ML20134D559
| ML20134D559 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 01/23/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20134D557 | List: |
| References | |
| 50-440-96-17, NUDOCS 9702050232 | |
| Download: ML20134D559 (30) | |
See also: IR 05000440/1996017
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
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Docket No: 50-440
License No: NPF-58
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Report No: 50-440/96-17
Licensee: Centerior Service Company
F5cility: Perry Nuclear Power Plant
Location: P 0. Box 97. A200
Perry, OH 44081
Dates: November 2 - December 20, 1996
Inspectors : D. Kosloff Senior Resident Inspector
R. Twigg, Resident Inspector
Approved by: J. M. Jacobson. Chief
Reactor Projects Branch 4
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9702050232 970123
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PDR ADOCK 05000440
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EXECUTIVE SUMMARY
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Perry fluclear Power Plant. Unit 1
flRC Inspection Report 50-440/96-17
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Lhis inspection included aspects of licensee operations, engineering,
maintenance. and plant support. The report covers a 7-week period of resident
inspection.
Onerations
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An operator error caused an inadvertent reactor power increase.
Previously implemented corrective actions for a similar event failed to
prevent the error, which involved unexpected opening of a reactor
recirculation flow control valve (Section 01.2).
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Engineering's identification of the apparent relationship between
chemistry sampling and jet pump flow indications demonstrated a
questioning attitude that led to effective corrective actioris
(Section 02.1).
.
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An operator made two errors while performing a cumbersome high pressure
core spray (HPCS) surveillance instruction (SVI), even though previous
performances should have identified the instruction for correction.
This SVI weakness was similar to a recently cited violation for which
corrective actions had not yet been completed (Section 04.1).
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The inspectors identified possible preconditioning issues during SVIs
performed by operations. Since additional inspection is needed, the
issues are considered an unresolved item (Sections 04.1 and 04.2).
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Operator and engineering response to an inspector-identified LPRM alarm
demonstrated effective teamwork (Section 04.3).
The licensee continued to use a variety of self-assessment techniques to
identity issues for corrective actions. The licensee recognized
weaknesses in its corrective action and work planning processes and
continued to pursue improvements in those processes (Section 07.1).
Maintenance
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Continued weaknesses in planning and preparations for risk-sensitive
work activities were demonstrated. However, the weaknesses were
addressed and the work was completed with only minor problems. RHR
flush connection check valve re
of these issues (Section M1.1) placement presented the broadest example
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Plant conditions in general continued to improve; however containment
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Maintenance activities related to an unexpected breaker trip were
generally prompt and appropriate. However, the failure to identify the
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- breaker defect prior to installation and during the initial shop l
inspection had previously been identified as a weakness. During the
review of the associated LER four apparent violations of technical
specifications were identified between A1ril 9. and September 17. 1996.
One of these involved a 41-hour period w1en the control room emergency l
recirculation (CRER) system was inoperable, and the actions required by t
Technical Specification 3.0.3 were not completed (Section M4.1).
Engineerinq
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The inspectors observed that a field clarification request used during l
breaker maintenance was inadequate. This was considered an unresolved I
item because additional inspection is needed to determine the extent and
~ significance of the issue (Section E2.1).
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The licensee promptly responded to another GE fuel design analysis
error. The repeated analytic errors are being tracked with a previously '
opened inspection follow-up item (Section E2.2).
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Engineering identified that they had failed to include the RHR flush
connection check valves in the ISI program. Engineering response to the
deficiency was prompt and conservative. Failure to test these check
valves was a non-cited violation of Technical Specification 5.5.2,
Primary Coolant Sources Outside Containment (Section E2.3).
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Several inconsistencies were noted between the UFSAR and plant '
practices, procedures, and parameters observed. The licensee included
the inconsistencies in its corrective action program (Section E2.4).
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The licensee completed a self-assessment of its emergeg, yrvice water
system. identifying numerous design engineering issues. Coh ective
actions had not been developed (Section 7.1).
Plant Support
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The licensee made a flotification of an Unusual Event in response to a
loss of offsite communications capability. Overall performance was
excellent. Personnel demonstrated teamwork and concise and accurate
communications. A weakness in anticipating equipment needs and
procedural direction for a loss of offsite communications was overcome
by personnel promptly adapting to the conditions encountered. The TSC
and OSC were promptly activated, provided appropriate support to the
plant, and was considered a strength (Section P2).
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Reoort Details
Summary of Plant Status
The plant operated at full power throughout the inspection period except for
short power reductions for testing, control rod realignments, and recovery
from a reactor recirculation flow control valve transient.
I. Operations -
01 Conduct of Operations'
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. While in general, the conduct of
operations continued to be safety-focused, an inadvertent reactivity
increase occurred and is of concern. *
01.2 Unexoected Increase in Reactor Reactivity
a. Insnection Scone (71707. 92901) 1
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Operator response to a failed local reactor power range monitor led to
unexpected opening of "A" Reactor Recirculation Flow Control Valve
(FCV). Reactor power increased as a result of increased recirculation
flow. The inspectors observed recovery efforts and reviewed relevant
issues leading to the inadvertent power increase from 99% to 100.2%
reactor thermal power (by heat balance).
b. Observations and Findinos
On Saturday. November 9. a local reactor power range monitor failed
high, causing one of six average power range monitors (APRM) to
erroneously indicate increasing reactor power. The indication caused an
automatic flow demand limit " runback" (partial closure) of the FCVs.
The operators verified the runback was due to erroneous indication and
stopped FCV motion with power at 98%. The erroneous indication was
corrected. The operators had stopped FCV motion by shutting down the
hydraulic power units (HPU) for the FCVs.
Each FCV (A and B) had one HPU with two subloops (1 and 2). One subloop
was required to provide hydraulic force to adjust the position of the
associated FCV, thereby adjusting reactor core flow and power. In
October, the inspectors had informed the operators of increased noise
from Subloop *A2.* Subsequent vibration testing led the responsible
system engineer (RSE) to request " limited use only" of Subloop ' A2. '
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J To restore automatic runback capability and return reactor power to 100% l
the operators began to restart the HPUs. The procedure to start a
subloop required the operators to verify that fuses for the subloop
solenoid valves (used to isolate the non-operating subloop and control
the hydraulic pressure from the operating subloop) were not blown. - -
Perry and other plants had experienced numerous blown fuses caused by '
sticking solenoid valves. One of the Subloop 'Al' solenoid fuses was
found blown. After discussions with the RSE. the operators chose to
start the HPU without replacing or determining the cause of the blown
fuse, relying on Subloop ' A2. '
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Upon starting 'A' HPU, the FCV began to open, increasing reactor power.
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Apparently, the valve with the blown fuse had failed open and '
incorrectly directed hydraulic pressure to the FCV in the open
direction. About 12 seconds after the 'A' HPU pump was started, the
shift supervisor stopped the unintended FCV motion by shutting down the
HPU from the reactor control panel. In 1994. a similar solenoid valve i
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failure had occurred, causing a change in reactivity at low power. As a !
result of that event, operator knowledge an'J t, aining provided l
opportunity to prevent recurrence.
The inspectors reviewed computer records and observed that reactor power
peaked at about 100.2% (by thermal heat balance calculated at 5-second
intervals). The inspectors verified that :he thermal power records were ,
consistent with the APRM records. The rec >rds indicated that the
operators had promptly reduced flow with FU! B and reduced power to 98%.
