ML16154A641
| ML16154A641 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 07/25/1994 |
| From: | Carroll R, Harmon P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A640 | List: |
| References | |
| 50-269-94-19, 50-270-94-19, 50-287-94-19, NUDOCS 9408090156 | |
| Download: ML16154A641 (13) | |
See also: IR 05000269/1994019
Text
REo
IUNITED
STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/94-19, 50-270/94-19 and 50-287/94-19
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242-0001
Docket Nos.: 50-269, 50-270, and 50-287
License Nos.: DPR-38, DPR-47, and DPR-55
Facility Name: Oconee Units 1, 2, and 3
Inspection Conducted: June 5 - July 2, 1994
Inspectors:
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P. E. Harmon, Seniof Resfdent Inspector
Date Signed
W. K. Poertner, Resident Inspector
L. A. Keller, Resident Inspector
P. G. Humphrey, Resident Inspector
Approved by:
_
_
_
_
_
_
_
_
_
_
_
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R. E. Carroll, Acting Chief
Date Signed
Reactor Projects Section 3A
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, maintenance and surveillance testing, onsite
engineering, plant support, and inspection of open items.
Results:
Two Deviations were identified. The first deviation involved a
failure to properly classify portions of the low pressure
injection system suction piping as Class II (paragraph 4).
The
second deviation involved a failure to meet Final Safety Analysis
Report programmatic requirements for system class boundary welds
(paragraph 4).
A strength was identified in the licensee's efforts to
investigate/resolve a potential water hammer problem in the Unit 1
low pressure service water system (paragraph 5.b).
9408090156 940727
ADOCK 05000269
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
B. Peele, Station Manager
S. Benesole, Regulatory Compliance Manager
D. Coyle, Systems Engineering Manager
J. Davis, Engineering Manager
T. Coutu, Operations Support Manager
B. Dolan, Safety Assurance Manager
W. Foster, Superintendent, Mechanical Maintenance
J. Hampton, Vice President, Oconee Site
D. Hubbard, Component Engineering Manager
- C. Little, Superintendent, Instrument and Electrical (I&E)
- G. Rothenberger, Operations Superintendent
R. Sweigart, Work Control Superintendent
- S. Nader, System Engineering
- M. Bailey, Regulatory Compliance
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
- Attended exit interview.
2.
Plant Operations (71707)
a.
General
The inspectors reviewed plant operations throughout the reporting
period to verify conformance with regulatory requirements,
Technical Specifications (TS), and administrative controls.
Control room logs, shift turnover records, temporary modification
log, and equipment removal and restoration records were reviewed
routinely. Discussions were conducted with plant operations,
maintenance, chemistry, health physics, instrument & electrical
(I&E), and engineering personnel.
Activities within the control rooms were monitored on an almost
daily basis. Inspections were conducted on day and night shifts,
during weekdays and on weekends. Inspectors attended some shift
changes to evaluate shift turnover performance. Actions observed
were conducted as required by the licensee's Administrative
Procedures. The complement of licensed personnel on each shift
inspected met or exceeded the requirements of TS. Operators were
responsive to plant annunciator alarms and were cognizant of plant
conditions.
Plant tours were taken throughout the reporting period on a
routine basis. During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation control
2
practices were observed.
b.
Plant Status
Unit 1 remained shutdown in a scheduled Refueling Outage until
June 27, 1994, when it was placed on-line at 2:47 p.m.
Unit 2 operated at or near 100 percent power throughout the
inspection period.
Unit 3 operated at 100 percent power throughout the inspection
period with the exception of June 7, 1994, when power was reduced
to 82 percent due to a steam leak in the Heater Drain System. The
leak was repaired and power was restored to 100 percent the
following day.
c.
Unit 1 Axial Power Shaping Rod (APSR) Replacement
On June 4, 1994, while attempting to latch the Unit 1 axial power
shaping rods (APSRs) to their control rod drive mechanisms
(CRDMs), the licensee determined that the rods could not be
connected. The licensee had replaced the APSRs earlier in the
outage during the core offload/reload. The licensee determined
that the new APSRs' couplings were not compatible with the Unit 1
CRDMs and that they could not be coupled. The APSRs were of a
type compatible with type "C" CRDM lead screw bayonets and the
Unit 1 CRDMs are type "A".
The mismatch did not allow sufficient
depth in the APSR hub to engage the APSR to the lead screw. At
the time of this discovery the reactor vessel head was installed
and tensioned.
