ML18065A281
| ML18065A281 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 11/02/1995 |
| From: | Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML18065A279 | List: |
| References | |
| 50-255-95-11, NUDOCS 9511160353 | |
| Download: ML18065A281 (16) | |
See also: IR 05000255/1995011
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II I
REPORT NO.
50-255/95011
FACILITY
Palisades Nuclear Generating Plant.
LICENSEE
Palisades Nuclear Generating Plant
27780 Blue Star Memorial Highway
Covert, MI 49043-9530
DATES
August 22 through October 11, 1995.
INSPECTORS.
M. Parker, Senior Resident Inspector
P. Prescott, Resident Inspector
D. Passehl, Resident Inspector
J. Cameron,. DRSS Inspector
A. Dunlop, DRS Inspector
G. Hausman, .DRS Inspector
J. Guzman, DRS Inspector
D. Hartland, DRP Inspector
I. Yin, DRS Inspector
..
APPROVED BY
-
.. ~ ,~
//,,.*.
=---;:;Q -;4c/t~
- tl W .. J. Kropp~* Chief
/
Re'actor p.rojects *Branch 3
AREAS INSPECTED
J- :;l - f;;;~
Date
A routine, unannounced inspection of operations, engineering, maintenance,
inservice testing, and plant support was performed.
Safety assessment and
quality verification activities were routinely evaluated .
9511160353 951102
ADOCK 05000255
G
SUMMARY OF INSPECTION RESULTS
The following material condition problems occurred during this inspection
period which resulted in plant transients that challenged the plant operators:
On August 30. a power reduction was performed in order to facilitate
repairing switchyard motor operated disconnects.
Thermography results
had indicated significant hot spots.
Operator actions were good;
however, some weaknesses were noted in three-way communications.
On September 3, operators experienced a loss of load on the main
generator when the number two governor valve failed closed.
The problem
was identified as a broken wire on the number two governor valve linear
variable differential transformer (LVDT).
On September 11, operations identified broken connections between the
main generator and isophase bus.
The discovery of the problem by
operations personnel was considered good.
On September 18, two cooling tower fans lost fan blades which caused the
tripping of two other cooling fans and damage to some deluge piping
Also the vibration trip for one cooling fan did not.work.
Othar material condition issues identified during this inspection were:
- On Septembe~ 6, the variable speed charging pump was taken ~ut of
service to repack the plungers.
The problem of short packing life
expectancy continued, even though engineering had placed significant
resources to resolving the issue.
During the plant shutdown evolution on September 11, one of the
atmospheric steam dump .valves used to maintain primary coolant system
temperature, failed to open.
The inspectors noted the number of rags to catch oil throughout the
plant was considered excessive, and was another indicator of plant
material condition.
Managemeht response to these material conditions was considered conservative.
However, based on the number of material condition issues identified soon
after a refuel outage, material condition remains an area of concern.
Control of foreign materfal continued to be a weakness.
Several examples were
detailed in the previous inspection report S0-2SS/9S009.
The inspectors were
concerned with the uncontrolled use of rags with motors in the plant.
Examples of continued FME problems are:
On September 13, during decontamination of charging pump SSA, a rag was
sucked into the motor .
2
On October 3, a rag was found in the auxiliary feed pump, P-8C. The
licensee could not determine when this may have occurred.
The unexpected control rod drive mechanism (CROM) withdrawal which
occurred in the previous inspection period, was caused by an unattached
wire lug found lodged between two terminal strip connections.
The
mechanism was worked on during the outage.
ASSESSMENT BY FUNCTIONAL AREA
OPERATIONS (section I . 0) .
Operations performance in respon.se to several events that occurred
during the inspection period was good.
.Minor weaknesses in three-way communication were identified.
Operations management made conservative decisions in response to the
events.
During routing sampling of the safety injection tank, the operators
failure to open the fill valve and his subsequent unauthorized actions
to remedy the situation compounded the problem resulting in exceeding
the one hour sampling time .
MAINTENANCE (section 2.0).
When a cont~act valve technician was injured during maintenance on the
moisture separator drain tank level control valve, the inspectors noted
- no formal administrative measures were instituted to avoid similar
occurrences in the future.
Poor worker practices from a safety and radiological stand point were
identified by the* inspectors.
Some of these *examples occurred *during
the refuel outage, and others were from this inspection period.
The material condition problems with the cracked gene~ator isophase bus
connectors and motor operated switthyard could have been detected prior.
to the refuel outage.
Both of these problems led to plant shutdowns.
ENGINEERING (section 3.0).
