ML20132E830
| ML20132E830 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 12/17/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20132E825 | List: |
| References | |
| 50-361-96-15, 50-362-96-15, NUDOCS 9612230416 | |
| Download: ML20132E830 (21) | |
See also: IR 05000361/1996015
Text
._
.
_.
.
.
.-
.-...
-
.. .
-,- . - _ , . .
>
,
,
.
ENCLOSURE 2
. -
.
U.S. NUCLEAR REGULATORY COMMISSION
,
REGION IV
Docket Nos.:
50-361
50-362
License Nos.:
,
Report No.:
50-361/96-15
50-362/96-15
Licensee:
Southern California Edison Co.
Facility:
San Onofre Nuclear Generating Station, Units 2 and 3
d
Location:
5000 S. Pacific Coast Hwy.
2
San Clemente, California
!
Dates:
October 20 through November 30,1996
,
inspectors:
J. A. Sloan, Senior Resident inspector
J. J. Russell, Resident inspector
D. L. Solorio, Resident inspector
i
B. J. Olson, Project inspector
Approved By:
Dennis F. Kirsch, Chief, Branch F
Division of Reactor Projects
ATTACHMENT:
Supplemental Information
4
,
"
9612230416 961217
ADOCK 05000361
G
-_.
. ,-
..
.
.
-
- -
_~
-
.-
.-
-
- - - -
.
.
EXECUTIVE SUMMARY
-
,
San Onofre Nuclear Generating Station, Units 2 and 3
l
NRC Inspection Report 50-361/96-15;50-362/96-15
,
Operations
The inspector identified that volume control tank (VCT) inlet diversion
Valve 3LV0227A was in " auto" with the block valve to radwaste closed. This was
not in accordance with Abnormal Alignment 3-96-34, in effect at that time, and
was a violation of Technical Specification (TS) 5.5.1.1.a for failure to follow
procedures (Section 01.2). Operations management had previously identified
several component mispositioning events in recent months as a performance
concern, and had performed a self-assessment. The licensee's Nuclear Oversight
Division had also recently raised a concern regarding the large number (47) of
mispositioning events reported in 1996 (Section 07.1).
The licensee was monitoring a slow increase in containment gaseous activity, and
was proactive in planning to reset the Critical Functions Monitoring System (CFMS)
alarms to avoid operator distractions. However, the licensee missed an opportunity
to avoid the Containment Purge Isolation Signal (CPIS) A actuation, primarily
because of a general lack of awareness of the CPIS setpoint. The licensee could
have predicted that the CPIS setpoint would be reached and taken actions to reset
the setpoint (Section 01.4).
Operator actions in response to a dropped control element assembly (CEA) were in
accordance with TS requirements. Oversight by Operations management and
reactor engineering was effective in ensuring activities were coordinated and that
TS and Core Operating Limits Report requirements were accurately understood
(Section 01.3).
A noncited violation was identified after operators failed to follow procedural
controls for removal of a control element assembly calculator (CEAC) from service.
Inattention to these controls by operators led to a surveillance being missed.
Operators missed several opportunities to ensure that the surveillance would be
completed. Operators exhibited weak command and control, in that the control
operator (CO) did not provide direction to the assistant control operator (ACO) to
perform the surveillance, and the control room supervisor (CRS) did not adequately
oversee the activities to ensure operators had initiated a surveillance required by TS
(Section 04.1).
Maintenance
Instrumentation & Control (l&C) technicians lacked sufficient knowledge of licensee
computer systems used to identify and retrieve current drawings, which contributed
to an unplanned core protection calculator (CPC) channel trip (Section E3.1).
-
_
-
-..,.-aas
, ,
a
- ~ . , . -
.a-.--+u.ua...~
=
-x-
1
a-
n
_- ,-- .
.u-.-
s
- - . _
-~._,s-
-
1+
.
2
-2-
-
.
Enoineerina
The licensee did not have data to confirm that leakage from the emergency chilled
4
water (ECW) system was within the values added to the design basis
,
document (DBD) in 1993. Until the inspector identified the issue, Engineering did
not follow up on recommendations made at that time to evaluate the need for
}
safety related makeup and for development of a system leakage test, indicating an
isolated weakness in system management (Section E2.2).
The licensee's identification and correction of a methodology error in a vendor
4
calculation was an excellent finding demonstrating strength in the licensee's reload
technology transfer program (Section E4.1).
J
The nonconformance report (NCR) process used to modify the CPC inputs did not
j
ensure that affected procedures were identified and revised. This weakness had
not been fully addressed in recent NCR program changes (Section E3.1).
,
Plant Sucoort
The inspector's observation that scaffolding rendered some safe-shutdown
'
.
emergency lighting ineffective revealed a programmatic weakness in the licensee's
program for control of emergency lighting, in that emergency lighting inspections
4
I
were ineffective in identifying the lighting deficiencies and the scaffolding
procedures did not address the effect of scaffolding on the lighting. Licensee
corrective actions were thorough (Section P2.1).
,
_ _
-
.
- -
- - . - . -
-
= _.- _ ._ - - . - .
.
- - . - -
>
,
.
Report Details
.
Summary of Plant Status
Unit 2 operated at essentially 100 percent power from the beginning of this inspection
period until November 23,1996, when the unit began a power coastdown to refueling.
The unit shut down to Mode 3 on November 30,1996, and commenced its Cycle 9
refueling outage. The unit was in Mode 4 at the end of this inspection period.
Unit 3 operated at essentially 100 percent power from the beginning of this inspection
period until October 31,1996, when a CEA dropped into the core (Section 01.3), and
power was reduced to approximately 43 percent. After the CEA was recovered, power
was increased. The unit operated at essentially 100 percent power from November 2,
1996, until the end of this inspection period.
