ML20202E901
| ML20202E901 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 02/11/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20202E892 | List: |
| References | |
| 50-361-97-27, 50-362-97-27, NUDOCS 9802190083 | |
| Download: ML20202E901 (19) | |
See also: IR 05000361/1997027
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ENCLOSURE 2
L U.S. NUCLEAR REGULATORY COMMISSION
L REGION IV -
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Docket Nos.: 50-361
50 362
License Nos.: NPF 10
Report No.: 50 361/97-27
50-362/97 27
Licensee: Southern California Edison Co.
Facility; San Onofre Nuclear Generating Station, Units 2 and 3
Location: 5000 S. Pacific Coast Hwy.
San Clemente, California
Dates: December 21,1997, through January 31,1998
Inspectors: J. A. Sloan, Senior Resident inspector
J. G. Kramer, Resident inspector
J. J. Russell, Resident inspector
Approved By: Dennis F. Kirsch, Chief, Branch F
Division of Reactor Projects
ATTACHMENT: SupplementalInformation
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99021*/0083 980211
{DR ADOCK 05000361
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EXECUTIVE SUMMARY
San Onofre Nuclear Generatic a Station, Units 2 and 3
NRC Inspection Report 50 361/97 27; 50-362/97-27
This routine announced inspection included aspects of licensee operations, maintenance,
engineering, and plant support. This report covers a 6-week period of resident inspection.
Ooerations
. Operations during this inspection period were characterized by improved
communicaticr. among operators, continued frequent Operations management
monitoring of activities, and conservative decision making. Operational activities were
well-ple ted, and prejob briefings were thorough (Section 01.1).
. Operator responses to an inadvertent Unit 2 loss of condensate polishing flow, a Unit 3
ground on a nonsafety-related electrical bus, anu a Unit 3 complete loss of the core
operating limits supervisory system (COLSS) were excellent, All of these off normal
conditions occurred during a short time period. The availability of extra reactor
operators enabled normal control board monitoring to occur during the responses
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(Section 01.2).
- During the planned reactor shutdown of Unit 2 for the midcycle outage, several
strengths were oisserved. Operator communications were thorough and complete,
augmented staffing was effectively coordinated, and supervisory oversight was evident.
The use of scripting to help coordinate activities was effective. Performance of the
standard posttrip actions was formal and professional (Section 01.3).
- The permanent reduction of reactor coolant system (RCS) cold leg temperature (T-cold)
was well planned and smoothly executed. The prejob briefing was very thorough
(Section 01.4).
. Operators performed preparations for, and entry into, midloop conditions in a thorough
and safety conscious manner. RCS Level monitoring practices and performance
improved since the previous period of midloop operations. Management oversight was
continuous and effective, and contingency plans were in place. The time-to-boil
calculation results were inconsistent, but conservative, due to an operator's error and
sone minor differences in the calculation methodology between operators. Overall
performance for the drain to midloop was outstanding (Section 01.5).
- Dunng routine operator rounds a nuclear plant equipment operator (NPEO) was
attentive and thorough. Communications with the control room were frequent and
effective. Although some minor material deficiencies were first observed by the
inspectors, the NPEO's responses to the conditions were rigorous. The NPEO's use of
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the hand-held computer's trend capability to identify a potential degrading condition was
outstanding (Section 04.1)(
- : Local monitoring of emergency diesel generator (EDC peration was weak because a
. high fuel fiar differential pressure condition went unnwiced immediately after an EDG
start, until brought to Operations' attention by the inspectors.: This was largely because1 4
EDG operating logs were not programmatically taken until the EDG had been operating -
for about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, and because th ' :al annunciator failed to remain illuminated, even
- though the fuel filter differential p sure was about 13 psid above the annunciation;
setpoint (Section O4.2). i
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Maintenance
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- A detailed walkdown of_the component cooling water (CCW) system revealed that the -
overall external material condition was excellent, with only minor deficiencies observed
(Section 02.1).
- J - A aoncited violation was identified based on the licensee's determination that
procedures had not been adequately followed in 1993 for inspecting the lubricant---
volume in a safety-related motor-operated valve actuator. The licensee's corrective
- actions were broad and thorough (Section M2.1).
Engmeering
- - The licensee's operability assessment for a motor-operated valve actuation that had
. insufficient lubricant was thorough, soundly based, and well documented (Section M2.1).
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. The licensee's evaluation of the core damage probability (CDP) for the planned Unit 2
midcycle outage was thorough. The recommendations of the Nuclear Safety Group -
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. resulted in the implementation of changes to reduce risk in the planned outage, with little
impact on outage operations (Section E1.1).
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- The facility change evaluation (FCE) for the RCS T-cold temperature reduction was
thorough (Section E1.2).
-* -.The initial operability astessment of seismically unsecured fire _ extinguishers in the
Unit 2 containment, performed by design engineers, was weak, because it did not
address all fire extinguisher locations and was not rigorous in supporting conclusions -
that the fully charged extinguishers did not represent missile hazards (Section F2.1).
