ML18065B216
| ML18065B216 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 04/16/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML18065B214 | List: |
| References | |
| 50-255-98-02, 50-255-98-2, NUDOCS 9804270158 | |
| Download: ML18065B216 (24) | |
See also: IR 05000255/1998002
Text
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U.S. NUCLEAR REGULATORY COMMISSION
Docket No:
License No:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
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9804270158 980416
ADOCK 05000255
G
REGION Ill
50-255
50-255/98002 (DR P)
Consumers Power Company
212 West Michigan Avenue
Jackson, Ml 49201
Palisades Nuclear Generating Plant
27780 Blue Star Memorial Highway
Covert, Ml 49043-9530
January 28 through March 13, 1998
J. Lennartz, Senior Resident Inspector
P. Prescott, Resident Inspector
Bruce L. Burgess, Chief
Reactor Projects Branch 6
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EXECUTIVE SUMMARY
Palisades Nuclear Generating Plant
NRC Inspection Report No. 50-255/98002
This inspection reviewed aspects of licensee operations, maintenance, engineering, and plant
support. The report covers a seven-week period of resident inspection.
Operations
Conservative decision making was noted by the inspectors during plant startup and
subsequent power escalation following emergent equipment problems. Plant response to
emergent issues was prompt and appropriate actions were implemented (Section 01.2).
The failure to properly secure a watertight door in accordance with procedural
requirements was a violation. Also, the inspectors identified several weaknesses in the
initial evaluation of.watertight door Number 59. The primary concern was a lack of safety
focus associated with the engineering department's review of the* undogged door. The
re-review and proposed corrective actions were more thorough (Section 02.1 ).
The inspectors noted that previously identified procedural weaknesses in the cold
weather checklist still existed. More significantly, the inspectors noted a large backlog of
outstanding procedure change requests. The inspectors were concerned that the long
delay of incorporating procedure ch~nges would have a negative impact in that licensee
personnel would be reluctant to submit additional needed procedure change requests.
Licensee management promptly allocated more personnel to the procedures group
(Section 03.1).
The licensee identified a condition outside the design basis involving inadequate
procedural guidance to ensure that high pressure air is restored during a loss of coolant
accident concurrent with a loss of power to the high pressure air compressors. Prompt
appropriate corrective actions were taken. This was considered a non-cited violation.
(Section 03.2).
The crew used procedures appropriately and completed the mitigative actions for the *
inadvertent containment high radiation in a timely manner. Crew communications, at
times, were weak (Section 04.3).
An independent team completed an audit in the area of operations. Overall, the audit
team concluded that the operations department at Palisades was functioning effectively.
The team reviewed individual procedure weaknesses and concluded they were minor.
However, the number of outstanding procedure changes was a concern. The audit
team's observations regarding procedures validated the inspectors concerns in this area
(Section 07.1)
2
Maintenance
Overall, good procedure adherence and maintenance work practices were noted ..
However, examples of weaknesses in post maintenance testing continued
(Section M1 .1 ).
Problems with control rod drive contactors continue. However, the problem associated
with Control Rod Drive 35 was caused by an error in reassembly of the contactor after
cleaning and inspection. Post maintenance testing for CRD 35 was considered
appropriate (Section M4.1).
Engineering
The redundant capability of the instrument air system was good. However, reliability of
the compressors appeared to be a problem due to service water silting problems, which
had not been addressed by the licensee (Section E2.1).
The licensee's review and root cause analysis of the circumstances surrounding the
inadvertent containment high radiation event were rigorous. This resulted in identification
of a condition outside design basis regarding the containment radiation monitoring
system. The proposed corrective actions were considered thorough. This was
considered a non-cited violation. (Section E7).
Plant Support
The inspectors identified a common misunderstanding among licens~e personnel for the
posted radiological requirements applicable to 2400 volt electrical Bus 1 C. Prompt and
thorough corrective actions were taken (Section R8.1 )~
- ~,
Emergency Planning personnel effectively used an emergency drill to accomplish stated
objectives and to conduct training. The problems associated with an untimely response
of a search and rescue team identified last year was not evident during this drill
(Section PS) .
