ML18067A595
| ML18067A595 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 06/17/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML18067A592 | List: |
| References | |
| 50-255-97-05, 50-255-97-5, NUDOCS 9707010168 | |
| Download: ML18067A595 (27) | |
See also: IR 05000255/1997005
Text
U.S. NUCLEAR REGULATORY COMMISSION
Docket No.:
License No.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9707010168 970617
ADOCK 05000255
a
REGION Ill
50-255
50-255/97005(DRP)
Consumers Power Company
21 2 West Michigan Avenue
Jackson, Ml 49201
Palisades Nuclear Generating Plant
27780 Blue Star Memori~I Highway
Covert, Ml 49043-9530
March 1 through April 11, 1997
M. Parker, Senior Resident Inspector
P. Prescott, Resident Inspector
Bruce L Burgess, Chief
Reactor Projects Branch 6
EXECUTIVE SUMMARY
Palisades Nuclear Generating Plant
NRC Inspection Report 50-255/97005
This inspection reviewed aspects of licensee operations, maintenance, engineering and
plant support. The report covers a 6-week period of resident inspection.
Operations
The inspectors identified that a drawing discrepancy associated with the safeguards
high pressure air system was not dispositioned in a timely manner.
(Section 01 .2).
The inspectors concluded that, after identification by an operator, good followup
resulted in timely actions preventing further degradation of service water bay level
(Section 01.3).
Maintenance
The inspectors' review of the main steam isolation valve Code repair issue
determined that the licensee failed to provide adequate oversight resulting in an
improper code repair on these valves. The licensee understood the significance of
the event and the need to apply resources necessary to prevent recurrence.
Violations were identified for the failure to perform a proper Code repair, failure to
issue an LER within thirty days, and three examples of a failure to follow
procedures (Section M 1. 2). Corrective actions to date appeared to be thorough.
Engineering
The inspectors determined that the licensee initially did not aggressively pursue
resolution of the power cable ampacity issues. (Section E 1. 1).
The inspectors expressed concerns with timeliness of corrective actions. The
findings were discussed with the nuclear performance assessment department
(NPAD). NPAD agreed the data indicated a performance problem. Currently, NPAD
is trending these additional items to determine the significance and what future
actions may be necessary (Section E1 .2).
Due to the inspectors' concern with potential high pressure air system pressure
control valve degradation, the licensee developed a schedule to open and inspect
the valves in question. (Section E1 .3).
\\
Plant Support
The inspectors concluded that the licensee's placement of the criticality monitoring
devices was in accordance with 10 CFR 70.24 (a)(2). However, the inspectors
2
-
--.:.. __ _
-*-
were unable to determine the sensitivity of the monitors, as required by
10 CFR 70.24(a)(2), since the licensee was unable to produce any analysis to
support this conclusion. This was considered an Unresolved Item
(50-255/97005-04(DRP)) pending further evaluation by the licensee (Section R 1.2).
3
REPORT DETAILS
Summary of Plant Status
The plant operated at essentially 99.6 percent power for the entire inspection report
period. There was one power reduction commenced at 9:30 pm est on March 4, 1997, to
repack the P-1 OA heater drain pump. A return to full power began at 10:39 pm (EST) on
March 5, 1997. Full power was achieved at 5:59 am est on March 6, 1997. April 11,
1997, marked the 52nd day of the current power production run.
I. Operations
01
Conduct of Operations
01.1
General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. The conduct of operations was considered by the
inspectors to be good; specific events and noteworthy observations are detailed
below.
01.2
High Pressure Air Drawing Discrepancies
a.
Inspection Scope (71707)
The inspectors observed portions of several plant activities.
b.
Observations and Findings
During a routine followup of the safeguards high pressure air system concerns with
plugging of Moore pressure control regulators, the inspectors identified concerns
with controlled drawings. The inspectors identified that a line had been mistakenly
dropped from the high pressure controlled air drawing, M-225, sheet 2, during the
revision process. The inspectors reviewed controlled drawings in the control room
and noted that the drawing had been modified by a penciled in correction. Also,
controlled drawings in the tagging center were observed to be addressed in a
similar manner. Discussions with system engineering noted that they were not
aware of the discrepancy as they were utilizing outdated laminated drawings.
Further followup did not identify that any drawing change had been initiated to
correct the discrepancy.
c.
Conclusions
The inspectors concluded that the drawing error was very minor in nature;
however, the inspectors were more concerned with the failure to properly address
this issue in a timely manner. This concern was discussed at the exit.
4
01.3
Service Water Pump Bay Debris Intrusion
a.
Inspection Scope (71707, 61726 and 62703)
The inspectors followed the licensee's actions in response to continuing fouling of
the service water bay traveling screens and service water pump basket strainers.
b.
Observations and Findings
As a result of a decrease in service water bay level on February 13, 1997, in which
level was observed to have decreased approximately two feet due to icing and
buildup of-.debris on the traveling screens, the inspectors have continued to closely
monitor the licensee's actions to address further service water fouling conditions.
Periodically, throughout the inspection period, the inspectors have observed an
increased frequency of debris intrusion into the service water bay. This condition
has been observed at the service water bay traveling screens, service water pump
basket strainers, and cooling tower pump seal coolers. Since initial identification,
the licensee has taken additional measures to address this concern, including
heightened awareness by both the operating shift and system engineering. The
increased monitoring has resulted in timely identification of debris intrusion by the
operating shift prior to encountering a significant buildup. The inspectors have
observed operations and system engineering involvement in the troubleshooting
efforts to understand the cause of debris intrusion. Initial evaluation of the debris
has indicated that it is not indigenous to Lake Michigan. System engineering has
noted that the debris is from runoff due to recent heavy rains, and its impact is
compounded by high lake levels and westerly wind conditions. The inspectors have
observed increased entry into limiting conditions for operation (LCO) due to
declaring the service water pumps inoperable for service water pump basket
strainer cleaning.
c.
