ML18066A260
| ML18066A260 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 07/30/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML18066A259 | List: |
| References | |
| 50-255-98-10, NUDOCS 9808040109 | |
| Download: ML18066A260 (26) | |
See also: IR 05000255/1998010
Text
U.S. NUCLEAR REGULA TORY COMMISSION
Docket No:
License No:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9808040109 980730
ADOCK 05000255
G
REGION Ill
50-255
50-255/9801 O(DRP)
Consumers Energy Company
212 West Michigan Avenue
Jackson, Ml 49201
Palisades Nuclear Generating Plant
27780 Blue Star Memorial Highway
Covert, Ml 49043-9530
May 7 .through July 1, 1998
J. Lennartz, Senior Resident Inspector
- P. Prescott, Resident Inspector
E. * Schweibinz, Project Engineer
Bruce L. Burgess, Chief
Reactor Projects Branch 6
EXECUTIVE SUMMARY
Palisades Nuclear Generating Plant
NRC Inspection Report 50-255/9801 O
This inspection involved aspects of licensee operations, maintenance, engineering, and plant
support. The report covers the period from May 7 throug~ July 1, 1998.
Operations
There were no unplanned losses of shutdown cooling and the shutdown operations plan
was complied with during the outage. Plant management's decision to restart the plant
with one stage of a primary coolant pump seal in apparent failure was based on several
factors including the associated risk (Section 01.1 ).
The consequences of the momentarily misaligned rod during low power physics testing
were minor; however, the incident was significant from a reactivity management
standpoint and resulted in a non-cited violation of station operating procedures (SOP). In
addition, the nuclear control operators did not implement self-checking techniques while
performing reactivity manipulations. Equipment reliability problems, specifically the
primary indicating position associated with the plant computer, contributed to the rod
being misaligned. The licensee's review of this event in the followup to the condition
report was viewed as adequate. Operations management instituted appropriate
corrective actions to prevent recurrence in a timely manner. However, the initial actions
taken by the on-shift crew to determine the cause were considered weak (Section 01.2) .
Proper plant configuration was not maintained during performance of surveillance
"'
refueling test (RT)-8C and while filling the safety injection tank bottles per SOP-4,
Section 7.1.2. The improper plant configuration was self-revealing, indicated a weakness
in equipment control, and was a violation of regulatory requirements. The self-revealing
incident during performance of RT-8C resulted in pumping approximately 1200 gallons of
water from the refueling cavity to the containment sump while the plant was in the
refueling condition with the shutdown cooling system in operation. The licensee's audit of
equipment control processes in response to the incidents was thorough and effective
(Section 01.3).
Sufficient progress was being made to decrease the number of "control room
deficiencies" and "operations concerns." None of the remaining deficiencies would
significantly challenge the operators (Section 02.1 ).
The control room environment was professional and operator performance was generally
good during plant startup activities. The procedure deficiency that was identified by a
reactor operator during performance of a surveillance test, which prevented starting a
charging pump with no suction source, was a positive. However, the operators
apparently did not trend the appropriate parameters on the plant computer during
- - --performance of a different surveillance test which resulted in the failure to identify that the
refueling cavity level was slowly decreasing. This contributed to dumping 1200 gallons of
water from the reactor cavity to the containment sump while the plant was in the refueling
condition with shutdown cooling in operation (Section 04) .
2
Maintenance
Overall, the inspectors observed during maintenance and surveillance activities, good
procedure adherence and maintenance and radiation work practices (Section M1).
The inspectors have documented past performance issues with the main turbines and
generator. However, the licensee's plans addressed the inspectors' reliability concerns
with the main turbine and were adequate (Section M2.1).
Engineering
The licensee struggled with planning and execution of the primary coolant pump lube oil *
system modifications. The licensee is aware that planning and completing modifications
is an area for improvement, but as yet has been unsuccessful in resolving the problems
(Section E2.1).
Licensee personnel continue to struggle with basic Technical Specification requirements
and their applicability to plant equipment as evidenced by engineering personnel's lack of
understandin.g of what constituted a Technical Specification functional test. This lack of
understanding contributed to the failure of surveillance procedure P0-1 to test the high
startup rate trip and is considered a non-cited violation. The licensee~s review of the
event was found to be adequate. However, this event underscored the necessity that all
plant personnel need to fully understand Technical Specification requirements
(Section E2.2).
Plant Support
Radiological practices obsef\\'.ed during the maintenance activities and plant walkdowns
were adequate (Section R8.1).
- - --
-
--~~ ---~
3
Report Details
Summary of Plant Status
The plant completed a scheduled refueling outage during this inspection period. The reactor was
taken critical on June, 3, 1998, and maintained in hot standby for low power physics testing. The
main generator was synchronized to the grid on June 7, 1998, and power was subsequently
raised to 33 percent. On June 9, 1998, the plant was shutdown to hot standby to perform main
turbine balancing due to elevated main turbine bearing vibrations. The turbine had received
extensive work during the outage. The main generator was then synchronized to the grid on
June, 10, 1998, and plant power was raised to full power on June 13, 1998. The plant has
remaineq at essentially full power since that time.
I. Operations
01
Conduct of Operations
01.1
General Comments (71707)
In general, the decorum in the control room was professional and free of excessive
activities during the outage. Pre-evolution briefs and operator training were conducted
prior to activities which presented increased risk such as establishing shutdown cooling
and mid-loop operations. There were no unplanned losses of shutdown cooling or spent
fuel pool cooling. In addition, the licensee's "Shutdown Operations Protection Plan," was
complied with when the primary coolant system was at less than or equal to
300° Fahrenheit (F).
The first stage of a primary coolant pump seal apparently failed during reactor startup.
The parameters that are monitored for primary coolant pump seal's first stage indicated
that it had not staged as designed. However, the pump seal has four stages which were
all designed to withstand primary coolant system pressure and the probability of all four
stages catastrophically failing was extremely low. Plant procedures required a plant
shutdown if two of the four stages in a primary coolant pump seal failed. Licensee
management assessed the situation and the plant was returned to power operations on
June 7, 1998, and power was raised to 33 percent. Licensee management's basis for the
decision to restart the plant included the following: (1) low risk associated with the other
stages of the primary coolant pump seals failing causing a loss of coolant accident;
(2) plant procedures existed and operator training regarding was conducted to ensure
suffi~ient mitigating actions if a second stage failed; (3) historical experience with the
primary coolant pump seals; (4) the added radiation dose that would be expended to
conduct the repairs; and (5) the vulnerability for other seal failures if the primary coolant
pumps were stopped and restarted to conduct repairs.