Plant Sucoort
. The inspectors identified that a Unit 2 safety injection tank (SIT) sample isolation valve
located in containment had not been fully closed after a sample had been drawn,
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resuiting in minor leakage from the sample point. This indicated a weakness in attention
to detail on the part of the chemistry technician performing the sample (Section R4.1).
- The inspectr.,.. .uentified that the licensee failed to ensure that 3 fire extinguishers left in -
Unit 2 containnient during Mode 1 operations were properly seismically secured.
Ultimately, the licensee determined that 7 out of 32 fire extinguishers in Unit 2
containment were not properly restrained. This was a violation of the licensee's seismic -
program requirements (Section F2.1).
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flagert Details
Summary of Plant Status -
Unit 2 began this inspection period operating at 80 percent power. On December 22,1997,
following repairs to a failed circulat ng water pump motor, power was increased to 100 percent.
The unit operated at essentially 100 percent power until January 24,1998, when the unit was
shut down for a planned midcycle outage to irspect the steam generators. The RCS was
drained to midloop conditions on January 27i 1998, and the unit operated in Mode 5 at midloop
' for the rest of the inspection period.
Unit 3 operated at essentially 100 percent reactor power throughout this inspecuon period.
l. Operations
01 Conduct of Operations
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01.1 General Comments (71707)
The inspectors observed routine operational activities throughout this inspection period.
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Some of the activities observed included:
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- Shift tumovers (multiple observations)
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NPEO rounds (Unit 2) (one observation)
- Projob briefing for a permanent reduc' ion of RCS T-cold (Unit 2)
'* Preparations for draining the RCS to midloop (Unit 2)
- NPEO response to leaking spent fuel pool isolation valve (Unit 2)
- lsolation and restoration of atmospheric dump valve nitrogen system (Unit 2)
- Routine control room activities (multiple observations)
- Daily manager's meetings (multiple observations)
Operations during this inspection period were characterized by improved
communications among operators, continued frequent Operations management
monitoring of activities, and conservative decision making. Operational activities were
well-planned, and prejob briefings were thorough.
01.2 Control Room Ooerator Resoonse - Units 2 and 3
a. Insoection Scoce (71707)
On January 9,1998, the inspectors observed Units 2 and 3 control room operators
responding to various off-normal conditions.
b. Observations and Findinos
Unit 2 operators responded to an inadvertent opening of a condensate full flow polishing
demineralizer bypass valve. This bypass valve opening occurred during maintenance
on a condensate demineralizer controller. Unit 2 operators reestabliched condensate
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demineralizer flow by allowing the secondary system to stabilize and then gradually
shutting the bypass valve.
The common control operator performed ground isolation for 480 Volt non-Class 1E
Dus 3807, which had developed a ground.
Unit 3 operators responded to a complete loss of the COLSS. Normal COLSS failed
when the plant monitoring system failed due to an intermittent failure of an internal
communication link. The plant monitoring system providas data for the Technical
Specification (TS)-required normal COLSS Backup COLSS was out of service for a
scheduled surveillance. Unit 3 operators correctly implemented all monitoring required
by TS, and then terminated the backup COLSS surveillance and returned backup
COLSS to service.
The inspectors found that, for each condition described above, operators correctly
31iagnosed the condition and promptly took actions to correct the condition. Use of
rocedures, and compliance with TS, was excellent. Communications between
operators was good, and supervision by the Unit 2 and Unit 3 control room supervisors
was excellent. Two additional reactor operators (in addition to the two normally
assigned to the unit) assisted in performing the TS-required Unit 3 monitoring, allowing
normal control board monitoring.
c.s Conclusions
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Operator responses to an inadvertent linit 2 loss of condensate polishing flow, a Unit 3
ground on a nonsafety-related electrical bus, and a Unit 3 complete loss of the COLSS
system were excellent. All of these off-normal conditions occurred dunng a short time
period. The availability of extra reactor operators enabled normal control board
monitoring to occur during the "esponses.
01.3 Reactor Shutdown for Midevcle Outaae (Unit 2)
a. Insoection Scoce (71707)
On January 24,1998, the inspectors observed operatora reduce power from 60 percent
and shut down the reactor in preparation for the Unit 2 midcycle outage.
b. Observaticns and Findinos
The shutdown immediately folicwed completing heat treating the salt water cooling
system, which had left the unit at approximately 80 percent power.
Several extra operators were on shift to support the planned shutdown. Additionally,
Operations management was in the control room providing supervisory oversight, and
reactor engineers were in the control room monitonng and advising operators regarding
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reactivity lasues. Throughout the evolution, the control room supervisor and control
operator coordinated the activities of the support personnel effectively and efficiently.
Communications between operators during the evolution were consistently formal and
complete.- Only one instance was observed in which licensee management
- expectations for communications wat not met.