The licensee initiated an outage schedule change to pull the
reactor vessel head and plenum, refill the transfer canal, and
transfer the eight fuel assemblies containing the APSRs to the
spent fuel pool.
The licensee contacted the vendor, Babcock and
Wilcox (B&W), to determine if new APSRs could be obtained. A
vendor reanalysis of the service life of the old APSRs was
commenced to determine if it could be extended and the old APSRs
reinstalled for cycle 16.
The reanalysis determined that the
service life could be extended from 8 effective full power years
(EFPY) to 15 EFPY. Based on this analysis the licensee decided to
reinstall the old APSRs and reload the core. The inspectors
reviewed the analysis and observed the reinstallation of the old
APSRs. APSR component shuffle and core reload were completed on
June 8, 1994. The reactor vessel head was reinstalled and
tensioned on June 10, 1994.
d.
Indications of Cracks in the Breathing Air System Containment
Penetration Piping
The Breathing Air (BA) System is not safety-related or seismically
qualified with the exception of the section of piping between the
3
containment penetration isolation valves (3BA-171 & 3BA-172).
During the last Unit 3 outage, approximately 20 pin hole leaks
were discovered and repaired in the piping downstream of the
inside containment isolation valve (3BA-172). A section of the
piping was sent.off for metallurgical examination which revealed
that the piping was undergoing chloride induced stress corrosion
cracking. The licensee attributed the cracking to the fact that
the original BA compressors used chlorinated drinking water for
the seal supply and that this chlorinated water had gotten into
the system.
On June 6, 1994, the licensee performed an ultrasonic test (UT) on
the section of piping between the outside BA containment isolation
valve (3BA-171) and the containment wall.
The UT examination
revealed several indications in the heat affected zone next to the
socket weld for 3BA-171. Due to the size of the piping (2 inch
outer diameter, schedule 80 pipe, .218 inches thick), the licensee
was unable to determine if the indications were actual cracks or
surface irregularities. Since they were unable to determine the
exact nature of the UT indications, the licensee assumed them to
be cracks. The following day the section of piping inside the
Unit 3 Reactor Building (RB), as well as the piping on either side
of the penetration on Units 1 and 2 were ultrasonically tested.
Indications were found on the section of piping inside the Unit 3
RB as well as on both sides of the penetration for Unit 2. No
indications were found on either side of the Unit 1 penetration.
Dye penetrant tests were conducted where there were UT
indications. The dye penetrant tests found no indications of
through-wall cracks. The dye penetrant test results combined with
the last local leak rate tests (LLRTs) for these penetrations
indicated that the short-term integrity of the penetrations was
acceptable. The only remaining concern was the ability of the
piping in question to withstand a seismic event and still maintain
containment integrity. This concern was resolved with the
implementation of Temporary Modifications (TMs) 1148 for Unit 2,
and 1149 for Unit 3. The TMs decoupled the penetration piping
from the rest of the BA system by removing a small section of pipe
upstream of the outside containment isolation valve (BA-171).
This in turn removed the potential for seismic loading on the
piping in question. The licensee intends to replace the
questionable piping before the end of the next refueling outage
for each unit. The inspectors found the licensee's corrective
actions acceptable.
Within the areas reviewed, licensee activities were satisfactory. No
violations or deviations were identified.
3.
Maintenance and Surveillance Testing (62703 and 61726)
a.
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
4
personnel and that approved procedures adequately described work
that was not within the skill of the craft. Activities,
procedures and work orders (WO) were examined to verify that
proper authorization and clearance to begin work was given;
cleanliness was maintained; exposure was controlled; equipment was
properly returned to service; and limiting conditions for
operation were met.
Maintenance activities observed or reviewed in whole or in part:
(1) IP/O/B/3012/001, Diagnostic Testing Of Air Operated Valves
On June 8, 1994, the inspectors reviewed diagnostic testing
of Feedwater Valve FWD-CV-0082. The purpose of the testing
was to evaluate the operating parameters of the valve. A
computerized diagnostic test instrument was utilized for the
activity and the effort was performed under the direction of
the equipment vendor.
The inspectors verified that the test had been properly
authorized and that the activities performed and data
collected were in accordance with procedural requirements.
(2) IP/1/A/0305/003, Nuclear Instrumentation and Reactor
Protective System.
On June 8, 1994, the inspectors reviewed work in progress
during the performance of IP/1/A/0305/003, Nuclear
Instrumentation and Reactor Protective System, RP Channel
Calibration And Functional Test. This procedure was
performed on Unit 1 during the outage to verify the trip
parameters of the nuclear instrumentation and reactor
protective system were properly calibrated.