The plant was subsequently shutdown on June 9, 1998,Jo.r an unrelated_issue and_then _____ . __ _
returned to power operations on June 10, 1998. The primary coolant pump seal's first
stage, which indicated failed, re-staged for no apparent reason during the plant startup on
June 10, 1998, and the resultant pump first stage seal parameters indicated normal and
remained stable .
4
01.2
Control Rod 13 Misaligned During Low Power Physics Testing
a.
_Inspection Scope (71707)
The inspectors observed the operating crew for the majority of low power physics testing
during plant startup from the 1998 refueling outage. Surveillance Procedure T-191,
"Startup Physics Test Program," was reviewed for adequacy. The pre-job brief for T-191
was observed. The inspectors observed licensee activities during the subsequent
followup to Control Rod Drive 13 being mispositioned, which occurred during low power
physics testing.
Observations and Findings
On June 3, 1998, Control Rod 13 was mispositioned. The control rod was moved to a
position approximately 14 inches further inserted into the core than the rest of the control
rods in its group (Shutdown Group B). Technical Specification (TS) 3.10.4.a stated that a
control rod is considered misaligned if it is out of position from the remainder of the bank
by more than 8 inches. The control rod was restored to an aligned position within two
minutes; exiting the TS. This event occurred during low power physics testing for fuel
cycle 14 in support of plant startup at the end of the 1998 refueling outage.
At the time Control Rod 13 was moved, Section 5.3, "Control Rod Group Worth
Measurements - Rod Swapping Method," of procedure T-191 was being performed. The
reactor operator was diluting and inserting Group B rods using the rod control system in
the manual group mode. This was to compensate for positive reactivity being added from
the dilution, as allowed by the procedure. A 4 inch and 8 inch rod deviation alarm
appeared to annunciate simultaneously and the reactor operator noticed that only
Group B Control Rod 13 was moving. Control Rod 13 was at approximately 74 inches
while the rest of the group was at approximately 93 inches. The reactor operator then
appropriately repositioned rod 13 to be in compliance with the annunciator response
procedure. The crew, at this time, had suspected a rod control system problem.
Subsequent to the Control Rod 13 misposition, the plant information processor (PIP)
failed and all control rod position was lost. The failure was attributed to a PIP softWare
problem causing an electronic buffer to saturate, resulting in the loss of control rod
position indication. The buffer saturated twice within approximately 10-15 minutes. After
the second time, T-191 was aborted and the PIP was rebooted to clear the buffer. Each
time that PIP was lost due to the buffer saturating, both the four inch and eight inch rod
deviation alarms came in simultaneously.
The control room supervisor indicated that the deviation alarms had come in and that only
one rod moved in the bank when the reactor operator was attempting to insert Group B
control rods. The inspectors reviewed the rod trace on the computer for the Group B
control rods. In discussions with the nuclear engineer, it was noted that the reactor
- operator may have had the rod control system in the manual individualmode._T:h.e_ __ .
control room supervisor stated that this was new information. Also, Palisades plant
computer (PPC) showed that only rod 13 was moving which would indicate that rod 13
was selected with the rod control system in the manual individual mode. These
indications were initially not utilized by the on-shift crew to determine the cause of the
mispositioned rod. The inspectors indicated that this was important information that the
5
control room supervisor should have had before the operations crew tried to resolve the
suspected rod control problem.
The decision was made to stop the test until the cause could be determined. The
discussions encompassed a number of potential scenarios that may have led to the
problem, including operator error. No definitive root cause was identified at that time.
However, operations management determined that the surveillance could continue and
instituted the following immediate corrective actions:
Independent verification of rod control switch positions
Another individual monitoring rod positions on the PPC to alert the reactor
operator of potential 4 inch rod deviations
The 4-inch deviation alarm was verified to be functional
System engineering provided monitoring for potential rod control system and
annunciator problems
The inspectors were concerned that the test was allowed to continue without aggressively
trying to determine a definitive root cause. System engineering identified a terminal strip
that had come loose inside the control panels that was associated with the Group B
control rods. However, it was unlikely this contributed to the indications seen. The
terminal board was loose, but there was no evidence (burn marks, etc.) that would
indicate it had come in contact with another electronic device or was grounded. Electrical
tape was placed on a metal strip that was located just below the terminal block to act as
an insulator, as a precaution. System engineering determined that troubleshooting could
not be safely performed during low power physics testing.
The licensee initiated a condition report on the rod misposition. The lfcensee's evaluation
of this event determined the root cause to be inadequate self-checking. The licensee
was working with the vendor to resolve the PIP software problem. Operations
management directed the use of a second verification for control rod reactivity
. manipulations. The licensee decided that rebooting of the PIP software would be done at
25 and 100 percent power, and quarterly thereafter in order to ensure that the electronic
- buffer does not saturate. Operations personnel continued to review the proper actions to
ensure that stop, think, act and review (STAR) is appropriately utilized.
System Operating Procedure (SOP)-6, (Revision 18 - 5/27/98), "Reactor Control System,"
Step 4.1.8, required that the Rod-to-Group deviation shall not exceed 8 inches.
Mispostioning an individual rod greater than 8 inches from its associated group position is
a procedure violation of SOP-6 rod alignment requirements. This non-repetitive,
licensee-identified and corrected procedure violation is being treated as a Non-Cited
Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy
(50-255/98010-01 ).
6
Conclusions
The consequences of the momentarily misaligned rod during low power physics testing
were minor; however, the incident was significant from a reactivity management
standpoint and resulted in a non-cited violation of station operating procedures. In
addition, the nuclear control operators did not implement self-checking techniques while
performing reactivity manipulations. Equipment reliability problems, specifically the
primary indicating position associated with the plant computer, contributed to the rod
being misaligned. The licensee's review of this event in the followup to the condition
report was viewed as adequate. Operations management instituted appropriate
corrective actions to prevent recurrence in a timely manner. However, the initial actions
taken by the on-shift crew to detemiine the cause were considered weak.
01.3
Equipment Control Deficiencies
a.
Inspection Scope (71707)
The inspectors reviewed condition reports (C-PAL-98-1031, C-PAL-98-1037, and
C-PAL-98-1038), control room logs, switching and tagging order 98-00374, operating
procedures, administrative procedures, and applicable piping and instrument drawings
(M203 Sheet 1, Revision 42 and M210 Sheet 2, Revision 26).
b.