Conclusions
The inspectors concluded that the licensee has provided the appropriate resources
to closely monitor service water bay debris intrusion and provided additional
oversight to monitor icing conditions. The inspectors concluded that continued
monitoring is warranted to ensure system performance is not impaired by further
intrusion of debris past the service water basket strainers into the service water
system.
08
Miscellaneous Operations Issues (92702)
- ---(Closed) Violation 50-255/95014-02: Failure to maintain low press_urizer_ PL~Ss_u_r~
function of safety injection system (SIS) operable. On January 18, 1996, the
reactor was being placed in cold shutdown due to faulted 2400 VAC cables that
supplied the 1 D bus. A work order for disabling the SIS was noted by an electrical
maintenance supervisor. After a discussion with the shift supervisor (SS), a review
of plant conditions, and a review of what were thought to be applicable
5
requirements, the SS released the work order. Primary coolant system (PCS)*
temperature was at approximately 364°F at the time the work order was released.
This work disabled the SIS actuation on low pressurizer pressure when PCS
temperature was approximately 364°F. This was a violation of Technical
Specifications (TS) section 3.17 .2, which required the SIS actuation signal to be
operable above 300°F.
Several program and process barriers were breached requiring corrective actions for
each. For the problems delineated below, the licensee's corrective action in
response to the item is also provided:
.,. __ The work order block marked "TS Involvement" referenced TS 3.17.
However, this section was not referred to and another section of TS was
thought to be the applicable requirement.
All maintenance supervisors were counselled on assuming any prerequisite is met
prior to commencing work. Also, operators, especially senior reactor operators,
were trained to verify information using available references when making decisions
affecting plant status or safety.
Procedure GOP-9, Attachment 1, section 4.4 stated, "When PCS is less than
210°F (ie, cold shutdown), then initiate work order to disable SIS actuation
circuits {refer to SOP-3, step 7. 7 .1 }. " These steps went unheeded in the
decision making process to disable SIS.*
TS 3.16 "Engineering Safety Features System Instrumentation Settings,"
was referenced as the controlling requirement.
Training was given to operators on the significance of adherence to both the TS
and the procedure in conjunction with disabling the SIS actuation signal.
Electrical maintenance procedure ESS~E-24, "Disable/Enable The SIS
Actuation On Low Pressurizer Pressure," section 3.3, specifies plant
condition to be "cold shutdown." Procedure step 5.1 requires the assigned
supervisor ensure all prerequisites are completed. The plant condition of
cold shutdown was not verified.
The procedure was revised in section 3.4 to state, "As controlled by the authorizing
work order." This is standard with other procedures. Section 3.3 still states "cold
shutdown."
SOP-3 section 7. 7 was revised to include reference to ESS-E-24. This procedure
performs the actual disabling/enabling of the SIS circuitry. This item is clQ~ed.
- (Closed) LER 50-255/96-004: Safety injection disabled with primary coolant
system greater than 300°F. This event resulted in Violation 50-255/95014-02.
The inspectors reviewed the adequacy of the licensee's corrective actions
6
pertaining to the LER in response to the violation, as noted above. This item is
closed.
II. Maintenance
M 1
Conduct of Maintenance
M1 .1
General Comments
a.
Inspection Scope (62703 and 61726)
The inspectors observed all or portions of the foUowing work activities:
Work Order No:
- *
- *
- *
24710994:
24511071:
24711073:
24611820:
FIN TEAM:
HSF97080:
24 710599N.2:
Surveillance Activities
Ml-2:
Ml-005A:
Ml-06:
Ml-27E:
Ml-39:
b.
Observations and Findings
Repack of P~1 OA heater drain pump
Repack, disassemble pump, and decontaminate P-55A
charging pump
DC circuit ground troubleshooting
Perform MSE-E-38 PM/EOPM of Safety Related
Limitorque Type SMB Actuators on VOP-307 2
(charging pump line to SI test line isol. valve)
Replacement of failed diaphragm on CV-5501, M-598
Evaporator Concentrator level control valve
Hot spots flu'sh on tilt pit drain line
Perform resin removal and flush line from tank T-80
equipment drain tank
Reactor Protective Trip Units
Containment High Pressure Test *
Area Monitor Operational Checks
Functional Check of PCS Low Temperature
Overpressure Protection (L TOP) System
Auxiliary Feedwater Actuation System Logic Test
The inspectors found the work performed under these activities to be professional
and thorough. All work observed was performed with the work package present
and in active use. Work packages were comprehensive for the task and post
maintenance testing .requirements were adequate. The inspector_s_fr_e_quently _______ .
observed supervisors and system engineers monitoring work practices. When
applicable, appropriate radiation control measures were in place.
7
c.
Conclusions
In general, the inspectors observed good procedure adherence and maintenance
practices. However, detailed below is the inspectors' follow up to the main steam
isolation valve issue that occurred during the 1996 refueling outage. The
inspectors' and licensee's review of this event identified several maintenance
process and human performance issues. See the specific observations detailed
below.
M1 .2 Main Steam Isolation Valves (MSIVs) Repair Issues
a.
Inspection Scope (62703)
In inspection report 50-255/96017, the inspectors reviewed the events that led to
potentially inadequate repairs to the stuffing box plugs in both main steam isolation
valve (MSIV) leakoff lines; identified as an unresolved item 50-255/96017-04. This
was a followup by the inspectors to the process weaknesses found and the
licensee's actions to prevent recurrence.
b.