3
Report Details
Summary of Plant Status
The plant was at full power at the start of the inspection period. The plant was shutdown from
February 6 through 8, 1998, for a scheduled outage to refill the P-SOC primary coolant pump
motor oil reservoir and to inspect the pump for oil leakage. Operators completed the reactor
startup on February 8, 1998, and the generator was synchronized to the grid on February 9,
1998. The power escalation was put on hold at 22 percent power on February 10, 1998, due to
noted problems with the thermal margin monitors. Operations resumed the power escalation on
February 11, 1998, and the plant was at essentially full power on February 12, 1998.
I. Operations
01
Conduct of Operations
01.1
General Comments {71707)
The inspedors conducted frequent reviews of ongoing plant operations. The inspectors
considered that the conduct of operations was generally good; specific events and
noteworthy observations are detailed below.
01.2
Plant Maneuvering for Planned Outage
a.
Inspection Scope (71707)
The inspectors observed selected activities during a planned out~ge on February 6-8,
1998, including plant shutdown and startup. The inspectors also observed various
activities during the power escalation.
b.
Observations and Findings
The licensee determined, based on trending data, that a slight pre-existing oil leak on
Primary Coolant Pump (PCP) P-SOC would have resulted in a motor oil reservoir low level
prior to the start of the 1998 refueling outage scheduled in late April 1998. Therefore, a
short outage was scheduled to add oil to the PCP P-SOC motor oil reservoir. Observation
of PCP SOC during a containment entry did not identify new oil leaks and it was noted that
the leakage from existing oil leaks were contained within the pump's oil collection system.
Control rod drive (CRD) problems emerged while the plant was in hot standby during the
approach to criticality on February 8, 1998, following the outage. The plant was placed in
hot shutdown to investigate and conduct CRD repairs. Licensee management was
contacted and immediately responded to the plant. A management meeting was held to
discuss the circumstances surrounding the CRD problems. The discussions included
potential procedural adherence and maintenance practice deficiencies. No procedural--
adherence problems were noted; however, a deficiency regarding maintenance practices
(discussed further in Section M.4, "Maintenance Staff Knowledge and Performance," of
this report.) was identified. The plant startup was successfully completed later that same
day following the CRD maintenance.
4
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C.
During the power escalation on February 10, 1998, with reactor power at approximately
22 percent, problems with the Thermal Margin Monitor (TMM) emerged which potentially
affected equipment operability. The TMMs are part of the excore power distribution
monitoring system and provide the Thermal Margin/Low Pressure (TM/LP) reactor trip
signal to the reactor protection system as well as nuclear flux offset alarms. Operations
and plant management conservatively stopped the power escalation for approximately
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> due to the TMMs' questionable operability. An investigation revealed that the
TMMs were always operable. An escalation to full power was successfully accomplished
following the determination that the TMM's were operable.
Conclusions
Plant managements' decisions regarding the plant startup and subsequent power
escalation following emergent equipment problems were conservative. Management
response to emergent issues was prompt and appropriate actions were directed.
02
Operational Status of Facilities and Equipment
02.1
Safeguards Watertight Door Issue
a.
Inspection Scope (71707 and 37551)
The inspectors reviewed the investigation conducted by plant personnel into the
circumstances surrounding watertight door Number 59. This door is located between the
east and west safeguards rooms and was found undogged. The Final Safety Analysis
Report and design basis document (DBD) - 7.08, "Plant Protection Against Flooding,"
were reviewed. The inspectors also observed a management review board meeting on
this issue.
b.
Observations and Findings
On January 13, 1998, a maintenance worker found the watertight door between east and
west safeguards undogged. There was no one present, other than the maintenance
worker, in either room at the time. The licensee's investigation could not determine the
individual responsible for leaving the door undogged. The sign on the door delineating
the watertight door requirements was worn to the extent that the wording was not
discernable.
Administrative Procedure (AP) 4.02, "Control of Equipment," required that When the
watertight door was not in use then all dogs are engaged or, if someone is in the room,
only one dog is engaged. Failure to properly secure watertight door Number 59 in
accordance with AP 4.02 requirements was considered a violation of 10 CFR Part 50,
Appendix 8, Criterion V (50-255/98002-01 ).
The licensee initiated a Level II condition report and assigned a condition review team
leader (CRTL). The CRTL was responsible to ensure that the condition report was
investigated and analyzed to determine root cause(s) and that appropriate corrective
actions to prevent recurrence were identified.