Operators closely monitored the power reduction rate to schieve an almost steady
15 percent per hour, which was the target rate.
The licensee had prepared a detailed script of the anticipated activities, including start i
and completion times, associated with the shutdown. The script paralleled, but did not
replace, the procedures. The script was very accurate, and assisted in coordinating
- activities during the shutdown.
The reactor was manually tripped from anproximately 15 percent power in accordance l
with licensee procedures. Following the reactor trip, the operators performed the
standard posttrip actions in a formal and professional manner, ,
c. Conclusions
During the planned reactor shutdown of Unit 2 for the midcycle outage, several;
- strengths were observed. Operator communications were thorough and complete,
augmented staffing was effectively coordinated, and supervisory oversight was evident.
The use of scripting to help coordinate activities was effective. Operators-in-training
were properly supervised as they performed reactivity manipulations.- Performance of
the standard posttrip actions was formal and professional
01.4 Permanent Reduction of RCS T-cold (Units 2 and 31
a. insoection Scoce (71707)
The inspectors observed the prejob briefing for the permanent reduction of RCS T-cold
in Unit 2 on January 20,1998. The inspectors reviewed plant parameter trends of the
temperature reductions in both units.
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b. Qbservations and Findinos
The licensee implemented a permanent reduction in RCS T-cold from 553 *F to
approximately 548 'F (until turbine control valves were wide open) on January 20
and 29;1998, in Units 2 and 3, respectively.
The licensee consulted its vendors and detemiined that the only set point that needed to
be changed to support the reduction was in the nonsafety-related steam bypass control
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system, in order to maintain the existing load reject capacity. The licensee implemented
the required set point change within one day of the temperature reduction in each unit.
The prejob briefing addressed procedural controls, roles and responsibilities, and
management expectations. Expected plant response was addressed with respect to
reactivity, power distribution, power indications, RCS flow, operating margins, RCS
inventory. pressurizer pressure, feedwater control, steam bypass control system issues,
secondary plant response, and electrical output.- Expected alarms were identified, and
termination criteria for the evolution were specified.
c. Conclusions 1
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The implementation of a permanent reduction of RCS T-cold was well planned and
smoothly executed. The prejob briefing was very thorough. Comments regarding the
field change evaluation associated with the reduction are in Section E1.2.
01.5 Midlooo coerations (Unit 2)
a. Insoection Scooe (71707)
The inspectors observed the preparations for, entry into, and steady state operation in
midlooo conditions in Unit 2.
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b Observations and Findinos
The licensee utilized a closed circuit television monitor to remotely monitor the reactor
water level sight glass. Operations installed a mor ' 5 the continuously-manned
Operations work process control area, and estabbed an expectation that the sight
glass level be observed at least once every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This was a significant
improvement in the sight glass level monitoring capability since the 1997 outages.
The prejob briefing for the drain to midloop was thorough, addressing planned and
contingent conditions and expected responses. Because of the short time-tr boil
(17 minutes) at the time of the draindown, extra operators were assigned to remain in
the radiologically controlled area ready to vent the shutdown cooling system if needed.
Prior to commencing the draindown, the licensee ensured that all the level indicating
systems were properly aligned and calibrated.
The draindown was perform . ' on January 27 and 28,1998. Two reactor operators and
an Operations manager in tt.a control room, in addition to the normal crew, assisted in
the draindown. Levelindication available included a reactor level monitoring system, a
diverse level monitoring system, a local sight glass, and incore reactor thermocouples.
Attention by the operators to this instrurnentation, and the agreement of the
instrumentation, was excellent. A hold point at 36 inches in the 42-inch hot leg was
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I used both to ensure that the instrumentation was correlating properly, and to calculate
- the time to-boiling at 26 inches in the ' lot leg. Based on continuous observation of the
evolution, the inspectors found that control room staffing and attention to level
indications were excellent.
Control room operators calculated the time-to-boil with 26 inches level in the hot leg (the
targat level) while at the 36-inch hold point mentioned above. The data for the
calculation was contained in Procedure SO23 5-1.8.1, " Shutdown Nuclear Safety,"
Revision 5, in a table of time since shutdown and time to-boil at 26 inches, with a- l
correction factor for core exit temperatures other than 120 'F. The control room
operators calculated a time-to-boil of 17.3 minutes at 1:58 a.m. on January 28,1998,
with core exit average temperature of 118.6 'F, The inspectors performed the same
calculation and determined that the operators had made a minor error in correlating time
since shutdown to fractions of days, mistaking 1:58 a.m. for 12:58 a.m. Also, the
inspectors calculated a 17.2 minute time-to boil, using a smaller interval of the nonlinear
time-to-boil numbers for interoolation than the operators had used. The inspectors also
' observed that the calculation was performed by two operators working together, and the
- calculation was not independently verified. The inspectors found that the time-to-boil-
was greater than 17 minutes (the minimum time), but that errors occurred in performing
the calculation.
c. Conclusions
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Operators performed preparations for, and entry into, midloop conditions in a thorough -
und safety-conscious manner. Level monitoring practices and performance improved
since the previous period of midloop operations. Management oversight was continuous
and effective, and contingency plans were in place. The time-to-boil calculation results
were inconsistent, but conservative, due to an operator's error and some minor
differences in the calculation methodology between operators. Overall performance for
the drain to midloop was outstanding.