Observations and Findings
On December 20, 1996, with the plant in hot shutdown, both MSIVs (CV-0501 and
CV-0510) were found leaking steam from the plugged west stuffing box leakoff
points. Initially, the valve contractor and the planning organization were requested
to evaluate appropriate repairs. The licensee decided a temporary leak repair was
. .
preferable; otherwise, the plant would have to return to cold shutdown to perform
permanent repairs.
Initial inspections identified that CV-0501 had a pinhole leak and CV-051 O had
several pin hole leaks at the threaded connection. The licensee's temporary leak
repair vendor, after an earlier initial review of the job, was brought onsite to initiate
repairs on January 6, 1997. The plant was at 20 percent power. The vendor
began drilling on CV-0510 first. However, drilling stopped when the vendor noted
leakage through what appeared to be fractures in the plug. Work was stopped on
CV-0510 and a decision was made to proceed on CV-0501. On CV-0501 , the
vendor began drilling into the pipe plug to prepare for threading in the leak injection
fitting. However, the vendor stopped because steam began leaking almost
immediately after the start of drilling, which would be indicative of an abnormal
configuration of the high pressure pipe plug. The inspectors noted that the licensee
did not evaluate problems with CV-0510 prior to starting work on CV-0501.
Licensee management was informed of the valves' condition and decided to bring
the plant to cold shutdown to make permanent repairs.
The inspectors reviewed past valve history. CV-0501 began leaking at the leakoff
plug in 1992. Leakage was minimal. System engineering trended leakage until the
1993 refueling outage. Although permanent repairs were performed, a work
history did not exist. A seal weld was requested but was not performed. In 1995,
another leak developed at the plug. The plug was drilled and pumped with a leak
8
sealant. It was subsequently pumped three more times prior to the 1996 refueling
outage. On CV-0510, there was no documented history of leakage of the stuffing
box leakoff pipe plugs.
During the refueling outage, extensive preventive maintenance (PMs) was
performed on CV-0501. As part of these activities, the stuffing box pipe plug was
to be replaced to restore system integrity after a temporary leak injection hole was
drilled into the plug body. Work order 24512907, step 6, required that the original
plug be replaced and seal welded. The original plug was not removed. Instead, on
November 16, 1996, a seal weld was placed over the leak injected plug and around*
the threads. To facilitate seal welding, the hex head of the plug was ground away.
The weld supervisor, after discussions with the valve team supervision approved
this repair even though the weld inspection checklist (WIC) sketch depicted the plug
hex head in place. Failure to adhere to the weld inspection checklist was
considered an example of a violation of 10 CFR 50, Appendix B, Criterion V
(50-255/97005-3A).
Preventive maintenance (PM) was also performed during the outage on CV~0510.
As part of the maintenance, the plug was to be seal welded. This action was taken
as a precaution to prevent leakage similar to CV-0501. Upon inspection, the
welder found the plug appeared to have a square versus hex head. The welder
discussed the condition with the contractor valve team manager instead of the
welding supervisor. Also, problems were encountered during welding, which were
indicative of welding dissimilar metals. The weld used to seal CV-0510 on
November 1 6, 1997, was not the weld specified by the weld inspection checklist.
This was another missed opportunity to identify a problem. The decision to accept
the condition was based on the premise that a non-destructive examination (NOE)
would be performed; therefore, any problems would be identified. A lab report
documenting a metal analysis of the plug indicated the plug material was 125 psig
cast iron versus the specified high pressure steel rated at 3000 psig. This also
explained \\IVhY welding proved difficult. The failure to adhere to the procedure
(weld inspection checklist) is another example of a violation of 1 O CFR 50,
Appendix 8, Criterion V (50-255/97005-038). *
The inspectors noted several maintenance work practice deficiencies during their
inspection. The licensee also identified similar concerns through a special
investigative team assigned to evaluate this condition. First, in the pre-job briefs
held for both MSIV PM activities, the welders were not included. Secondly, there
were design issues involving the grinding away of the hex head and seal welding
over the drilled hole in CV-0501. Both were accomplished without implementing
the required design change controls. Third, the inspectors review and the licensee
investigation identified a lack of questioning attitude on the part of welding
_____ QerSQDQ~I. . T_he as- left GOndition of the plug seal welds was different than
_
indicated on the WIC sketch. The welding supervisor approved the seal weld even
though the WIC sketch depicted the plug head in place. Work orders existed to
cover the general work activities on the valve. However, the WOs were not used
at the work site during the pipe plug activities. The failure to have the work orders
9
.. .........:~.
. c .
d.
at the work site is a third example of a violation of 1 O CFR 50, Appendix B,
Criterion V (50-255/97005-3C).
For CV-0510, the welder found the plug appeared to have a square head versus a
hex head. Also, the plug was degraded as there was a fracture in the head of the
plug. However, the weld supervisor was not made aware of these issues until after
the seal weld was completed, Also, for CV-0510, no records were found that
indicated the plug repairs or modifications were made. Finally, there was no single
point of contact during the maintenance activities performed on the valve for
problem resolution.
Both MSIVs are ASME Code Class 2 valves, which shall be repaired in accordance ....
with ASME Code Section XI. Failure to perform a proper ASME Code repair was
considered a Violation (50-255/97005-01 ).
The inspectors followed the licensee's root cause investigation and subsequent
corrective actions. Both leaking plugs were permanently repaired by installing
3,000 psi forged steel, one inch pipe plugs with high temperature sealant through
design change FES97-003. The issue was discussed with the various work
groups. The event was reviewed, weaknesses identified and corrective actions
discussed. Maintenance management developed action items, which were
incorporated into the department master action plan.