Findings and Observations
Administrative procedure (AP)-4.02, Revision 15, "Equipment Control," Step 4.4, required .
that the Shift Supervisor was responsible for maintaining proper plant configuration
(equipment control). However, the following examples of plant configuration deficiencies
resulted in self-revealing incidents during the outage:
Refueling test (RT)-8C, "Engineered Safeguards System - Left Channel,"
Revision 10, was performed on May 16, 1998. The plant was in refueling
shutdown condition (mode}, the shutdown cooling system was in service, the
reactor vessel head was removed, and the refueling cavity was flooded
- (647' 3" elevation). The test's purpose was to fulfill TS testing requirements for
the left channel safeguards and emergency power equipment.
The system lineup established by the procedure failed to verify the position of the
manual isolation valves (ES-3042, ES-3046, ES-3047, and ES-3038) for the
safety injection tanks' pressure control valves. Caution tags hanging on the main
control board for the safety injection tank pressure control valves indicated that
the associated manual isolation valves were closed. However, the manual
isolation valves were opened on May 16, 1998, during a valve lineup restoration
following a non-related work activity. The test line-up required opening the safety
injection.tank pressure control valves and the drain line (CV-3069) to the safety
injection refueling water tank. This lineup established a flow path from the
-*refueling cavity (primary coolant system) to the primary system drain tank via the
inservice shutdown cooling pump: Approximately 1200 gallons of water flowed to
the primary system .drain tank before the operators identified and isolated the flow
path by closing CV-3069. The primary system drain tank subsequently overflowed
to the clean waste receiver tank room in containment.
7
- The crew was unaware that the safety injection tank pressure control valves'
manual isolation valves were opened prior to performing surveillance
procedure RT-BC. The loss of 1200 gallons from the refueling cavity was not
significant regarding core cooling capabilities. However, it was significant from an
equipment control and procedural adequacy standpoint. Caution tags hanging on
the controllers for the pressure control valves on the main control board indicated
that the associated manual isolation valves were closed. These valves were
closed as a matter of convenience during the primary coolant system pressurized
inspection earlier in the outage. However, the caution tags were not specifically
tied to the work activity and did not get cleared when that activity was completed;
therefore, the valve configuration did not match the status as indicated in the
control room. A condition report (C-PAL-98-1031) was generated and entered
into the licensee's corrective action program.
The event required cleanup of the clean waste receiver tank room: which resulted
in an unnecessary 49 mrem of expended dose and two personnel contaminations.
Also, overfilling the primary system drain tank resulted in the associated level
transmitter (LT-1001) being over-ranged, which was later recalibrated. A
condition report (C-PAL-98-1037) was generated and entered into the licensee's
corrective action system.
Fortuitously, this event did not also occur during the earlier performance of RT-80
because the safety injection tank pressure control valves' manual isolation valves
were closed for unrelated maintenance.
The control room operators attempted to fill the safety injection tanks on
May 17, 1998, per Standard Operating Procedure (SOP) - 4, "Containment Spray
System," Section 7.1.2, "To Fill safety Injection Tanks T-82A, T-828, T-82C, and
T-820 With Primary Coolant System Depressurized and Shutdown Cooling in
Service," Revision 19. Pressure in all four safety injection tanks began to rise
slowly and unexpectedly during the fill process. The operators recognized the off-
norrnal condition and secured the fill evolution. Operators dispatched to
investigate the flow path identified that a manual valve (MV-CRW724) in the vent
path to the waste gas system, which should have been open, was caution tagged
closed for an unrelated work activity. The valve was downstream of the safety
inj.ection tank vent valves that were opened by the control room operators per
SOP-4. However, the operators were unaware that MV-CRW724 was closed.
This configuration was entered in the caution tag logbook; however, nothing in the
logbook entry identified that closing MV-CRW724 would preclude venting the
safety injection tanks during filling and this limitation was not recognized by the
operators. Operations personnel generated condition report C-PAL-98-1038
which was designated as "level 2" which required a root cause determination and
identification of actions to prevent recurrence for closure.
The Shift Supervisor's failure to maintain proper plant configuration during performance of
RT-8C-and sop:;.t is a violationAP-4.02. (50-255/98010-02(0RP)).
8
Operations management implemented some immediate corrective actions in response to
the identified plant configuration (equipment control} deficiencies which included an audit
of equipment status control processes. Senior Reactor Operator and Control Room
turnover Sheets, the Equipment Status Control Record, the Caution Tag Logbook, and
the Auxiliary Operator Turnover Sheets were audited for accuracy. Several deficiencies
were identified which included: (1) 12 control room caution tags that no longer applied
were still in place; (2) five caution tags that had been cleared were not signed off in the
log; and (3) eight items on the Equipment Status Control Record had been returned to
normal without having the record updated. The equipment control deficiencies identified
by the licensee during the audit were not safety significant and were immediately
corrected. There were no additional similar equipment control issues following the audit.
Also, the licensee was evaluating the feasibility of tracking equipment status
electronically, or by some other more rigorous method.
c.
Conclusions
The inspectors concluded that proper plant configuration was not maintained during
performance of surveillance refueling test RT-SC and while filling the safety injection tank
bottles per SOP-4, Section 7.1.2. The improper plant configuration indicated a weakness
in equipment control and was a violation of regulatory requirements. The self-revealing
incident during performance of RT-SC resulted in pumping approximately 1200 gallons of
water from the refueling cavity to the containment sump while the plant was in the
refueling condition with the shutdown cooling system in operation. The licensee's audit of
equipment control processes in response to the incidents was thorough and effective.
02
Operational Status of Facilities and Equipment
02.1
Control Room Deficiencies and Operations Concerns (71707)
The inspectors compared the list of "control room deficiencies" and "operations concerns"
that existed before the refueling outage with the list that existed after the outage was
completed. These items were tracked by the licensee's production group. There were
approximately 71 total items contained in these categories prior to the outage.
Maintenance activities were completed on all of the 36 items that were scheduled for the
outage and a few emergent items were added. Thirty-nine total items existed following
the outage. The inspectors reviewed the list of items that remained and noted that work
orders have been developed for all of the items and that they were prioritized. A few of
the items have been scheduled for maintenance while the majority of them are in various
stages of the process (i.e., planning, waiting for parts, waiting for engineering, or waiting
to be scheduled). None of the items are associated with any TS limiting condition for
operation time clock. However, low flow through the failed fuel radiation monitor (RIA-
0202A) has been listed under "control room deficiencies" for approximately 113 days,
which rendered RIA-0202A inoperable. This required daily primary coolant samples for
gross gamma per TS Table 4.2.1.1. Past attempts to. return the failed fuel radiation
monitor to service have been unsuccessful. Senior plant management has directed that
-*--the-appropriate plant staff take ownership of this issue until it is resolved. Engineering
personnel continued to work on
9
this issue. The inspectors concluded that sufficient progress was being made to
decrease the number of "control room deficiencies" and "operations concerns." Also,
none of the remaining deficiencies would significantly challenge plant operators during
normal or emergency plant operations.