This created an approximate 8% imbalance in tiow between the two reactor
recirculation loops. Technical Specification (TS) 3.4.1 was entered due
to a greater than 5% flow mismatch between loops. The action statement
for this TS required a shutdown of one of the recirculation loops
(single loop operation) if the flow mismatch could not be reduced to
less than 5% within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
The acting plant manager (engineering director). operations management,
reactor engineers. and RSEs promptly responded to the site. At 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
and 51 minutes into the 2-hour action statement. the inspectors verified
that the operators had successfully driven rods in to reach 88% reactor
power and increased flow in the B recirculation loop, exiting TS 3.4.1.
On Sunday. November 10. the inspectors observed that the operators used
appropriate vigilance when starting Subloop 'Al' after solenoid valve ;
replacement. The Vice President (VP) - Nuclear and the acting plant '
manager provided additional oversight of control room FCV operations.
The VP - Nuclear briefed the inspectors on plans for a comprehensive
review of the event using the plant's corrective action process. On
November 11. the inspectors observed that a multidisciplinary team had
been assembled to evaluate the event and relevant issues. The team's
efforts were continuing at the end of the inspection period.
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c. Conclusions
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This event was caused by an operator error. Although reactor power did
not exceed TS limits the unexpected change in reactivity was of concern
' because there had been opportunities to avoid the event. For example.
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operator knowledge and training, and corrective actions for a previous
event should have prevented this event. This event is an Unresolved 3
item pending further NRC review (URI 50-440/96017-01(DRP)). ;
02 Operational Status of Facilities and Equipment
02.1 Core Flow Indication Deviation -
- a. Insoection Scone (71707. 92901)"'
The inspectors reviewed the evaluation of a licensee-identified core
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flow indication deviation.
b. Observations and Findings
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During routine reactor engineering training for core flow calibration on
December 2. the licensee identified that jet pump calibrated core flow
was about 3.0% higher than the measured core flow. However this
difference was conservative in relation to core thermal limits. The
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Updated Final Safety Analysis Report (UFSAR) stated that the uncertainty
in the core flow measurement was 2.5%. The reactor engineer documented
this condition in PIF 96-3594. The responsible system engineer (RSE)
coordinated the evaluation of this condition. One of four calibrated
flow transmitters was reading higher than the other three. Several
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causes were postulated for the difference in readings. Maintenance and
enc,1neering personnel evaluated each postulated cause. There was no
e'idence that any of the postulated causes had affected the
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instrumentation. Based on the history and the evaluation of the
pc stulated causes, the RSE concluded that the calibrated flow
transmitter readirg should be considered valid and that the measured
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' flow indication should be adjusted conservatively to match the
calibrated flow indication. The licensee adjusted measured flow
electronically, by procedure. to match the calibrated flow. The reactor
engineer was concerned that the difference in calibrated flow might have
been an early indication of a jet pump problem. Therefore additional
data monitoring of jet pump flows was established.
On December 12. the measured and calibrated flows again indicated a 3.0%
difference. Detailed analysis of the data indicated the difference was
inverse to the difference identified on December 2. Using this
additional information the RSE looked for activities that had occurred
on December 12 and prior to December 2.
One common activity had been
chemistry water sampling using an instrument line from one of the four
calibrated jet pumps on December 12 and prior to December 2. Sampling
involved opening and closing valve' that isolate the sampling line from
the calibrated jet pump. The licensee concluded that sampling prior to
December 2 had introduced an error in the calibrated flow. The licensee
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e had adjusted the measured flow on December 2 to correct an error in the !
calibrated flow unknowingly introduced by the sampling. Sampling on i
December 12 returned the calibrated flow to normal and revealed that the l
measured flow in loop B had been in error by 3% since December 2.. !
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Technical Specification 3.4.1. Recirculation loops Operating, required
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other. . The operators used the measured flow to compare recirculation
loop flows. From December 2 until December 12. the potential existed to
exceed TS 3.4.1 because of the licensee-introduced 3% error. The
inspectors reviewed the operator logs and verified that TS 3.4.1 had not
been violated. The licensee discontinued chemistry sampling from the
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Jump sample line and continued to review the physi. cal relationship i
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of t1e sampling to jet pump indicated flows.
c. Conclusions-
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Engineering's identification of the apparent relationship between the !
chemistry sampling and jet pump flow indications demonstrated a '
questioning attitude that led to effective corrective actions.
Additional data monitoring after the initial corrective actions ~
facilitated an understanding of the relationship between chemistry
sampling and jet pump calibrated core flow. No TS limits were
challenged. >
04 Operator Knowledge and Performance *
04.1 Surveillance Procedure Weaknesses
a. Insoection Stone (61726. 71707. and 92901)
l The inspectors observed a briefing conducted by the unit supervisor (US) :
l and the subsequent performance of surveillance instruction SVI E22-
T2001. " Quarterly High Pressure Core Spray (HPCS) Pump and Valve
j Operability Test."
b. Observations and Findinas:
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Some sections of the HPCS surveillance were cumbersome for the operators j
L to implement. None of the examples observed prevented the operator from
complying with the procedure. However, the operator sometimes had to
stop the surveillance and discuss the procedure with the US and shift
supervisor (SS) to verify his understanding of the procedure. An
l example was the step that appeared to require removal of all motor
! operated valve (MOV) test equipment, which could have prevented
i completion of MOV testing for E22-F010. HPCS first test valve to the
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condensate storage tank (CST). On another occasion the supervising
operator failed to measure valve stroke time on the first stroke of a
' valve, as recuired by the SVI. This was the result of the HPCS suction
being alignec to the suppression pool instead of the CST. causing the
i E22-F010 valve to unexpectedly close before the operator was ready to
j time the valve. A note in the SVI had designated the CST as the
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preferred suction source, but had not indicated why. Another failure to
measure valve
the test due to stroke time on
an operator the first stroke occurred near the end of
error. Following this surveillance, the
operator was assigned the task of evaluating the SVI for revision.
c. Conclusions
This SVI had been 3erformed several times since it had been revised in
March,1995 and tie cumbersome sections had not been corrected. This
SVI weakness was similar to a procedure violation cited in the previous
inspection report (50-440/96011-02(DRP)) for which corrective actions
had not yet been completed.
" Additionally the inspectors needed more information to determine whether
multiple strokes of MOVs preconditioned the valves. Therefore this is
an Unresolved Item (URI 50-440/96017-02(DRP)).
04.2 Potential Preconditioning Durina Emergency Diesel Generator Testing
a. Inspection Scone (71707. 92901)
The inspectors observed performances of the Division 1 and 2 Emergency
Diesel Generator (EDG) monthly surveillance instructions (SVI).
b Observations and Findings:
The inspectors observed EDG pre-start evolutions that included 2 manual
rolls of the EDG and a roll of about 10 revolutions with the air start
system.
Later, during another observation of an EDG SVI, the inspectors
observed that the air start roll was about 4 revolutions. The exact
number of revolutions was dif ficult to verify because of the rapid
acceleration and high speed of the EDG flywheel. The SVI directs the
operators to obtain "at least two revolutions." A recent URC inspection
at another facility concluded that 10 revolutions of a similar EDG
during prestart primed the fuel system and constituted preconditioning
of the EDG. The RSE stated that the fuel system at Perry did not have
the same susceptibility to a loss of prime.
c. Conclusions
Additional inspection is necessary to resolve how many revolutions of
the EDG would precondition the EDG. The inspectors will evaluate this
issue in conjunction with the URI (50-440/96017-02(DRP)) discussed above
(Section 4.1), related to possible MOV preconditioning.