'
Reporta bility
On March 6, 1997, during a management review board (MRS) meeting for condition
report (C-PAL)97-007 the licensee questioned reportability for the unauthorized
repairs conducted to the stuffing box plugs on the MSIV's. Based upon this
discussion, the licensee determined that a 30 day licensee event report (LER) was
required to be submitted to the NRC based upon 10 CFR 50. 73. The inspectors
questioned the licensee's basis for start of the 30 day report, as It appeared that
the licensee had ample information on February 19, 1997, because the results of
the evaluation of the material composition for the stuffing box plug for MSIV
CV-0510 were 'Obtained, which was forwarded from the laboratory to the plant
site. The laboratory results confirmed that the installed stuffing box plug was cast
iron material and; therefore, a 125 psig plug was installed versus the required 3000
psig high pressure steel plug. In addition, on/or about January 10, 1997, adequate
information was available to determine that an unauthorized code repair had been
conducted to MSIV CV-0501, in that an unauthorized seal weld was performed on
the stuffing box plug on the MSIV. This condition was not identified until the plant
was started up on January 6, 1997. The failure to report a condition outside the
design basis of the plant within 30 days is considered a violation of 1 0 CFR 50. 73
. (50-255/97005-02).
- ----- ----- -- ---- -
Conclusions
The inspectors concluded the licensee failed to maintain adequate control over the
MSIV stuffing box valve pipe plug repairs, as evidenced by the procedural violation
10
with three examples. CV-0501 and CV-051 O should have been repaired in
accordance with ASME Section XI and this was considered a violation. Also, the
licensee failed to make a timely report to the NRC, a third violation.
However, the inspectors reviewed the licensee's extensive corrective actions to
date, which demonstrated an understanding of the potential significance of the
event. The inspectors' evaluation of the safety significance determined that had
the pipe plugs actually failed, the safety significance would have been minimal. The
leakage would have represented an additional potential radiological release,
coincident with a steam generator tube rupture. However, the leakage would be
small compared to the large secondary coolant mass released to atmosphere
through the atmospheric dump valves. Sufficient margin existed in the radiological
dose calculations to account for this minor leakage. The inspectors, through
observations of subsequent maintenance work did not identify additional examples
of inadequate procedural adherence or improper oversight of contractor and licensee
maintenance personnel.
MS
Miscellaneous Maintenance Issues (92902)
(Closed) LER 50-255/95-001: Malfunction of left channel design basis accident
(DBAl sequencer resulted in inadvertent actuation of left channel safeguards
equipment. The left channel sequencer, MC-34L, spuriously activated on March 2,
1995. All safeguards equipment responded as required. The licensee formed a
team to determine root cause. The team determined that a failure of the micro-
processor module of the electronic DBA sequencer caused the event. The
sequencer is a programmable logic controller (PLC) that consists of a main micro-
processor and various input/output (1/0) modules for each piece of equipment
actuated by the sequencer. The microprocessor was replaced and operability of the
sequencer verified. The microprocessor was sent to the vendor for testing. The
vendor could not simulate the problem, but agreed with the licensee's conclusion
that the problem was most likely a faulty component that caused an intermittent
- memory or processor error. The inspectors reviewed the historical performance of
the DBA sequencer. A similar event occurred in 1989, to the right channel
sequencer. However, similarity was limited to the loss of active lights on the 1/0
cards and the inability to recreate the failure. In 1995, a polarity sensitive capacitor
was incorrectly installed during manufacture in the processor unit of MC-34L,
which caused its power supply to fail. During repair/diagnosis of the failure by the
vendor, it was determined that a capacitor had been installed backwards and was
the cause of the MC-34L failure. The inspecto.rs concluded that this did not appear
to be a generic reliability or maintenance issue. This item is closed.
{Closed) Violation 50-255/95002-01: Failure to perform the required independent
verifica_tiQIJ. A fieLc;I_ t!3chnician caused a false reactor trip indication while landing __
electrical leads to install a personal computer (PC) to record main generator output
data, per temporary modification (TM)94-017. The TM provided the steps for
installing the PC, but the field technician failed to follow these steps .
11
The inspectors had the following observations concerning the installation of the TM.
For each observation, the corrective action is outlined:
Contrary to TM Procedure 94-017, there was no independent verification
performed for each step of the TM.
Administrative procedure 9.31 was revised so that the independent verification
shall occur concurrent with the TM installation.
The proper method of independent verification was not understood by the
field technician.
The event was reviewed with all technicians. Also, written expectations for work
at Palisades was issued to all technicians.
The quality of the documentation of work performed was poor. Also, the
instructions in the TM were not clear.
The event was reviewed with planners and a memo sent to each planner stating
that relevant information from a temporary modification will be incorporated into
the work order. This event was also reviewed with all maintenance supervisors
sharing lessons learned from this event. The electrical and instrumentation and
control (I & C) supervisors were issued management expectations for work that
involves Consumers employees that are not permanently assigned to the Palisades
plant. A memo was issued to all engineering personnel to review this event. This
item is closed.
Ill. Engineering
E1
Conduct of Engineering
E1 .1
Power Cable Ampacity Review
a.
Inspection Scope (37551)
The inspectors reviewed engineering's progress on the issue of determining if plant
power cables are within Final Safety Analysis Report (FSAR) requirements for cable
ampacity and temperature limits. If a cable was identified outside of these limits,
then the inspectors reviewed the associated operability determination for adequacy.
b.