04
Operator Knowledge and Performance
a.
Inspection Scope (71707)
The inspectors observed operator performance during plant startup following the outage,
low power physics testing, and routine activities. Also, the inspectors reviewed the
condition report (9S-1031), computer trends, and control room log entries pertaining to
performance of surveillance RT-SC, "Engineered Safeguards System - Left Channel,"
b.
Observations and Findings
The inspectors observed the following during plant startup following the outage:
In general, the control room environment was professional, and unnecessary
activities ~nd personnel were not allowed in the control room.
Three-way communications between control room operators was utilized most of
the time.
The control room supervisor coordinated the startup activities pertaining to the
reactor operator and balance of plant operators. However, the control room
supervisor, at times, focused on single parameters and referenced annunciator
response procedures which detracted from control room oversight responsibilities.
The crew did not appear to anticipate the resultant drop in primary coolant system
average temperature <Tavg) when turbine power was raised at the same time feed
water system flow to the steam generators had to be increased to raise steam
generator levels. The crew subsequently stopped turbine load increase to
stabilize steam generator levels and T avg*
The inspectors noted that the reactor operator identified, during performance of
procedure RT-SO, "Engineered Safeguards System - Right Channel," that there was not a
suction source aligned to the charging pump at the time that the procedure steps
directing starting the charging pump. The "reactor operator did not actually start the pump
and the test was placed on hold until the problem was resolved. The procedure's pre-test
alignment for operation of the charging pumps did not include the required suction source
from the volume control tank. The procedure was appropriately revised and the test was
subsequently completed satisfactorily. The inspectors verified that this same deficiency
did not exist in RT-SC, "Engineered Safeguards System - Left Channel." Procedure
RT-SO had been reviewed prior to the surveillance being performed due to the recent
- --concemwith the adequacy of protedures;-however, the deficiency regarding the charging
pump suction source was overlooked.
While performing surveillance RT-SC, "Engineered Safeguards System - Left Channel," a
flow path was established which resulted in pumping approximately 1200 gallons of water
10
from the refueling cavity to the containment sump. Refueling cavity (primary coolant
system) level could have been monitored using pressurizer level indication. Pressurizer
level and containment sump level could have been trended by the primary plant computer
which would show level changes very quickly if the appropriate trending parameters were
established. However, the refueling cavity level lowered slowly for approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
and 20 minutes without the operators identifying it. A call from personnel inside
containment to the control room regarding water on the floor in the in clean waste
receiver room prompted the operators. Following the call, the operators immediately
isolated the inappropriate flow path by closing CV-3069, which was opened as part of the
test lineup.
c.
Conclusions
The control room environment was professional and operator performance was generally
good during plant startup activities. The procedure deficiency that was identified by a
reactor operator during performance of a surveillance test which prevented starting a
charging pump with no suction source was a positive. However, the operators apparently
did not trend the appropriate parameters on the primary plant computer during
performance of surveillance test RT-BC, which resulted in the failure to identify that the
refueling cavity level was slowly decreasing. This contributed to dumping 1200 gallons of
water from the reactor cavity to the containment sump while the plant was in the refueling
condition with shutdown cooling in operation.
08
Miscellaneous Operations Issues (92901, 92702 and 92700)
08.1
{Closed) Violation 50-255/97008-01: Exceeding licensed thermal power limits. On
February 7, 1996, reactor thermal power was indicated to have exceed the power level
stated in the facility's license. This occurred during a delithiation evolution to control
primary coolant system chemistry parameters. The operations shift was aware that, by
Procedure GOP-12, Revision 12, "Heat Balance Calculation," reactor power was .allowed
to reach 100.99 percent. The power level was controlled and monitored in compliance
with the existing-procedures and resulted in an indicated plant power level slightly in
excess of 100 percent power for nine consecutive hours.
Procedure GOP-12, Revision 12, considered license condition steady state limit to be met
if reactor power averaged over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was below 2530 megawatts (100 percent
power). Minor excursions above 100 percent power were considered acceptable as long
as peak power did not exceed 101 percent and the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> average power was less than
2530 megawatts.
The inspectors issued a task interface agreement (TIA) to the Office of Nuclear Reactor
Regulation (NRR) for resolution of the concern. The response to the TIA stated that
deliberately raising power above the licensed limit was inappropriate: The licensee
performed a more accurate caliormeteric uncertainty analysis. This analysis concluded
that actual power did not exceed the design basis value during _t_he de_lithia1i.on. The
. results of a more accurate ultrasonic flow-meter (UFM) revealed that actual power was
2.2 percent less than the indicated power that was based on the feedwater venturis.
11
However, the licensee concluded that the 'procedural requirements of GOP-12 did not
meet NRC guidance. The following procedure revisions to GOP-12 were completed:
(1) if 100 percent power was exceeded, then power should be immediately reduced to
less than 100 percent due to this being a violation of the license; (2) if reactor power
exceeded 100.99 percent as indicated on the Palisades plant computer, then plant
operation was outside of the design basis; and (3) if power exceeded 100 percent during
a plant transient, then a condition report shall be initiated to evaluate if 100 percent power
was exceeded. This item is closed.
08.2
(Closed) LER 50-255/97-011-00: Starting of a primary coolant pump with steam
. generator temperature greater than cold leg temperature. The inspectors determined that
the corrective actions taken to address violation 50-255/97013-01 were pertinent to this
LER. The violation was closed out in this inspection report (Section 08.3); therefore, this
item is closed.
08.3
(Closed) Violation 50-255197013-01: An inadequate procedure allowed operators to start
a primary coolant pump (PCP) without meeting TS requirements. On October 12, 1997, a
plant heatup was in progress. The plant was at 250 psia and 130° F. Plant prerequisites
and checklists were completed and PCP P-500 was started. Immediately following the
pump start, primary coolant system (PCS) pressure started to rise. PCS pressure rose to
280 psia due to the heat energy that had been transferred from the steam generator
secondary to the PCS. A low temperature overpressure protection (L TOP) actuation did
not occur because the LTOP setpoint at a PCS temperature of 130° F was 310 psia.
Technical Specifications required that starting of a PCP shall not be initiated unless the
steam generator secondary temperature is less than or equal to T cold* *
One method to obtain steam generator secondary side temperature to verify compliance
with TS was to obtain a contact temperature reading from a steam generator secondary
side hand hole cover. However, the temperature provided by this method can differ from
the bulk average temperature if the secondary side fluid is not adequately mixed, which
occurred in this instance.