04.3 local Power Range Monitor (LPRM) Failure
a. Insnection Scone (37551. 71707. and 92901)
The inspectors regularly reviewed reactor thermal 1imit computer
printouts.
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b. Observations and findings: l
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On December 9. at about 2:30 p.m., the inspectors observed that "11CSU1B
404046D6 *** LPRM DRIFT WARNING" had been printed by the computer at
2:05 p.m. Although the thennal limit data was printed hourly, the
operators logged the data once a day on the midnight shift in accordance
with the TS requirements. Shortly after the inspectors asked the
operator at the controls about the computer alarm, another "LPRM DRIFT
WARNING" was printed at 2:35 p.m.
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The operators and the shift technical I
advisor (STA) did not understand the alarm. While the STA was
contacting the reactor engineer for additional information, the '
operators reviewed a live LPRM computer display. No abnormal deviations -
were apparent. l
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At 3:37 p.m. the reactor engineer created a computer printout of recent i
LPRM 40-33 D power indications. The inspectors reviewed the file and
observed that between 2:05 p.m. and 3:29 p.m. LPRM 40-33 D power
indications varied from 48.3% to 54.7% with constant reactor power
Recent hourly thermal limit printouts had indicated that LPRM 40-33 D
data had been rejected by the computer as unreliable. The inspectors l
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verified that LPRM 40-33 0 was prompt-ly removed from service and that
there were still ample LPRMs available to meet TS requirements for l
reliable power and thermal limit indications. The inspectors also
verified that LPRM upscale and downscale annunciator alarms had been {
available had the LPRM drift increased.
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c. Conclusions .
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Although the operators and the STA did not understand the inspector-
identified computer alarm, they immediately contacted the reactor i
engineer who provided the operators with appropriate guidance. '
Corrective actions were completed promptly. This demonstrated effective
operations and engineering teamwork. The operators reviewed the thermal
limits data as required by the technical specifications.
07.1 Licensee Self-Assessment Activities (40500)
a. Insnection Scone
lhe inspectors observed or reviewed the following self-assessment
activities that addressed multiple functional areas, as well as
operations:
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Licensee routine manager's meetings
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Planning meetings for residual heat removal (RHR) check valve work
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Special Perry onsite review committee (PORC) meeting to evaluate
work planned for the RHR check valves
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Potential issue forms (PIF)
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Meetings of the task force evaluating the FCV power increase
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b. Observations and Findings
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The meetings were attended by appropriate personnel and there was i
substantive discussion of specific issues. The llanning meetings and I
PORC meeting related to the check valve work emplasized conservative .
operations and identified weaknesses in the planning process. About
430 PIFs were written during the inspection period by a variety of
personnel who represented a wide cross section of plant organizations. ,
The task force evaluating the FCV power increase was thorough. )
c. Conclusions
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The licensee continued te use a variety of self-assessment techniques to
identify and evaluate issuea *at required corrective actions. The
licensee recognized weaknesses in its corrective action and work
planning processes and continued to pursue improvements in those l
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II. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments I
a. Insnection Scone ( 61726, 62707, and 92902) I
Using Inspection Procedures 61726. 62707, and 92902. the inspectors I
observed all or portions of the following maintenance and surveillance
testing (SVI) activities:
. Periodic Test Instruction (PTI) C11-P0001 control rod drive hydraulics
control system tuneup
. * EME R85-13011 1E22C0001 Perform megger and general maintenance checks
(see Section E2.1)
. SVI E22-T1202 HPCS system ilow rate low channel fmctional test
. SVI E22-T1200 HPCS system discharge pressure high channel f unctional
test
. IMI E2-42 (Instrument Maintenance Instruction) t illing and venting of
suppression pool level instrument 1ines
. SVI E22-T2001 Quarterly HPCS pump and valve operability test
. SV1 E22-T1319 diesel generator start and load Division III
. SVI R43-T1317 diesel generator start and load Division I
. SVI R43-T1318 diesel generator start and load Division II
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testing and replacement of RHR check valves. The inspectors reviewed
the planning activities and associated procedures for the evolution and
potential recovery plans.
. WO 96-5120 P11 Establish freeze seal
. WO 96-5115/6 E12F0063A/0086 Drain piping and replace check valves
. WO 96-5139 E12F0063A Test 8" check valve removed from E12 'A'
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b. Observations and Findings
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The inspectors found that most of the observed work activities were
performed without any concerns. Those activities where concerns were
identified are discussed in Sections 04.1. 04.2, E2.1, and E2.3.
The replacement and testing of the residual heat removal (RHR) check
valves (see Section E2.3) which provided isolation from the condensate
transfer and storage system (P11), required extensive planning and
preparation because of potential consequences of postulated failures
during the work activities. Those consequences included flooding of a
division of RHR, reactor shutdown, and loss of Ell. Flooding of a 1
division of RHR was possible because freeze seals of 8-inch P11 supply
lines were necessary to effect replacement. The inspectors observed l
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questioning attitudes on the part of the licensee staff throughout the
prelarations for the evolution. Responses to the questions exposed
weacnesses in the planning for the evolution. Conservative resolution i
of the weaknesses delayed implementation for approximately 2 weeks. The
inspectors reviewed contingency plans for freeze seal failure. All
contingencies had been identified and actions were taken to minimize
postulated impacts.
The inspectors observed coordination and implementation of the
activities. The inspectors identified some minor concerns, the most
significant was a vent valve left open on a nitrogen supply bottle,
making the bottle useless. Several nitrogen bottles had been staged so
this had no impact on the work: The planned activities were completed
with minimal interruptions.
Management review and oversight of the planning, as well as
implementation, of the evolution was thorough and conservative.
However, there was no management participation in the post-job critique. ,
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c. Conclusions
Continued weaknesses in planning and preparations for risk-sensitive
work activities were demonstrated. However, the weaknesses were
identified and addressed and the work was completed with only minor
problems.
M2 Maintenance and Material Condition of Facilities and Equipment
a. Insnection Scone (71707. 92720)
The inspectors observed the material condition of facilities and
equipment during routine inspections of the plant and during inspection
of maintenance and surveillance activities. Material condition
observed by the inspectors had been identified by the licensee, problems
monitored, and scheduled for repair.
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b. Observations and findings
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The licensee continued to maintain most areas of the plant with minimal
material condition problems. Improvements included roof leakage repairs.
painting of the emergency service-water pumphouse and replacement of
control rod drive pumps. Equipment repairs continued and included
replacement of 13.800 VAC transformers and retubing of a non-safety heat
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exchanger.
Some minor equipment problems were identified by the inspectors in
' containment. Examples identified by the inspectors included water
leakage from a HVAC cooler with water dri) ping two levels below onto a
scram discharge isolation vent valve, higi vibration levels on the HPU
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Subloop 'A2' pump (see Section 01.2 b.), a missing' light cover, and
loose fan belts on a HVAC cooler.
c. Conclusions
Plant conditions in general continued to improve; however. containment
conditions declined slightly.