5
The inspectors identified several weaknesses in the licensee's initial review. The internal
flooding analysis documented in DBD - 7.08 takes credit for operator action within
10 minutes to mitigate flooding caused by line ruptures and relies on remote detection by
operators in response to sump alarms in the control room. *However, the inspectors
noted that the alarm and response procedure (ARP) - 8 for an east or west safeguards
room sump high alarm was deficient in that Operator action was limited to verification of
sump pump operation indication in the control room. There was no requirement to have
an auxiliary operator inspect the cause for the alarm or the condition of the flooding in
either room. DBD - 7.08 also took credit for hourly fire tours by security as a means of
flood detection. However, the inspectors determined that hourly fire tours were not
occurring. The inspectors also noted that the flood door at one time was alarmed to
security's secondary alarm station by a micro-switch that actuated the alarm when the
door was opened. The inspectors were initially told by engineering that this was for a
high radiation alarm. The inspectors reviewed the high radiation alarm schematics and
found that the licensee's assumption was incorrect.
The inspectors noted that the micro-switch was referenced in security schematics. The
technician responsible for maintaining security equipment recalled during discussions
with the inspectors that the door was alarmed for watertight purposes. Included in
DBD - 7.08 was "NRC Guidelines for Protection from Flooding of Equipment Important to
Safety" which indicated that an alarm was a method to control watertight doors. This was
included as a reference to Safety Evaluation Plant (SEP) Topic V1-7.D. However,
Palisades was built prior to issuance ofthe SEP and was therefore not committed to its
requirements. The inspectors questioned why this would be included in the DBD.
However, neither the inspectors nor licensee personnel could find any documented
reference as to when and why. the micro-switch was disconnected.
The inspectors were concerned that the licensee's initial review did not focus on the
safety implications of the door being left open. The licensee's determination was that
flooding concurrent with the need for emergency core cooling systems to mitigate an
accident was not a valid assumption. However, the plant would find it difficult to ensure
safe plant operation after a flooding event that involved both trains of emergency core
cooling. The licensee conducted a second review of watertight door Number 59 following
discussions with the inspectors. A proposed corrective action from the second review
was to perform an engineering evaluation regarding a door 59 alarm because of the
potential for losing both trains of emergency core cooling systems due to flooding.
c.
Conclusions
The inspectors identified several weaknesses in the licensee's initial evaluation regarding
improper dogging of watertight door Number 59. The main concern was the licensee's
lack of safety focus during their review. The inspectors found the second review and the
proposed corrective actions more thorough.
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03
Operations Procedures and Documentation
03.1
Palisades' Cold Weather Preparations
a.
Inspection Scope (71714)
The inspectors reviewed the licensee's cold weather protective measures program to
ensure that safety-related systems were protected against cold weather. The inspectors
held discussions with the cold weather checklist procedure sponsor. The backlog of
procedure change requests were reviewed. Potential problem areas around the plant
were inspected for proper cold weather preparations. Past inspection report findings
were reviewed for possible recurring issues.
b.
Observations and Findings
The licensee's cold weather program consists of two operating checklists, CL-CWCL-1,
"Cold Weather Checklist," and CL-CWCL-2, "Cold Weather Checklist - Electrical." The
inspectors noted that the checklists had several pen and ink annotations to reference
various pieces of equipment that were tagged out or to note recommended changes to
the check lists. The inspectors observed this problem the previous year also. The
licensee had not developed a method for operators to track the status of various
equipment to ensure that proper cold weather preparations were implemented for
equipment returned to service. The licensee recently implemented a procedure change*
that required the checklist to be reperformed during operator rounds when the outside
temperature falls to less than 20° F. However, the inspectors identified that the operator
rounds did not note this requirement.
The inspectors reviewed the backlog of procedure change requests for the cold weather
checklist. There were several outstanding procedure change requests. One procedure
change request was over a year old and three comments from the 1996 checklists were
not yet incorporated. The inspectors expressed concern to operations management that
individuals recommending procedure change requests may get frustrated from the lack of
action taken to address concerns. The inspectors noted that the overall backlog of
procedure change requests was large. There were approximately 970 outstanding
operations procedure change requests. Further review found that a total of
1797 procedure change requests were outstanding for all departments. Recent NRC
examination of licensee events, such as the component cooling water inventory loss
(Report 50-255/97018), and the CRD Number 38 event (Report 50-255/97014), have
shown a weakness in the area of procedural adequacy. The inspectors were also aware
that recent operations attention in the area of procedural adherence may result in an
. increase in the existing backlog.