During this inspection, the inspectors noted the following with engineering
evaluations:
Several submittals for a relief request to a Code alternative for the
core spray and low pressure safety injection pumps failed to have the
required technical justification and properly interpret lOCFR 50.55 a
guidance .
3
Progress appeared adequate on the P-55A charging pump packing problem
with management involvement being evident.
The tnspectors noted good
oversight of the job by engineering personnel.
Engineering resolution to a problem with bowed swithchgear cubicles was
weak.
This problem, identified a few years ago, led to station power
breaker 252-201, failing to close in.
The inspectors had the following observations pertaining to system
engineering:
During a plant tour, the inspectors noted the motor heater for the high
pressure system injection (HPSI) pump was not functioning.
This was
brought to the system engineer's attention.
The system engineer was
unaware of the existence of the motor heaters.
The system engineer
decided to check all safety-related pumps.
Duri~g the check of the status of motor heaters, the system engineer
found a rag in the air intake of the motor driven auxiliary feedwater
pump,
P~BC. The inspectors felt this was a good example of. thorough
followup of an issue.
PLANT SUPPORT (section 4.0).
The inspectors identified the following concerns:
The licensee experienced numerous challenges during the outage in
controlling station radiation dose and radiation worker practices, as
well as the pre-outage planning of ALARA packages.
Communication of management expectations app*eared weak in the area of
radiological protection.
During this inspection period, the residents also continued to identify
poor radiation work practices.
Summary Of Open Items
Violation:
One violation was identified.
The violation described in
paragraph 2.3.3 of the inspection report involved the failure to obtain* NRC
approval of reli~f request number 4, which established alternative vibration
acceptance criteria for the low pressure safety injection and containment
spray pumps (255/95011-01) .
4
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1.0
1.1
1.2
INSPECTION DETAILS
OPERATIONS
NRC Inspection Procedures 71707 were used in the performance of an
inspection of ongoing plant operations.
Switchyard Motor Operated Disconnect Repairs
On August 29, 1995, the licensee was notified of the results of
thermography testing performed in the switchyard. Thermography results
indicated significant hot spots {high resistance) on the "X" and "Z"
phases of the motor operated disconnect {26H5 MOD) in the switchyard
from the main transformer.
The thermography results noted the
temperature to be 120° C. above ambient on the "z" phase.
Normal
expected temperature is approximately 10° C. above ambient.
The
licensee's Lab Services Division recommends that the plant take action
to correct the problem when the temperature is greater than 40° C. above
ambient~ The main disconnects are unisolable from the switchyard
without taking the generator off line.* At midnight on August 30, 1995,
the licensee initiated a power reduction to 50 percent power.
At this
power level the temperature dropped to less than 53° C. above ambient
temperature.
The vendor recommendation for continuous operation is less
than 53° C.
Pl~nt operators commenced a further power reduction on
September 1, 1995, in preparation for taking the unit offline. The main
generator was taken of fl i ne on September 2, 1995.
The licensee
completed the necessary repairs to the motor operated disconnects in the
switchyard along with a short forced outage repairs and returned the
uriit back to service on September 2, 1995.
Damaged Isophase Bus Connectors
On September 11, 1995, the licensee reduced power to two percent and
took the main generator off-line.after discovering some damage to a
isophase bus flexible connector.
The connector was one of eight for
each phase which linked the main generator to the bus.
Each connector
was comprised of 44 individual copper sheets which were layered to form
a single bus bar.
The licensee discovered that six of the layers were
completely severed on the damaged connector and that a seventh layer was
cracked.* The licensee inspected the other connectors and discovered
cracks on one located on a different phase.
The licensee attributed the
damage to vibration-induced fatigue. Analysis of the connectors by the.
l.icensee's laboratory is still pending.
Due to 'the unavailability of replacement parts, the licensee performed a
temporary repair of the damaged connectors.
The licensee removed the
severed layers and installed stainless steel hardware on both ends of
each connector to aid in relieving stresses at those areas.
Following
the repairs, the licensee returned the unit* to service on September
13th.
The licensee intended to replace all of the connectors during a
future forced outage.
In the meantime, the licensee wa~ performing
5
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1.3
2.0
periodic inspections of the connectors to ensure that further damage
does not develop. The inspectors expressed concern that not all
connections can be visually checked during operation.
Station Power Breaker Trip
On September 13, 1995, while transferring the 4160V non-safeguards bus
lB from startup to station power, breaker 252-201 failed to close during
the initial two attempts.