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M4 Maintenance Staff Knowledge and Performance
M4.1 Loss of Control Ibom Ventilation Safety Function Due to Degraded Breaker
a. Insnection Stone-(37551, 62707. 92700. and 92902)
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The inspectors reviewed LER 96-008-00. " Degraded Breaker Results in Loss '
of Safety Function and Exceeding Technical Specification Action
Statements." Additional inspection related to this event was also
documented in Inspection Report 50-440/96011.
b. Observations and Findings
1. Description of tite. Event
On September 16. 1996, at approximately 1:51 p.m., with the plant at
full power, a 48) volt alternating current (VAC) circuit breaker EF-1-D-
09 unexpectedly tripped on overcurrent. This occurred about 2 minutes
after fuel handling building (FHB) heating ventilation, and air
conditioning (HVAC) supply fan "B" was started (exhaust fan "B" was
already running). The breaker trip removed power from safety-related
Division (Div) 2 motor control center (MCC) EF-1-0-09. -Since there was
no apparent reason for the breaker trip, the shift supervisor declared
the MCC inoperable and had the breaker removed for further inspection.
Initial inspections and testing of the removed breaker and other
equipment did not reveal any reason for the breaker trip.. ;
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Technical Specification (TS) Limiting Condition for Operation (LCO) i
3.8.7. Action A.1 required the MCC to be restored to operability within !
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. If operability could not be restored within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> then TS
LCO Action C.1 required the plant to be in Mode 3 (hot shutdown) within {
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the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Clear specific written and verbal instructions were ,
promptly given to the shift supervisor on preparing the plant for an
orderly shutdown upon approaching the end of the action statement time
limit. One of the replacement breakers was almost ready for use at
9:51 p.m.. when the action statement time limit was reached. The
licensee determined that if it began reducing plant power within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
of entering LCO Action C.1. there would be ample time for an orderly
shutdown. Since breaker replacement was imminent, plant power was not
reduced. The breaker was replaced and power was restored to the MCC at
11:32 p.m. At 12:44 a.m. on September 17. upon completion of a review
of inspection and testing done on the MCC and the new breaker, the shift
supervisor declared the MCC operable and exited the TS action statement.
On September 20. the responsible system engineer (RSE) identified that
two current
breaker. On transformer
September 26. (CT)
thewire
RSEconnections were reversed on the
' firmed with the breaker vendor
that the reversed connections woul e caused the breaker to trip at
about 350 amps instead of the expeueo 660 amps. The RSE determined
that the breaker had been installed on March 10. 1996. during the fifth
refueling outage (RF05). A load analysis by the licensee determined
that the breaker would have tripped if a postulated loss of off-site
power (LOOP) loss of coolant accident (LOCA), or a LOOP coincident with
a LOCA were to have occurred whenever FHB exhaust fan 'B' had been
energized. This analysis was based on the breaker's reduced trip
setpoint in conjunction with the automatic reconnection of safety loads
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required by plant design.
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Therefore, whenever FHB exhaust fan 'B' had been in operation. MCC EF-1-
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D-09 and its loads, including the Div 2 CRER subsystem. had been l
inoperable. A review of operating logs also determined that the Div 1
CRER subsystem was out-of-service (005) for maintenance from August 5 at
4:46 a.m. to August 6. 1996, at 10:25 p.m., about 41-hours and 39
minutes. Therefore, during this period both trains of the CR HVAC
emergency recirculation (CRER) mode were inoperable: a loss of safety
function. During this period, the plant was in Mode 1 (power
operation). however TS LCO 3.0.3 was not entered as required.
From March 10. 1996 (when the improperly wired breaker was installed) to I
September 16, 1996, several safety functions were lost on several
occasions, the most significant being the loss of safety function for
the control room recirculation system.
2. Breaker Descrintion
The affected breaker was a K-line 600 Series breaker manufactured by ABB
Company. Inc. in December 1995, with a POWER SHIELD solid state trip
device. The trip device received breaker load current in)ut data from
l three current transformers (CT). one for each phase. Eac1 CT had two
i wires for its load current data. The A phase CT wires had been reversed
~
where they attached to a terminal board near the bottom of the breaker.
reversing the CT load data polarity. When the solid stated trip device
!
combined the cts input data. it developed a current indication about
13 i
_ .-
.-
twice as large as intended. Vendor testing confirmed a trip setpoint
-
reduction from 660 amps (110%) to 350 amps.
This same breaker had tripped on July 3,1996, when it was touched by a
non-licensed. operator Although this trip was not caused by the wiring
error, the licensee had an opportunity to identify the problem by
inspecting the breaker.
3.0 Motor Control Center description
Most of the loads supplied by MCC EF-1-D-09 MCC were associated with
HVAC as shown by the following Div 2 load list: -
. CR HVAC Supply FanB' '
. CR HVAC Return Fan 'B'
. CRER Fan 'B'
. FHB HVAC Exhaust Fan 'B'
. FHB HVAC Exhaust Electrical Heater 'B'
= FHB HVAC Supoly Fan 'B'
. Emergency Closed Cooling Pump Area Ventilation Fan 'B'
. MCC Switchgear and Battery Room Recirculation Fan 'B'
. MCC Switchgear and Battery Room Exhaust Fan 'B'
. Control Complex Cooling System Chiller 'B' Oil Pump.
. Standby Liquid Control Auxiliary Mixing Tank Transfer Pump B
. ATWS Uninterruptible Power Supply - Alternate Supply
4.0 Control Room HVAC System Descrintion
The control room heating, ventilation. and air conditioning (CRHVAC)
system provided cooling, heating ventilation, and when required, smoke
removal, for the control room. In addition, the emergency recirculation ,
l
mode of CRHVAC provided the necessary particulate and gaseous filtration !
of the air supplied to the control room areas during emergency and other
abnormal conditions to reduce the radiation dose for control room
personnel. The system included two identical, redundant subsystems
l (A and B).
The control complex chillers provided chilled water to the cooling coils
I
' of their respective CRHVAC train as well as to the cooling coils for
other safety-related areas in the control complex. During accident ,
'
l
conditions, the CRHVAC would transfer from normal operation to emergency
l recirculation.
l
l 5.0 Secuence of Events
l )
l
3/10/96 480 VAC supply circuit breaker EF1009, manufactured by ABB,
I
was installed during RF05. Six other similar 480 VAC
l
breakers were installed at about the same time. I
3/11/96 FHB Exhaust Fan and Heater 'B' started. This made MCC EF-1- 1
D-09 inoperable, however the plant was in Modes 4 (cold
14
.- - . . . - _ . - _ - - _ - . .
.-
- shutdown) or 5 (refueling) with no irradiated fuel movement
and the MCC was not required to be operable.
3/13/96 FHB Exhaust Fan and Heater 'B' shut down. MCC EF-1-0-09 was
operable again. - -
4/09/96 Plant entered Mode 1. MCC EF-1-0-09 was now required to be
4/11/96 FHB Exhaust Fan and Heater 'B' started at 8:00 a.m., MCC EF- i
1-D-09 inoperable. TS LCO 3.8.7 was entered (not
recognized). TS LCO action statement A.1 was exceeded at
4:00 p.m.
4/17/96 CRER 'A' declared inoperable at 3:00 a.m. for maintenance.
plant was then in TS LCO 3.0.3 (not recognized). At
5:19 a.m. FHB Exhaust Fan and Heater 'B' was shut down. TS
LCO 3.8.7 exited. TS LCO 3.0.3 exited without exceeding
action statement time limit.
.
4/20/96 Train A CRER declared operable.
5/08/96 FHB Exhaust Fan and Heater 'B' started at 2:35 a.m.. MCC EF-
,
,
! 1-D-09 inoperable, and TS LC0 3.8.7 was entered (not
recognized).
1
TS LCD action statement Al was exceeded at
10:35 a.m.
i 5/31/96 Plant placed in Mode 4 after an unrelated scram. This
placed plant in compliance with TS LCO 3.8.7.
