ML20126B522
| ML20126B522 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 12/10/1992 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20126B491 | List: |
| References | |
| 50-440-92-22, NUDOCS 9212220118 | |
| Download: ML20126B522 (18) | |
See also: IR 05000440/1992022
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V. S. NUCLEAR REGULATORY COMMISSION
REGION 111
Report No. 50-440/92(22(DRP)
Docket No. 50-440 License No. NPT-58
Licensee: Cleveland Electric illuminating Company
Post Office Box 5000
Cleveland, Oil 44101
facility Name: Perry Nuclear Power Plant
inspection At: Perry Site, Perry, Ohio
inspection Conducted: October 20 through November 20, 1992
Inspectors: A. Vogel
P. Hiland
E. Duncan
Approver' By: b Im _ tt\ 60 st
R. D. LanksbupyTChief Date
Reactor Projects-Section 3B
JJupection Summary
Jnspection on October 20 throuah November 20. 1932 (Report No.
50-440/92022(DRfil
Arras inspecteA: Routine unannounced safety inspection by resident inspectors
of licensee event report- followup, surveillance observations, maintenance
observations, operational safety verification, event followup, cold weather
preparations, and evaluation of licensee self-assessment capabilities.
Results Of the seven areas inspected, one violation was identified
concerning a failure to enter the Technical Specification (TS) 3.0.3 action.
statement when the limiting condition for operation could not be met following
identification of excessive secondary containment bypass leakage (paragraph
6.b.3). In addition, one non-cited violation (NCV) was identified in the area
of licensee event report followup (paragraph 2.b).
The following is a summary of the licensee's performance during this
inspection period:
Plant Operations
The reactor plant was operated at or near full power until October 23
when a reactor shutdown was commenced to repair a crack in the
condensate header. On October 24, during the shutdown, the reactor was
tripped from 22 percent power due to an inability to. complete a
, surveillance of the rod pattern controller. The plant was restarted on
l October 30 and remained at or near full power for the duration of the '
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report period. Operator control of the plant shutdown and startup was
good, with the exception of a missed average power range monitor gain
adjustment surveillance on November 1.
Maintenance / Surveillance
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The quality of observed maintenance and surveillance activities was I
good. During a tour of the drywell, the inspector identified tools and I
other debris left behind from previous work activities. . An apparent !
lack of management supervision to ensure work area cleanliness during '
and after maintenance activities was a significant contributing cause
for the deficiencies.
[naineerino and Technical S.unnqti
The engineering evaluation which supported continued plant operations
with the condensate pipe crack was assessed as weak by the NRC staff.
Subsequent discussions with the NRC resulted in the licensee shutting ,
the plant down to repair the crack. -
Safety Assessment and Ouality Verification
The quality of reviewed event reports was acceptable. The on-site
review committee was evaluated as effective. On November 5, an apparent .
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weakness in the licensee's understanding of the basis for Technical
Specification requirements contributed to the licensee's failure to take
action in accordance with TS 3.0.3.
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. DETAILS
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1. Persons ContAcied
a. Cleveland Electric 111uminatina Company
R. Stratman, Vice President - Nuclear, Perry Nuclear Power
Plant (PNPP) !
- K. Donovan, Manager, licensing and Compliance l
- M. Gmyrek, Operations Manager, PNPP !
- S. Kensicki, Director, Perry Nuclear Engineering i
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Department (PNED)
- F. Stead, Director, Perry Nuclear Support Department
(PNSD)
- H. Hegrat, Compliance Engineer, PNSD
- E. Riley, Director, Perry Nuclear Assurance Department
(PNAD)
- W. Coleman, Manager, Quality Assurance Section, PNAD
- V. Concel, Manager, Technical Section, PNED
- D. Conran, Compliance Engineer, PNSD
M. Cohen, Manager, Maintenance Section, PNPP 4
P. Volza, Manager, Radiation Protection Section
- G. Cad, Supervisor, Maintenance Section, PNPP
D. Cobb, Superintendent, Plant Operations, PNPP
- W. Wright, Manager, Instrumentation and Controls Section, PNPP
b. U. S. Nuclear Reaulatory Commission
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- R. Lanksbury, Chief, Reactor Projects Section 3B,-RIII
P. Hiland, Senior Resident inspector, RIII
- A. Vegel, Resident inspector, Rill
- E. Duncan, Reactor Engineer, Rill
- Denotes those attending the exit meeting held on November 20,
1992. ,
2. Licensee Event _ Report (LER) Followun (90712. 92700)
Through review of records, the following event reports were reviewed-to
determine if reportability requirements were fulfilled, immediate
corrective actions were accomplished in accordance with Technical
Specifications (TS) and corrective action to prevent recurrence had.been
established:
a. fClosed) LER 50-440/92004-00: On March 21, 1992, during a planned .
manual shutdown of the plant, a reactor water cleanup (RWCU) '
system containment _ isolation occurred as a result of high system
differential flow. Immediate corrective action was taken to
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verify that no actual system leakage had occurred. The RWCU ,
system was' secured and subsequently returned to service.