The feed from start-up power remained closed
during the attempts, which prevented de-energization of the bus~ The
licensee determined that the cause of the problem was vibration induced
during breaker closure due to bowed metal on the bottom of the cubicle. *
The vibration was transmitted to the breaker's foot pedal which impacted
the tfip latch; As corrective action, the licensee te~porarily *
installed some vice grips to secure the pedal in place during the
breaker closure. The licensee intends to* install a temporary
modification to bolt the pedal in place during a future activity
requiring operation of the breaker.
During follow-up discussions with the system ~ngineer, the inspectors
determined that the condition did not affect the auto-trip* function of
the breaker.
In addition, the system engineer was not concerned about a
spurious trip of the breaker, which would result in a reactor trip, due
to the magnitude of vibration required to trip the latch.
The inspectors als~ discovered that the licensee had identified the
problem with the bowed cubicle a few years ago after experiencing some .
problems with other breakers located adjacent to 252-201.
The licensee
determined at that time that the cause of the bowed cubicles was water
intrusion from outside a turbine building roll-up door*lo.cated near the
cubicles.
As corrective action to this condition, the licensee*bolted
down the bowed. cubicles during the last refueling outage.
However, this
action did not prevent the latest problem with breaker 252-201.
The
inspectors will review the licensee's investigation of C-PAL-95-1387,
which was initiated to document the condition, to ensure that actions
are taken to prevent recurrence.
MAINTENANCE
_NRC Inspection Procedures 62703, 61726 and 73756 were used to perform an
inspection of maintenance and testing activities.
2.1
Maintenance Activities
Portions of the.following maintenance activities were observed or
reviewed:
- Repair of CV-0608, heater drain valve
- Repair of motor operated disconnect (26H5 MOD)
- Temporary repair of damaged isophase bus connector
- Troubleshooting boric acid pump piping heat tracing
- Governor valve no. 2, repair broken wire
6
- Installation of 3/4" drain line on P-55A, charging pump
- Installation of seal water filter and flow re.gulating valve on P-55A
- Cooling tower fan failure {89 & Bll)
2.1.1 Technicians Injured During Valve Troubleshooting
A contract valve technician was injured during maintenance to repair a
flow problem on moisture separator drain tank {MSDT) level control valve
CV-0608.
Maintenance technicians were troubleshooting CV-0608 to
investigate the reason why the valve would not automatically control
MSOT level. The upstream and downstream manual isolation valves were.
closed; however, the isolation valves were known to have seat leakage.
Further, there was no vent path to relieve internal system pressure
prior to starting work.
Workers were aware that the piping adjacent to
CV-0608 was pressurized prior to working the valve.
The work plan
instructed maintenance workers to adjust the valve's position to allow
the V-Ball inside CV-0608 to pass full flow when actuator was fn the
full open position.
The intent and nature of the work was not to breach
the pressure boundary.
However, during the initial disassembly to
-
adjust the position, the valve stem unexpectedly ejected from CV~0608,
allowing water at approximately 300 °F and 500 psig in the adjacent
piping to escape and flash to steam.
The worker closest to the valve
received serious burns; two others receiv~d less serious injuries. All
three workers were treated at area hd~pitals.
The licensee's initial *investfgation found that the split ring and
retaining rings on both ends of the valve stem were missing~ The split
and retaining rings would have held the stem in place during the
position adjustments.
The licensee concluded that the rings were
gradually worn away during plant op~ration, probably since 1988, when
maintenance ~as last performed on CV-0608.
The root cause of the
missing rings was indeterminate at the close of the inspection period.
The inspector found that the licensee's immediate response of taking
care of the injured workers and quarantining the area around the valve
was satisfactory.
The licensee's followup actions to replace CV-0608
with a new valve, and to modify the adjacent piping by installing a
vent, were acceptable.
The licensee decided not to initiate a work
request to repair the leaking isolation valves. This was based on the
installation of the vent, and the size of the leak, which was determined
to be fairly small.
The licensee is continuing to work with the vendor
to further investigate this event.
2.1.2 Poor Worker Practices
During troubleshooting of the boric acid pump system line heat tracing;
an inspector observed a worker in a designated contaminated area without
rubber booties, only cloth booties. Also the same worker was observed
stepping on heat traced piping., rather than using a ladder to work on a
junction box.
- *
.7
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The inspector monitored installation of a modification to the P-55A
charging pump.
The modification involved installation of a filter to
the seal water line and rerouting of the seal drain line. A worker came
down to discuss problems being encountered during the modification
without a hard hat and ear plugs.
During decontamination activities on the "A" evaporator, a worker was
observed leaving the immediate area with his dosimetry and TLD on the
stepoff pad, to get poly bags for tools and trash, rather than keeping
his dosimetry with him.