6/10/96 Plant entered Mode 2 at 5:44 a.m. This mode change with MCC
EF-1-0-09 inoperable violated TS LC0 3.0.4.
6/11/96 Plant entered Mode 1 at 2:00 p.m. This mode change with MCC
EF-1-0-09 inoperable violated TS LC0 3.0.4.
6/17/96 At 8:43 a.m. FHB Exhaust Fan and Heater 'B' shut down. TS
1
1
LCO 3.8.7 was exited.
6/25/96 FHB Exhaust fan and Heater 'B' started at 12:45 a.m.. MCC
EF-1-D-09 inoperable. TS LC0 3.8.7 was entered (not
recognized) and its action statement A.1 was exceeded at
8:45 a.m.
! 8/05/96 CRER 'A' declared inoperable at 4:07 a.m. for maintenance.
l plant was then in TS LCO 3.0.3 (not recognized).
,
8/06/96 TS LCO requirement to place the unit in Mode 4 by 5:07 p.m.
was not met. ,
i
'
8/06/96 CRER 'A' declared operable at 10:55 p.m.. TS LCO 3.0.3
,
exited.
i 15
4
!
.- --
_ _ _ _ _ . . _ _ _. ._
1
i
,
'
,
1
9/16/96 EFID09 tripped after start of FHB Supply Fan T Breaker
-
replaced. Initial inspection by licensee and ABB l
!
representative did not reveal cause of the breaker trip. l
9/17/96 MCC EF-1-0-09 declared operable with replacement breaker. i
9/20/96 RSE's breaker inspection revealed that the phase A CT wires
were landed on the incorrect terminal block locations,
,
reversing the phase A load current data polarity. !
,
9/26/96 RSE discussion with the vendor indicated that reversed CT !
,
polarity would cause the solid trip device to indicate a
current about twice the expected value. This configuration {
!' j
would cause a tireaker trip at a lower current.
9/27/96 The licensee inspected the CT lower leads on three of the '
,
seven breakers installed during RF05. No problems were l
i
i
identified. '
1
,
10/01/96 The inspectors contacted a compliance engineer for
additional information on the solid state trip devices.
-
The l
RSE informed the inspectors of the reversed polarity effect.
,
l
The inspectors observed the as-found wiring configuration.
10/02/96 The inspectors observed licensee inspections of the CT loter
leads on the last three of the new 480 VAC breakers
installed in RF05. No problems were identified
, 10/ 4/96 The licensee identified two occasions where a CRER loss of
safety function had occurred. The NRC was notified in
accordance with 10 CFR 50.72.
10/10/96 Vendor's laboratory test confirmed that the affected breater
trip setpoint was about half of the intended trip setpoint.
The licensee performed a review which identified multiple
safety function losses.
11/ 4/96 Licensee Event Report (LER) 96-008-00: " Degraded Breaker
Results in Loss of Safety function and Exceeding Technical
Specification Action Statements" issued in accordance with
6.0 Root Cause
The licensee concluded that the root cause of this event was a
manufacturing wiring error which caused the affected breaker to exceed
its trip setpoint with less than expected current flow. The inspectors
concluded that the root cause was inadequate preinstallation testing,
inspection, or postinstallation testing of the breaker, which failed to
identify the manufacturing error. The difference was not significant
because the licensee had developed remedial or corrective actions to
address both potential root causes.
16
. . , _ . -
.
7.0 Safety Sinnificance
,
!
A review hy the licensee identified loss of safety functions on multiple
occasions due to the breaker trip setpoint reduction. The licensee
recognized that in the event of-a LOOP /L0CA with FHB exhaust fan 'B'
operating. the breaker would have tripped, causing loss of CRER 'B. '
In the event of a postulated accident with breaker EFID09 tripping
coincident with Div 1 EDG being inoperable, a direct loss of CRER,
emergency closed cooling (ECC) pump area, and MCC switchgear and battery
room ventilation systems resulting in a loss of safety functions would
have occurred that could have impacted the mitigation of an accident.
As a result of the loss of ECC pump area ventilation, with no operator
action, increasing temperature could have caused a loss of the ECC
safety function resulting in eventual inoperability of low pressure core
spray (LPCS), low pressure coolant injection (LPCI), reactor core
isolation cooling (RCIC), containment spray, suppression pool cooling,
and the hydrogen analyzers. Loss of MCC switchgear and battery room
ventilation could also have resulted in a similar loss of safety systems
over an extended period of time, if room temperatures rose to
unacceptable levels. -
The licensee performed calculations that indicated that it would take
more than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for each of the affected areas to reach a high enough
temperature to affect equipment in the rooms. The inspectors observed
the licensee perform a field time study to verify that the required
equipment could be restored within 30 minutes by manual operator action.
This action used existing procedures for MCC restoration with which the
operators were already familiar.
8.0 Iicensee Corrective Actions
As part of the licensee's immediate corrective actions for this event,
the defective breaker was replaced. the six similar breakers installed
during RF05 were checked for similar wiring errors, and the operability
of other similar breakers was evaluated.
The following additional corrective actions were also accomplished:
A refurbished breaker supplying the reduridant division of
ventilation equipment was checked for proper polarity.
-
A field time study was performed to validate the time needed to
restore MCC EF-1-D-09 during a postulated accident.
-
Maintenance instructions were changed to check the wiring of the
cts and to test for correct polarity.
-
A review of safety-related breakers was performed to determine if
further testing was required to verify proper breaker operation.
17
- _ _ _ . . _ _ _ _ _ .
.
The following long term actions had been developed but not completed by
.
the end of the inspection:
-
The vendor was to provide documentation that training on this
event was provided to breaker assembly personnel.
The RSE began gathering information from other utilities to
-
determine if similar problems had been identified.
-
Half (12 breakers) of the similar refurbished breakers that were
not normally subjected to a current above the faulted trip
setpoint_were to be checked for wiring errors.
-
Engineering was to 3rovide a prioritized list of safety-related
breakers to be checced for wiring errors.
9.0 Technical Specification Aoparent Violations
MCC EF-1-0-09 was inoperable on multiple occasions due to the breaker
trip setpoint reduction between March 11, and September 16, 1996. On
this basis, the following apparent violations were identified:
.
Technical Specification LC0 3.0.3 requires that when an LC0 is not
met and the associated actions are not met. the unit shall be
placed in a mode in which the LCO is not applicable. Action shall
be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit, as applicable in:
1. Mode 2 (startup) within 7 hour8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />s:
2. Mode 3 (hot shutdown) within 13 hour1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />s: and
3. Mode 4 (cold shutdown) within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />.
From August 5 to August 6, for about 41 hours4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br />, with the CRER
system inoperable, which required entry into TS LC0 3.0.3, the
licensee failed to initiate action within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit
in mode 4 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />. This is an apparent violation (EEI 50- l
440/97017-03(DRP)).
.
Technical Specification LCO 3.0.4 prohibits entry into a new mode
when an LCO is not met and the associated actions do not permit
continued operation in the new operating condition. The plant
operating condition was changed when LCOs were not met on two
occasions: when the plant was taken to mode 3 on June 10. at
5:44 a.m., and when the plant was taken to mode 1 on June 11. at
2:00 p.m. Therefore, this LCO was apparently violated on those
occasions (EEI 50-440/96017-04(DRP)).
l
.
Technical Specification LCO 3.8.7 Action A.1 required an
'
inoperable Div 2 AC electrical subsystem (MCC EF-1-D-09) to be
restored to operable status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Moreover, Actions C.1
and C.2 required the unit to be placed in at least mode 3 within ;
the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in mode 4 within the next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> if MCC j
EF-1-D-09 was not restored to operable status. This LCO was l
18 I
.