1. Operations
01
Conduct of Operations
01.1 General Comments (71707)
Operators were observed to generally carefully monitor control board indications,
refer to procedures frequently during many evolutions, and make conservative
decisions regarding plant safety. Routine control room oversight by Operations
management was evident. Operators were responsive to emergent conditions and
alarms However, several system valve linup problems have been identified
rece" e, demonstrating the need for improved attention to detail (Section 07.1).
01.2 VCT Inlet Diversion Valve Controller in an incorrect Mode - Unit 3
a.
Inspection Scone (71707)
On October 18,1996, the inspector inspected the Unit 3 main control boards and
observed that the VCT inlet diversion Valve 3LV0227A controller was not in the
correct position per an abnormal alignment in effect at that time. The inspector
reviewed documents and interviewed personnel associated with this observation,
b.
Observations and Findinas
On October 18,1996, the inspector identified that VCT inlet diversion
Valve 3LV0227A was in " auto," with the block valve to radwaste, Valve 3MU924,
closed. This was not in accordance with Abnormal Alignment 3-96-34 in effect at
that time. The inspector notified Unit 3 operators, who repositioned the controller
to " manual /VCT" and initiated Action Request (AR) 961001022. Abnormal
Alignment 3-96-34 had been initiated on April 25,1996, because Valve 3LV0227A,
which is a three-position valve, leaked fluid to radwaste when positioned to the
VCT. Abnormal Alignment 3-96-34 required that Valve 3MU924 be closed, except
as needed to divert to radwaste, and that Valve 3LV0227A be maintained in
.-
_ _.-
_ . _ _ _ _ _ _ _ _ _ _ . _ . _
____-._.__.m
_
i
e
!.
-2-
" manual /VCT," except when diverting to radwaste. A precaution in Abnormal
.
j .
Alignment 3 96-34 warned operators not to divert to radwaste without opening
j
Valve 3MU924. With Valve 3LVO227A in " auto," the valve would automatically
i
reposition to divert letdown flow to radwaste when the VCT level increased to
g
78 percent.
!
The inspector determined that positioning Valve 3LVO227A to divert to radwaste,
1
f
while Valve 3MU924 was shut, would result in a loss of letdown flow. Letdown
system pressure would increase, causing the backpressure regulating valves to
i
close and the pressure relief valves in the system to lift. The intermediate pressure
letdown relief valve,3PSV9206, had a setpoint of 650 psig, and the low pressure -
r
letdown relief valve,3PSV9208, had a setpoint of 200 psig. Operators would then
'
have had to take prompt action to restere letdown flow. The plant was designed to
4
withstand 100 loss of letdown flow transients.
1
The inspector determined that, during steady-state operations, operators generally
i
controlled reactor coolant system (RCS) inventory, such that additions to the RCS
did not result in VCT level changes, by simultaneeusly diverting letdown to
I
radwaste. Operators did not normally rely on the automatic VCT water level control
l
capability, and Valve 3LVO227A would not normally shift position automatically
j
without a plant transient causing an approximate 8 degree elevation in RCS
l
temperature or a control system failure,
,
j
s
.I
.
'
Licensee corrective actions addressed incorporating instructions from long-standing
j
abnormal alignments into permanent operating procedures. The licensee also
i
counseled the operators involved.
j
1
1
I
The failure to have Valve 3LVO227A aligned as required by Abnormal-
Alignment 3-96-34 was a violation of TS 5.5.1.1.a for failure to fellow procedures
]
(Violation 50-362/96015-01). Although the safety consequence of this violation
was low, the inspector found that the condition existed during a shift turnover (the
!
mispositioning was a result of not changing the controller mode after performing a
water inventory balance the preceding day) and should have been noted by
operators at that time. The inspector also found that the abnormal alignment,
i
despite having been in effect for approximately 6 months, placed the controller in a
mode that was different from the mode called for in permanent procedures and no
!
measures were in effect to resolve the opportunities this created for the controller
j
to be mispositioned.
'
i
Operations management had previously identified several component mispositioning
i
events in recent months as a performance concern, and had performed a self-
assessment. Additionally, Nuclear Oversight recently addressed an observed high
number of such events by various line divisions, including Operations
(Section 07.1).
1
,
. ___
_ _ _
. _ .
.__
___ ._.
. .
-
_
>
.
4
i
i
i
3
=
i
,
The inspector also observed that the Updated Final Safety Analysis Report (UFSAR)
states, in Section 9.3.4.2.1.2, that an automatic system maintains the water level
in the VCT, and that the letdown flow is automatically diverted to the boric acid
recycle system when the highest permissible water level is reached in the VCT.
The licensee initiated AR 961100216 to review the accuracy of this statement in
the UFSAR.
,
The inspector found that the UFSAR description of VCT operation was misleading in
that it stated that VCT level was maintained by the automatic system when, in fact,
during normal steady-state operations, operators manually controlled VCT level.
However, the VCT level control capability was normally selected for automatic
control. Licensee changes to the UFSAR will be reviewed as a followup item
(Inspector Followup item 50-361(362)/96015-02).
i
c.
Conclusion
The failure to have Valve 3LV0227A aligned as required by Abnormal
,
j
Alignment 3-96-34 was a violation. A followup item was created to review licensee
i
changes to the UFSAR because of a discrepancy identified by the inspector.
01.3 Drocoed CEA - Unit 3
a
a.
Insoection Scooe (71707)
.
At 7:17 p.m. on October 31,1996, while Unit 3 was operating at approximately
'
99 percent power, Shutdown Group A CEA 49 dropped fully into the core. The
inspector responded to the site and reviewed the circumstances of the event.
b.