2.2
Surveillance Activities
Portions of the following surveillance activities were observed or*
reviewed:
- SOP-3, Safety Injection Tank Boron Sample
- Ml-43, Reactor Vessel Level Monitoring System Channel Check
NMS~l-7, ExCore Monitoring Calibration
2.2.1 Safety Injection Tank (SIT) Sampling
On September 15, 1995, control operators initiated a routine sampling of
SIT-82A per Standard Operating Procedure (SOP-3).
During sampling, the
SIT pressure and_ level dropped below technical specification (TS) values
as expected, resulting in the licensee entering a one hour TS LCO .
After obtaining the SIT sample, control operators attempted to restore
the tank level and pressure by refilling the tank utilizing the high
pressure safety injection (HPSI) system.
Operators were unable to
achieve a normal f i 11 rate and noted a slow rise in both tank level and
pressure, but observed that -relief valve RV-3161 had lifted. Operators
throttled M0-3068 in an attempt to keep RV-3161 closed.
In an attempt
to facilitate the- fill, the control operator reduced T-82A pressure to
increase the fill rate. During the fill, it was observed that the SIT
fill and drain valve, CV-3039, was closed.
SOP-3 was reviewed and CV-
3039 was opened in accordance with procedure steps~ Level was restored
at the normal fill rate.
Level was restored to within the TS value
within the required time limit of one hour; however, due to the venting
of T-82A pressure by the operator, nitrogen addition was required to
restore nitrogen pressure to normal.
The subsequent nitrogen addition
exceeded the TS limit and resulted in the licensee entering a more
restrictive TS LCO.
TS 3.3.2 requires that if the SIT is not restored
to service within one hour, that the reactor be placed in hot shutdown
within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The operators subsequently restored pressure within
the following 14 minutes (total LCO time 74 minutes). Although the
licensee determined that a violation of TS did not occur, the failure of
the operator to follow SOP-3 caused the licensee to exceed the one hour
TS LCO.
In addition, the shift's action to remedy the situation further
complicated and extended the out of service time, resulting in
exceeding the one hour LCO.
This licensee-identified and corrected
violation is being treated as a Non-Cited Violation, consistent with
Section VII of the *NRC Enforcement Policy.
8
2.3
Inservice Test Program (ISTl
The inspectors noted that the second IO-year IST i nterva 1 ended. in May
I995, and the licensee commenced the third IO-year program when they
exited the refueling outage in August 1995 .. The second IO-year program
was based on the 1983 edition of the ASHE Code, while the new program
was based on the 1989 edition (OM standards).
The new program was not
yet approved by the licensee or submitted to the NRC, although test
procedures were being revised to incorporate the new testing
requirements prior to their performance.
The inspectors reviewed the Safety Evaluation Report (SER) for the
second IO-year IST interval, dated April 20, I995, to determine the
status of relief requests that need approval prior to implementation.
Relief request number 4 was approved to use OM-6 for the second IO-year
IST interval; however, it denied the alternative to the Code vibration
limits for the containment spray (CS) and low pressure safety injection
(LPSI) pumps.
The licensee; however, previously i~plemented the revised
vibration limits for these pumps without prior NRC approval.
2.3.1 Background
The licensee initially requested relief to use velocity versus mils for
vibration measurements in a submittal dated June 28~ 1991.
The relief
stated prior NRC approval was not required as it met the guidance in
Generic Letter (GL) 89-04, "Guidance on Developing Acceptable Inservice
Test Programs."
However, this issue; was not addressed in the GL as
stated in a SER dated July 15, 1992.
The SER also denied this request
based on lack of information on the pumps, such as specific velocity
ranges for which this relief request applied.
Based on a
misunderstanding that prior approval was not required, the licensee had
previously implemented this relief request.
The relief request was resubmitted on December 29, 1992, which
identified the CS and LPSI pumps as'the components that required the
relief and provided specific velocity ranges.
The alert and required
action ranges for these pumps exceeded the OM-6 absolute limits, which
were approved for use by ASME Code Case 465 and 10 CFR 55.55a.
As
discussed above, this relief was also denied.
The SER stated that the
licensee must continue to meet the Code requirements for these pumps.
The SER further stated that if the licensee believed additional
information would support approval of an increased alert. range (required
action range maintained at OM-6 limits), a relief request should be
submitted with the third IO-year program; however, submittal with the
third ten-year interval program did not imply that the requirement to
meet the Code in the interim was not required.
The licensee revised the
test procedures to incorporate the OM-6 required action range; however,
in most cases the alert ranges were deleted or exceeded the OM-6
absolute limits. A relief request, however, was not submitted
requesting approval to use this alternative, yet the alternative was
implemented by the licensee .