-
apparently violated on several occasions (reference paragraph
M4.1.b.5. Sequence of Events) (eel 50-440/96017-05(DRP)).
.
Technical Specification LCO 3.7.3 Action A.1 required the
. inoperable CRER 'B' subsystem to be restored to operable status
within 7 days. Moreover, action statements B.1 and B.2 required
the unit to be in mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in mode 4 within 36
hours if the inoperable CRER subsystem was not restored to
operable status within the time required by Action A.1. This LCO
was a)parently violated on several occasions (reference paragraph
M4.1.3.5, Sequence of Events) (EEI 50-440/96017-06(DRP)).
.
c. Conclusions
.
From April 11 to September 17, 1996, four apparent violations of
technical specifications occurred, including one for a 41-hour period
with the CRER system inoperable during which the actions required by TS 3.0.3 were not completed.
III. Engineerina
E2 Engineering Support of Facilities and Equipment
>
E2.1 Field Clarification Recuest Use Durina Maintenance
a.
'
Insnection Scone (37551 and 627071
i
The inspectors observed maintenance perform a general check of the HPCS
>
pump electrical breaker. Subsequently the inspectors reviewed a
related field clarification request (FCR).
b. Observations and Findings
l
The craft were instructed by the maintenance supervisor to visually
' inspect the breaker for any abnormalities. The craft identified cracks
in the corners of the molded coil sensor assemblies for GR-5 ground
fault relays. The cracks radiated from the lower two mounting bolts
(four bolts total) outward to the edge of the plate. The supervisor
stated that FCR 016809 addressed the issue and that a number of breakers
exhibited the same deficiency. The inspectors reviewed the FCR and
identified the following:
!
! o The FCR was completed in 1992.
l
'
o The FCR did not include a documented basis for the conclusion
that the breaker condition was acceptable.
o The extent of the condition (i.e., what other breakers had
similar problems) was not addressed by the FCR.
19
- . _ _ _ . _. _ _ _ _ _ . __ _ _ _ _ _ _ _ _ _
i
.
-
o General Electrical Instruction (GEI) 0104. Step 5.1.2 stated.
" Inspect the relay for imperfections, damage
NOTE: .
The sensor is acceptable to use provided that the
sensor is not loose. the crack is not through the entire cross
section, or the internal coil is not visible." - '
The inspectors discussed the issues with engineering and PIF 96-3768 was
issued. The acting engineering manager stated that engineering had been
working on improving the FCR process as a result of other identified
problems.
_ c. Conclusions
The age of the FCR and the fact that it did not consider extent of
condition made its current use for multiple breakers questionable.
Since the FCR did not include a documented basis the inspectors could
not evaluate whether it was acceptable for even the original breaker i
'
that it addressed. The instructions provided in GEI-0104 were
inadequate. The quality of this FCR and its use for justification of a
,
I
deficiency in a safety related component requires additional inspection :
to determine the extent and significance of the issue and is an l
Unresolved Item (URI 50-440/96017-07(DRP)).
E2.2 General Electric (GE) Fuel Desion Error
a. Insnection Scone (37551)
The licensee received verbal notification from GE Nuclear Fuel of an
error to the Cycle '6 loss of coolant accident (LOCA) analysis. The
inspectors evaluated engineering's evaluation of and response to the
error.
b. Observations and Findings
Preliminary calculations indicated an increase in the LOCA peak clad
temperature (PCT) of approximately 15 Fahrenheit (F). which exceeded
the PCT limit of 2200 F established in 10 CFR 50.46. The licensee
documented the issue with PIF 96-3507. GE recommended and the licensee
promptly implemented, a limit of 0.970 for the Maximum Average Planar
Heat Generation Ratio (MAPRAT). normally limited to 1.000. The
inspectors verified that the operators were briefed and aware of the new
limit. The errors were related to GE 11 fuel that Perry was using
during Cycle 6. GE reviewed its analysis and identified excess
conservatism. Reduction of the conservatism compensated for the error
and allowed the plant to return its MAPRAT limit to 1.000. This issue
will be evaluated in the future as part of a previous Inspection Follow-
up Item (IFI 50-440/96003-13(DRP)), opened based on other identified GE
core design errors.
20
. .- - , . . _ . ___ -. _ - . _. . .
I
l -
$
E2.3 Inservice Inspection Program Corrective Actions I
'
a. Inspection Scone (37551 and 37001)_
1
Engineers identified four residual heat removal (RHR) check valves
(1E12-F0063A, 638, 63C. and 86) that had not been included in the in-
l
' service inspection (ISI) program. The inspectors evaluated engineering
activities related to this deficiency.
b. Observations and Findings l
!
!
These check valves provided isolation of the RHR system from the non-
safety related condensate transfer and storage system. Failure to
include the valves in the ISl~ program presented the potential to exceed
the limits developed in the UFSAR analysis for compliance with 10 CFR
'
100.11 offsite radiation dose limits after postulated accidents. After
some postulated accidents, the RHR system would contain highly
radioactive fluid and the check valves were designed to prevent that
)
fluid from spreading to other systems outside containment. The valves :
had not been tested since they had been installed during plant !
construction. The licensee's administrative leakage limit for all
potential radioactive leakage outside containment was 5 gallons per hour !
(gph) and the limit for the analysis was 10 gph. Testing (see :
Section M1.1) of the valves was completed and when the valve as-found
leakage was added to other previously identified leakage. the total as-
found leakage was 5.3 gph. Some valves were replaced and the total as-
left leakage was less than 5.0 gph.
c. Conclusions
!
This ISI program deficiency was identified by the licensee during
corrective action
dated November activities for an earlier violation (50-440/EA 96-367)
6, 1996. Engineering response to the deficiency was
prompt and conservative. However there were some delays in completing
the corrective actions because of planning weaknesses (Section M1.1 b.).
Failure to test these check valves was a violation of Technical
Specification 5.5.2 Primary Coolant Sources Outside Containment. This
licensee-identified and corrected violation is being treated as a Non-
Cited Violation (NCV 50-440/96017-08(DRP)) consisterit with
Section Vll.8.1 of the NRC Enforcement Policy, NUREG-1600.
!
E2.4 Review of Uodated Final Safety Analysis Report (UFSAR) Commitments
The inspectors reviewed applicable portions of the UFSAR that related to
the areas inspected: no inconsistencies were identified. The inspectors
also reviewed items that the licensee had identified during its review
of the UFSAR. The licensee included the inconsistencies in its
corrective action program. These may be reviewed in a future ins 3ection
based on the NRC's recently established policy (61 FR 54461. Octo)er 18,
4 1996) for the review of licensee-identified UFSAR inconsistencies.
21
. ..
l
.
The inspectors also reviewed current safety evaluations for some of the
-
identified UFSAR inconsistencies. The safety evaluations were timely
and appropriate for the identified issues. It appeared that the
licensee had addressed the inconsistencies appropriately in accordance
with the safety significance. . .
E7 Quality Assurance in Engineering Activities
,
E7.1 Emergency Service Water System Operational Performance Inspection
a. Inspection Scone (37551 and 40500)
The inspectors attended the exit meeting for the licensee's self-
assessment inspection and reviewed PIFs developed during the inspection.