Observations and Findinas
Operators responded by initiating a power reduction in accordance with TS Limiting
Condition for Operation (LCO) 3.1.5, Condition C (one shutdown CEA misaligned
,
greater than 7 inches), to meet the requirements of the Core Operating Limits
Report, which required an 18 percent power reduction. However, azimuthal power
tilt increased to 0.30 as a result of the dropped CEA, which was near the periphery
'
of the core. TS LCO 3.2.3, Condition C, required that power be reduced to less
,
,
than 50 percent within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> with tilt greater than 0.10; thus, operators
1
continued the downpower, reaching approximately 43 percent power by
approximately 10:30 p.m.
A plant equipment operator observed that indications in the CEDMCS cabinets were
,
abnormal for CEAs 49 and 53, both in Shutdown Group A Subgroup 13. He also
!
observed that a toggle switch at the bottom of the cabinet, controlling blowers in
the cabinet, was in the "off" position. He turned the blowers on. Additionally, one
of the two CEDMCS room coolers was out of service for maintenance, with work in
progress, at the time the CEA dropped.
i
, . -
__
>
i
.
.
'
.
-4-
i
,
At 9:17 p.m., operators entered TS LCO 3.1.5, Condition D, requiring shutdown to
Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, as the result of the CEA misalignment not having been
l
corrected within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (Condition C).
'
l&C technicians and the system engineer responded to troubleshoot and repair the
]
j
cause of the dropped CEA. They took coil traces and determined that all four CEAs
i
'
in Shutdown Group A Subgroup 13 were missing at least one phase of power.
1
Further inspection identified that six optical isolator chips were loose in their
sockets. The technicians tested the chips, determined that they were functional,
'
and reseated them. Additional coil traces showed that all four CEAs were still
missing one phase. This condition was determined to be caused by a blown fuse.
j
The fuse was replaced and the system was retested satisfactorily.
a
At approximately 10:33 p.m., CEA 49 was relatched and operators i;cgan to fully
withdraw it to align it with the rest of Shutdown Group A. A reactor engineer and
the Operations superintendent were present to advise and monitor operator actions.
1
CEA 49 was aligned at approximately 11:53 p.m. Power was slowly increased, and
j
was restored to 100 percent on November 2,1996.
!
The licensee initiated AR 961100003 to document the event, the root cause
determination, and associated corrective actions. The licensee's preliminary
determination was that high temperature in the CEDMCS cabinet caused the CEA to
drop. As of the end of this inspection period the licensee had not determined how
or when the blower switch had been turned off.
i
l
i
c.
Conclusions
<
Operator actions in response to the dropped CEA were in accordance with TS
requirements. Oversight by Operations management and reactor engineering was
'
effective in ensuring activities were coordinated and that TS and Core Operating
Limits Report requirements were accurately understood.
4
01.4 CPIS - Unit 3
a.
Insoection Scope (71707. 71750)
The inspector reviewed licensee activities surrounding a CPIS A actuation that
occurred in Unit 3 on October 25,1996.
-
!
b.
Observations and Findinas
I
i
The CPIS was initiated by containment gaseous Radiation Monitor (RM) 3RE7807C
reaching its setpoint (900 cpm). Because a purge was not in progress at the time,
no equipment changed state.
j
,
.
.
-5-
-
The licensee had been aware of, and had been actively monitoring, an increasing
trend in containment gaseous activity since approximately October 20. The
increased activity was approximately linear between October 20 ar.d October 25.
The trend was also apparent on Train B containment gaseous RM 3RE7804C. The
licensee had initiated AR 961001168 on October 24, stating that the CFMS alarm
point for RM 3RE7804C should be increased to avoid nuisance alarms and to
provide an alarm based on approximately 1.0 gpm RCS leakage. This sensitivity
was described in the UFSAR and was in accordance with NRC Regulatory
Guide 1.45.
AR 961001168 documented that the increased gaseous activity was apparently due
to approximately 0.1 gpm of RCS leakage from the pressurizer steam space, since
particulate activity was not increasing.
After the return to full power on November 2, following a dropped CEA (see
Section 01.3), the containment gaseous activity again increased. The licensee
made a containment entry on November 5 and observed that the vent to
containment from the pressurizer, Valve 3HV0298 was leaking at approximately
0.05 gpm. This was consistent with observed gaseous activity. In the days
following the containment entry, the activity level stabilized at approximately
1000 cpm.
c.
Conclusions
The licensee was monitoring a slow increase in containment gaseous activity, and
was proactive in planning to reset the CFMS alarms to avoid operator distractions.
The license missed an opportunity to avoid the CPIS A actuation primarily because
of a general lack of awareness of the CPIS setpoint. The licensee could have
predicted that the CPIS setpoint would be reached on October 25, and taken
actions to reset the setpoint.
04
Operator Knowledge and Performance
04.1 Failure to Comolete Surveillance - Unit 2
a.
Insoection Scoce (71707)
The inspector reviewed the circumstances surrounding Operation's failure to
perform a conditional surveillance.
b.
Observations and Findinas
On November 1,1996, Unit 2 operators declared CEAC #1 inoperable for
performance of an 18-month surveillance. The same day the licensee reported to
.
.
.
6-
the NRC that operators failed to complete a 4-hour surveillance within the required
time period, required by TS 3.3.3, Action A, when they made the CEAC inoperable.
.
However, Action B of TS 3.3.3 allowed continued operation in the event Action A
l
was not completed within the required 4-hour period, as long as the actions of
Condition B were completed within the next 4-hour period. Because operators
completed the surveillance required by Action A within the second 4-hour period,
the TS allowed continued operation in accordance with the provisions of Action A
until the CEAC was returned to service.