9
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2.3.2 Discussion
The licensee believed that changing Code acceptance criteria was allowed
by 10 CFR 50.55a(f)(5)(iv) since it was impractical to meet the Code
limits during low flow testing. The use of impracticality in this
context was incorrect, as impractical conditions apply to physical
design constraints or high dose rate due to design configurations, and
not to elements of the required testing, with possible exceptions where
physical constraints actually limit the licensee's ability to perform
elements of the test. This was riot the case in the specific testing, as
the options open to the licensee included placing the pumps on an
increased testing frequency during an interim period while awaiting NRC
approval of the requested alternative. The establishment of less
conservative vibration limits than required by the Code would constitute
an alternative to the Code and required prior NRC approval before
implementation.
The NRC issued guidance on implementing alternatives to
Code requirements in Section 6 of NUREG-1482.
2.3.3 Conclusion
2.4
Since implementation of the Code alternative was not authorized prior to
implementation, this is considered ~ violation {255/95011-01) of 10 CFR
50.55a(3).
The licensee did not identify any additional relief requests
for the third 10-year interval that required prior NRC approval .
. The licensee submitted a revised relief request, dated September 18,
1995, that proposed an alert limit established based on past pump
hi story for each bearing direction. * The required action range for the
pumps would not exceed the OM-6 absolute limits. Until this relief is
approved by the NRC, the licensee stated alert limits would be in
accordance with OM-6 and increased testing would be performed as
necessary to meet the Code requirements.
Action on Previous Inspection Findings
2.4.1 (Closed) Unresolved Item 50-255/92028-01:
This item concerned the
adequacy of low flow inservice test (IST) of the P-8B auxiliary
feedwater pump (AFW) to ensure the pump's operational readiness .. Based
on discussions with NRR, it was concluded that the flow rates used fo~
IST could be determined by the licensee as the ASME Code only specifies
a repeatable value for the t~st. The licensee; however, must ensure
that the testing used to verify the pump's operational readiness was
acceptable to meet design requirements.
The licensee performed the full
flow special test T-187, "AFW Turbine K-8 and Pump P-8B Performance," on
a 10 year frequency or following major maintenance.
Although the pump*
performance was less than the original pump curve during the tests
performed in 1990 and 1991, the pump still met the design requirements.
Based on the 1991 test results, the pump has a 50 gpm margin.
The
licensee also performed a correlation of the design requirements and the
acceptance criteria established in the IST.
The IST acceptance criteria
appeared to provide sufficient assurance that the licensee would be able
to verify AFW pump degradation.
This item is closed.
10
2.4.2 (Closed) Violation 50-255/92028-02: This item concerned the inadequate
acceptance criteria for testing the low pressure safety injection (LPSI)
and primary coolant system (PCS) loop check valves to the full open
position. Q0-88, "ESS theck Valve Operability Test," was revised to
incorporate the design required flow rate of 1601 gpm for the LPSI *check
valves as determined by engineering analysis EA-E-PAL-93-004E-Ol.
The
valves successfully met the acceptance criteria during subsequent tests.
The PCS loop check valves were full stroked per R0-105, "Full Flow Test
for SIT Check Valves and PCS Loop Check Valves," with the use of non-
intrusive testing techniques during the 1995 refuel outage.
The PCS
loop check valves were also partially stroked per Q0-88 on a cold
shutdown frequency.
The licensee also reviewed other check valves in the IST program to
. ensure test procedures contained adequate acceptance criteria to verify
the full open stroke test. Several discrepancies were identified and in
most cases adequately resolved.
However, the resolution identified in
E-PAL-93-004-0 for check valves CVC-2099 and CVC-2105 did not appear
appropriate.
The maximum accident flow the valves were required to pass
was 40 gpm; however, the test procedure, Q0-17, "lnservice Test
Procedure: Charging Pumps," a~ceptance criteria was based on the
acceptance criteria for the positive displacement pump, which could be
as low as 35.1 gpm.
This did not meet the guidance in Generic Letter 89-04, Position 1.
The licensee previously performed non-intrusive testing {NIT) on these
valves~ which indicated the valves would open at the lower flow rate.
The NIT was going to be performed on a refueling outage frequency {one
valve every other outage).
NUREG-1482, "Guidelines for Inservice
Testing at Nuclear Power Plants," section 4.1.2; stated that a sampling
program for NIT could be used; however, the sampling must be performed
based on the testing frequency.
Since the valves were tested on a
quarterly basis, the NIT must also be on one of the valves each quarter.