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Licensee Investiaation of Root Cause and Corrective Actions
Root Cause
The licensee determined the root cause for this event was a design
deficiency associated with the unexpected formation of steam voids
in the RWCU regenerative heat exchangers (RHXs) while opcrating-in
the reduced feedwater temperature mode of operation. As the RWCU
system cool down progressed, the voids collapsed and return flow
refilled the RHXs instead of returning to the reactor pressure
vessel (RPV) v;a the feedwater injection line. A high
differential flow was sensed by the leak detection ' system and
resulted in a RWCU containment isolation.
Corrective Action
Pursuant to corrective actions for previous similar events, the
licensee submitted to the NRC on October 30, 1991,- a Technical
Specification Change Request, " Reactor Water Cleanup System
Isolation Actuation Instrumentation." The request included
changes to various instrument setpoints to alleviate spurious
system isolations. In addition, modifications were made to the
computer monitoring program to alert the operators that conditions
for steam voiding may exist in the system. All licensed operators
were trained on the lessons learned with regard to this event. At
the time of this report the proposed Technical Specification
change was still under review by the NRC.
Inspectors Review
The_ _ initial investigation of this event was documented in
Inspection Report 50-440/92003, paragraph 6.b.(5), dated April 27,
1992. A review of licensee efforts in response to similar RWCU.
isolation events was also documented in the above report in
paragraph 3.a. During this inspection period, the inspectors
reviewed applicable licensee documentation and noted that all
corrective action commitments specific to this event were ,
completed. This item is closed,
b. (Cl_ossd) LER 50-440/92011-00: Failure to perform surveillance
results in two inoperable intermediate range monitor (IRM)
channels and violation of TS 3.3.1.a. On May 3, 1992,'while in .
Operational Condition 5, REFUELING, two IRM channels-became
inoperable for approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> due to failure to complete
the surveillance requirements. In addition, the-TS 3.3.1.a action
requirement to insert a half scram on the reactor protection
system (RPS) for. the inoperable IRMs was not performed within the
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> TS time limit.
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Licensee Investiaat. ion of Root Cause and Corrective Actions
Root Cause
The licensee determined the root cause of this event was personnel
error, failure to follow procedure. When reviewing the
surveillance schedule on May 2, 1992, the Unit Supervisor (US)
failed to refer to surveillance instruction SVI-C51-T0022C "lRM C
and G Neutron Flux Trips channel functional Test for IC51-K601C
and IC51-K60lG" to determine TS requirements pricr to deferring
the surveillance. This review was required by Plant
Administrative Procedure (PAP-1105), " Surveillance Test Control."
Corrective Action
Corrective actions included counselling the US with respect to the
requirement for procedural compliance. Additionally, as part of
the established requalification training program, all plant
licensed operators were instructed on the lessons learned from
this event.
Inspecton Review
The inspectors reviewed the applicable licensee documentation and
noted that all corrective action commitments were completed. The
inspectors concluded that the licensee's corrective actions
appeared reasonable and adequate to prevent recurrence. Failure.
of the licensee ~ to insert a half scram on RPS Channel C within
I hour of the IRMs being rendered inoperable was a violation of TS-
action statement 3.3.1.a. This violation was not cited because
the licensee's efforts in identifying and correcting the violation
met the criteria specified in Section VII.B of_ the " General
Statement of Policy and Procedure for NRC Enforcement Actions,"
(Enforcement Policy, 10 CFR Part 2, Appendix C (1992)). This-item
is closed,
No violations or deviations were identified; however, one non-cited
violation was identified. ,
3. Monthly Surveillance Observation (61726)
for the surveillance activities listed below, the inspectors verified
one or more of the following: testing was performed in accordance with
procedures; test instrumentation was calibrated; limiting-conditions for-
operation were met; removal _ and restoration of-the affected components
were properly accomplished;: test results conformed with technical
specifications, procedure requirements, and were reviewed by personnel
other than the individual directing the test; and any deficiencies
identified during the testing were properly reviewed _and resolved by
appropriate management personnel.
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hirveillance Activity Title
SVI-E32-T0398A Main Steam Isolation Valve (MSIV) Leakage
Control System - Outboard Steam Line
Header Pressure Functional for IE32-N655.