Operators logged the inoperability in the CEAC log book. The book included a
column, that was signed and verified by the CO and ACO, respectively, to ensure
the 4-hour surveillance was initiated when making a CEAC inoperable. However,
the CO did not direct the ACO to initiate the 4-hour surveillance. Additionally, the
ACO did not verify who had initiated the surveillance. This was more significant
since the ACO is normally responsible for performing surveillances such as the
4-hour surveillance for CEA position.
Work Authorization Record 2-9603373 for the CEAC work did not list the 4-hour
surveillance needed to be performed, but did direct the CEAC to be removed from
service in accordance with Procedure SO23-3 2.13c
The CO had made an entry in the CO log at 8:40 a.m. stating that CEAC #1 was
removed in accordance with Procedure SO23-3-2.13, " Core Protection / Control
Element Assembly Calculator Operation," Revision 7. The CO stated that he had
reviewed the procedure, but had failed to review Section 6.5.2, which directed the
4-hour surveillance to be initiated when a CEAC was removed from service.
At the time the CO and ACO were making the CEAC inoperable the CRS was in the
control room. The CO stated that the CRS was not observing their activities
directly. Procedure SO123-0-2, "CRS Authority, Responsibilities, and Duties,"
Revision 3, Step 6.2.3, required the CRS to direct and coordinate the activities of
the operating crew with approved procedures, TS, and Licensee Controlled
Specifications (LCS). The procedure also required the CRS to review the TS when
removing equipment from service. The CRS dM not direct and coordinate the
activities of the crew nor review the TS when equipment was removed from
service. Procedure SO123-0-3, "CO's Responsibilities and Duties," Revision 1,
Step 6.2.4.1, also required the CO to " ensure control room round sheets or shift
relief status and surveillances are completed in the assigned time frame." The CO
did not ensure the surveillance was completed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
Shortly af ter the CEAC was taken out of service the operators became involved in a
long evolution to support a pump retest. Following completion of the pump retest,
approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after removing the CEAC from service, operators realized
they had missed the 4-hour surveillance.
o
'
,
.
e
i
7
-
,
TS 3.3.3, Action A.1, required that if one CEAC was inoperable, to perform a
SR 3.1.5.1 once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. SR 3.1.5.1 required verification that the position of
each full and part length CEA was within 7 inches of all other CEAs in its group. At
3:15 p.m. the CO made a log entry that position verification required by the TS had
!
been completed. However, Condition B stated that, if the required action for
Condition A was not met within its required completion time, to verify that the
departure from nucleate boiling ratio requirement of LCO 3.2.4 was met within
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Because operators completed this verification within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the TS
')
requirements were met.
The licensee briefed all operators regarding this event, emphasized the need to
ensure that a timer is started to ensure that the surveillances are performed.
c.
Conclusions
The 4-hour surveillance required by Action A of TS 3.3.3 was not completed 'within
the required time frame; however, the licensee complied with Action B within the
required time frame, which was provided in the event Action A was not completed.
Therefore, TS requirements were met.
I
l
l
Operators failed to follow procedural controls for removal of a CEAC from service.
1
Operators missed several opportunities to ensure that the surveillance would be
completed. The licensee's administrative controls for roles and responsibilities for
operators were sufficiently detailed to ensure operators understood they should
'
follow TS and perform surveillances required when removing equipment from
i
service, inattention to these controls by operators led to the surveillance being
missed. While the operators were aware of the requirement to perform the
i
surveillance, they did not take action to ensure that it would be performed. The
failure to follow the procedures was a violation of TS 5.5.1.1.a. This
i
licensee-identified and corrected violation is being treated as a noncited violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy
(NCV 50-361/96015-03).
1
Operators exhibited weak command and control, in that the CO did not provide
direction to the ACO to perform the surveillance, and the CRS did not adequately
oversee the activities to ensure operators had initiated a surveillance required by TS.
4
07
Quality Assurance in Operations
07.1 Component Miscositionina Events
Recently, the licensee had experienced certain valve mispositioning situations
(i.e., RCS head vent valve in Unit 3 and pressurizer spray line drain valves in
Unit 2). These situations were of concern to the NRC and the mispositioned head
vent valve was the subject of a recent special NRC inspection.
l
_
. ..
.
.
.
,
,
.
i
i
.
-8-
i
Operations management maintained an ongoing list and analysis of performance
'
issues. In this program, component mispositioning by operators had been identified
as a concern. Operations had performed a self-assessment in this area in about
i
July 1996.
On November 5,1996, Nuclear Oversight sent a memorandum to the Vice
President, Nuclear Generation, requesting action regarding 47 component
mispositioning events that had been reported in ARs in 1996, validating NRC
concerns in this area. The events involved personnel from Operations and other
divisions. In the memorandum, Nuclear Oversight requested identification of a
i
responsible manager to address the broad issue, including establishing appropriate
metrics for evaluating and tracking progress in improving performance in this area.
j
The inspector considered Nuclear Oversight's assessment to be significant and
timely in that it established a larger scope to this important issue.
08
Miscellaneous Operations issues (71707, 92700)
08.1 (Closed) Licensee Event Report (LER) 50-362/96006-00: containment purge
isolation actuation. This issue is discussed in Section 01.
j
08.2 (Closed) LER 50-362/96004-00: RCS pressure boundary leakage due to a failed
resistance temperature detector (RTD) thermowell. This issue was previously
discussed in NRC Inspection Report 50-361(362)/96011.
08.3 Institute of Nuclear Power Operations Report
The inspector reviewed the Institute of Nuclear Power Operations report of its
periodic evaluation of performance of San Onofre. The report had been received by
the licensee in September 1996.