' The inspection was modeled on the NRC's Temporary Instruction for
Service Water System Operational Performance Inspections.
b. Observations and Findings
The meeting was attended by appropriate personnel and there was
substantive discussion of the issues presented. The issues. initially
documented with 57 PIFs. included engineering process weaknesses:
response to Generic Letter 89-13 and associated commitments: update
weaknesses for the UFSAR: and potential operability concerns for ESW
Div. 1 at elevated lake temperatures. The inspection team inciuded
Perry personnel, consultants. and personnel from other plants.
c. Conclusions
The inspection identified a number of issues and was an indication of
effective self-assessment. The effectiveness of the licensee's
!
corrective action plan was not assessed because corrective actions had
not yet been developed for the issues.
IV. Plant Support
P2 Staff Knowledge and Performance in Emergency Preparedness
'
a. Inspection Scone (71750. 92904. 93702)
t
On December 19 the shift supervisor (SS) determined that the plant had
a significant loss of offsite communications capability and classified
the loss as an Unusual Event. The inspectors used Inspection Procedures
71750. 92904, and 93702 to evaluate the licensee's performance.
b. Observations and Findings
l
'
l
At about 1:30 p.m. the inspectors observed that the resident inspector
! office outside telephone lines were dead. Since the NRC operations
center emergency notification system (ENS) phone was part of the same
telephone system, an inspector went to the control room to inform the
SS. The SS. who was attempting to determine the cause of an associated
22
. .
failure of the plant personal paging system. promptly determined that
-
the ENS and other offsite notification phones were dead. The SS. with
the assistance of EP communicators. confirmed that no offsite phones
designated for Emergency Plan (EP) use were available. The onsite
telephone system was functioning nonnally. The SS promptly notified
operations management and EP personnel of the problem and began
reviewing the EP procedure. The inspectors verified that EP support for
the SS was prompt and effective.
<
At 2:00 p.m. the SS declared that the plant was in an Unusual Event and
directed the EP communicators to begin making offsite notifications with
two cellular phones that had been brought to the control room. These
phones had not been prestaged for EP response and there were no plans or
procedures for their use. The inspectors observed the EP communicators
begin the offsite notifications from the plant lunch room because the
cellular phones could not be used in the control room. The
communicators were not familiar with the cellular phones, existing
procedures had been intended for use with specialized notification
phones in the control room or EP facilities, and it was more difficult
to make the notifications with only two phones available. The
communicators, assisted by EP and engineering personnel. promptly
adapted to the unexpected conditions and completed the required
notifications within the time limits. The SS also made a conservative i
decision to activate the technical support center (TSC) and the
operations support center (OSC). Minimum staffing was established for
the emergency operations facility. These facilities were not needed for
the Notification of Unusual Event (NOUE) but were activated because the
SS anticipated that if another plant event occurred it would be
) difficult to activate facilities with only two cellular phones. The t
inspectors had no capability to communicate with offsite NRC facilities
or other government agencies. When the licensee obtained additional
cellular phones, the inspectors borrowed one to contact the Region III
office and verify that EP communications with the NRC were adequate. !
l
The inspectors verified that the TSC and OSC were activated and I
assisting the SS in restoring offsite communications. The licensee l
determined that communications had been lost because a sewage line I
excavation contractor had severed an underground fiber optic cable about ;
1 kilometer from the licensee-controlled area. Engineering personnel '
determined thot the Lcl'mhone company had provided the contractor with
incorrect information on the cable location.
Normally this single event would not have caused a significant loss of
offsite communications capability. However. on September 22. the site's
microwave communications tower had been damaged, eliminating a backup I
telephone link, and repairs to the tower had not been started. The
telephone company dispatched a cable-splicing crew to the site of the l
i
severed cable. At about 6:00 p.m. the inspectors verified that plant
maintenance personnel had provided the telephone company with portable
lighting and heating equi
monitor repair progress. pment and had stationed plant personnel to
23
.
-
At about 11:30 p.m. the inspectors verified that the offsite phone lines
were functioning. At about midnight the inspectors verified that
personnel at the excavation site had developed an appropriate plan to
protect the phone line until the excavation was completed. At
12:40 a.m. on December 20. the TSC concluded that appropriate
communications testing had been completed and terminated the NOUE. At
about 8:30 a.m. the onsite EP coordiriator provided the inspectors with a
copy of the Event Closecut Summary required by Ap]endix 1 of NUREG-0654.
The plant manager later informed the inspectors tlat he would be
retaining some of the company's emergency cellular phones on site for EP
use.
c.
_
Conclusions
,
Overall, emergency response performance was excellent. The shift
supervisor made a timely event classification and offsite agencies were
notified within the required times. All observed personnel demonstrated
teamwork and concise and accurate communications. The prompt decision
to activate the TSC and OSC was a strength. A weakness in anticipating
equipment needs and procedural direction for a significant loss of
offsite communications capability was-overcome by personnel promptly
adapting to the conditions encountered and functioning effectively as a
team. The plant manager recognized the weakness and initiated prompt
actions to correct it. The TSC and OSC were promptly activated and
provided appropriate support to the plant. Facility personnel were
professional and strongly focused on response to the event. The
licensee provided excellent support to the telephone company repair
Crew.
V. Manacement Meetinos
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on December 20. 1996 and
on December 27, 1996. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary
information was identified.
24
.-. . _. . _ . _ __ _- - _ . . _ _ . . ._-_. .
.
! PARTIAL LIST OF PERSONS CONTACTED
i-
licensee
J. C. Stelz. Senior Vice President - -
L. W. Myers. Vice President - Nuclear
R. D. Brandt. General Manager Operations
N. L. Bonner. Engineering Director
l L. W. Worley, Nuclear Services Director
W. W. Kanda, Nuclear Assurance Director
J. Messina, Operations Manager
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INSPECTION PROCEDURES USED
IP 37001: 10 CFR 50.59 Safety Evaluation Program
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving, and
Preventing Problems
IP 61726: Surveillance Observations
IP 62707: Maintenance Observation
IP 71500: Balance of Plant Inspection
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities ~
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IP 92720: Corrective Action
IP 92901: Followup - Operations
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IP 92904: Followup - Plant Support
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
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ITEMS OPENE0. CLOSED, AND DISCUSSED
Onened
50-440/96017-01 URI Inadvertent power change caused by FCV movement
50-440/96017-02 URI EDG and HPCS test passible preconditioning
50-440/96017-03 eel Apparent LCO 3.0.3 violation, breaker inoperable
50-440/96017-04 EEI Apparent LCO 3.0.4 violation, breaker inoperable
50-440-96017-05 eel Apparent LCO 3.8.7 violation, breaker inoperable
50-440/96017-06 EEI Apparent LCO 3.7.3 violation, breaker inoperable
50-440/96017-07 URI Improper use of FCR
50-440/96017-08 NCV TS 5.5.2. RHR check valves not tested
Closed
50-440/96017-08 NCV TS 5.5.2. RHR check valves not tested
Discussed
50-440/96003-16 IFl GE core design errors
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- LIST OF ACRONYMS USED
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APRM AVERAGE POWER RANGE MONITOR
ATWS ANTICIPATED TRANSIENT WITHOUT SCRAM )
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BOP BALANCE OF PLANT . .