Observations and Findings
l~_Ln?_Pe!?ti_on report 50-255/96017, the inspectors reviewed the licensee's
development of a degraded equipment list in response to Ge-neric letter (GL). 91--18,-
"Resolution Of Degraded And Nonconforming Condition." This action was taken to
ensure that an appropriate overview of equipment/system operability had been
conducted prior to startup from the 1996 refueling outage. GL 91-18 provides
guidance on resolution of degraded and nonconforming conditions affecting safety-
12
related systems structures and components (SSCs). The inspectors reviewed the
list for thoroughness and potential conflicts with GL 91-18 guidance or
noncompliance with 10 CFR 50 Appendix B "Corrective Action." Specifically, the
inspectors looked for timely and adequate repair or engineering safety analyses of
the issues identified.
One of the issues that came out of the degraded equipment list was the
acceptability of the licensee's methodology for calculating cable ampacity. Since
1988, the licensee has been in the process of reviewing cables within the plant to
evaluate the impact of accelerated aging due to heat degradation of the insulation
caused while energized. The licensee had determined that 2700 of 2900 power
cables in 424 cable trays were routed in trays with greater than 30 percent fill. .. _
The licensee concluded that while certain analyzed cables exceeded Code ampacity
limits, the cable thermal limits were not exceeded and therefore, the FSAR design
basis was met. Section 8.5.2 of the FSAR states, in part, "Cables installed in
ventilated trays, conduit or underground ducts are thermally sized in accordance
with National Electrical Code (NEC) or the Insulated Power Cable Engineer
Association/Insulated Cable Engineer Association (IPCEA/ICEA) ampacity values.
Ampacities are adjusted based on actual field conditions when possible. These
adjustments may include, but not be limited to, conductor operating temperature,
ambient temperature, cable diameter, tray depth of fill, conduit percent fill, and
firestops."
Prior to startup from the 1996 refueling outage on December 25, 1996, the
licensee justified operability of 41 cables based upon a bounding Harshe-Black
analysis. Presently, the Harshe-Black methodology used to justify operability for
these cables has not been approved for use by the NRC. The Code assumes that
all cables are continuously energized and carrying rated current. The Harshe-Black
methodology considers only those cables that are energized for a design basis
accident (OBA). Harshe-Black also differs from the Code in that the code calculated
ampacity limit ensures the cable thermal limit will not be exceeded, while the
Harshe-Black method allows the ampacity limits to be exceeded because field
testing of ampacity (at Palisades) demonstrated that a cable could be above the
100 percent ampacity limit and the cable thermal limit will not be exceeded.
On March 31, 1997, the licensee determined that a number of cables might exceed
the ampacity of the non-refined Harshe-Black methodology; meaning direct readings
of environmental and operating conditions will be required for calculations.
During
this comprehensive review, the inspectors were notified by the licensee that 1 7
cables have been calculated to exceed the Harshe-Black methodology. The licensee
discussed with the inspectors the methods that would be used to determine
operability of the 17 cables. The licensee intends to provide direct temperature and
---cun:ent.measurements and perform a visual inspection to justify c_o!l~inued_ . ______ _
operability of the affected cables. The licensee provided an informal completion
date of the end of 1997 for this review. The inspectors expressed a concern to the .
licensee that this target date may not allow sufficient time to incorporate cable
13
--*-
c.
replacement, if determined necessary, by start of the May 1998 refueling outage.
The licensee has since reevaluated the time required to analyze the cables and
committed to complete evaluations of the remaining cables within a few months.
Conclusions
The inspectors determined the licensee's actions were adequate. The licensee did
not initially appear to be aggressively pursuing resolution of this issue. The NRC
intends to review the licensee's final engineering analysis to determine whether the
cables are within FSAR requirements, degraded but operable, or require
replacement. The licensee has also agreed to incorporate any necessary cable
replacements within the scope of the 1998 refueling outage.
E1 .2 Timely Resolution Of Issues
a.
Inspection Scope (37551)
In inspection report 50-255/97002, the inspectors reviewed the events surrounding
a February 1997, P-66A high pressure safety injection (HPSI) pump breaker trip.
The trip occurred while attempting to charge a safety injection tank (SIT). As part
of that review, the inspectors also looked at a similar event that occurred in July
1996. Specifically, the inspectors reviewed the licensee's timeliness of corrective
actions to address the events.
b.
Observations and Findings
The scenario for the two events was similar. While refilling a SIT following a
sampling collection, the HPSI pump tripped. Inspection of the HPSI pump breaker
revealed that the "Y" phase time overcurrent (TOC) relay had actuated, which
tripped the pump. Also, in October 1996, an auxiliary operator during rounds,
found the "Y" phase TOC relay target had dropped in. In each case, a different*
root cause was determined to have initiated the breaker trip or TOC relay flag to
drop in. The inspectors observed the licensee's actions for each event. Immediate
actions by the licensee were appropriate.
However, when the inspectors reviewed the assigned corrective actions of the
condition report (CR) from the July event, only two of the four corrective actions
had been completed. The procurement of spare relays had been extended from the
original November 1996, to March 1997 completion date. The action to revise
procedure SOP-3, "Safety Injection and Shutdown Cooling System," to permit the
use of the o.ther HPSI pump P-668, to fill the SITs at full primary coolant system
pressure, if justified by engineering analysis, was due to be completed in November
1996. This was also-given an-extension to-April 1997 .. Subsequentl¥., the liceosee_
had re-evaluated the issues. Spare parts have been procured and the procedure
revision completed.