II. Maintenance
M1
Conduct of Maintenance
M 1.1 General Comments
a.
Insoection Scope (62707)
The inspector observed all or portions of the following work activities:
Replace spent fuel pool cooling branch connection with new style fitting -
Unit 2
Install flat bar support brackets on refueling water storage tanks - Unit 3
/
+
.
.
.
.
.g.
b.
Observations and Findinas
The inspectors found the work performed under these activities to be thorough. All
work observed was performed with the work package present and in active use.
Technicians were knowledgeable and professional. The inspectors frequently
observed supervisors and system engineers monitoring job progress, and quality
control personnel were present whenever required by procedure. When applicable,
appropriate radiation controls were in place.
In addition, see the specific discussions of maintenance observed under
Section E3.1, below.
M1.2 General Comments on Surveillance Activities
a.
Insoection Scooe (61726)
The inspector observed all or portions of the following surveillance activities:
Engineered safety feature group relay K-112A, K-625A, and K-725A
semiannual test - Unit 3
,
Main and auxiliary feedwater valve testing - cold shutdown and refueling
interval - Unit 2
b.
Observations and Findinas
The inspectors found all surveillances performed under these activities to be
thorough. All surveillances observed were performed with the work package
present end in active use. Technicians were knowledgeable and professional. The
1
inspectors frequently observed supervisors and system engineers monitoring job
progress, and quality control personnel were present whenever required by
procedure.
M8
Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Violation 50-361(362)/96008-01: performance of maintenance activities
on the wrong components. This violation involved two instances where technicians
performed work on wrong components after being briefly interrupted in their work.
The licensee's corrective actions for the violation were identified in a letter to the
NRC dated September 11,1996. The inspector reviewed licensee documents and
determined that the corrective actions were either completed or scheduled for
completion. The inspector also spoke with Maintenance technicians and determined
that management was emphasizing self and cross checking to ensure that correct
components are worked on.
.
.- -
.
. _- . -
- ~ _ - -
~
.. . . .
.
-.
- --
,
l
,
i
t
-10-
-
t
M8.2 (Closed) Inspector Followuo item 50-361/93016-02: differences in ultrasonic
testing wall thickness measurements. This item was opened after repetitive
measurements indicated that component wall thickness had changed by more than
five percent, which was the accuracy range of the test equipment. The licensee
!
evaluated the measurements and determined that wall thickness was greater than
the code specified minimum thickness. The licensee also determined that the
measurement differences were attributable to operator technique and component
variability. The inspector discussed the issue with licensee personnel and agreed
with their evaluation of the issue. The inspector also noted that the licensee's
,
l
program required an examination of the entire grid area if one measurement was
!
less than the manufacturer's minimum wall thickness.
l
Ill. Enaineerina
E2
Engineering Support of Facilities and Equipment
E2.1
Review of Facility and Eouloment Conformance to UFSAR Descriotion
A recent discovery of a licensee operating its facility in a manner contrary to the
UFSAR description highlighted the need for a special focused review that compares
plant practices, procedures and/or parameters to the UFSAR description. While
,
performing the inspections discussed in this report, the inspectors reviewed the
applicable sections of the UFSAR that related to the inspection areas inspected.
The following inconsistency was noted between the wording of the UFSAR and the
.
l
plant practices, procedures and/or parameters observed by the inspectors:
i
The description of the method used to control VCT level, in UFSAR
]
Section 9.3.4.2.1.2, was found to be inconsistent (Section 01.2 ).
i
E2.2 ECW System Leakaoe Detection
a.
Inspection Scope (37551)
The inspector interviewed cognizant ec.gir'sers and walked down portions of the
(common to both units) ECW system * srder to determine leakage detection
methods in place. The inspector also reviewed DSD SO23-800, " Auxiliary Building
Emergency Chilled Water System," Revision 0,
b.
Observations and Findinos
The ECW system is a closed-loop safety-related system that supplies chilled water
for cooling safety-related equipment tsuch as emergency core cooling pump room
coolers and charging pump room coolers) and to provide habitability. The system
automatically starts on various engineered safety signals. Two emergency chiller
,
!
units provide chilled water to both units. A nominal 60-gallon compression tank
t
i
L
'
.
.
.
.
-11-
provides for compression and contraction of the chilled water, maintains suction
head to the chilled water pump, and prevents voiding in the system high points.
The system normally contains approximately 1200 gallons of water with 42
separate cooling coils located throughout both units. Tank pressure is provided by
a closed volume of air. The tank has an automatic makeup, based on low tank
pressure, that comes from nonsafety-related nuclear service water. There is no
control room indication of initiation of automatic makeup.
If an event occurred, and the nonsafety automatic makeup for the system was lost,
and if system leakage was sufficient, the system compression tank could lose level.
Air from the compression tank could then enter the suction of the pump, and the
system could fail.
The licensee logged compression tank level locally, in addition it was normal
practice for operators and the cognizant engineer, if they observed leakage during
normal plant tours, to evaluate the amount of the leakage, and generate ARs for
Maintenance to repair the leakage. However, the inspector found that although
these methods would detect some leakage, they did not quantify system leakage
with reasonable assurance at any one time. The inspector found that operators had
'
no ready means to determine, nor did they determine, the amount of makeup taking
place. However, the inspector found that these monitoring methods did provide
some assurance that significant undetected leaks would not occur.
,
Immediately after inspector questioning during October 1996, Station Technical
personnel discovered, and Maintenance personnel repaired, a 60 cc/hr leak in a
compression tank drain line. The licensee had determined in 1993, as a result of
{
DBD in 1992, that with a low compression tank level, 200 cc/hr leakage was
acceptable; with a high tank level,950 cc/hr leakage was acceptable. The licensee
also generated ARs 961000554 and 961200136 to reevaluate the acceptable
leakage numbers and to initiate a test for leakage.