When the PCS is on shutdown cooling, the return temperature is typically cooler than
indicated PCS temperatures. Use of this temperature as a lower bound value of T cotd is
normally more conservative than direct T cold indication. However, that was not true in this
instance.
Operating Procedure SOP-1, "Primary Coolant System," did not adequately account for
the temperature measurement limitations. The procedure permitted use of shutdown
cooling return temperature instead of T cold to verify compliance with TS. The crew also
failed to question the significance of T cold being lower than shutdown cooling return and
steam generator handhole temperatures.
The licensee took the following corrective actions:
- *----*-The Operations Superintendent conducted a critique of this event with the *
operating crews. Compliance with TS was stressed .
12
-
~ ------- *-
Training for operators was conducted on the effects of steam generator
stratification. This included the effects when PCPs are started and when steam
ge~erators are placed on recirculation or bubbled with nitrogen.
Procedure SOP-1 was revised. A caution was added that if the secondary side of
the steam generators are not on recirculation or nitrogen bubbling, then
stratification may result in a non-representative temperature indication. Also,
starting the first PCP will transfer heat into the PCS or if the steam generators are
cooler than the PCS, starting the first .PCP will transfer heat out of the PCS and
potentially drop PCS pressure below minimum pressure for PCP operation. There
were additional procedural requirements added to ensure compliance with TS that
the inspectors found adequate to prevent a similar recurrence. This item is
closed.
08.4
(Closed) Unresolved Item 50-255/96017-03: Failure to maintain radial peaking factors
within TS limits. On December 30, 1996, the licensee performed a power escalation to
full power following a plant startup from a refueling outage. At approximately 93 percent
. power, a Palisades lncore Detector Algorithm (PIDAL) run confirmed that the core
operation parameters were within limits. The reactor engineer evaluated the data and
determined that it was acceptable to proceed to full power with no further restrictions.
Based on the acceptable PIDAL run at 93 percent power, no further evaluation was
deemed necessary. Full power was -reached on December 31, 1996. During a routine
review that day of the PIDAL, a reactor engineer identified that the maximum total pin
peaking factor value of 1. 957 exceeded the TS limit of 1.954.
The inspectors' review of the event identified the following contributors. There was a lack
of adequate oversight of the power escalation by reactor engineering. A decision to
continue the power escalation following a data review at 93 percent power was viewed as
non-conservative because radial peaking factors were within three percent of the fuel
vendor's evaluation.
,
The licensee completed the following corrective actions. A revised calcu.lation of the
peaking factors was documented in engineering analysis EA-PID-96-04. From the
inspectors' review of the revised calculation it was determined that the actual pin peak
measurement*fell just below TS limits, therefore, no violation of TS occurred.
Procedure T-191, "Startup Physics Test Program," was revised to require at each
five percent increase in reactor power through 95 percent power level, a review of the
resulting PIDAL output and trending of radial peaking factors be performed. Procedure
DWT-12, "Monitoring Reactor Parameters," was revised to include the guidelines to follow
should the margin between radial peaking factors and the TS limits be less than
two percent. Finally, Procedure 4.40, "Reactor Engineering Department Organization and
Responsibilities," was re.vised to provide reactor engineering support for reactor startups,
shutdowns, planned plant power changes and transient recovery. The inspectors have
noted improved reactor engineering oversight during recent plant evolutions. No similar
recent problems have occurred. The inspectors did not view this unresolved_i~_m as a
_ potential TS violation because the-licensee later determined that the TS radial peaking
factor limits were not exceeded. This item is closed.
13
II. Maintenance
M1
Conduct of Maintenance
a.
Inspection Scope (62707 and 61726)
The inspectors observed all or portions of the following work activities:
Work Order No:
24514097
24513328
32800100
16200140
24614167
24714320
Surveillance Activities
T-186 .
R0-127
R0-22
b.
Observations and Findings
EDG1-1, breaker: replace under voltage load shed relay
with qualified seismic qualification users group (SQUG)
relay
P~2s, condensate pump: install new oil cooler
Steam generator E-50A: remove steam generator nozzle
dam
Reactor cavity_: remove 240 rem hot spot from tri-nuke filter
Primary system sampling isolation control valve CV-1910'
weld downstream Class I piping
RCV-2276, nitrogen backup station pressure control valve:
change set pressure from 150 psig to 175 psig
Engineered safeguards system - right channel
Auxiliary feedwater turbine overspeed trip test and governor
setting
Auxiliary feedwater system 18-month test procedure
Control rod drop times
The inspectors noted that the work was performed in a professional and thorough
manner. All work observed was being conducted with the work package present and in
active use. Work packages were comprehensive for the task, and post-maintenance
testing requirements were adequate. The inspectors frequently observed supervisors
and system engineers monitoring work. When applicable, work was done with the
_ -~l?.~Ql?_riate_radiation control rne_asures in place.
c.
Conclusions
Overall, the inspectors observed, during maintenance and surveillanc.e activities, good
procedure adherence, and maintenance and radiation work practices.
14
-*
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1
Low Pressure Turbine Material Condition Concerns
a.
Inspection Scope (62707)
The inspectors observed portions of maintenance inspections and repairs to the low
pressure (LP) turbine. Discussions were held with the engineering manager in charge of
oversight of the inspections and repairs. Portions of vibration testing were observed
during startup from the 1998 refueling outage. Future inspection and repair activities
were also reviewed.
b.
.Observations and Findings
In July 1997, a step change in vibration occurred on the LP "A" turbine (see Inspection
Report 50-255/97009). The licensee and vendor concluded that an approximately
2 inch long piece of shroud had come off the rotor. While performing an LP "A" turbine
inspection during the 1998 refueling outage, it was identified that a blade had been
thrown from the L-3 blade row on the generator end of the rotor. The blade was found in
two pieces inside the turbine casing. A small portion of the blade root remained in the
rotor disc. One other blade in the same group had impact damage too significant to
repair. In combination the blade damage resulted in imbalance of the rotor.
Non-destructive examinations and visual inspections were performed to identify the total
scope of the damage and to assess the overall impact that the resultant imbalance had
on the rotor. Additional problems were identified. This resulted in the removal of five
more blades with root indications as well as the lead blade in the group that contained the
impact-damaged blade. Eventually, the LP "B" turbine was opened and the L-1 and L-3
blade rows were inspected. Five blades on the L-3 generator row, one blade on the L-1
governor end and two blades on the L-1 generator end had indications.