SVI-E22-Til83 High Pressure Core Spray Valve Lineup
Verification and System Venting.
SVI-C71-T0039 MSIV Reactor Protection System Channel !
Check. l
No violations or deviations were identified.
4. Monthly Maintenance 0bservation (62703)
Maintenance activities of safety-related systems and components listed ,
below were observed and/or reviewed to ascertain-that activities were
conducted in accordance with approved procedures, regulatory guides and
industry codes or standards, and in conformance with Technical
Specifications.
The following items were considered during this review: the limiting
conditions for operation were met while components or systems were
removed from service, approvals were obtained prior to initiating the :
work, activities were accomplished using-approved procedures and were
inspected as applicable, functional testing and/or calibrations were
performed prior to returning components or systems to service, quality
control records were maintained, activities were accomplished by
qualified personnel, parts and materials used were properly certified,
radiological controls were implemented, and fire prevention contr_ols
were implemented.
Work requests were reviewed to determine the status of outstanding jobs
and to assure that priority was assigned to safety-related equipment
maintenance which may affect system performance.
Specific Maintenance Activities Observed: i
Hork Order / Repetitive Task No. _Jitle
WO-91-3399 Valve IN25F05368 - Body to Bonnet Gasket
Replacement.
WO-92-4178 Replace Motor on Reactor Water Cleanup!
Valve IG33F0004.
WO-92-4023 Replace Motor Pinion Gear Set on Reactor
Core isolation Cooling for Valve
IE51F0064.
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WO-92-3115 Install Strainer Basket on Service Water
Pump A.
WO-92-3116 Install Strainer Basket on Service Water
Pump B.
No violations or deviations were identified.
5. Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable
logs, and conducted discussions with control room operators during this
inspection period. The inspectors verified the operability of selected
emergency systems, reviewed tagout records, and verified tracking of
limiting conditions for operation associated with affected components.
Tours of the pump houses, control complex, the intermediate, auxiliary,
reactor, radwarte, and turbine buildings were conducted to observe plant
equipment conditions including potential fire hazards, fluid leaks, and
excessive vibrations, and to verify that maintenance requests had been-
initiated for certain pieces of equipment in need of maintenance. The
inspectors by observation and direct interview verified that the
physical security plan was being implemented in accordance with the
station security plan. ,
The inspectors observed plant housekeeping, general plant cleanliness
conditions, and verified implementation of radiation protection
controls, in addition, the inspectors observed construction of the low- 4
level radioactive waste building and the emplacement of a new breakwall
on site property,
a. Condensate Pipe Crack
On October 19, 1992, the licensee identified a steam-leak in the
vicinity of the direct contact heater. Subsequent investigation
of the leak on October 22, which included removal of insulation,
uncovered a crack approximately 9 inches (22.8 cm) in length. The
crack was located near a welded connection between the 30-inch
(76.2 cm) main condensate header and one of three.18-inch (45.7
cm) lines which fed the direct contact heater. The licensee set
up a camera to monitor the crack and initiated plans to
temporarily repair the leak with a clamping device. On
October 23, following discussions with NRC management concerning
the possibility of crack propagation, the licensee _ commenced a
plant shutdown to repair the crack. While shut down, the licensee
weld repaired the crack and restored the condensate system back to-
operation on October _ 27, 1992. The licensee's root cause
determination was in progress at the end of the inspection period.
The inspectors reviewed documentation, observed repair efforts,
and discussed with licensee management the significance.of the
crack. Though the licensee did shut down the plant to repair the
leak, the inspectors were concerned with the licensee's initial
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plans to only monitor the leak while temporary repairs were being
formulated. The inspectors concerns were based on the uncertain
cause for the leak and the potential personnel hazard that the
leak presented in case a rupture occurred abruptly while repairs
were in progress, in addition, NRC regional and headquarters
management questioned the licensee's engineering evaluations
supporting continued operation until temporary repairs could be
affected. Specifically, the licensee's engineering staff appeared
to have only accounted for stresses imposed on the crack by normal
system pressure, not taking into account other potential stresses
including manufacturing and/or vibration induced stresses. Though
the licensee did eventually take the conservative action of
shutting down, the inspectors were concerned with the licensee's
apparently inadequate engineering evaluation which supported
continued operation with the crack. The adequacy of licensee
engineering evaluations will be further reviewed in future
inspections of licensee engineering and technical support
activities,
b. Plant Housekeepina and Eauipment Condition
During the forced outage to repair the condensate pipe crack, the
inspectors conducted walkdowns of areas normally not inspected
during power operations. The inspectors toured the drywell, the
main steam line tunnel, and other areas in the turbine building
and heater bay. As a result, several discrepancies were noted
concerning plant housekeeping and equipment condition,
in the drywell, the inspector identified tools, bolts, scaffolding
material, and other debris left over from previous maintenance and
surveillance activities. The licensee subsequently removed the
material from the drywell. The inspector discussed with licensee
management what controls were in place to ensure that work areas
were maintained clean and that tools were accounted for. Though
licensee procedures do provide guidance on post work cleanup and
tool accountability, the licensee concluded that an apparent lack
of supervisory oversight to ensure that the guidance was being
followed was the cause for the discrepancies. Licensee action to
improva supervisory performance in this area was being evaluated
in a programmatic review of supervisor responsibilities. The
adequacy of the licensee's corrective actions to improve post
maintenance cleanup will be evaluated in future inspections of
plant maintenance activities and during routine observation of
plant housekeeping.