02 Operational Status of Facilities and Equipment
O2.1 CCW System Walkdown - Units 2 and 3
a. Insoection Scoce (71707)
The inspectors performed a walkdown of the Units 2 and 3 CCW system. The
inspectors reviewed Procedure SO23-3-3.18, " Component Cooling / Saltwater System
Tests," Revision 8; Document DBD-SO23-400, "CCW System Design Bases
Document," Revision 5; and CCW piping and instrument Diagrams 40127A through
40127G.
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b. Observations and Findinos
The inspectors reviewed Procedure SO23 3-3.18 and determined that the alignment
verifications irmleded the necessary valves to ensure compliance with TS Surveillance
Requirement 3.7.7.2. Surveillance Requirement 3.7.7.2 required the licensee to verify
that each CCW valve i the flow path servicing safety-related equipment was in the
correct pcsition.
The inspectors verified that the CCW valves were in their correct position. However, the
inspectors identified severallabeling discrepancies. The inspectors observed that a
majority of the control room and local valve identification tag noun names did not match
Procedure SO23-3 3.18, and in some cases the procedure noun name did not
completely describe the valve. For example, the procedure noun name for
Valve S21203MUOO9 was " Containment Spray Pump." The localidentification tag noun
name for Valve S21203MU009 was "CNTMT Spray Pump 2P012 CCW Supply ISO." in
addition, the inspectors observed several instances of handwritten valve position
identification marks on the valves. The inspectors discussed the discrepancies with the
Operations supervisor. The inspectors concluded that, although the valve identification
tag did not match the procedure, sufficient information (valve number and noun name)
was available to the operators to ensure proper valve operation.
The inspectors identified several valve deficiencies. The local position indication for
Valve 3HV6212 was missing. Valve 3HV6222A had a grease leak both on the drain
plug and where the motor fastens to the actuator housing. Valves 3HV6221 and
3HV6551 had their manual handwheel clutch levers positioned aga;nst electrical
conduits. TM local position indicator for Valve 3HCV6537 indicated 15 percent open
when the valve was, in fact, closed. The inspectors discussed the discrepancies with
Operations management.
During the review of the piping and instrument diagrams, the inspectors observed
transition errors between sheets.
Operations management initiated Action Requests (AR) 980100471 through 980100474,
and 980100965, to address the inspectors' concerns,
c. Conclusions
The CCW system contained minor differences between local valve identification tags
and the monthly alignment procedure. In addition, several valve deficiencies were
identified by inspectors during a system walkdown and were appropriately addressed by
the licensee. The overall external material condition of the CCW system was excellent.
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04 Operator Knowledge and Performance
Cr 1 NPEO Rounds (Unit 2)
a. Insoection Scoca (71707)
On January 11,1998, the inspectors observed the inside portion of the Unit 2 primary
NPEO (Position 23) rounds,
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b. Observations and Findinos
Prior to initiating the rounds, the Unit 2 control operator briefed the NPEO on specific
activities that needed to be performed in conjunction with the normal rounds. The
NPEO was properly equipped and prepared for the assigned rounds.
The NPEO demonstrated thorough familiarity with the hand-held computer utilized to ,
record the data from the rounds. Prior to initiating the inside rounds, the NPEO
identified an adverse equipment trend (declining pressure in the CCW backup nitrogen
system) utilizing the data trending function of the hand-held computer During the
rounds, the NPEO utilized th computer to take notes and record required data. The a
NPEO also demonstrated flexibility la changing the sequence of the rounds, which was
controlled by the computer.
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Several minor material deficiencies were identified by the inspectors during the tour
(missing fasteners, nicked insulation, and boric acid buildup on components), in each
case the NPEO promptly documented the deficiency and initiated ARs as warranted.
The NPEO properly investigated water leakage observed from a spent fuel pool fill
valve, including obtaining Health Physics support to confirm that the water was not
contaminated.
The NPEO frequently communicated with the control operator during the rounds
regarding identified deficiencies and coordination of activities.
c. ' onclusions
During normal rounds the NPEO was attentive and thorough. Communications with the
control room were frequent and effective. Although some minor material deficiencies
were first observed by the inspectors, the NPEO's responses to the conditions were
rigorous. The NPEO's use of the hand-held computer's trend capability to identify a
potential degrading condition was outstanding.