Inspections of other turbine parts identified several other problems. The LP "B" rotor was
not in the optimal position. The rotor differential instrumentation settings should have
been changed to reflect the reduced clearances of the LP "B" rotor. If the differential
alarms had been set properly, operations may have been alerted earlier to the potential
for rotor blade rubbing. Thrust bearing clearances appeared to be excessive. The thrust
shoes and oil seal showed unusual signs of wear.
The blade rows with the damaged blades were totally refurbished during the refueling
outage. Other actions were also completed during the refueling outage to improve the .
turbines' reliability. The licensee is currently reviewing ways to improve long-term
reliability of the turbines and generator. Some of the recommendations for the
1999 refueling outage include: an end to end (HP turbine to generator alignment);
replacement of the thrust bearing, runout checks on all discs, journals and couplings; and*
a review of blade groupings to ensure_that harmonic; reductions are made.
15
c.
Conclusions
The inspectors have documented past performance issues with the main turbines and
generator. However, the licensee's plans addressed the inspectors reliability concerns
with the main turbine and were adequate.
MS
- Miscellaneous Maintenance Issues (92902)
M8.1
(Closed) Unresolved Item 50-255/94012-02: Degraded material condition of charging
Pump P-55A. The inspectors noted an increase in equipment problems associated with
P-55A. Problems were related to design issues and poor maintenance practices. Some
of the problems noted were; poor pump seal package life, banging and vibration problems
in the charging pump suction line, frequent pump speed oscillations and clattering of the
discharge check valve. These and other deficiencies had led to an increased
out-of-service time of P-55A to effect repairs. An underlying factor was the licensee's
inability to determine the root cause or causes associated with the above problems.
The licensee did improve several longstanding problems. A hollow plunger design with a
titanium nitrite coating along with a new Kevlar packing design did extend packing life.
The seal c::ooling system was improved with a new 40 micron filter to remove seal water
impurities. The electric motor was replaced and vibration indications were reduced. The
fluid drive was replaced with a rebuilt unit. Mechanical wear of the fluid drive had
contributed to small speed oscillations. Gauges were installed on the fluid drive oil cooler
to trend oil temperature and pressure to aid in determining future replacement of the
P-55A fluid drive.
However, abnormal banging noises still intermittently occur on the P-55A pump. A
reciprocating pump consulting firm performed a hydraulic survey on the pump. A number
of contributors to the problem were identified. During the 1996 refueling outage, an
attempt was made at installing the required connections for the installation of a suction
booster pump that would increase suction pressure entering the pump cylinder block and
reduce cavitation. This project was unsuccessful due to the difficulty encountered while
performing welding. Licensee efforts are still ongoing to correct the abnormal banging
pump noise.
Suction accumulator performance is also a continuing problem. The bladder typ*e
accumulator is subject to hydrogen migration. Over pressurization of the suction bladder
charge pressure has been observed due to hydrogen migration. System engineering is
currently pursuing potential modifications to the bladder design.
Palisades has made an improvement in charging pump performance. However,
problems are still evident. The licensee has improved monitoring techniques and has a
better idea of the causes of the problems identified; therefore, the inspectors consider
this item closed.
16
.
Ill. Engineering
E2 *
Engineering Support of Facilities and Equipment
E2.1
Primary Coolant Pump P-50C Modification Implementation Difficulties
a.
Inspection Scope (37551)
The inspectors.reviewed the modification and work order package for primary coolant
Pump P-SOC. Discussions were held with the design engineer and maintenance
personnel that performed the work associated with the modification.
b.
Observations and Findings
A modification to enhance the Primary Coolant Pump P-SOC lubricating oil (LO) piping.
system reliability was performed in the 1998 refueling outage. Functional Equivalent
Substitution (FES)97-133 replaced a portion of the skid mounted P-SOC LO piping. The
piping consists of two subsystems, the backup bearing and lift pump oil systems. The
purpose of the modification was to eliminate existing piping flanges that were prone to
developing leaks. The modification replaced part of the carbon steel piping in the
LO subsystem with hoses and stainless steel tubing. The bearing oil coolers were
replaced with identical coolers, but rated for higher pressure. Hoses were chosen to
replace the flanged pipe.
There were a number of difficulties noted with.the job. The responsible maintenance
supervisor generated a condition report (C-PAL-98-1066) that identified several problems.
The hoses that replaced the flanged joints were a longer length than originally anticipated
once the end fittings were installed. This changed severa! dimensions that necessitated
drawing revisions. The stainless tubing was a different outside diameter than expected
which required several of the fittings to be machined in order to fit up and weld. Some
welds also had to be cut and redone. Some fittings had to be cut out and rewelded to
new drawings as a result of drawing changes and parts availability. Oil leaks developed
on the threaded adaptor fittings from the hoses to the LO coolers. The oil systems were
drained and the fittings were soldered into place. No other leaks were identified. The.
problems encountered resulted in more time to complete the modification and higher than
expected dose to maintenance personnel.
c.
Conclusions
The licensee struggled with planning and execution of the P-50C LO system
modifications. The licensee is aware that planning and completing modifications is an
area for improvement, but as yet, has been unsuccessful in resolving the problems .
17
E2.2
High Startup Rate Trip Functional Test Weakness
a.
Inspection Scope (37551)
The inspectors reviewed the licensee's followup actions to address a missed TS
functional test requirement in sur\\teillance procedure P0-1, "Operations Pre-Startup
Test." The corrective action review board meeting was observed. The root cause
evaluation report was reviewed. Discussions were held with members of the condition
report review team.
b.
Observation and Findings
On April 11, 1998, during the review of the safety review for a revision to TS surveillance
P0-1, the engineer performing the review identified that the procedure did not meet the
requirements of TS table 4.17.1 item 3, for a channel functional test of the reactor
protection system (RPS) high startup rate (SUR) trip. The surveillance covered all of the
requirements of a channel functional test for the high SUR trip with the exception of a
step to verify that the trip was received. A channel functional test was required by
TS 4.17.1 within seven days prior to each reactor startup. Fortuitously, successful
completion of Rl-99, "Left Channel Nuclear Instrumentation Calibration," and Rl-103,
"Right Channel Nuclear Instrumentation Calibration," surveillance procedures
demonstrated that the RPS high SUR trip would have performed its design function,
These channel calibration surveillances are performed on an 18-month interval.