The licensee indicated the procedure would be revised to include NIT on
a quarterly sampling basis. This item is closed.
3.4.3 (Closed) Violation 50-255/94014-29:
This item concerned the failure to
test check valves CVC-2138 and CVC-2139 to the full open position.
Surveillance procedure Q0-18, "Inservice Test Procedure: Conceritrated
Boric Acid Pumps," was revised and the valves tested in May 1994.
This
item is closed.
3.0
ENGINEERING
3.1
NRC Inspection Procedure 37551 was used to perform an inspection of
engineering activities. The findings showed performance was good.
Unexpected Control Rod Withdrawal:
On August 17, 1995, during low power physics testing, the licensee
experienced a control rod drive mechanism (CROM) withdrawal demand when
a CROM insertion demand was initiated. The control room operators were
11
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3.2
3.2.1
inserting the Group 4 control rods {38, 39, 40 and 41}, when a rod
deviation alarm was received. Subsequent checks determined that control
rod 40 was greater than 4 inches higher than the other Group 4 control
rods and had traveled in the opposite direction.
CROM-40 was declared
inoperable and the reactor was borated to a shutdown condition for
troubleshooting (see LER 255/95011}.
The licensee replaced CROM-40 and determined that a foreign material
exclusion (FME} problem caused the CRDM-40 failure.
Visual inspection
of CROM-40's motor junction box, revealed that the "up" and "down" limit
switches (LS-40/1 and LS-40/2, respectively) were shorted by an
unattached wire lug.
The unattached wire lug was found lodged between
the LS-40/1 and LS-40/2 terminal strip connections.* Several CROMs were
worked on during the recent outage; however, the exact time when the
wire lug was introduced into the motor junction box could not be
determined.
The licensee speculated that the FME problem was probably
introduced during earlier maintenance work.
CROM ground detection troubleshooting isolated a 45-50 Vac (400 Hertz)
ground in CROM-15.
The CRDMs power source was ungrounded and the
circuitry did not contain a ground detection system." As a result,
ground detection troubleshooting was performed to determine if CROM-40
was masking an additional problem.
Troubleshooting isolated the ground
-to CROM-15, which was removed and subsequently replaced with the
original retested CROM-40 .
The inspe.ctors concluded that the licensee's investigation, evaluation
and resolution of the CROM withdrawal problem was good.
A team approach
was taken for coordination of the conducted activities. Engineering
directed troubleshooting efforts to isolate and evaluate the problem.
Operations was actively involved in the engineering directed effort.
Steps were taken to ensure that all personnel were aware of their
assigned tasks.
The licensee issued an informational licensee event
report (LER) 255/95011, which identif~ed the proposed long term
corrective actions.
Action on Previous Inspection Findings
CClrised) LER 255/92026-01: The licensee failed to ensure changes to
station operating procedures did not conflict system configuration
requirements identified in the licensee design basis documents.
The
affected operation was revised.
The licensee follow up actions were
considered adequate.
This LER is closed.
3.2.2 (Closed) LER 255/94006: February 1994 through-wall leak of containment
sump check valve CK-ES3166.
The plant was taken to cold shutdown and
actions were initiated to identify the failure mechanism, the extent of
degradation,
repair method, and actions required to prevent recurrence.
Metallurgical analyses and nondestructive examination techniques were
used to identify the failure mechanism as intergranular attack (IGA) due
to sensitization in a weld-repaired region of the valve casting. These
welds were made during the time of original plant construction.
12
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The repair consisted of a weld overlay on the check valve (and also~
conservatively, on the opposite train valve, CK-ES-3181) per ASME Code
Case N504-1.
The repair efforts were reviewed by both NRC Region III
and NRR cognizant engineers and were found to be satisfactory. The
repair process and actions taken are described in further detail in
inspection report 50-255/94004.
To prevent recurrence, Palisades reassessed stainless steel weld
practices to ensure controls exist to minimize corrosion stemming from
IGA, performed a historical review of modifications to identify high
risk susceptible components, and completed further destructive
metallurgical exams to evaluate the prevalence of IGA on susceptible
components.
The destructive testing was conducted on similar check
valves that were used in a similar service and enviroriment that were
replaced in 1995.
No IGA or cracking was observed. These actions were
reviewed by the NRC and found acceptable. This LER is closed .
. 3.2.3 {Closed) Unresolved Item 50-255/92028-03:
This item concerned the
capability of the fire water system to provide a backup water supply to
the AFW system.
The licensee developed engineering analysis EA-A-PAL-
94-095 that verified the fire water system would be able to provide
sufficient net positive suction head (NPSH) to the AF.W pumps as required
by Technical Specifications. This item is closed.