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04.2 Local EDG Monitorino
a. _Insoection Scoce (61726)
On January 14,1998, the inspectors observed Unit 2 operators perform portions of
Surveillance Procedure SO23 3-3.43.17,"ESF Subgroup Relay K-401B Semiannual
Test," Revision 3, concurrently with Surveillance Procedure SO23 3 3.23, " Diesel
Generator Operation," Temporary Change Notice 13-1, Attachment 1. This was a
semiannual TS-required fast start of EDG 2G003, as well as a verification of proper
operation of engineered safety features subgroup Relay K-4018, which provides for,
among other functions, an EDG start on a safety injection actuation signal.
b. Observations and Findinos
The inspectors observed EDG 2G003 start locally Approximately 30 seconds after the
EDG started and achieved rated speed and voltage, the inspectors observed that local
annunciation of " engine Number 1 fuel filter restriction" illuminated and then reflashed,
indicativo of a condition present, then cleared. The EDGs are tandem machines with
two engines coupled to one generator. At the same time as the annunciation described
above, the EDG momentarily increased frequency from 60 hertz to about 61 hertz. The
licensee later explained this oscillation was due to a transfer of EDG speed control from
an automatic safety injection actuation signal control circuit to a control room control
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circuit. The inspectors alerted the NPEO monitoring the EDG locally to the
! annunciation. The NPEO reset the reflashing annunciator, but made no immed ate
attempts to investigate fuel filter differential pressure. Operations personnel did not
observe the mon'entary increase in frequency. The inspectors then observed that local
engine Number 1 fuel filter differential pressure was about 63 psid, as indicated on
Gauge 2PDl5937D. The annunciation setpoint was 48 psid, and the Operations log
specification was less than 50 psiti. Despite the high differential pressure, local
annunciation failed to reflash or to raain illuminated.
The NPEO reported the high differential pressure to control room operators. In
accordance with the local annunciator tv.ponse procedure, the right fuel filter, which
had been in service, was removed from service, and the left fuel filter was placed in
service. Each EDG engine has two fuel filters, which may be placed in service
individually or in parallel. Fuel filter differential pressure dropped to about 36 psid.
Operations personnel initiated ARs both to investigate the lack of local annunciation
when fuel filter differential pressure was greater than its indicated setpoint, and to
replace the right fuel filter. The inspectors found that this action was satisfactory;
however, they also found that local EDG monitoring was weak in that the off-normal
condition was not observed by licensee operators, until brought to their attention by the
inspectors. As a result of this, and previous observations of local EDG monitoring, the
inspectors found that NPEOs were require 1 to complete a set of local EDG operating
logs about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after EDG start, but weie not required to monitor these same
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parameters immediately after EDG start. Consequently, if an off-normal condition did
not lead to local annunciation, the condition could go unnoticed, as described above.
c. Conclustom
Local monitoring of EDG operation was weak because a high fuel inter differential
pressure went unnoticed immediately after an EDG start, and until brought to
Operations attention by the inspectors. This was largely because EDG operating logs
were not programmatically taken until the EC'G had been operating for about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />,
and because local annunciation failed to remaia illuminated, even though the fuel filter
differential pressure was abots 13 psid above t ie annunciation setpoint.
05 Operator Training and Qualification
05.1 Reactivity Manioulations by Ooerators-in-Trainina (Unit 2) (71701)
During the reactor shutdown of Unit 2 on January 24,1998, the inspectors observed
three operators-in-training performing reactivity manipulations.
The assistant control operator thoroughly reviewed expected plant responses with each
of the operators before the manipulations. The assistant control operator closely
monitored performance of the manipulations, and verified that the expected responses
were achieved.
The inspectors concluded that the supervision of the operators-in-training was
consistent with regulatory requirements and licensee expectations.
II. Meintenance
M1 Conduct of Maintenance s
M1.1 General Comments
a. Insoection Scoce (62707)
The inspectors observed all or portions of the following work activities:
. Calibrate control room ammeter for saltwater cooling Pump 2P307 -Unit 2
. Replace saltwater cooling Pump 2MP112 moter - Unit 2
. Change out nitrogen bottles for atmospheric dump Valve 8419 - Unit 2
- Clean and plug e 'eaking tube in CCW Heat Exchanger 2ME002 - Unit 2
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bc Observations and Findings -
r - 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 krsowledgeable and professionalc.The inspectors frequently obsewed 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 a.idition, see the specific discussions of maintenance observed under Section M2.2,
belaw.
M1.2 General Comments on Surveillance Activities
a. 'nanection Scone (61726 and 71707)
The inspectors observed all or portions of the following surveillance activities:
t Engineered safety features subgroup Relay K-401B semiannual test - Unit 2 -
- Saltwater cooling Pump 2MP112 pump and valve test - Unit 2
+ Control element assembly position verification - Unit 2
- Atmospheric dump valve weekly checks- Unit 2
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~ The inspectors found all surveillances performed under these activities to be thorough.