The surveillance performed on the original wide range neutron monitors complied with the
original TS, since the nuclear instrumentation (NI) drawer had an internal trip with
external indication that was verified. Subsequently, the wide range NI drawers were .
replaced in 1991, with drawers that did not have internal trip and indication. When this
change occurred, the trip function associated with high SUR was no longer verified. This
oversight may have been due to TS changes, which removed the definition of a channel
functional test from the surveillance requirements section.
In 1994, the wording of the TS surveillance requirements reverted back to the definition
for channel functional test. However, a cross reference list provided by licensing
personnel at the time indicated that the requirements for the high SUR trip were
unchanged, allowing the error in P0-1 to remain.
The licensee's review of the root cause for this event placed much emphasis on
personnel error and administrative procedure guidance relative to departments affected
by TS change requests. Although procedural requirements exist, in practice it was
viewed as mostly an informal process. However,. the inspectors viewed the subsequent
discussions between engineers and members of the review team regarding the definition
of a channel functional test and its testing requirements as most significant. During the
subsequent review of other potentially affected procedures .. the engineers involved had
many questions pertaining to what constituted a TS channel functional test. The
inspectors determined that this was a similar basic laGk-of understanding of TS which
was a root cause for the simultaneous cross-tying of two trains of high pressure safety
injection detailed in Report 50-255/98007(DRP).
18
The licensee recognized the significance of this issue and how it related to other
procedural deficiencies discussed in previous inspection reports. Th.e operations
procedure group had a new supervisor recently appointed and the staff was augmented.
Training on TS was being planned for licensee personnel. Procedures were being
reviewed to ensure TS requirements were met. This will be a long-term issue, due to
upcoming implementation of the Improved TSs and size of the procedure backlog. No
other similar procedural deficiencies have been noted. This non-repetitive, licen*see-
identified and corrected violation of TSs is being treated as a Non-Cited Violation,
consistent with Section Vll.8.1 of the NRC Enforcement Policy (NCV 50-255/98010-03).
. c.
Conclusions
Licensee personnel continued to struggle with basic TS requirements and their
applicability to plant equipment as evidenced by engineering personnel's lack of
understanding of what constituted a TS functional test. This la~k of understanding
contributed to the failure of surveillance proced'ure P0-1 to test the high startup rate .trip
and is considered a non-cited violation. The licensee's review of the event was found to
be adequate. However, this event underscored the necessity that all plant personnel
need to fully understand TS requirements.
Miscellaneous Engineering Issues (92903 and 92700)
E8.1
{Closed) IFI 50-255/96003-03: Clarification of the Final Safety Analysis Report (FSAR)
and revisions to the refueling procedure. The inspectors had noted an inconsistency
between the FSAR and an engineering analysis. Specifically, the analysis stated that the
earliest possible time to begin a full core offload to the spent fuel pool (SFP) was seven
days (168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br />). It stated further that the analysis was conservative since the seven
days were from the time the reactor attains cold shutdown and does not account for the
time between reactor shutdown and cold shutdown. However, the FSAR stated loading
of the pool could begin 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> after shutdown .. Also, the inspectors noted the
refueling operations procedures had no precautionary or limitation statements about the
168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> wait time prior to fuel movement.
The licensee reperformed the engineering analysis (EA-A-PAL-96-011) to calculate the
heat removal capacity of the SFP cooling system, given an expected heat removal
capacity from discharged fuel. Technical Specification 3.8.5 required that the SFP tilt pit
storage area water temperature not exceed 150°F. The analysis assumed the 150°F
limit. A part of the engineering analysis calculated the maximum SFP heat removal
capacity with only one SFP cooling pump operating and assumed a 1 O percent reduction
in design SFP cooling pump flow. Also the component cooling water (CCW) flow through
the SFP cooling heat exchanger with only one pump running with a 1 O percent
degradation factor was assumed. The CCW inlet temperature was based on the design
limit of 90°F. A heat exchanger fouling factor was also assumed. The SFP cooling
design heat load was determined to be 28.64 x 106 Btu/hr. The second part of this
engineering analysis determined the bounding core off-load scenario. The scenario was
comprised of successive one-third core offloads followed by a full core offload occurring
150 d_ays after the beginning of the previous off-load's cooling time. The previous offload
--. needed to have cooled for a minimum of 150 days to prevent the heat load from
. exceeding the SFP heat removal capacity design limit. This scenario could happen if
damage occurred to the primary coolant system during a cycle that required the vessel to
19
be unloaded. The scenario chosen was more conservative than the actual Palisades off-
load history. The spent fuel decay heat load was calculated using the NRC Branch
Technical Position ASB 9-2, "Residual Decay Energy for Light-Water Reactors for long
Term Cooling." The calculated scenario required a cooling time of nine days (216 hours0.0025 days <br />0.06 hours <br />3.571429e-4 weeks <br />8.2188e-5 months <br />)
before core off-load could begin and stiff match the SFP cooling system heat removal
capability. The inspectors did note one problem with the calculation. The wrong revision
of the engineering analysis was referenced in the FSAR. The licensee planned to initiate
an editorial change to correct the deficiency.
The inspectors reviewed I icensee and Westinghouse vendor procedures to ensure that
fuel had decayed at least 216 hours0.0025 days <br />0.06 hours <br />3.571429e-4 weeks <br />8.2188e-5 months <br /> prior to movement of any fuel from the reactor to the
spent fuel poof. Both the licensee GCL 11.1, "Refueling/Fuel Handling Prerequisite
Master Checklist" and the vendor's Refueling Procedure CPAL-RFM-003 had been
revised to reflect the new engineering analysis. The FSAR Section 9.4, "Spend Fuel Poof
Cooling System" was also revised. This item is closed.
EB.2
{Closed) LER 50-255/97-003-00: Potential for steam voiding and water hammer in
containment air cooler system, and for over pressurization of closed piping systems. The
inspectors determined that the corrective actions to address this LER were pertinent to
unresolved item 50-255/96010-02. Therefore, this LER is closed and will be tracked by
the unresolved item.
EB.3
(Closed) LER 50-255/97-013-00: Failure to closure test two check valves results in a
violation of TS 6.5.7. This issue was addressed in the architectural engineering foffowup
inspection report 50-255/98003(DRS). The inspectors determined that the corrective
actions to address this LER were pertinent to violation 50-255/98003. Therefore, this
LER is closed and will be tracked by the violation.
E8.4
(Closed) LER 50-255/95006-00: *Inadequate auxiliary feedwater (AFW) pump low suction
pressure trip setpoints. Technical Specification 3.5.1 required, in part, that prior to
heating the primary coolant above 300°F, there shall be a minimum total of 100,000
gallons in the condensate storage and primary coolant system makeup tanks. This
volume is based on having enough water inventory to run the AFW system for eight hours
following a reactor trip. An engineering review of the AFW pumps for vortexing and air
~ntrapment showed that the possibility for pump damage existed at low tank levels.