Because of this example and other known instances of lack of a timely response to
issues, the inspectors reviewed the CR tracking system to verify how prevalent this
14
problem may be. The nuclear performance assessment department (NPAD) trended
the total number of CRs granted due date extensions and open CR corrective action
subdocuments for management review. NPAD also independently trended average
CR cycle time. The inspectors discussed with NPAD a concern that there may be
CRs that were given multiple extensions and CRs not meeting the original scheduled
completion period. Also, that system engineering may have the most significant
problem with extensions. From the discussion, NPAD performed a review of the
CR data base. For February 1997, out of the total 138 CRs granted extensions, 92
had one extension, 29 CRs had two extensions, and 10 CRs had 3 extensions.
There was one CR with 8 extensions. In February, only 57. 7 percent of the CRs
met the forecasted completion date. System engineering was granted the most due
date extensions (56) in the month of February.
c.
Conclusions .
The inspectors discussed the findings with NPAD and NPAD agreed the data
indicated a performance concern. Currently, NPAD is trending these additional*
items to determine the significance and what future actions may be necessary.
E 1 .3
Safeguards High Pressure Air System Reliability
a.
Inspection Scope (37551)
The inspectors reviewed the root cause analysis documenting the failure of a
pressure control valve (PCV) and an air regulator for the high pressure safety
injection (HPSI) .control valve. The inspector's review identified what could be
potentially viewed as a generic failure mechanism, the plugging of air regulator
controllers by rust accumulating on the debris screens. The inspectors reviewed
past work history on the PCVs and discussed the safeguards high pressure air
system performance with system engineering.
b:
Observations and Findings
On March 19, 1997, CV-3018, the HPSI discharge control valve cross-tie to train
two, was stroked. The valve was stroked closed and could not be stroked open.
The corresponding air regulator PCV was found to be plugged by rust that.
originated from the west engineering safeguards room high pressure air system
piping, which is carbon steel. The inspectors discussed with system engineering if
this had potential generic implications. From the discussions several longstanding
system deficiencies were noted. The present pressure control valves which were
installed in 1988, due to obsolescence of the previous valve. have a small orifice
with a screen that goes to a pilot chamber. That screen was found clogged with
rust,-which-disabled-the -PCV. The inspectors noted that .the piping-for-the. system- __ _
is carbon steel.
The inspectors reviewed the work history of PCVs and noted that the present PCVs
were installed in 1988, due to observed degradation of the original PCVs.
However, a review of the work history did not identify a reliability problem with the
15
valves. The inspectors, in discussions with system engineering, found that the
license's preventive maintenance program, known as Periodic Predetermined
Activities Control (PPAC), were stopped in 1991, due to concerns with taking the
valve out of service. System engineering had recently reinstituted the PPACs.
However, none of the PPACs have been performed to date. The inspectors
reviewed the safeguards high pressure air system drawings and noted that not all
PCVs were configured the same. Some PCVs had the air filters upstream of the
valve, as would be expected. However, the majority of the filters were located
downstream of the PCVs and system engineering was aware of the discrepancy.
However, the inspectors were concerned that this was a longstanding issue which
had not been resolved. Engineering followup on the issue was found to be minimal.
The inspectors noted nearly all valves have a backup system of either instrument air
or nitrogen. Further, system engineering noted that the pressure control valve
required a 10 psi differential pressure downstream before the PCV opens. The
inspectors identified that this could potentially mean the only time the PCV would
be operated is during the once a refueling outage high pressure air system
performance test. In normal system configuration the only air going through the
PCV is a nominal flow of bleed off air. The inspectors reviewed the refueling
outage performance test, T-205, "High Pressure Air System Performance
Verification." In the 1996 refueling outage the test was not performed. In the
1995 refueling outage, minimal testing was performed. The inspectors noted there
was questionable data from the test. The Final Safety Analysis Report (FSAR)
stated that there will be enough air to stroke required valves after 40 minutes. The
PCVs have a constant bleedoff port, yet the pressure did not dec;:ay after an hour.
Also, after stroking some valves, there was no system pressure loss noted. The
inspectors reviewed the FSAR and Technical Specifications for any testing
frequency requirements. None were found. The HP air system does not have a
design basis document (DBD). A DBD is under consideration for the near future.
In addition, the inspectors reviewed the licensee's probabilistic risk analysis (PRA)
which identified that the high pressure air compressors, C-6A and C-68, were fed
from the opposite train of power than the components they serve. This has led to
some PRA results that would not be expected if the compressor power feeds were
consistent with the served component power feeds. This becomes important in
scenarios where one train of power/components is failed and recirculation is
achieved more than one hour after accident initiation. Since it was demonstrated
that there is only enough air in the receiver tanks to last 40 minutes, the
containment sump valve would not open unless the compressors were available.
This type of scenario is most likely during fire events, especially in the west
safeguards room.
c.
Conclusions
The inspectors identified to the licensee the problems noted. System engineering
has since scheduled PM activiti.es to inspect and clean selected PCVs; specifically,
those that have filters downstream of the PCVs. These have been determined most
susceptible to plugging. System engineering was reviewing the feasibility of
modifications to improve system reportability .
16
- ---~-
Miscellaneous Engineering Issues (92700 and 92903)
(Closed) LER 50-255/95013: Circuit fuse coordination deficiency which affected
Appendix R safe shutdown equipment. Through the licensee's Appendix R
Enhancement Program, it was discovered that fuses in the potential transformer
(PT) circuit for the emergency diesel generator 1-1 were not properly _coordinated.
This could result in the PT primary side fuse blowing when Appendix R fire-related
faults appeared on a PT secondary side circuit. Blowing of the primary side fuse
should occur first to prevent fire-induced circuit faults from affecting diesel
generator operability. When the condition was discovered, compensatory measures
(hourly fire tours of the cable spreading room) were already in place. The lack of
fuse coordination in .the diesel generator PT circuit appeared to be an original design
deficiency.