3.2.4 {Closed) Inspection Follow-up Item 50-255/94014-26:
This item concerned
the component cooling water (CCW) heat exchanger differential pressure
and CCW flow correlation to determined flow rate from special test T-213
used in the CCW pump tests~ The DET also identified that during a
licensee review in late 1993, two questions were identified with the
curve developed by T-213.
These were documented on D~PAL-93-272 in
January 1994.
First, the curve did not take the expected hyperbolic
sh.ape, but was more of a straight line. .The second question concerned
the lack of verification of valve positions *in the test flow path.
The licensee conducted T-213 during the recent refueling outage.
The
test ensured valves in the test flow path were in.the open position
prior to performance.
The curve produced by test, when extrapolated,
produced the expected hyperbolic shape.
The licensee was still
reviewing the test results to determine if any changes needed to be made
to the IST pump test. Based on these results and intended actions, this
item is closed.
3.2.5 (Closed) Inspection Follow-up Item 50-255/94014-27:
This item concerned
the root cause of a stroke time increase for motor-operated valves M0-
3064 and M0-3066.
The valves' gear ratios were modified in the 1993
refuel outage.
The next two ISTs showed no change in the valve stroke
times and as such, the valves' reference values were not changed.
The
stroke time in December 1993, and subsequent test data increased from
- the previous measurements.
The licensee contributed the stroke time
increase to the gear change modification, although initial testing did
not indicate an increase in the stroke time .. The licensee was unable to
determine why the stroke times did not increase initially with the gear
13
, ...
3.2.6
change modification. Test results since December 1993 remained
consistent. Based on the consistent test results, there did not appear
to be a problem with the valves.
This item is closed.
(Closed) Inspection Follow-up Item 50-255/94014-30:
This item concerned
the testing of manual valve FW-150, which was relied on in emergency
operating procedures to be used as a backup steam supply regulator for
the AFW turbine driven pump.
Based on the plant's design basis, the
licensee concluded that the valve did not meet the criteria for
inclusion in the IST program; however, a periodic predetermined activity
control (PPAC) was developed to lubricate and stroke the valve on a
yearly basis.
The inspectors considered this acceptable.
The PPAC,
however, was not performed as scheduled during the recent refuel outage.
A corrective action document was initiated to address the missed PPAC.
The valve was successfully exercised on September 18, 1995.
This item
is closed.'
3.2. 7 COPEN> LER 50-255/95006: Inadequate auxiliary feedwater pump low suction
pressure trip setpoints. Originally identified on condition report C-
PAL-95-0877, the design of the AFW pump suction did not adequately
consider pump protection form air entrapment at low condensate storage
tank levels.
Inspectors reviewed the corrective*actions specified for
the AFW system and concluded that they were acceptable.
The lER also
raised a concern with the suction from the safety injection and
refueling water tank (SIRW) and concluded that it was acceptable based
on engineering judgement.
Further evaluation was *planned for the SIRW
and other large pumps; therefore this LER is open pending completion of
the licensee's evaluation. *
4.0
PLANT SUPPORT
4 .1
NRC Inspection Procedure 83750 was used to perform an inspection of
Plant Support Activities, with an emphasis on outage activities. The
level of performance in radiological protection was considered adequate.
No single finding was considered significant; however, the licensee *
experienced numerous challenges during the outage in controlling station
radiation dose and radiation worker practices, as well as the pre-outage
planning of ALARA packages.
The underlying weakness appeared to be
ineffective communication of management expectations in the area of
radiological protection.
External Exposure Control
The licensee completed the outage on August 17, 1995 with an outage dose
of 348 person-rem (3.48 person-sievert), versus an outage ALARA goal of
286 person-rem (2.86 person-sievert).
The outage dose was based upon
electronic dosimeter (ED) readings.
Actual reported doses will be based
upon thermoluminescent dosimeter (TLD) readings and will be 10 to 14
percent higher.
The reason for the higher TLD readings is discussed
below in Section 4.4. Notwithstanding the higher TLD readings, the
licensee experienced several challenges in meeting its outage ALARA
goal.
Two primary reasons for this were poo*r radiation work.er practices
14
- 4.2
4.3
and mixed performance du,ring the prejob ALARA reviews..
Both of those
challenges were discussed in Inspection Report 50-255/95008{DRP) and
additional information is provided below.
Pre-Job ALARA Planning
The licensee's performance during the completion of pre-job ALARA
reviews was mixed.