The inspectors verified that the equipment utilized for the
activity was calibrated, that the data taken was documented
as required, and that the work effort was performed per the
procedure.
(3) Work Order 94044401, Task 01, Repair 1C-850.
On June 13, 1994, the inspectors reviewed work in progress
associated with work order 94044401. The work order was
initiated to inspect/repair valve 1C-850, the motor driven
emergency feedwater pump hotwell suction check valve. The
valve had exhibited excessive leakage during the performance
of a back leakage surveillance test.
The inspectors reviewed the work order and observed work in
progress. Activities observed were satisfactory and
accomplished in accordance with approved procedures.
5
b.
Surveillance activities were conducted with approved procedures
and in accordance with site directives. The inspectors reviewed
surveillance performance, as well as system alignments and
restorations. The inspectors assessed the licensee's disposition
of discrepancies which were identified during the surveillance.
Surveillance activities observed or reviewed in whole or in part:
(1) IP/O/A/0330/003A, Control Rod Drive Rod Drop Time Test.
On June 21, 1994, the inspectors witnessed control rod drop
time testing on Unit 1. The test was performed near the
completion of refueling outage EOC-15 and was in accordance
with procedure IP/O/A/0330/003A, Control Rod Drive Rod Drop
Time Test. The purpose of the test was to functionally
check the Control Rod Drive System total trip time from the
manual trip button or the auxiliary power supply trip switch
to three-fourths insertion of each control rod into the core
from the fully withdrawn position. The requirement was for
each control rod to be fully withdrawn prior to performing
the drop time test. The acceptance criteria was that the
drop time not exceed 1.66 seconds with reactor coolant flow
at full flow conditions. However, the procedure did require
that the licensee evaluate rods with a drop time that
exceeded 1.40 seconds. A total of 20 rods fell within the
1.40 to 1.66 second range, but all rods dropped within the
1.66 second time frame.
A problem was experienced with control rod number 6 in group
5. During the initial test, the rod failed to move out when
the operator pulled the group 5 rods for the drop test. As
a result, Instrument and Electrical (I&E) technicians
verified that the associated fuses were good and that the
drive stator was receiving power. The operators then
attempted to withdraw the rod individually and were able to
withdraw the rod on the third attempt. A decision was made
to stop the rod withdrawal at 10 percent, drive the rod back
into the core, and attempt to withdraw it with the rest of
the group 5 rods. However, the operators were unable to
drive the rod back into the core and as a result the rod was
tripped, causing it to fall into the core. The rod was then
re-exercised successfully and withdrawn with the group.
Upon completion of the group 5 withdrawal, rod drop time
testing was successfully performed. The inspectors noted
that this was the same rod that had inadvertently dropped on
April 7, 1994, which prompted a reactor power reduction to
approximately 65 percent power as required by the technical
specifications.
(This previous event was documented in NRC
Inspection Report 50-269,270,287/94-11.)
Consequently, a
conference call was conducted on June 21, between NRC, the
licensee and the rod vendor. Although the problem(s) with
this rod had not been specifically identified/corrected, the
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NRC concluded that the safety function of the rod was
unaffected (i.e., the rod would drop when deenergized).
The
unit was subsequently restarted and placed on-line June 27,
without experiencing any further rod problems.
(2) PT/2/A/0600/12, Turbine Driven Emergency Feedwater Pump Test
The inspectors reviewed testing of the Unit 2 Turbine Driven
Emergency Feedwater Pump on June 28, 1994. The test was
performed to demonstrate operability of the pump as required
by the Technical Specifications. Test results were properly
documented and the pump was determined to be operable.
(3) OP/0/A/1600/10, Operation of the SSF Diesel Generator
The inspectors witnessed a post maintenance test of the safe
shutdown facility (SSF) diesel generator on June 6, 1994.
All parameters observed were satisfactory, and all
acceptance criteria were met.
(4) PT/0/A/610/06, 100 KV Power Supply From Lee Steam Station
This performance test implements a Technical Specification
required surveillance (TS 4.6.7) to demonstrate that a Lee
Steam Station combustion turbine can be started and
connected to the isolated 100kv line and carry the
equivalent of the maximum safeguards load of one Oconee unit
(4.8 MVA) within one hour. During the performance of this
test the licensee also incorporated steps to align the
central switchyard to the Unit 1 main feeder buses to obtain
data on current, voltage, and power on the main feeder buses
when the buses are powered from the Central Switchyard.