The inspectors reviewed the Functional Equivalent Substitution (FES) that
documented the licensee's review to install properly sized fuses . .The circuit was
monitored for maximum inrush current and maximum steady state load. With this
information, a proper fuse size was determined .to coordinate with the upstream
fuse and still have acceptable margin for the expected load and available short
circuit current. The inspectors reviewed work order no. 24611 60, that installed the
fuses. This item is closed. *
IV. Plant Support
R 1
Radiological Protection
R 1.1
Maintenance Outages and Daily Radiological Work Practices
a.
Inspection Scope (71750 and 83750)
The inspectors observed radiological worker activities during various maintenance
activities detailed in this inspection report, and also monitored radiological practices
during daily plant tours.
b.
Observations and Findings
The inspectors observation of jobs in progress during the maintenance activities
detailed above revealed that radiation technicians were visible at the job sites. The
technicians took appropriate actions and surveys in accordance with good ALARA
practices.
c.
Conclusions
The inspectors concluded that radiological practices observed during the
maintenance activities and plant daily walkdowns were adequate. The inspectors
had no concerns. Specific observations are detailed below.
17
R 1 .2
Criticality Accident Monitoring
-*a.
Inspection Scope (71750 and 83750)
The inspectors reviewed the licensees conformance with the requirements of 1 0
CFR 70.24, "Criticality Accident Requirements."
b.
Observations and Findings
In reviewing the licensees compliance to 10 CFR 70.24, the inspectors identified
that the licensee had provided two criticality monitors in the spent fuel pool/new
fuel storage area. 10 CFR 70.24(a)(2) requires a monitoring system that is capable
of detecting a criticality which generates radiation levels of 300 rems per hour one
foot from the source of the radiation. It also required that monitoring devices in the
system have a preset alarm point of not less than 5 millirems per hour nor more
than 20 millirems per hour. The device shall be no further than 1 20 feet from the
special nuclear material. The licensee has two radiation monitors located in the
spent fuel pool/new fuel storage areas that are within 1 20 feet of the spent fuel
pool/new fuel storage areas. The area radiation monitors. RIA-2313 and RIA-5709,
Spent Fuel Pool Area Radiation Monitors, are set to alarm locally along with
illuminating an annunciator in the control room at a preset value of 1 5 millirems per
hour. The inspectors observed monthly surveillance testing which confirmed that
the alarm setpoints were properly established. In reviewing the instrument
sensitivity, the inspectors were unable to locate an*y analysis to support the
instruments ability to detect a criticality which generates radiation levels of 300
rems per hour at one foot. The licensee's review was unable to locate any
established documentation. The licensee had taken action, in response to the
inspectors concerns, to prohibit further receipt of new fuel in the new fuel vault
until adequate supporting instrument sensitivity analysis can be provided.
However, the licensee has provided a supporting analysis that concludes that the
reactivity will be less than 0.95 under worst case for the new fuel storage array.
In reviewing the licensee's procedures, the inspectors identified that the licensee
utilizes Alarm Response Procedure (ARP)- 8, "Safeguard Safety Injection and
Isolation Scheme EK-13 (EC-13)," upon initiation of a criticality alarm. After
confirmation of a valid alarm, Off Normal Procedure (ONP)-11.2, "Fuel Handling
Accident," is implemented to ensure that the appropriate steps are taken including
evacuation of personnel from the affected area. The licensee has identified that
evacuation drills have been conducted for simulated fuel handling accidents during
annual exercises and provided training on site specific alarms including area
radiation monitor alarms as part of the annual General Employee Training. This
training includes recognition of the specific alarm along with the required response
- -----to the alarm. Although the licensee has not conducted_ arw evac~at_ior:i __ q_rjll~;Jor_the _
specific area radiation monitor alarms, this action appears to meet the intent of
18
c.
Conclusion
The inspectors concluded that the licensee's placement of the criticality monitoring
devices were in accordance with 10 CFR 70.24 (a)(2). However, the inspectors
were unable to determine the sensitivity of the monitors, as required by
10 CFR 70.24(a)(2), as the licensee was unable to produce any analysis to support
this conclusion. This was considered an Unresolved Item (50-255/97005-04(DRP)l
pending further evaluation by the licensee.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on April 16, 1997. No proprietary
information was identified .