The inspector also observed that Revision 0 to DBD SO23-800, completed in 1992,
left as an open item for engineering to resolve the need to install a safety-related
makeup source and the need of performing a system leakage test. The inspector
found thr.t acceptable leakage amounts had been developed, but that these other
issues ht d not been addressed as of this inspection report period,
c.
Concitsion
The licensee did not have data to confirm that leakage from the ECW system was
within the values added to the DBD in 1993. Until the irspector ider.tiNd the
issue, Engineering did not follow up on recommendations made at that time to
evaluate the need for safety-related makeup and for development of a system
leakage test, indicating an isolated weakness in system management.
_ _
_ __
.-
-12-
~
l
l
E2.3 Charoino Pumo 2P190 Breaker Failure - Unit 2
a.
Insoection Scope (37551)
The inspector reviewed the licensee's response to the failure of the safety-related
480 volt breaker for Charging Pump 2P190.
b.
Observations and Findinos
i
On October 22,1996, the breaker for Charging Pump 2P190 failed to close on
demand from the control room. it failed to close on a second attempt, and on a
,
third attempt it closed and then tripped open after approximately 3 minutes. The
licensee documented these failures in AR 961001008.
The licensee determined that the cause of the failures was that the roller assembly
was sticking, resulting in the breaker not being properly aligned in the cubicle and
the secondary contacts not being fully engaged.
The roller assembly was not included in the preventive maintenance program, and
had not been lubricated since assembly by the manufacturer. The vendor manual
for the breaker did not address preventive maintenance for the roller assembly.
The licensee contacted the vendor to determine the appropriate lubricant, and
intended to add inspection and lubrication of the roller assembly to the preventive
maintenance program for similar breakers.
,
]
l
The licensee replaced the breaker with a spare and restored the system to service.
c.
Conclusion
1
i
The licensee's resolution of a failed 480 voit safety-related breaker was prompt and
thorough.
E3
Engineering Procedures and Documentation
E3.1
RCS Temperature Element Wirina Modification - Unit 3
a.
Insoection Scoce (37551. 717071
^
During a review of the Unit 3 CO logs, the inspector determined that l&C
technicians caused a trip of CPC Channel A while performing a surveillance of RCS
cold leg temperature Indicator 3TI-0925-1. The inspector reviewed the
circumstances leading up to the event,
i
-
.
.
.
-13-
.
b.
Observations and Findinas
RTD 3TE-0925-1 once had been only used as the input to Indicator 3TI-0925-1.
However, because of a failure of another RTD in 1994, wiring changes and
modifications were made, in accordance with NCR 941100027, resulting in
RTD 3TE-0925-1 also supplying an input to CPC Channel A.
l&C technicians calibrating Indicator 3TI-0925-1 caused the trip of CPC Channel A
(on departure from nucleate boiling ratio and linear power density) during the
calibration activities. Work Authorization Record 3-9603339 referenced
Maintenance Order (MO) 96052709, which referenced Procedure S023-11-9.657,
" Surveillance Requirement Qualified Safety Parameter Display System A (OSPDS-A)
Calibration," Revision 6, for calibration of Indicator 3TI-0925-1. The procedure did
not mention that the RTD feeding indication 3TI-0925-1 performed a dual purpose.
The inspector considered that under other licensee design modification processes
the impact to the l&C procedure would have normally been evaluated.
Apparently, the technicians did not obtain the drawing change showing that the
RTD for Indication 3TI-0925-1 also supplied a temperature signal to CPC Channel A.
l&C supervision stated that the drawing change documents were not obtained
because the technician was unfamiliar with the software application used to obtain
drawings and missed the information in the computer system that stated there were
changes outstanding against the drawing.
The inspector determined that Maintenance personnel had received no training on
the used of the computer application used to obtain drawings. Apparently, the
technicians learned it on their own. In response to this weakness, the licensee
,
'
planned to conduct training of Maintenance personnel and to evaluate
'
enhancements to the computer application.
The inspector reviewed Procedure SO123-XV-5, " Nonconforming Material, Parts, or
Components", Temporary Change Notice 3-22, which was in effect when the
modification was made. The procedure did not require review of Operations or
Maintenance procedures when making a design modification, as the licensee's other
design change processes would. As a result, the inspector considered that the
opportunity was missed to identify that the modification of the RTD inputs could
affect the unit in an adverse manner.
j
The inspector reviewed the current procedure for NCRs and noted that it still
allowed plant modifications if operational instructions and drawings were reviewed
for impact. However, the inspector determined that the process still did not require
an impact review of surveillance and maintenance procedures, in response to this
programmatic weakness, the licensee agreed to revise the NCR process.
,
.
_.
- _ _
_ _
_ _.
_ . - -
_
_
-
,
.
.
'
14
.
c.
Conclusions
l&C technicians lacked sufficient knowledge of licensee computer systems used to
identify and retrieve current drawings. which contributed to an unplanned CPC
channel trip.
The NCR process used to make modify the CPC inputs did not ensure that affected
procedures were identified and revised. This weakness had not been fully
addressed in recent NCR program changes.
E4
Engineering Staff Knowledge and Performance
E4.1
Reload Analvsis Error
a.
Insoection Scooe (37551)
The inspector reviewed licensee performance in the identification and resolution of
an error in the fuel reload analysis.
b.