Although some reviews exhibited e*xce 11 ent
performance and vigilance on the part of ALARA planners, such as the 1-
24, or reactor vessel internals inspection project, the planners showed
poor performance in others, namely, the Alloy 600 ~roject. The initial
dose projections indicated 32 person-rem for the I-24 project. A
majority of the work was to be performed by workers standing on the edge
of the reactor vessel over a dry cavity.
The ALARA group rejected that
dose projection and sent the package back to the project engineers for
dose savings techniques. Through various changes to the work package,
including the use of a mock-up and partially filling the cavity, the
revised dose projection was 4.8 person-rem.
The actual total dose for
the project was 4.2 person-rem.
The licensee's challenges with regard
to the Alloy 600 project are fully described in Inspection Report 50-
255/95008(DRP).
In summary, due to equipment clearance constraints and
the erroneous use of the vendor's time estimate to complete the project,
the licensee's total dose for the Alloy 600 inspection project was 23
person-rem, versus an ALARA projection of 11 person-rem.
Radiation Worker (Radworker) Practices
Inspection Report 50-255/95008(DRP) described inspector observations of
poor radworker practices during the performance of two projects with
high radiological significance; the removal of the Core Support Barrel
and the Transfer of the Incore Detector Cask.
During both projects, the
inspectors observed radworkers loitering in areas with elevated dose
rates.
In neither case were the workers' behavior challenged,
suggesting a lack of aggressiveness by the licensee in reducing
individual dose.
Although these two projects are the only ones observed
by the inspectors that i-nvo 1 ved poor radworker practices, other
.
information was available to suggest that these were not isolated cases.
During the review of personnel contamination incidents (PCis), the
inspector observed an adverse trend in the number of PCis early in the
outage.
At the end of the outage, the licensee had recorded
approximately 1000 PCis.
Although none of the PCis were radiologically
significant to the contaminated individuals, they do suggest unchecked
poor radworker practices in contaminated areas.
The licensee.
..
acknowledged this possibility and was in the process of developing plans
to limit PCis and correct the poor radworker practices. Details of
those plans were not immediately available, but will be reviewed during
future inspections prior to the next outage .
15
4.4
Electronic Dosimeter/TLD Discrepancies
5.0
Personnel radiation dose received during the second quarter of 1995, as
determined by TLD, exceeded the dose recorded by electronic dosimetry
(ED).
Prior to the outage, the licensee changed vendors for the supply
and processing of TLDs, the primary source of recording exposure.
Due
to differences in the processing technique of each vendor, the average
TLD dose deviation between the two vendors was 12 percent.
The previous
vendor, actually the Consumers Power Co. laboratory, consistently
reported doses that were approximately 4 percent lower than the expected
dose on spiked TLDs.
The new vendor, a laboratory independent of
Consumers Power Co., reported doses that were approximately 8 percent
higher that the expected dose on spiked TLDs.
Differences of 10 percent
are acceptable for NVLAP.accreditation.
Since the EOs were calibrated
against expected TLD results from the former processor, this resulted in
them reading less than the TLD results from the new processor. Thus,
the outage dose, as reported to date via ED results, will be adjusted
higher approximately 12 percent, based on actual TLD readings, which are
reported quarterly, when they become available.
The adjusted exposure
results will not result in anyone receiving a reported dose in excess of
NRC regulatory, or licensee administrative, dose limits.
PERSONS CONTACTED AND MANAGEMENT MEETINGS
The inspectors contacted various licensee operations, maintenance,
engineering, and plant support personnel throughout the inspection
period.
Senior personnel* are listed below .
At the conclusion of the inspection on October 11, 1995, the inspectors
met with licensee representatives (denoted by*) and *summarized the
scope and findings of the inspection activities. The licensee did not
identify any of the documents or processes reviewed by the inspectors
are proprietary.
R. A.
- T. J.
- K. P.
G. B.
R. M.
- O. W.
- D. J.
s. y.
- R. B.
- C. R.
J. P.
H. L.
D. P.
- D. W.
- R. A .
Fenech, Vice President, Nuclear Operations
Palmisano, Plant General Manager
Powers, Nuclear Services General Manager
Szczotka, Nuclear Performance Assessment Manager
Swanson, Design Engineering Manager
Rogers, Operations Manager
Malone, Chemical & Radiological Services Manager
Wawro, Planning & Scheduling Manager
Kasper, Maintenance & Construction Manager
Ritt, Admini*stration Manager
Pomaranski, Deputy Maintenance & Construction Manager
Linsinbigler, Projects & Contracts Manager
Fadel, System Engineering Manager
Smedley, Licensing Manger
Vincent, Licensing Supervisor
16