. All sumeillances observed were 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.
ln addition, see the specific discussions of surveillances observed under Sections 04.2 -
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M2 Maintenance and Mateilal Condition of Facilities and Equipment
M2.2 Motor-Ooerated Vane Actuator Lubrication (Unit 2)
a. Insoection Scoce (37551 and 62707)
On December 29,1997, the licensee identified that the mote. aperated valve actuator
for Valve 2HV8162 the low pressure safety _ injection Pump 2P015 miniflow block valve,
had very little lubricant. The inspectors reviewed the licensee's evaluation and response
to this condition.
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b. Observations an1 Findinas
During performance of routine maintenance on December 29,1997, the licensee
identified that the actuator main housing of Valve 2VH8162 had very little lubricant, and
that the worm and worm gear were not immersed. The licensee documented this
condition in AR 97120157d.
The worm and worm gear had been replaced in 1993 (Cycle 7 refueling outage). The
preventive maintenance frequency for the actuator is 3R (every third refueling cycle),
and was scheduled for the next (Cycle 10) refueling outage.
The as-found motor-operated valve testing performed in December 1997 did not reveal
any degradation or anomalies. The licensee determined that the valve performance
was well within the margin requirements for valves in the Generic Letter 89-10
motor-operated valve program.
The valve is normally locked open, except during shutdown cooling operation, and is
infrequently operated. The licensee estimated that the valve had been cycled
approximately 20 times, primarily for quarterly inservice testing, since the 1993
overhaul. The licensee reviewed the results of the stroke timing tests since 1993 and
did not identify any adverse trend.
In response to the 1997 identification of insufficient lubrication, the licensee replaced the
worm and worm gear with new parts, refilled the actuator with lubricant, and performed
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as-left testing. Additionally, the licensee determined that past performance of
maintenance on Valve 2HV8162 had not been satit. factory, in that the as left
motor-operated valve testing in 1993 should have identified the deficiency, and that the
lubricant level had been checked on June 27,1993, and incorrectly documented as
satisfactory. Specifically, Procedure SO123-1-8.28, Temporary Change Notice 0-15,
was performed under Maintenance Order 921001237, and Step 6.2.2, that required
checking the lubrication level, was marked as complete and satisfactory. The licensee
documented in AR 971201574 that the step had been performed inadequately. This is a
violation of TS 6.8.1 (of the TS in effect at that time) for failure to follow procedures.
This nonrepetitive, licensee-identified and corrected violation is being treated as a
noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy
(NCV 50-361/97027-01).
The licensee inspected the worm and worm mar after they were removed and
determined that they were not damaged c- aded. The licensee stated that the parts
were initially supplied with a light coating t cant that may account for the lack of
degradation.
The licensee performed an operability assessment and determined that the valve was
operable during the time that it was inadequately lubricated.
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AR 971201574 states that the licensee will inspect all the other safety-related
motor-operated valve actuators that had similar maintenance during the Cycle 7 outages
and have not since been inspected. Other corrective actions included counseling the
personnelinvolved with the previous maintenance of Valve 2HV8162 and reviewing
expectations for self- and crost checking with the electricians,
c. Conclusions
A noncited violation was identified based on the licensee's identification that procedures
had not been adeauately followed in 1993 for inspecting the lubricant volume in a
safety-related motor operated valve actuator. The licensee's operability assessment for
the recently identified condition was thorough, soundly-based, and well documented,
and the corrective actions were broad and thorough.
til. Enaineerina
E1 Conduct of Engineering
E1,1 Probabilistic Risk Assessment of Planned Midevele Outaae (Unit 2)
a. Insoection Scone (37551 and 62707)
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The inspectors discussed the licensee's Probabilistic Risk Assessment evaluation of the
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Unit 2 mic' cycle outage planned to begin in late January 1998, based on the preliminary
outage scheduie, and reviewed the recommendations made by the Nuclear Sofety
Group to minimize the outage risks. The inspectors also reviewed the licensee's
comparisons of the CDP for various significant attematives to the planned schedule.
The inspectors participated in a January 14,1998, conference call between licensee and
NRC personnel discussing outage plans.
b. Obse vations and Findinas
The outage plan included 19 days of operation at midloop, with RCS level at
approximately 26 inches above the bottom of the hot leg. This period of midloop
operations was the primary contributor to the outage cumulative CDP, determined to
be 1.,5-5. The outage was planned to last 30 days.
The licensee determined that if the plan were revised to install nozzle dame, the period
of midloop operations would be reduced to approximately 10 days, the outage would be
extended by 1 day, and the CDP would be slightly reduced, to 1.2E-5.
The licensee also determined that the CDP for an alternative plan to operate at 19
inches above the bottom of the hot leg for 19 days would be 2E 5.
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The licensee determined that performing a full-core offload would substantially extend
the outage duration, but would reduce the period of midloop operation to 12 days, and
The recommendation made by the Nuclear Safety Group and incorporated into the
outage plan during midloop operation included maintaining both trains of emergency
core cooling equipment available, running both trains of saltwater cooling and
component cooling, aligning the containment spray pumps to backup the low pressure
safety injection pumps when conditions permit, and eliminating all switchyard work from
the outage during midloop operations, Several other recommendations were also made
and incorporated into the outage plan.