The licensee initially performed the test on June 8, 1994.
During the performance of the test, undervoltage alarms were
received as soon as the main feeder buses were aligned to
the standby buses powered from the central switchyard.
The
standby bus undervoltage alarm actuates at 4150 volts and
steady state voltage dropped to less than 4100 volts. The
test was aborted and the main feeder buses were realigned to
the 230 KV switchyard. The test was re-performed on the
morning of July 9 when the load on the 100 KV system was
reduced. Undervoltage alarms were again received as soon as
the standby buses were aligned to the main feeder buses.
Accordingly, the main feeder buses were realigned to the 230
KV switchyard. The licensee decided to install test
equipment on the secondary side of the transformer powered
from central switchyard and re-perform the test.
The test was re-performed on June 12, 1994. During this
test the licensee reduced major operating loads on Unit 1 to
one condenser circulating water pump, one low pressure
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service water pump, one low pressure injection pump, and one
chiller. When the main feeder buses were aligned to the
standby buses, voltage remained above 4150 volts. After
aligning the main feeder buses to the central switchyard,
the operators started a hotwell pump to obtain data during
the starting of a large 4KV motor. When the hotwell pump
was started voltage dipped to approximately 4094 volts and
recovered to 4134 volts. The operators secured the hotwell
pump and continued with the test. A Lee gas turbine was
started, the 100KV line was isolated, and the gas turbine
was loaded to 6 MW within 34 minutes.
The inspectors expressed concern with the capability of the
central switchyard as an offsite power supply. The licensee
stated that the testing conducted on the central switchyard
was to obtain data to compare with computer models and that
the data would be reviewed and appropriate actions taken.
This issue has been discussed previously with the licensee
and the inspectors will continue to monitor licensee
actions.
(5) PT/1/A/251/24, High Pressure Injection (HPI) Full Flow Test
This performance test establishes flow through the "A" and
"B"
trains of the Low Pressure Injection (LPI) to HPI
flowpath (piggyback mode of operation) and the "A" and "B"
trains of HPI to the Reactor Coolant System (RCS) to verify
proper operation of the check valves in each flowpath. The
procedure also compares HPI pump developed head at
approximately 500 gpm to a reference value to determine pump
operability per the requirements of ASME Section XI.
The inspectors reviewed the procedure and witnessed the
portion of the test conducted on the C HPI pump. During the
test, the C HPI pump did not obtain the required developed
head. The test acceptance criteria required a developed
head of 1055 to 1213 psid at a flow rate of 498 gpm. The
pump developed less than 1000 psid at the required flow
rate. The licensee performed subsequent special tests to
verify that the reduced developed head indication was
definitely a pump performance problem. The testing
determined that the problem was internal to the pump. The
licensee isolated the pump and replaced the pump internals.
Based on a review of the test data, the inspectors concluded
that the licensee's decision to replace the pump was
appropriate. The pump was repaired and satisfactorily
retested on June 15, 1994. The licensee subsequently
determined that an internal drain plug between stages had
loosened and backed out, allowing flow to short circuit
between the two stages.
Within the areas reviewed, licensee activities were satisfactory. No
4II8
violations or deviations were identified.
4.
Onsite Engineering (37551)
During the inspection period, the inspectors assessed the effectiveness
of the onsite design and engineering processes by reviewing engineering
evaluations, operability determinations, modification packages and other
areas involving the Engineering Department.
During a review of piping classifications associated with the Unit 1 low
pressure injection (LPI) suction piping, the inspectors questioned the
code class identified for the sections of piping between valves LP-30
and LP-22, and the corresponding section of piping between valves LP-29
and LP-21.
Valves LP-29 and LP-30 are check valves located in the LPI
suction supply line from the borated water storage tank (BWST). Valves
LP-22 and LP-21 are normally open motor operated valves located
downstream of check valve LP-30 and LP-29, respectively. The piping
diagram identified the piping as Duke Class C (Class III).
Review of
the Unit 2 and Unit 3 LPI systems identified that the Unit 2 valves and
piping were identified as Duke Class B (Class II) and that the Unit 3
valves and piping were identified as Duke Class C. The inspectors
believed that the subject piping should be Duke Class B, as discussed
below.