CFR CODE OF FEDERAL REGULATIONS '
CRER CONTROL ROOM EMERGENCY RECIRCULATION
CRHVAC CONTROL ROOM HEATING. VENTILATION, AND AIR CONDITIONING
CST CONDENSATE STORAGE TANK i
CT CURRENT TRANSFORMER
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. ECC EMERGENCY CLOSED COOLING
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ECCS EMERGENCY CORE COOLING SYSTEM
EDG EMERGENCY DIESEL GENERATOR
EEI ESCALATED ENFORCEMENT ITEM
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ENS EMERGENCY NOTIFICATION SYSTEM
ESW EMERGENCY SERVICE WATER
, FCR FIELD CLARIFICATION REQUEST
FCV FLOW CONTROL VALVE
i FHB FUEL HANDLIllG BUILDING -
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GEI GENERAL ELECTRICAL INSTRUCTION
GPH !
GALLONS PER HOUR
HPU HYDRAULIC POWER UNIT ,
HVAC HEATING, VENTILATION. AND AIR CONDITIONING
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INSPECTION FOLLOW-UP ITEM
IMI IllSTRUMENT MAINTENAf1CE IllSTRUCTION !
ISI INSERVICE INSPECTION PROGRAM
LCO LIMITING CONDITIONS FOR OPERATIONS
LER LICENSEE EVENT REPORT
LOCA LOSS OF COOLANT ACCIDENT
LPCI LOW PRESSURE COOLANT INJECTI0fl
LPCS LOW PRESSURE CORE SPRAY
LPRM LOCAL POWER RAllGE MONITOR
MAPRAT MAXIMUM AVERAGE PLANAR HEAT GENERATION RATIO :
MCC MOTOR CONTROL CEufER '
MOV MOTOR-0PERATED VALVE '
NOUE NOTIFICATION OF UNUSUAL EVElli
NPF l
fiUCLEAR POWER FACILITY
llRC UUCLEAR REGULATORY COMMISSION
NRR HUCLEAR REACTOR REGULATION
00S OUT OF SERVICE
OSC OPERATIONS SUPPORT CENTER
PCT PEAK CLAD TEMPERATURE
PDR PUBLIC DOCUMENT 900M
PIF POTENTIAL ISSUE FORM
PORC PLANT OPERATIONS REVIEW COMMITTEE
PTI PERIODIC TEST INSTRUCTION
RCIC REACTOR CORE ISOLATION COOLING l
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RF0 REFUELING OUTAGE
RSE RESPONSIBLE SYSTEM ENGINEER
SS SHIFT SUPERVISOR
STA SHIFT TECHNICAL ADVISOR
SVI SURVEILLANCE INSTRUCTION
TS TECHNICAL SPECIFICATION
UFSAR UPDATED FINAL SAFETY ANALYSIS REPORT
URI UNRESOLVED ITEM
US UNIT SUPERVISOR
VAC VOLT ALTERNATING CURRENT
VP - VICE PRESIDEfff
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PARlIAL LIST OF DOCUMENTS REVIEWED DURING THIS INSPECTI0tl
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Audit Report PA 96-21 Plant Operations Review Committee. 12/19/96
Communication Record Sheet, Dated 12/19/96 SUBJECT: NRC Notification
Control room standing orders, various dates
Control room computer printouts, various parameters, various dates
, Control room daily instructions, various dates
Control room daily instructions, supplemental reading, various dates
j Control room safety tag log, various dates
Control room strip charts, various )arameters
i Control room annunciator status boots, revisable format, various dates -
, Control room LC0 log, various dates
i Deficiency tags, various locations. various dates ~
l Design Change Package 91-0210 REV. 1
i Emergency Service Water - Operational Performance Inspection Summary l
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December 16, 1996
i Fire extinguisher inspection tags, various locations, various dates
GEK-63100. Operation and Maintenance Instructions. Hydraulic Control Unit 4/80
l; Limiting Access To Specific Areas (undated)
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Managers' Meeting Report - 11/4. 6, 8, 13 and 15/96 )
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Managers' Communication & Teamwork Meeting Report. 11/18. 20, 22, 25. & 27/96
Managers' Communication & Teamwork Meeting Peport. 12/2. 4. 6. 9, 11. & 13/96
, Managers' Communication & Teamwork Meeting Report. 12/16, 18. & 20/96
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Monthly Access Level Use Review For October. Dated 11/4/96
4 Monthly Access Level Use Review For November. Dated 12/5/96
Monthly ALARA Report 12/02/96
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Monthly Operations Report - November 1996
, ilRC Inspection 96017 Debrief Summary - 12/19/96
- Operator Training
- LOCA ANALYSIS ERROR (J-11: 11/25/96)
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Operational Surveillance Report No.96-057, 11/11/96. Control Rod Drive
Pump
- Operationc1 Surveillance Report No.96-058. 11/05/96
Operations Administrative Control Tags various locations. various dates
Operations Information Tags. various locations, various dates
PAP 0201. Conduct of Operations. Rev. 9. effective 3/28/95 i
Perry Daily Report - Tuesdays and Thursdays. except Nov. 28. 1996
Perry News Flash Results of Enforcement Conference, dated 11/11/96
Perry Plan for Excellence. General Familiarization - Undated.
PIF 96-3186 Issues. 11/20/96
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Plan of the Day - 11/04-08/1996
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Plan of the Day - 11/12-15/1996
Plan of the Day - 11/18-22/1996
Plan of the Day - 11/25-27 & 29/1996
- Plan of the Day - 12/02-06/1996
Plan of the Day - 12/09-13/1996
Plan of the Day - 12/16-20/1996
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Plant Log, Vol. 31. Pages 59 and 60, August 5 and 6. 1996
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Plant Log, Vol. 31, (11/01/96) Page No. 147 - 150 (11/C4/96)
Vol. 32, (11/05/96) Page No. 1- 46 (12/20/96)
Plant strip charts. various parameters, various dates
Potential Issue form No. 96-3337 through 96-3768
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PDS (Perry Operations Section) Performance Indicators - October 1996
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POS Performance Indicators - November 1996
Procedure / Instruction Change. Rev. 7 (PAP-1201). Change No. 2.
TITLE- Control of Measuring and Test Equipment dated 11/14/96
QCS Corrective Action Management Report Week Ending 11/B/96, dated 11D/96. .
Radiation Work Permit 97006
Radiologically Restricted Area Radiation Surveys. Various dates
Safety Tags. various locations. various dates
Simple Modification Request Form. No. 96-6043. Rev. 0 - 11/22/96
SURVEILLANCE AREA / ACTIVITY Review the use of Field Clarification Requests the
process followed by field generated As-Builts. and the timely updating
of department /section controlled procedures and drawings 11/5/96
SURVEILLANCE AREA / ACTIVITY Plant Operation / Remote Shutdown 11/12/96
SURVEILLANCE AREA / ACTIVITY Control Rod Drive Pump 11/11/96
SURVEILLANCE AREA / ACTIVITY E12/P11 System Outage for Check valve replacement
Surveillance Testing of the B21-F0067's. 3/21/96
Temporary Modification Tracking Report. November, dated 11/01/1996
Temporary Modification Tracking Report. December, dated 12/01/1996
Unit Log. Unit 1. Vol. 89.(11/01/96) Page No. 136 - 150 (11/07/96)
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Vol. 90.(11/07/96) Page No. 1 - 106 (12/20/96)
Updated Final Safety Analysis Report
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' Various System Description Manuals
Weekly Effluent and Release Rate Data Report. about November 4, 1996
Weekly Effluent and Release Rate Data Report, about November 11, 1996
Weekly Effluent and Release Rate Data Report, about November 18, 1996
Weekly Effluent and Release Rate Data Report. about November 25. 1996
Weekly Effluent and Release Rate Data Report, about December 12. 1996
Weekly Effluent and Release Rate Data Report about December 16, 1996
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