The licensee determined that the CDPs for all the options reviewed were below the
annual outage risk goal cf 3E-5.
c. Conclusions
The licensee's evaluation of the CDP for the planned Unit 2 midcycle outage was
thorough. The recommendations of the Nuclear Safety Group resulted in reduced risk,
in the planned outage, with little impact on outage operations.
E1.2 FCE for RCS T-Cold Reduction (Units 2 and 31
a. insoection Scoce (37551)
The inspectors reviewed FCE 2/3-97-003, Revision 0, *RCS Tcold Reduction of 5 5,"
that documented the licensee's evaluation of a permanent reduction in RCS Tvold,
b. Observations and Findines
The FCE clearly and thoroughly documented the reason for the change; the functional
objective of the change; the impact of the change on site programs, operations, and
procedures; and various aspects of design criteria that could be affected.
The licensee obtained an evaluation of the temperature reduction from Asea
Brown-Boveri, which was referenced in the FCE. The significant contnbution of the
vendor evaluation was the identification of the impact on load reject capability, which
emuld be compensated for by changes to the steam bypass control system settings.
The 10 CFR Part 50.59 safety evaluation was thorough and rigorous. The FCE included
change requests for the Updated Final Safety Analysis Report and for the RCS design
basis document.
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c. Conclusions
The FCE for the permanent reduction of RCS T-cold, including the 10 CFR Part 50.59
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safety evaluation, was thorough. Implementation of the temperature reduction is
discussion in Section 01.4.
IV, Plant Suonort
R4 Staff Performance and Knowledge in Radiological Protection and Chemistry
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R4,1 Laakina Samole Point - Unit 2
a. insoection Scone (71707 and 71750)
On December 18,1997, the inspectors accompanied licensee Engineering personnel
during a walkdown of Unit 2 containment outside the bioshield,- The unit was at full
power,
b. Observations and Findinos
Licensee personnel performed the walkdown in order to identify boric acid leaks prior to
the upcoming midcycle outage. Concurrent with this walkdown, a chemistry technician
sampled the SITS for boron concentration.
The inspectors identified that the SIT 2T008 sample point was leaking about 10 drops
per minute. The sample line was routed to a funne'. The funnel was routed to a floor
drain on the 45-foot level of containment that apparently was clogged. Water was rising
in the vertical path of the drain, and the drain filter plate was dislodged from the drain
opening and situated in the bottom of the vertical portion of the drain. 'ihe inspectors
informed the engineers of the leaking SIT sample point and the clogged drain. The
engineers reopened, then closed, the sample isolation valve, stopping the teck. The
engineers also evaluated the drain. The inspectors found that the chemistry technician
had weakness in attention to detail in not ensuring the sample isolation valve .vas fully
closed,
c. ConclusioQs
While in Unit 2 containment during Mode 1 operations, a chemistry technician failed to
ensure that a safety injection tank sample isolation valve was fully closed after drawing a
sample. This resulted in minor leakage from the sample point. The condition was
identified by the inspectors, indicating a weakness in attention to detail on the part of the
chemistry technician.
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F2 Status of Fire Protection Facilities and Equipment
F2.1 Unrestrained t: ire Extincui3hers Inside Containment - Unit 2
a. inspection Scoce (71707 and 71750)
On December 18,1997, the inspectors accompanied licensee Engineering personnel
during a walkdown of Unit 2 containment outside the bioshield. The unit was at full
power. Licensee personnel performed the walkdown in order to identify boric acid leaks.
b. Observations and Findinas
The inspectors checked four fire extinguisher cabinet doors during the walkdown. The
inspectors observed that fire extinguisher Cabinet Numbers 14,17, and 18 contained
doors that were not latched and were free to move. The design function of the fire
extinguisher cabinet doors was to provide seismic restraint to the fire extinguishers
inside the cabinets. The cabinets did have small frames that would prevent some
extinguishers from falling out of their cabinets, but the frames were not sufficient to, nor
intended to, restrain the extinguishers during vertical vibration caused by a seismic
event. On January 9,1998, Fire Protection engineers entered Unite and 3
containments to fully investigate the extent of the issue, in addition to the doors
mentioned above, the engineers found that Unit 2 fire extinguisher Cabinet Doors 1,5,
10, and 26 were not latched and were free to move. All of these cabinets contained
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latches that were loose except Cabinet 1 (which was not loose) ano Cabinet 26, which
did not have a latch installed. The Fire Protection engineers tightened the loose latches,
closed alllatches, and secured Cabinet 26 with plastic tie wrap.
All Unit 3 containment fire extir,guisher cabinet doors were found closed and latched.
The licensee determined that the cabinet doors in Unit 3 containment had a different
type latch than those in Unit 2 containment.
There are 32 fire extinguishers cabinets in Unit 2 containment outside the bioshield.