The Oconee Final Safety Analysis Report (FSAR) Chapter 3, Design of
Structures, Components, Equipment, and Systems, Section 3.2.2.1, System
Classifications, states:
"Class II systems, or portions of systems, are those whose loss or
failure could cause a hazard to plant personnel, but would
represent no hazard to the public. Class II systems normally
contain radioactive fluid whose temperature is above 212 degrees
F, and in addition, those portions of Engineered Safeguards
Systems which may see recirculated reactor building sump water
following a LOCA."
Following a LOCA and subsequent depletion of the BWST, the LPI sump
suction isolation valves are opened, LPI flow rates are adjusted, and
then the BWST is isolated by shutting valves LP-21 and LP-22. Until
LP-21/LP-22 are shut, check valves LP-29/LP-30 and the associated piping
down to valves LP-21/LP-22 are exposed/communicate with recirculated
sump water.
This item was reviewed by the licensee and discussed with licensee
management. Several conference calls were held between the licensee and
NRC to discuss the issue and obtain the licensee's position on the code
class requirements for the sections of piping identified. The licensee
stated that the subject check valves and piping were constructed as
Class III (Duke Class C) and were/are correctly classified. The
licensee's position was based on interpreting the intent of the original
licensing basis as requiring Class II when there is flow or the
potential for flow of recirculated sump water; the fact that LP-21 and
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LP-22 would only be open momentarily after the reactor building sump
isolation valves were opened; and that the presence of water from the
BWST in the subject lines would prevent any water molecules that had
been present in the reactor building sump from contacting the check
valves and piping in question. The licensee further stated that the
Unit 2 valves and piping would be reclassified as Duke Class C.
The inspectors' position with respect to this issue was that the FSAR
did not stipulate a time frame for exposure to recirculated sump water,
only that the piping may be exposed to recirculated sump water; that
single failure of the associated motor operated valve (and therefore
reliance of the associated check valve and piping as a boundary) was
recognized in the FSAR; and that gravity and the vertical configuration
of the subject piping would cause the relatively cold/dense BWST water
barrier to fall and be replaced by the hot/less dense recirculated sump
water.
This issue was reviewed by the NRC Office of Nuclear Reactor Regulation
(NRR) to determine the proper code class requirements for the subject
piping. This review determined that the piping should be classified as
Class II (Duke Class B).
This review also determined that the issue did
not represent a significant safety issue and that restart of Unit 1
prior to correction was accepteble. The failure to meet the code class
requirements contained in the FSAR with respect to the Unit 1 and Unit 3
low pressure injection BWST suction piping is identified as Deviation
269,287/94-19-01: Improper Code Classification.
During review of the code class requirements associated with the LPI
suction piping the inspectors identified that FSAR Section 3.2.2.1,
System Classifications, required that welds between classes of systems
(Class I to II, I to III, or II to III) be performed and inspected in
accordance with the rules for the higher class. The inspectors
determined that the licensee's program does not require that welds
between classes of systems be performed and inspected in accordance with
the rules for the higher class. The licensee stated that the class
boundary is considered to be the valve seat of the boundary valve
between the classes. The failure to meet the requirements of FSAR
Section 3.2.2.1 with respect to performing and inspecting welds between
classes of systems is identified as Deviation 269,270,287/94-19-02:
Failure to Meet FSAR Requirements with Respect to System Class Boundary
Within the areas inspected, two Deviations were identified.
5.
Plant Support (71750)
The inspectors assessed selected activities of licensee programs to
ensure conformance with facility policies and regulatory requirements.
During the inspection period, the following areas were reviewed:
SII
10
a.
Fire Protection (Notice Of Unusual Event - Oconee Unit 1)
A Notice Of Unusual Event (NOUE) was declared at 3:00 a.m., on
June 15, 1994, due to a fire on the Unit 1 main turbine. The fire
was discovered by the shift supervisor at approximately 1:45 a.m.
when he detected an unusual odor while walking through the area.
He then noticed smoke followed by flames emanating from the high
pressure turbine near the front standard. At the time, Unit 1 was
in Cold Shutdown for a refueling outage. However, steam pressure
had been applied to the turbine seals in preparation for plant
startup after the refueling outage.
The fire brigade was summoned and C02 fire extinguishers were used
on the flame. The flame reappeared several times until the area
was cooled down and water could be applied. By 3:30 a.m., the
fire was out with no signs of recurrence. At 4:36 a.m., the NOUE
was exited.