Observation Findinas
While reviewing vendor calculations as part of the reload technology transfer
program, licensee engineers identified a discrepancy in the data related to core
power distributions for dropped part-length CEAs (PLCEAs). Because the PLCEAs
are not uniform along their length, they introduce an axial asymmetry when inserted
into the core. The asymmetry was not properly addressed in the calculations,
resulting in a nonconservative acceptable operating region being included in the
LCS. The curve affected was LCS Figure 3.1.105-3, " Required Power Reduction
after Single PLCEA Deviation," which is part of the Core Operating Limits Report.
The licensee contacted the vendor, who confirmed the error as identified by the
licensee.
The licensee determined that TS operating limits prior to issuance of the LCS were
more conservative than required, and that the units had never operated in what was,
now determined to be an unacceptable region.
Had the licensee operated in the unacceptable region, which was applicable after a
PLCEA dropped over halfway into the core, departure from nucleate boiling limits
could have been exceeded.
The licensee d'ocumented the condition in AR 961100053, and implemented
immediate corrective action to require operators to comply with LCS
Figure 3.1.105-2, " Required Power Reduction After Single Group 6 Full Length CEA
Deviation," if a PLCEA dropped. LCS Figure 3.1.105-2 was more conservative than
required for plant safety for a dropped PLCEA.
.
7
- - .
- - .
. .
- ~ - . - ~
. . . - _ . - . - . _ - . - - . - ~
--..
1
,
! ,
i
1
-15-
-
1
1
4
c.
Conclusions
.-
l
The licensee's identification and correction of a methodology error in a vendor
calculation was an excellent finding demonstrating strength in the licensee's reload
j
technology transfer program.
$
E8-
Miscellaneous Engineering issues (92712) .
!
E8.1
(Closed) LER 50-362/96002-00.01: potential decalibration of log power level
4
j
- instrumentation. On February 9,1996, the licensee was notified by Asea-Brown
Boveri Combustion Engineering (CE) that a potential nonconservatism in the
calibration of logarithmic power channels reported by Waterford may exist at San
Onofre Units 2 and 3. The potential decalibration was attributed to physics effects,
j
which may cause the log power indication to vary significantly from actual plant
.
power during low power operation due to factors such as CEA position, temperature
i.
shadowing, boron changes, etc. CE estimated that the effects had the potential to
j
cause'the log power trip to be high by a factor of two, but less than a factor of 10.
l
In response, the licensee reduced the high logarithmic power trip setpoints, in both
j
units on all four channels, by a factor of 10, while CE performed a reanalysis to
determine the actual effect of the nonconservatisms. The inspector verified that the
.
j
licensee initiated MOs to change the setpoints.
s
.
!
.The inspector reviewed portions of the reanalysis performed by CE, which
t
concluded that the total of the decalibration effects was a factor of two. Based on
3
the calculated decalibration effect the log power trip setpoint was reanalyzed. The
results demonstrated that the previously installed setpoints would have allowed the
,
!
fog power trips to perform their intended safety functions. Following receipt of the
'
reanalysis, the licensee restored the trip setpoints to their previous values. The
licensee submitted Revision 1 of the LER to document that, based on the results of
CE's analysis, the condition previously reported was no longer reportable.
~
The inspector concluded that the !icensee's actions were conservative.
i
IV. Plant Suonort
j
R8
Miscellaneous Radiological Protection and Chemical lasues (92904)
i
R8.1
(Closed) Insoector Followuo item 50-362/96009-05: steam generator (SG)
blowdown RM valve misalignment. The licensee found an open bypass valve for.
SG 3E088 blowdown RM 3RE6759 that was unidentified on plant drawings. The
-licensee also found similar bypass valves for the other three SG blowdown RMs;
!
however, those bypass valves were in the closed position. The four bypass valves
were not depicted on plant drawings or specified in plant procedures.
__
-.
-
_.
_ _ _ _ .
.
- _ _ _ _ .
_
. . - _ _
l
.
.
'
.
16-
The inspector discussed this item with Engineering, Operations, and RM personnel.
The inspector also reviewed alarm response instructions, abnormal operating
instructions, and emergency operating instructions applicable to the SG blowdown
RMs. The SG blowdown RMs are used in conjunction with other RMs and sample
results to diagnose a SG tube rupture. While the open bypass valve rendered the
)
i
RM inoperable, the inspector concluded that operators could have diagnosed a SG
tube rupture using the other RMs and sample results. The inspector found that the
SG blowdown RMs were not required to be operable by TS. In addition, the
inspector reviewed the UFSAR and determined that the SG blowdown RMs were
not covered by the quality assurance provisions of 10 CFR Part 50, Appendix B.
i
Although the unidentified valves represented a configuration control problem, the
inspector concluded that no violation of NRC requirements occurred. A field change
was performed to remove the four bypass valves from the SG blowdown RMs. The
licensee inspected other RMs and found no other unidentified valves.
P2
Status of Emergency Preparedness Facilities, Equipment, and Resources
P2.1
Safe Shutdown Emeroency Liahts Olocked By Scaffoldino - Unit 2
a.
Insoection Scoce (71707. 71750)
The inspector walked down portions of Unit 2 during an electrical outage and
observed that some emergency lights were blocked by scaffolding. The inspector
evaluated licensee controls for temporary scaffolding erected in the Unit 2 main
steam safety valve (MSSV) area.
b.
Observations and Findinas
On October 17,1996, during a plant walkdown of the MSSV area, the inspector
observed that temporary scaffolding, erected for painting, was blocking safe
shutdown 8-hour emergency lights illuminating an access and egress path to safe
shutdown components and illumination of two safe shutdown components,
atmospheric dump Valve 2HV8421, and turbine auxiliary feedwater pump steam
supply Valve 2HV8200. The inspector informed the licensee of the degradation of
the emergency lighting and determined that the licensee had been previously
unaware of the condition. The inspector determined that plant equipment operators
routinely, at least once per shift, toured the MSSV areas on both units.