Additionally, it was determined the low suction pressure trip (LSPT) setpoints were
improperly set because vortexing at various flow rates was not taken into consideration.
An inspection of the tank for a vortex breaker found that no vortex breaker was installed;
however, the inspection found that the AFW suction ended in a 10-inch standpipe which
was not indicated on any of the available drawings. The results of these reviews
determined that the AFW pumps had not been properly protected from a pump trip due to
vortexing or air entrapment and that the 100,000 gallon inventory would not have been
available during all post accident scenarios. The following corrective actions were taken:
The LSPT setpoints were adjusted to ensure no more than 5 percent air
entrapment to the AFW pumps.
.---- ----- :---
-;-The condensate inventory calculation was revised to take into account the new
LPST setpoints .
20
.
I
The standpipe was cut down to 1.25 inches in length to reduce the unused water
inventory which would remain at the bottom of the tank.
The plant modification package (FC-954) which changed the LPST setpoints also
added several cautions which required the operators to closely monitor the
running AFW pump when the tank level approaches the trip level.
The licensee identified this issue during a review of design calculations on the AFW
system to address vortexing and air-entrapment; therefore, it is reasonable to assume it
would not have been found sooner. The alarm setpoints have been changed to reflect
the recent vortexing calculations. These actions appeared adequate to prevent
recurrence. This non-repetitive, licensee-identified and corrected violation is being
treated as a Non-Cited Violation (50-.255/98010-04), consistent with Section Vll.B.1 of the
NRC Enforcement Policy. This item is closed.
IV. Plant Support
R1
Radiological Protection
R8.1
Refueling Outage and Daily Radiological Work Practices (71750 and 62707)
a.
- Inspection Scope (62707)
The inspectors observed radiological worker activities during various maintenance
activities detailed in this report, and also monitored radiological practices during routine
plant tours. The inspectors' observation of jobs in progress revealed that radiation
technic.ians were visible at the job sites. Also, the technicians took appropriate actions
and surveys in accordance with good ALARA practices. The inspectors concluded that
radiological practices observed during the maintenance activities and plant daily
walkdowns were adequate.
S1
Conduct of Security and Safeguards Activities (71750)
During normal resident inspection activities, routine observations were conducted in the
areas of security and safeguards activities using Inspection Procedure 71750. No
discrepancies were noted.
F1
Control of Fire Protection Activities (71750)
During normal resident inspection activities, routine observations were conducted in the
area of fire protection activities using Inspection Procedure 71750. No discrepancies
were noted.
- -- - --------
21
V. Management Meetings
X1
Exit Meeting
The inspectors presented the inspection results to members of licensee management at
the conclusion of the inspection on July 1, 1998. No proprietary information was
identified by the licensee .
22
..
PARTIAL LIST OF PERSONS CONTACTED
Licensee
R. A. Fenech, Senior Vice President, Nuclear, Fossil, and Hydro Operations
T. J .. Palmisano, Site Vice President - Palisades
M. P. Banks, Manager, Chemical & Radiation Services
E. Chatfield, Manager, Training
P. D. Fitton, Manager, System Engineering
R. J. Gerling, Manager, Design Engineering
K. M. Haas, Director, Engineering
N. L. Haskell, Director, Licensing
R. L. Massa, Shift Operations Supervisor
J. P. Pomeranski, Manager, Maintenance
D. W. Rogers, General Manager, Plant Operations
G. B. Szczotka, Manager, Nuclear Performance Assessment Department
S. Y. Wawro, Director, Maintenance and Planning
R. G. Schaaf, Project Manager, NRR
23
INSPECTION PROCEDURES USED
IP 37551:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
Onsite Engineering
Surveillance Observations
Maintenance Observation
Plant Operations
Plant Support Activities
IP 92700:
IP 92901:
Follow-up Licensee Event Reports
Follow-up Operations
IP 92902:
Follow-up Maintenance
IP 92903:
Follow-up Engineering
ITEMS OPENED AND CLOSED
ITEMS.OPENED
50-255/98010-01
50-255/98010-02
50-255/98010-03
50-255/98010-04
ITEMS CLOSED
50-255/94012-02
50-255/95006-00
LER
50/255/96003-03
IFI
50-255/96017-03
50-255/97008-01
50-255/97-11-00
LER
Failure to follow procedural requirements pertaining
to control rod alignment
Inadequate equipment control
Faih.~re to perform a TS channel functional test *
Inadequate auxiliary feedwater pump low suction
pressure trip setpoints
Degraded material condition of charging pump
Inadequate auxiliary feedwater (AFW) pump low
suction pressure trip setpoints
Clarification of the Final Safety Analysis Report and
revisions to the refueling procedure
Failure to maintain radial peaking factors within TS
limits
Exceeding licensed thermal power limits
Starting of a primary coolant pump with steam
generator temperature greater than cold leg
temperature
24
50-255/97013-01
50-255/97-03-00
LER
50-255/97-13-00
LER
50-255/98010-03
50-255/98010-04
Inadequate procedure which allowed operators to
start a primary coolant pump without meeting TS
requirements
Potential for steam voiding and water hammer in
containment air cooler system, and for over
pressurization of closed piping systems
Failure to closure test two check valves results iii a
violation of TS 6.5.7
Failure.to perform a TS channel functional test
Inadequate auxiliary feedwater pump low suction
pressure trip setpoints
25
A LARA
ccw
CFR
CV
EOG
IFI
KV
LER
NI
NRC
PIDAL
PSIA
SUR
TS
UFM
v
LIST OF ACRONYMS USED
As Low As Reasonably Achievable
. Component Cooling Water
Code of Federal Regulations
Control Valve
Division of Reactor Projects
Division of Reactor Safety
Final Safety Analysis Report
Inspection Follow-up Item
Kilo-Volts
Licensee Event Report
Lubricating Oil
. Low Temperature Over pressurization Protection
Nuclear Instrumentation
Nuclear Regulatory Commission
Nuclear. Reactor Regulation
Primary Coolant Pump
Primary Coolant System
Public Document Room
Palisades lncore Detector Algorithm
Plant Information Processor
Palisades Plant Computer
Pounds per Square Inch Atmospheric
Po.unds per Square Inch Gravity
Regulatory Guide
Refueling Operations
Refueling Technical
Spent Fuel Pool
Start Up Rate
Task Interface Agreement
Technical Specifications
Ultra-sonic Flow Meter
Unresolved Item
Volts
Violation
26