While conducting an inspection of the lower elevations of the
turbine building, the inspector observed a U-bolt pipe hanger
support on the floor. Upon further investigation, the inspector
determined that the U-bolt apparently was from a pipe support for
the 12-inch (30.5 cm) circulating water box drain tank pump
discharge header. Subsequently, upon being notified of the
discrepancy by the inspector, the licensee conducted a walkdown of
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the system. As a result, the licensee discovered an additional U-
bolt missing, weld cracks on several pipe supports, and several
loose nuts on Hilti anchor bolts. A nonconformance report (NR-92-
N-298) was initiated to evaluate and document the deficiencies and
corrective action was initiated to repair the affected supports.
The licensee determined the root cause for the failure was a
possible system transient due to previous problems with the
waterbox drain pump and discharge check valve. The inspector '
questioned the licensee on why a system walkdown was not performed
by the system engineer during the shutdown, since problems with
the system were experienced earlier in the operating cycle. As a
result of discussions with licensee management, the inspector
concluded that due to the workload on the engineering staff during
the outage, particularly in support of repairs to the condensate
pipe, a system engineer walkdown of the circulating water system
was not performed in the turbine building. The licensee
determined that improved management of the system engineer
workload was required to ensure that system walkdowns were
performed. The inspectors will continue to evaluate licensee
performance in this area during routine evaluation of the
condition of plant equipment,
c. Plant Shutdown and Startuo Observations
On October 24, 1992, during the plant shutdown to repair the crack
in the condensate header, the operators manually tripped the
reactor from 22 percent reactor power. The reactor trip was
necessitated by the inability to perform steps 5.1.3.5 or 5.1.4.5
of Technical Specification required surveillance SVI-Cll-T1019,
" Rod Pattern Controller System Test Below Low Power Setpoint."
The steps required that an insequence rod not at an insert or
withdrawal limit be selected to verify that block and inhibit
indications reset. At the time this surveillance was performed,
all insequence rods were at the insert or withdrawal limits.
Therefore, the operators could not complete the steps in the
surveillance procedure. The operators subsequently tripped.the
reactor in accordance with plant operating procedures and
proceeded to place the plant in a cold shutdown condition. To
prevent recurrence, the licensee revised surveillance procedure
SVI-Cll-T1019 to allow for rods at the withdrawal limit to be
tested to verify operability of the rod pattern controller._ The
procedure was revised on October 28, 1992, prior to the plant
restart.
During the plant shutdown, repairs were conducted on the
condensate header crack and maintenance was performed to repair
various other minor steam leaks in the plant. In addition, the
outboard reactor water cleanup and reactor core isolation cooling
containment isolation valves were modified to correct deficiencies
previously identified in inspection report 50-440/91018(DRS) dated
November 5, 1992.
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On October 30, 1992, upon completion of maintenance and repair
activities, reactor startup was commenced. During the ascension !
to full power, a problem was identified with feedwater flow
indications, and a Technical Specification required surveillance i
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was not performed when required. These problems are discussed
separately in paragraphs 5 d and 5.e of this report.
During the plant shutdown and startup, the inspectors observed
control room activities, in general, both evolutions were
performed in a controlled and deliberate manner. With the
exception of the missed surveillance, discussed in paragraph 5.e,
the operators performed their tasks in accordance with plant
instructions. Overall, the inspectors concluded that the
operators remained attentive to changing plant conditions and i
maintained positive control of the evolutions in progress.
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d. Feedwater Flow Anomalies at low Power
On November 1,1992, during plant startup, difficulties with
feedwater flow instrumentation were experienced which prevented
operators from obtaining an accurate heat balance. Specifically,
feedwater flow, as determined by the differential pressure across
the feedwater venturis was indicating lower than expected at low
power based upon independent indications such as steam flow,
reactor feed pump turbine (RFPT) suction flows, and megawatts
(electric).