19
PARTIAL LIST OF PERSONS CONTACTED
-Licensee
R. A. Fenech, Senior Vice President,
Nuclear, Fossil, and Hydro Operations
T. J. Palmisano, Site Vice President - Palisades
G. B. Szczotka,. Manager, Nuclear Performance Assessment Department
D. W. Rogers, General Manager, Plant Operations
D. P. Fadel, Director of Engineering
S. Y. Wawro, Director, Maintenance and Planning
J. L. Hanson, Director, Strategic Business Issues
R. J. Gerling, Design Engineering Manager
A. L. Williams, Acting Manager, System Engineering
T. C. Berdine, Manager, Licensing
J. P. Pomeranski, Manager, Maintenance
D. G. Malone, Shift Operations Supervisor
M. P. Banks, Manager, Chemical & Radiation Services
K. M. Haas, Manager, Training
M. E. Parker, Senior Resident Inspector. Palisades
P. F. Prescott, Resident Inspector. Palisades
20
- -1p 37551:
IP 61726:
IP 62703:
IP 71707:
IP 71750:
IP 83750:
IP 92700:
IP 92903:
INSPECTION PROCEDURES USED
Onsite Engineering
Surveillance Observations
Maintenance Observation
Plant Operations
Plant Support Activities
Occupational Radiation Exposure
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
Followup - Engineering
ITEMS OPENED
50-255/97005-01
Unauthorized Code repair performed on MSIVs
50-255/97005-02
Failure to submit a LER within 30 days as required by 10 CFR
50.73
50-255/97005-03
Failure to perform MSIV repairs in accordance with 10
CFR 50 Appendix B requirements
50-255/97005-04
- Unable to dete.rmine sensitivity of criticality monitors per 10
CFR 70.24
ITEMS CLOSED
50-255/96-017-04 URI
Inadequate repairs to stuffing box plugs in MSIVs
50-255/95014-02
Failure to maintain low pressurizer pressure function of safety
. injection system operable
50-255/96-004
LER
Safety injection disabled with PCS greater than 300 ° F
50-255/95-001
LER
Malfunction of left channel OBA sequencer resulted in
inadvertent actuation of left channel safeguards equipment
50-255/95002-01
Failure to perform the requireq independent verification
50-255/95-013
LER
Circuit fuse coordination deficiency which affected Appendix R
safe shutdown equipment
21
ff--AP
CFR
CR
CV
FES
GL
ICEA
IFI
IPCEA
IR
LCO
LER
NPAD
NRC
ONP
oos
PPAC
P-T--- --- -* . -
RIA
LIST OF ACRONYMS USED
Administrative Procedure
As Low As Reasonably Achievable
Alarm Response Procedure
American Society of Mechanical Engineers
Code of Federal Regulations
Condition Report
Control Room Supervisor
Control Valve
Design Basis Accident
Design Basis Document
Division of Reactor Projects
Functional Equipment Substitution
Final Safety Analysis Report
Generic Letter
High Pressure Safety Injection
Insulated Cable Engineer Association
Inspection Followup Item
Insulated Power Cable Engineer Association
Inspection Report
Limiting Conditions for Operation
Licensee Event Report
Low Temperature Overpressure
Management Review Board
Non-Cited Violation
Nuclear Performance Assessment Department
Nuclear Regulatory Commission
Office of Nuclear Reactor Regulation
Off Normal Procedure
Out of Service
Primary Coolant System
Pressure Control Valve
Programmable Logic Controller
Public Document Room
Preventive Maintenance
Periodic & Predetermined Activity Control
Potential Transformer
Refueling Outage
Radiation Indication Alarm
Safety Injection
Safety Injection System
Safety Injection Tank
22
..
..
--ssc
sv
TM
TS
VAC
Senior Reactor Operator
Shift Supervisor
Systems, Structures and Components
Solenoid Valve
System Operating Procedure
Time Overcurrent
Technical Specification
Volts Alternating Current
Weld Inspection Checklist
- '
September 18, 1998
Mr. Thomas J. Palmisano
Site Vice President and General Manager
Palisades Nuclear Generating Plant
27780 Blue Star Memorial Highway
Covert, Ml 49043-9530
SUBJECT:
PALISADES INSPECTION REPORT 50-255/98015(DRP)
Dear Mr. Palmisano:
On August 21, 1998, the NRC completed an inspection conducted at your Palisades
Nuclear Generating Plant. The enclosed report presents the results of that inspection.
The inspection covered a 7-week period. Areas examined during the inspection are*
identified in the report. Within these areas, the inspection consisted of a selective *
examination of procedures and representative records, interviews with personnel, and
observation of activities in progress. The purpose of the inspection effort was to determine
whether activities authorized by the license were conducted safely and in accordance with
NRC requirements.
The operating crew demonstrated positive command and control while implementing the
emergency operating procedures in response to an inadvertent main feedwater pump trip
and resultant reactor trip. Your staff's root cause analysis for the main feedwater pump trip
- was comprehensive and thorough.
No violations or deviations of NRC requirements were identified.
In accordance with 10 CFR 2. 790 of the NRC's "Rules of Practice," a copy of this letter and
the enclosure will be placed in the NRC Public Document Room.
Sincerely,
Original signed by ..
Geoffrey E. Grant, Director -
Division of Reactor Projects
Docket No.: 50-255
. License No.: DPR-20
Enclosure:
ln~pection Report 50-255/98015(DRP)
n {' r'I r o f\\
.
9810290171 980918
ADOCK 05000255
Cl
See Attached Distribution:
See Previous Concurrences
DOCUMENT NAME: C:\\WORK\\PAL98015.DRP
To receive a copy of this document, indicate in the box "C" =Copy w/o attach/encl
"E" = Copy w/attach encl "N" = No copy
OFFICE
Riii
Riii
Riii
Riii
NAME
Schweibinz/co
Burgess
Shear
Grant
DATE
09/ /98
09/ /98
09/ /98
09/ /98
T. Palmisano
-2-
\\
cc w/encl:
R. Fenech, Senior Vice President, Nuclear
Fossil and Hydro Operations
N. Haskell, Director, Licensing
R. Whale, Michigan, Public Service Commission
Michigan Department of Environmental Quality
Department of Attorney General (Ml)
Emergency Management Division, Ml Department
of State Police
T. Palmisano
-2-
cc w/encl:
R. Fenech, Senior Vice President, Nuclear
Distribution:
CAC (E-Mail)
Fossil and Hydro Operations
N. Haskell, Director, Licensing
R. Whale, Michigan, Public Service Commission*
Michigan Department of Environmental Quality
Department. of Attorney General (Ml)
Emergency Management Division, Ml Department
of State Police
Project Mgr., NRR w/encl
J. Caldwell, Riii w/encl
C. Pederson, Riii w/encl
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SRI Palisades w/encl
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