The licensee determined that honing oil had been spilled inside
the insulation surrounding the steam seal supply piping during the
process of refacing the upper and lower mating surfaces of the
high pressure turbine steam chest. Honing oil has a low flash
point and ignited when the steam line was heated. The difficulties
experienced in extinguishing the flame resulted from the fact that
the source of the fire was located between the insulation and the
heated pipe. There was no damage to the main turbine. Having
responded onsite when notified of the NOUE, the inspectors found
the licensee's assessment of the fire and its cause to be
acceptable.
b.
Low Pressure Service Water (LPSW) Component Damage
During the Unit 1 outage, plant personnel observed indications of
damaged components on the Unit 1 side of the combined Unit 1 and 2
LPSW system. These indications included eight damaged pressure
gauges associated with the reactor building auxiliary coolers, and
over-ranged flow transmitters. In addition, the 181 auxiliary
cooler supply header was found leaking, a key in the valve
operator for LPSW-254 was found sheared, and an individual in the
Unit 1 Reactor Building had reported a loud bang during a routine
Engineered Safeguards (ES) test which, in part, automatically
realigned several valves in the LPSW system. Due to these
separate observations, the licensee postulated that a water hammer
or overpressure event may have occurred to part of the Unit 1 LPSW
system. An action plan was prepared to investigate the individual
observations in an attempt to determine whether a damaging event
had occurred, and whether such an event had compromised the
integrity of the LPSW system. The Plant Manager directed the
plant staff to provide their conclusions and recommendations prior
to restart of Unit 1 from the refueling outage, and set completion
of the review as a condition for startup.
Review of plant records indicated that the ES testing occurred in
the same time frame as the loud noise heard in the Reactor
Building. The licensee became concerned that LPSW realignment
during ES testing may have initiated a water hammer, and damage to
the system might occur during an actual ES condition in the
future. Special instrumentation was temporarily installed on the
LPSW system and the ES test was re-performed. There was no
evidence of a water hammer or other pressure transient during the
test. A walkdown of the Reactor Building portion of the LPSW
system was performed, including visual inspection of hangers and
snubbers. In addition, the damaged gauges and transmitters were
disassembled to determine the root cause of their failure.
The licensee concluded that some of the indications could be
ascribed to a water hammer, but the damage found was relatively
minor in nature and would not have compromised the system's
integrity. In addition, the ES test which was re-performed
provided assurance that the system would perform the necessary
realignment without being damaged by a water hammer. The root
cause of the damaged gauges was determined to be vibration
induced, similar to previous events associated with the particular
gauges in question. Overpressure could not be ruled out as the
root cause of the transmitter damage. After reviewing the staff's
conclusions, the Plant Manager concurred and allowed the Unit 1
startup to proceed.
The inspectors attended the meetings and observed the decision
making process surrounding this issue. The methodology employed
in the action plan and the conclusions reached were well ordered
and executed. The inspectors agreed with the final determination
that the plant staff reached. While some minor pressure transient
or water hammer could not be absolutely ruled out, system
integrity did not appear to have been compromised. Further, some
assurance had been provided that an ES actuation in the future
would not produce system damage.
Substantial licensee effort was expended to assure continued
integrity and operability of the LPSW system in this case. The
plant staff demonstrated initiative and safety consciousness in
resolving a question of safety system operability. Plant
management demonstrated a willingness to expend resources to
assure the present and future safety of the plant. Licensee
performance in resolving this issue is considered a strength.
No violations or deviations were identified.
6.
Inspection of Open Items
The following open item was reviewed using licensee reports, inspection
record review, and discussions with licensee personnel, as appropriate:
a.
(Closed) Unresolved Item 269,270,287/92-27-01: Nonsafety-Related
12
Power Supplies to the LPI Cooler Throttle Valves.
The licensee performed a modification on all three units to change
the power supplies of the throttle valves to safety-related motor
control centers.
Within the areas reviewed, licensee activities were satisfactory. No
violations or deviations were identified.
7.
Exit Interview
The inspection scope and findings were summarized on July 6, 1994, with
those persons indicated in paragraph 1 above. The inspectors described
the areas inspected and discussed in detail the inspection findings
addressed in the summary and listed below. The licensee did not
identify as proprietary any of the material provided to or reviewed by
the inspectors during this inspection.
Item Number
Description/Reference Paragraph
50-269,287/94-19-01
Deviation: Improper Code Classification
(paragraph 4).
50-269,270,287/94-19-02
Deviation: Failure to Meet FSAR
Requirements with Respect to System Class
Boundary Welds (paragraph 4).