The licensee verified that pressure transmitters and associated
instrumentation were within calibration limits and reviewed
historical data for trending analysis. As a result, the licensee
determined that during each startup a_ higher _ reactor power level
hed been required before reactor power based on feed flow (from
the venturis) would agree with reactor- power based on other
indications. In Cycle 1 it was possible to obtain a core heat
balance at 15 percent thermal power. During Cycle 2, power had to
be increased to 20 percent to obtain a balance; during Cycle 3, _to
25 percent; and now in Cycle 4, to greatcr than 25 percent.
During the November 1,1992, startup, power was at 52 percent when
agreement between power indications was obtained. _ At the end of
the inspection period, the licensee was investigating this
phenomenon. Though the cause for the indication problems'at low -
power had not been determined, the licensee evaluated'that at
higher reactor _ power the: flow venturis.were ;pparently providing
accurate indication of_ feed flow. Due to tne unknown cause for
the indicated flow disparity,'the licens* conservatively decided
to limit reactor power to 99 percent until a better understanding
of the phenomenon could be made. The power limit of 99 percent is
based upon an_ apparent 0.5 psid error in differential pressure
across the venturi extrapolated to e .1 M1bm/hr error at 100
percent reactor power. The iresp w ors will continue to monitor
licensee efforts to deter 6 e the root cause for the feed flow '
venturi indication probi m
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c. Missed Averaae Power Ranae Monitor Gain Ad.iustment Surveillance
On November 1, 1992 the licensee identified that the average power
range monitor (APRM) gain adjustment surveillance had not been
performed as required by TS. Specifically, TS table 4.3.1.1-1
footnote (d) required that APRM channels be calibrated to conform
to the power values calculated through a heat balance during
Operational Condition I when thermal power is greater than or
equal to 25 percent of rated thermal power. Additionally, for the
provisions of TS 4.0.4 not to be applicable, the surveillance was
to be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of reaching 25 percent power.
Technical Specification 4.0.4 prevents entry into an operational
condition unless the surveillance requirements associated with the
limiting condition for operation (LCO) have been performed within a
the applicable surveillance interval. During the startup, with--
the plant in Operational Condition 1 at 24.4 percent power, the
licensee completed surveillance SVI-C51-T0024 "APRM Gain and
Channel Calibration" on October 31, at 8:12 p.m. (EST), using
feedwater pump inlet feedwater flow data. Subsequently, power was
raised to greater than 25 percent at approximately 1:00 a.m. on
November 1. At 2:48 a.m. preparations were commenced to reperform
the surveillance, but difficulties were encountered with the
indicated flow received from the feedwater venturis. Plant
procedures required that feedwater flow for- the heat balance be
obtained from the venturis when greater than 25 percent reactor
power. Consequently SVI-C51-T0024 could not be performed as
written. The feedwater flow venturi problem is discussed in
paragraph 5.d of this inspection report. At 3:45 p.m. the
oncoming unit supervisor noted that the surveillance had not been
performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of reaching 25 percent power. Following
power increase to 52 percent, SVI-C51-T0024 was completed
satisfactorilly at 10:30 p.m.
The licensee initiated condition report CR-92-255 to document
event investigation and track subsequent corrective action. In
addition, an LER was to be submitted. The inspectors will review- _
the results of _the licensee's investigation and evaluate the
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adequacy of corrective action in -a future inspection report. *
f. Incoerable Containment Pressure Channel Due to Improper Valve
Lineun
On November 8,1992, while in Operational Condition 1, _ POWER . _
OPERATIONS, plant operators noticed a discrepancy between the-two-
wide range containment pressure channels displayed on the
Emergency Response Information System (ERIS). Containment
pressure instrument 023-N270A read -0.3 psig, while the other
k channel's instrument,-D23-N2708, read +0.3 psig. The licensee
l commenced an investigation. On November 10, 1992, Instrumentation
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and Control (I&C) personnel discovered that containment pressure
i instrument 023-N270A was in an improper valve lineup, rendering
the instrument inoperable. The licensee initiated condition
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report CR-92-261 to document event investigation and track ,
subsequent corrective action. In addition, an LER was to be
submitted at a later date.
The inspectors will review the results of the licensee's
investigation and evaluate the adequacy of corrective action in a
future inspection report,
g. Feedwater Control Problemi
On November 11,1992, at 7:45 p.m., with the plant operating _ at 99
percent power, a perturbation in the feedwater control system
resulted in a reactor water level and power transient. Reactor
water level increased to above the level 7 high level alarm
setpoint then decreased to below the level 4 low level alarm
setpoint before settling out in the normal operating band.
