEC and could not be located by plant personnel.
PIF 456-201-96-1879 was generated by plant personnel to document
that temporary alteration 96-1-007 was misplaced for about
10 days. The original temporary alteration paperwork could not be
located and a copy, including all signatures, was reconstituted by
site engineering personnel. The temporary alteration was removed
from the plant and the associated components were returned to pre-
alteration configuration. Investigation of the problem revealed
that the original temporary alteration paperwork may have become
contaminated and discarded as radioactive waste.
The inspector reviewed 10 CFR 50.59 safety evaluations for a sample of
temporary alterations. The evaluations were performed correctly and
referenced required licensino and design documents.
The inspector performed a walkdown of several temporary alterations in
the plant. The temporary alterations were generally found to be in
agreement with installation paperwork and the UFSAR. Examples of minor
problems, such as missing valve labels, found by the inspector were
quickly corrected by the associated system engineer after being
reported. The installation problems that were found were associated
with temporary alterations installed for greater than 18 months.
c. Conclusions
Temporary alterations were found to be installed in accordance with
plans and no unauthorized alterations were found. Any probler.s
identified were of minor significance and therefore, not being
considered as a violation. The inspectors concluded that the number of
temporary alterations installed greater than 18 months was high (14) and
that the licensee had not met the intent of their controls to not have
temporary alterations installed for greater than 18 months. System and
site engineering personnel appeared to maintain open temporary
alterations as listed in the associated documentation.
.
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i IV. PLANT SUPPORT
l
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R1 Radiological Protection and Chemistry (RP&C) Controls (71750) :
R1.1 General Observations ;
a. Insoection Scope
l Normal daily tours of the auxiliary building.
l b. Observations and Findinas
J
i The inspectors observed that the amount of contaminated floor space was
j low and access to plant equipment was nct restricted. Floors were kept
1 clean and rooms were well lit. Contaminated areas and radiation
i boundaries were clearly marked.
i
i c. Conclusions
I
i Based on observations during this inspection, the inspectors concluded
] that radiological housekeeping and contamination control was good. No
j problems were identified.
i
i R8 Miscellaneous RP&C Issues (92904)
i R8.1 JClosed) IFI 96008-06: Ins)ector to review licensee's post-outage
j evaluation of the cause of ligher dose rates and the contribution ,
- of rework and emergent work to the higher dose total. The higher
2
dose rates during the recent Unit 2 5th-cycle refueling outage
(A2R05) were attributed to an increased deposition of radioactive
l corrosion products from the core on out-of-core surfaces. This :
! increase occurred due to a reactor coolant pH increase caused by j
the leakage of lithium from a bypassed chemical and volume control I
(CV) demineralizer and the effect of decreasing reactor coolant i
temperature on a low and decreasing concentration of boric acid. I
For corrective action, the licensee revised procedure Bw0P CV-10.
"CV Filters-Isolation and Return to Service." to allow the
demineralizer to remain in service when the CV letdown filter was
being changed. In addition, the licensee will be lowering the
reactor coolant pH slightly during future shutdowns to compensate
for the decreasing temperature and boric acid concentration.
Regarding the higher dose total, the licensee identified that
about 38 person-rem came from unplanned work added to the outage
for various reasons and about 9 person-rem came from increased
time spent on planned work. A lessons-learned review was done for
A2R05 and incorporated into planning for the recent mid-cycle
outage on Unit 1 with greater emphasis on outage scope " freeze"
and completing jobs within the scheduled time. This appears to be
a good method of reducing radiation exposure.
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S1 Conduct of Security and Safeguards Activities (71750) j
S1.1 General Observations
a. Inspection Scone
f Normal daily tours of the interior and exterior of plant buildings.
b. Observations and Findings
The inspectors observed that security guards performed entry searches of ;
personnel and their belongings well. Security guards responded to two -
door alarms accidently generated by the inspectors in a timely manor. l
Guards stationed in the alarm stations were alert and were able to '
inform the inspectors of malfunctioning equipment and the required
compensatory actions.
c. Conclusions
During this inspection period, security guards were observed performing
their routines as expected. No problems were identified.
V. Manaaement Meetinas
X1 Exit Meeting Summary
l
The inspectors 3 resented the inspection results to members of licensee I
management at t1e conclusion of the inspection on October 18. 1996. The
licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary
information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
H. G. Stanley. Site Vice President
T. Tulon. Station Manager
H. Pontious. Nuclear Licensing Administrator
E. Roche. Executive Assistant
W. McCue. Support Services Director
R. Flessner. Site Quality Verification Director
R. Byers. Maintenance Superint'endent
D. Miller. Work Control Superintendent
T. Simpkin. Regulatory Assurance Supervisor
H. Cybul. System Engineering Supervisor
J. Meister. Engireering Manager
D. Coo)er. Operations Manager
M. Turaak. Independent Safety Engineering Group Supervisor l
M. Paevey. Regulatory Performance Administrator
M. Cassidy. Regulatory Assurance - NRC Coordinator
NRC 1
L. Miller. Chief. Reactor Projects Branch 4
C. Phillias. Senior Resident Inspector
M. Kunowsci Resident Inspector
IONS
T. Esper
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fI
INSPECTION PROCEDURES USED
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IP 37550: Engineering
i IP 375f;1: Onsite Engineering
, IP 61726: Surveillance Observations
! IP 71707: Plant Operations
! IP 71750: Plant Support Activities
l IP 92901: Followup - Plant Operations
- IP 92902: Followup - Plant Maintenance
j IP 92904: Followup - Plant Support
- :
d
ITEMS OPENED. CLOSED. AND DISCUSSED
l
Opened
50-456/96014-01 VIO failure to use the correct
3rocedural revision to test the 1B
E
50-457/96014-02 NCV failure to follow procedures
50-456/457/96014-03 IFI failure analysis of two breakers and
the operability assessment of the
remaining breakers
50-456/457/96014-04 URI review of valves surveillance
requirements
50-456/96014-05 NCV failure to follow procedures
50-456/96014-06 URI roll-up fire doors fail to close i
50-456/96014-07 NCV failure to follow administrative l
'
procedure
Closed l
50-456/457/95017-04 IFI surveillance revision for post-
accident neutron monitoring system
50-456/457/96008-06 IFI Jost-outage evaluation of cause of
ligh dose rates and contribution of
rework and emergent work to higher
dose total
50-456/96002-00 LER loss of operability of both trains
of control room ventilation
50-456/96014-02 NCV failure to follow procedures
50-456/96014-05 NCV failure to follow procedures
25
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LIST OF ACRONYMS USED
.
AR Action Request
ASME American Society of Mechanical Engineers
BYA Bypass Breaker A
CFR Code of Federal Regulations
CV Volume Control
DG Diesel Generator
EA Equipment Attendant
EO Equipment Operator
ECCS Emergency Core Cooling System
ESF Engineered Safety Features
FOTP Fuel Oil Transfer Pump
IFI Inspection Followup Item
LER Licensee Event Report
LLRT Local Leak Rate Test
MOV Motor-0perated Valve
NRC Nuclear Regulatory Commission
PIF Problem Identification Form
PM Preventive Maintenance
RCFC Reactor Containment Fan Cooling
R0 Reactor Operator
SSPC Solid State Protection System
TPC Tem 3orary Procedure Change
TS Tec1nical Specification
UFSAR Updated Final Safety Analysis Report
VOTES Valve Operation. Test and Evaluation System
WEC Work Execution Center
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