The inspector reviewed the LCS for safe shutdown emergency lights, LCS 3.7.114,
and determined that the LCS required that when a light was made inoperable,
operators were directed to utilize portable lanterns after a 14-day time period.
However, since the operators were previously unaware of the degradation, no
tracking mechanism was initiated to ensure that after 14 days portable lanterns
would be used in the affected areas. However, the inspector observed that plant
operators routinely carried flashlights. The inspector verified that, in the safe
shutdown from outside the control room, backpacks given to all operators during
C
.
.
..
-
-17-
implementation of the emergency operating instruction for safe shutdown outside
the control room contained portable lanterns. In addition, as discussed below, the
inspector also could not determine that the lights were blocked for more than
14 days. Once the operators were aware that the lights were blocked, tracing was
initiated in accordance with LCS 3.7.114.
The inspector determined that the procedure controlling scaffolding erection did not
provide guidance to sensitize craft personnel that the illumination path of emergency
lights should not be blocked. In addition, the inspector determined that the
Emergency Preparedness procedure for weekly plant inspections did not sensitize
fire inspectors to the poter.tial of scaffolding blocking emergency lights. The
inspector verified that a weekly inspection of the MSSV had been performed;
however, because the fire inspection procedure did not state the need to look for
degradation of emergency lighting, the licensee inspectors did not identify the
scaffolding problem. As a result, the licensee revised these program procedures to
reflect the need to prevent scaffolding from blocking emergency lighting or to take
the appropriate compensatory actions if not preventable.
The inspector reviewed the " work done" section of MO 96052477, used for control
of the scaffolding activities. The scaffolding blocking the lighting i!!uminating safe
shutdown Valvos 2HV8200 and 2HV8421 was documented as being built less than
14 days prior.to the observation. The date for when the scaffolding blocking the
access and egress paths to the area was built could not be determined.
c.
Conclusions
The scaffolding that was blocking the safe shutdown emergency lights was not
documented as being erected for more than 14 days. Therefore, no LCS violation
occurred. The inspector considered that even though operators were not tracking
the inoperability of the emergency lights to ensure that at 14 days they needed to
utilize portable lanterns, the safety consequence was minimal because, during a
shutdown from outside the control room, emergency supply kits provided to
operators contained portable lanterns. While the root cause was a programmatic
breakdown in the programs for control of scaffolding erection and inspection of fire
protection equipment, the licensee corrective actions were thorough.
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management
at the exit meeting on December 4,1996. The licensee acknowledged the findings
presented.
. _ . . _ _ _ _ _ _ _ _ _ . . ._- . _ . . . . . _ .
. _ - _ _ .
_
- _ _ _ . _ _ . - . _ . _ _ _ . . _ _ - . . _ - - _ _ . . _ _ _ _ _ _ _ _ .
s
e
!
i
f
e-
-
18-
t
!
The inspectors asked the licensee whether any materials examined during the
I
inspection should be considered proprietary. No proprietary information was
identified.
l
!
!
!
t
t
i
7
$
t
I
i
l
!
I
r
i
l
i
l
..
..
,_ . .-
_ _
- .
.,
_.
- _
_
_
_
_ . .
.
_ _ . _ _ .
,
o
i
.
.
ATTACHMENT
PARTIAL LIST OF PERSONS CONTACTED
4
1
Licensee
,
.
D. Brieg, Manager, Station Technical
!
4
J. Fee, Manager, Maintenance
'
l
G. Gibson, Manager, Compliance
D. Herbst, Manager, Site Quality Assurance
5
P. Knapp, Manager, Health Physics
R. Krieger, Vice President, Nuclear Generation
D. Nunn, Vice President, Engineering and Technical Services
l
T. Vogt, Plant Superintendent, Units 2 and 3
'
R. Waldo, Manager, Operations
M. Wharton, Manager, Nuclear Engineering Design
'
INSPECTION PROCEDURES USED
,
IP 37551:
Onsite Engineering
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observations
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 92700:
On Site LER Review
IP 92712:
Inoffice Review of LER
.
IP 92902:
Followup - Maintenance
IP 92904:
Followup - Plant Support
,
ITEMS OPENED AND CLOSED
Ooened
50-362/96015-01
VCT inlet diversion valve controller in incorrect mode
50-361 (362)/96015-02
IFl
UFSAR changes to VCT operation
Ooened and Closed
/
50-361/96015-03
NCV missed CEAC surveiPar.ca
,
- --
- . - _ _
- . . . - . - -
. -
__
-
.
.
2-
e
.
-2-
Closed
P
50-361/93016-02
IFl
differences in ultrasonic testing wall thickness
measurements
i
50-361/96008-01
performance of maintenance activities on wrong unit
!
50-362/96006-00
LER
containment purging isolation actuat!on
60-362/96004-00
LER
50-362/96002-00, 01
LER
potential decalibration of log powei level
instrumentation
50-362/96009-05
IFl
LIST OF ACRONYMS USED
,
assistant control operator
action request
Combustion Engineering
control element assembly
CEAC
control element assembly calculator
c
control element drive mechanism control system
critical functions monitoring system
CO
control operator
core protection calculator
CPIS
containment purge isolation signal
control room supervisor
design basis document
ECW
emergency chilled water
l&C
instrumentation and controls
LCO
limiting condition for operation
i
licensee-controlled specifications
LER
licensee event report
MO
maintenance order
nonconformance report
Public Document Room
PLCEA
part-length control element assembly
radiation monitor
resistance temperature detector
TS
technical specification
Updated Final Safety Analysis Report
volume control tank
,
W