Reactor power oscillated for approximately 1 minute then returned
to normal. The peak reactor thermal power during the transient
was 100.9 percent. Initial troubleshooting determined there was a
problem in the "B" reactor feed pump turbine (RFPT) control
system, and the controller was placed in manual. On November 12,
at 6:35 a.m., with the "B" RFPT in manual, a similar transient
occurred. Again reactor water level 7 and level 4 alarms were
received and power oscillations peaked at 100.9 percent.
Subsequent troubleshooting isolated the cause of the feedwater
controller problem to a circuit board in the feed flow logic
circuitry. Specifically, the indicated feed flow from the "B"
RFPT circuit card apparently spuriously spiked causing RFPT. "A" to
respond to the false feed flow signal. As a result, the "A" RFPT
would initially respond to the false feed flow variance then react
to correct the subsequent reactor level changes. The licensee
replaced the suspected circuit cards and returned the RFPT to the
master level controller on November 13. Following repairs, the
feedwater co'itrol system operated normally without fur.her
problems . The licensee was investigating the root cause of the
circuit card problems.
h. Inadeouate Retest of Lower Containment Airlock Door
On October 21, the lower containment airlock was declared
inoperable for maintenance to investigate seal inflation light
indication problems for the inner door. A faulty. pressure switch
was identified as the cause for the indication problem. The
pressure switch was replaced and leak-checked. A_ retest, which
required cycling of the airlock inner door three times while
verifying proper operation of the door, lights, and pressure
switch was performed. On October 23, at 3:15_a.m. the lower
containment airlock was declared operable.
On October 23, at 10:00 a.m., the licensee determined that the
retest performed earlier was inadequate because the pressure
integrity of the lower containment inner airlock door seal
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pneumatic system was broken by the maintenance performed. As a
result, TS surveillance requirement 4.6.1.3.e (conducting a seal
pneumatic system leak test) was not met. Consequently, the
airlock was again_ declared inoperable. On October 24, at
6:32 a.m., the airlock was declared operable following
satisfactory performance of surveillance SVI-PS3-T7305, " Lower
Containment Airlock Pneumatic System Leak Test, Pen #305."
On November 12, the licensee identified a discrepancy between the -
piping system diagram, the electrical elementary diagram, and the
pressure switch as installed in the field for the lower
containment airlock. Further investigation determined that the-
retest on October 24 was done on the wrong pneumatic system,
rendering the retest invalid. As a result, the lower containment
inner airlock door was declared inoperable at 1:30 p.m. _ On
November 13, at 6:43 a.m., the test of the seal pneumatic system
associated with the pressure switch was completed satisfactorily
and the lower cont 61nment airlock was declared operable.
The licensee initiated an investigation of this event and-
documented their findings and corrective actions in LER 92-20
dated November 20, 1992. The inspectors will review the results
of the licensee's evaluation and evaluate the adequacy of
corrective action during review of LER 92-20 in a future
inspection report.
No violations or deviations were identified.
6. Onsite followun of Events at Operatina Power Reactors (93702)
a. General
The inspectors performed onsite followup activities for events
which occurred during the inspection period. Followup inspection
included one or more of the following: reviews of operating logs, '
procedures, and condition reports; direct observation of licensee
actions; and interviews of licensee personnel. For each event,.
the inspectors reviewed one or more of the following: the
sequence of actions; the functioning of safety systems required by
plant conditions; licensee actions to verify consistency with
plant procedures and license conditions; and verification of the
nature of the event. Additionally. -in some cases, the inspectors
verified that the' licensee's investigation identified root causes
of_ equipment malfunctions and/or personnel errors and the licensee-
was taking or had taken appropriate corrective actions. Details
of the events and licensee corrective actions noted during the
inspector's followup are provided below.
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b. Details
(1) B_eactor Protection System Actuation
On Octobar 24, 1992, at 12:56 a.m., during the plant
shutdown to repair the condensate header crack, following a
manual reactor trip from 22 percent reactor power, a reactor
protection system (RPS) actuation occurred on low reactor
water level. A full scram signal was generated by the RPS
when reactor water level decreased below the level 3
setpoint. This event followed a planned manual scram
performed in accordance with plant operating procedures.
All of the control rods were already inserted and no rod
movement occurred due to the second RPS actuation. The
licensee informed the NRC Operations Center of this event
via the Emergency Notification System (ENS) at about 3:30
a.m. on October 24, 1992.