Cabinets 1,5,10, and 17 contained 800 psig,20 pounds weight, carbon dioxide
cylinders. Cabinets 14,18, and 26 contained 195 psig,20 pounds weight, dry chemical
cylinders. Cabinet 10 was located about 2 feet away from Valve S21219MUO93, a
refueling cavity drain valve. The other locations did not contain any large valves within
4 feet. Licensee engineers assumed that a cylinder would be restricted to a 4-foot
radius if it fell from a cabinet.
After initial discovery by the inspectors on December 18,1997, licensee design
engineers performed an operability assessment of the three specific fire extinguisher
locations identified by the inspectors (AR 971201140). The engineers determined that,
although seismic configuration was not maintained, the pressurized fire extinguishers
did not pose a risk to nearby equipment. The inspectors reviewed the operability
assessment and found that it did not address all relevant aspects of the issue. It did not
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rigorously support the conclusion that an extinguisher or its nozzle could not become a
missile hazard. Additionally, it did not address the remaining 29 extinguishers in
containment.
Unit 2 containment fire extinguishers and their associated cabinets were inspected
during every unit shutdown of greater than 30 days' duration, using Fire Protection
Procedure SO123-Xll 52, Attrchment 3," Fire Surveillance Data Record-Unit 2
Containment." Unit 2 cabinets were last inspected on December 7,1996, during the
Cycle 9 refueling outage. All cabinets, with respect to doors, were recorded as
satisfactory, except Cabinet Number 26. AR 960800977 was used to document the
missing latch; however, no corrective actions were taken at that time. St*p 2 of
Procedure SO123 Xil-52 states in part that the intended function of the cabinet is to hold
the extinguisher, that the doors must be able to be closed, and that the cabinet door
must latch properly.
After the January 9,1998. containment entry, licensee personnel identif;ed numerous
similar deficiencies with fire extinguisher cabinet doors outside containment.
10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality
shall be prescribed by documented procedures and that these activities shall be
accomplished in accordance with these procedures. Maintenance Procedure
SO123-1-20, " Seismic Controls," Revision 5, Step 6.3.6, states that " restraints shall be
placed to ensure the equipment does not topple over during a seismic event." The fire
extinguishers described above, located in Unit 2 containment, were not restrained to
ensure that they did not fall from the cabinets and topple over
(Violation 50-361/9727-02).
At the exit mesting, the licensee questioned the applicability of Procedure SO123-1-20 to
equipment failures, based on an assumption that most of the cabinets became
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fact that all but two of the latch mechanisms on the unlatched cabinets were found to be
loose, but determined that the licensee did not establish that the looseness caused the
uniatching, or that the looseness was not preventable by reasonable licensee quality
assurance measures or mar,agement controls. On the contrary, the inspectors
determined that the apparently prevalent condition of loose latching mechanisms could
reasonably have been identified and corrected during the routine inspections the
licensee performed,
c. Conclusiom
The licensee failed to ensure that 7 out of 32 fire extinguishers in Unit 2 containment
were properly seismically secured during Mode 1 operations. This was r violation of
licensee's seismic program requirements. The inspectors identified this issue during an
at-power entry of Unit 2 containment during a walkdown with licensee engineers. The
initial operability assessment, performed by design engineers, was weak, because it did
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not address all fire extinguisher locations and was not rigorous in supporting conclusions
that the fully charged extinguishers did not represent missile hazards.
V. Mananoment Meetings
X1 Exit Meeting Summary '
The inspectors presented the inspection results to members of licensee management at
the exit meeting on February 4,1998. 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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ATTACHMENT
SUPPLEMENTAL INFORMATION
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PARTIAL LIST OF PERSONS CONTACTED
Licensen
J. Clark, Manager, Chemistry
J. Fee, Manager, Maintenance
G. Gibson, Manager, Compliance
D. Herbst, Manager, Site Quality Assurance
M. Herschthal, Manager, Station Technical (Acting)
J. Madigan, Manager, Health P"" tics (Acting)
R. Krieger, Vice President, Nuclear Generation
D. Nunn, Vice President, Engineering and Technical Services
T. Vogt, Plant Superintendent, Units 2 and 3
R. Waldo, Manager, Operations
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations ,
1
IP 71707: Plant Overations
IP 71750: Plant support Activities
ITEMS OPENED AND CLOSED
Ooened
50-361/97027-02 VIO seismic restraint of fire extinguishers in containment
Ooened and Closed
50-361/97027 01 NCV motor operated valve actuator with insufficient lubricant
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LIST OF ACRONYMS USED
AR action request
= CCW component cooling water. -
CDP. - core damage probability
.COLSS core operating limits supervisory report
EDG . emergency diesel generator
- FCE facility change evaluation
NPEO nuclear plant equipment operator
- PDR Public Document Room :
SIT . safety injection tank
T-cold cold leg temperature --
-TS technical specifications
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