The licensee conducted a review of this event and determined
that the level 3 RPS actuation was an expected plant
response. Due to the reactor water level shrink and swell
characteristic of a boiling water reactor (BWR), the level
decrease was expected and was accounted for by procedural
steps to raise water level to the top of the operating band
before the scram was initiated. Additionally, operations
personnel anticipated the level transient by reviewing
appropriate instructions before the manual reactor trip was
initiated. The licensee concluded that the water level
decrease below the level 3 setpoint was part of a preplanned
sequence during reactor operation and need not be reported.
On November 13, the licensee informed the NRC Operations
Center and retracted the October 24 notification.
The inspectors reviewed licensee procedures, interviewed
plant operators, and reviewed data from previous reactor
trips. The inspectors concluded that the operators were
cognizant of the expected plant transient and that the plant
response was similar to previous reactor trips from
approximately the same power level.
(2) Loral Leak Rate Testina of Nuclear Closed Caplina
Containment Isolation Valve
On October 27, 1992, at 11:00 p.m., the licensee determined
that containment secondary bypass leakage exceeded Technical
Specification 3.6.1.2.d limits following local leak rate
testing (LLRT) of nuclear closed cooling (NCC) containment
isolation valve IP43F140. The licensee informed the NRC
Operation: Center of this event via the ENS at about
2:00 a.m. on October 28, 1992.
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1' During performance of "NCC Containment Isolation Valve
Operability Test" surveillance on October 27, outboard-
containment isolation valve IP43F140 gave dual indication
when in the closed position. Following maintenance, in
which the valve position limit switches were adjusted to
correct the indication problem, a LLRT was performed. The
LLRT was required because IP43F140 was a butterfly valve
whose leakage characteristics could be affected by limit
switch adjustments. Excessive leakage was noted and the ENS-
notification was made. At the time of the notification . it
was not known if the maintenance caused the leakage or if
the valve had been leaking during operation.
The licensee conducted an investigation and determined that
the failure of the post maintenance test did not provide = w
evidence that the valve was leaking during the modes of
operation for which the Technical Specification was
applicable. Technical Specifiation 3.6.1.2.d applied in
Operational Conditions 1,-2, and 3. At the time of the post
maintenance test, the plant was in Operational Condition 4,
where the leakage requirements were not applicable. The
licensee determined that the cause for the excessive leakage
was the maintenance activity performed on the limit switches
and that there was no firm evidence to indicate that the
valve was leaking during the modes- of operation for which
the Technical Specifications were applicable. Based on the
above, on November 13 the licensee informed the NRC
Operations Center and retracted the October 27 notification.
(3) Secondary Containment Bvoass leakaoe in Excess of Linita
On November 5,1992, while in Operational Condition 1, POWER
OPERATIONS, at 99 percent reactor power,-the licensee
diacovered that based upon the results of local-leak rate
testing (LLRT) of a 42-inch (106.68 cm) coitainment purge -
supply line penetration, the secondary containment bypass
leakage rate exceeded TS limits. Upon recognizing that
contalnment bypass leakage limits were exceeded, the
licensee failed to take appropriate-action as specified in
On November 5, at 4:15 p.m., upon reviewing the deta
obtained during performance of SVI-M14-T9313, " Type C Local.
t eak Rate Test of IM14 Penetraticn V313," a leakage rate of
3130-standard cubic c u timeters per minute (sccm) was
calculated for the penetr. tion. Specific to this
penetration, TS 4.6.1.8.4 allowed leakage up to_.05 L,
(5011.6 sccm). Therefore tie penetration' leakage was within
limits. However, when the leakage from the penetration
(3130 sccm) was combined w'.th the previously recorded
secondary containment byp.ss-leakage, the total,
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6598.34 sccm, was greater than the total secondary
containment bypass leakage limit of .0504 L, (5051.74 sccm)
allowed by TS 3.6.1.2.d. The subsequent action statements
applicable in Operational Conditions 1, 2, and 3 required,
in part, that secondary contai nent bypass leakage paths be
restored to less than or equal to .0504 L, prior to
increasing reactor coolant temperature above 200 F. Since
the plant was in Operational Condition- 1 at 99 percent
reactor power, the licensee's staff questioned the-
applicability of the TS in their current plant condition.
Though the licensee did recognize that they might-be in a
condition outside of the TS LCO, and therefcre TS.3.0.3
would be applicable, no action was taken in- accordance with
the TS 3.0.3 requirement. At approximately 7:00 p.m. the
licensee contacted a member of the NRC staff to discuss the
situation. At that time it was not apparent that the TS 3.0.3 requirements were applicable. On November 6, 1992, at
approximately 6:00 a.m., the containment purge supply
penetration was declared operable following valve repair and
satisfactory retest. Af ter a review of TS requirements by
the NRC staff and discussions between the staff and the-
licensee on November 6 it became apparent that the licensee-
did not take appropriate action in accordance with TS 3.0.3.
On November 6, at 6:30 p.m., the licensee notified the'NRC-
Operations Center via ENS that required actions in
accordance with-TS 3.0.3 were not taken on November 5
following discovery of excess secondary containment bypass
leakage.
Technical Specification 3.0.3 required that when a limiting
condition for operation (LCO) is not met, except as provided
in the associated action. requirements, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action
shall be initiated to place the unit in an operational
condition in which the specification does not apply.
Contrary to the above, on November 5, 1992, upon not meeting
the LC0 action requirements of TS 3.6.1.2, 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 />, in accordance with
TS 3.0.3, to place the plant in Operational Condition-4,
COLD SHUTDOWN, where TS 3.6.1.2 would not be applicable.
This is a violation (440/92022-01(DRP)).
One violation and no deviations were-identified.
7. Evaluation of Licensee Self-Assessment'Capabilitv(40500)
a. On-Site Review Committee-
c During the report period, the inspectors observed on-site review
committee meetings to evaluate that organization's effectiveness-.
For the meeting attended, the inspectors considered the following.
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attributes: 'the degree of-plant management involvement and/or
domination of discussions;'if constructive discussion occurred; if. .
the-majority of the committee consistently voted the same as the
chairperson; if_the committee was biased toward operation or
safety; and,'if the committee used design basis, the Updated
Safety Analysis Report (USAR), or vendor' technical manuals for
their determinations in addition to the.. Technical Specifications.
In preparation for the meeting, the inspectors reviewed the draft
submittals given to the on-site review committee for approval.
Itemt presented to the on-site review committee included safety
evaluations, temporary changes to procedures, setpoint change
requests, procedural revisions, and design change packages.
During this report period, the following on-site review committee
meeting was observed by the inspectors:
Meetina No, Date
92-128 11/19/92
For the meeting observed, the inspectors cencluded that the
function of the on-site review committee was effectively
implemented.
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No violations or deviations were identified.
8. Cold Weather Preparations (71714)
The inspectors reviewed the licensee's implementation of the -freeze
protection program. This included a review of freeze protection off-
normal instruction ONI-R36 and various system operating instructions,
including those for emergency service water, condensate storage and
transfer, and heat tracing. A walkdown of heat trace control panels-and
other freeze protection systems to verify proper operation was
performed. Also, the-inspectors discussed implementation-of the freeze
protection program with operations and engineering personnel to essess
their familiarity with cold weather preparations.
Off-nornal instruction ONI-R36 and-pertinent system operating
instructions: appeared to provide adequate freeze protection when
l- implemented. The portions of the freeze protection-systems walked down
l by the inspectors were observed to be operating properly, and plant
i personnel questioned were familiar with ONI-R36 and its contents. The-
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inspectors noted that although heat tracing had not been reinstalled ,
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following the circulating water system pipe. rupture event'on December
- 22, 1991,- contingency plans'to prevent this-piping from freezing in the
i event of a system shutdown appeared adequate. _ The inspectors also noted
i that specific procedures to-address freeze protection in the event of-a
failure of the freeze protection system did not exist. However,
discussions with operations and engineering personnel indicated that-
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9- contingency plans had been considered and appeared reasonable. Based
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upon the above observations, the inspectors-concluded that the
licensee's freeze protection program had been adequately implemented.
No violations or deviations were identified.
9. Manaaement Chanaes
The licensee announced that Mr. Mike Lyster, Vice President - Nuclear,
the senior licensee manager on site, resigned his position effective
December 17, 1992. Mr. Lyster will become the site vice president at
the Dresden Nuclear Power Station. At the end of this inspection period
the licensee had not announced his successor.
10. Items for Which a " Notice of Violation" Will Not Be issued _
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During this inspection, certain activities, as described above in
paragraph 2.b, appeared to be in violation'of NRC requirements.
However, the licensee identified this violation and it will not be cited
because the criteria specifieo in Section VII.B. of the " General
Statement of Policy and Procedure for NRC Enforcement Actions," :
(Enforcement Policy, 10 CFR Part 2, Appendix C, (1992)), were satisfied,
11. Exit Interviews
The inspectors met with the licensee representatives denoted in i
paragraph 1 throughout the inspection period and on November 20, 1992. '
The inspectors summarized the scope and results of the inspection and
discussed the likely content of the inspection report. The licensee did
not indicate that any of the information disclosed during the inspection
could be considered proprietary in nature.
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During the report period, the inspectors attended the following exit
interviews:
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Inspector Exit Date
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J. R. Kniceley (Security) 11/20/92
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