The inspectors identified that the list of open procedure change requests were not
prioritized. A review of the licensee's management report for tracking procedures did not
include, except for operations, the number of outstanding procedure change requests .
. The number reported to exist, however, was significantly less (600 vice 972) than the
backlog identified by the inspectors. Licensee management was aware that a large
backlog existed. However, the inspectors identified that the licensee was not sure how
large the backlog was and that the backlog had not been prioritized.
7
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Licensee management directed two Operation's Department personnel to independently
review and prioritize the backlog following discussions with the inspectors. The total
backlog was divided into three categories which included: (1) 221 significant requests of
which 220 were in progress; (2) 683 enhancement requests; and (3) 70 requests that
would not be required until after the upcoming refueling outage. A majority (150) of the
significant requests were related to Emergency Operating Procedures which are due to
be implemented later this year. Also, the licensee allocated additional resources to the
procedure group.
c.
Conclusions
03:2
a.
b.
The inspectors noted that previously identified procedural weaknesses in cold weather
checklists still existed. More significantly, the inspectors noted a large backlog of
outstanding procedure change requests. The inspectors were concerned that the long
delay of incorporating procedure changes would have a negative impact in that licensee
personnel would be reluctant to submit additional needed procedure change requests.
Licensee management promptly allocated more personnel to the procedures group.
Lack of Definitive Procedural Guidance to Ensure High Pressure Air Availability
Inspection Scope (71707)
The inspectors reviewed the condition report (C-PAL-98-03.69) and the event notification
regarding the required operator actions during accident conditions for the High Pressure
(HP) Air System which were not adequately addressed in operating procedures. Also, the
inspectors reviewed the interim contingency actions and training provided to the on-shift
- crews as well as the permanent procedure revisions.
Observations and Findings
The licensee identified, during a review of HP air system operation, that the required
operator actions to restore HP air following a loss of coolant accident (LOCA) concurrent
with loss of power to the air compressors (i.e. loss of off-site power) were not adequately
defined in operating procedures. Some operator actions, which were permitted by plant
design basis, were required to ensure HP air availability for a range of small break
LOCAs. However, the operating procedures lacked definitive guidance and therefore,
there was the potential that the operators would fail to take the actions needed to ensure
HP air availability. The time to take the required actions was dependent on the break size
which would determine when recirculation cooling had to be established. This time. could
range from one hour, for large break LOCAs, to many hours as the break size decreased.
The licensee stated that the minimum time of one hour was very conservative.
Failure to take the necessary actions could jeopardize the emergency core cooling
system (ECCS) function to supply long term recirculation core cooling following a LOCA
with a loss of off-site power event. The HP air receivers' pressure would decrease during
the event due to the HP air compressors being deenergized following the designed load - -- - -*
shed. Therefore, HP air pressure may be insufficient when needed to open the ECCS
containment sump valves to establish ECCS recirculation cooling from the.containment
sump. The licensee reported this to the NRC via a 10 CFR 50. 72, one hour non-
emergency notification on March 5, 1998, as a condition outside design basis.
8
The licensee immediately provided interim guidance and training to the operating crews
regarding the required operator actions to ensure HP air availability following a LOCA with
loss of power to the HP air compressors. Permanent procedure revisions were
completed the next day. A step was added to Alarm and Response Procedure, (ARP)-7,
Annunciator Number 18, "High Pressure Control Air Compressors Hi-Lo Pressure," to
direct the operators to refer to the Standard Operating Procedure, (SOP)-20, to restore
HP air pressure if power was lost to the compressors with a LOCA in progress. Also,
Attachment 2, "To Restore HP Air In Emergency Conditions," was added to SOP-20 to
direct the specific actions. The licensee indicated that the appropriate Emergency
Operating Procedures (EOP) would also be revised. However, no specific date for
completing the EOP revisions was set at this time. The lack of definitive procedural*
guidance to accomplish required operator actions that were permitted by the design
bases to ensure HP air availability during a LOCA concurrent with a loss of power to the
HP air compressors is a Violation of 10 CFR 50, Appendix B, Criterion Ill, "Design
Control." However, this issue was identified by the licensee and prompt appropriate
corrective actions were taken. Therefore, this was a Non-Cited Violation consistent with
Section Vll.B.1 of the Enforcement Policy (50-255/98002-02).
c.
Conclusions
The licensee took prompt corrective actions after identifying a condition outside design
basis regarding inadequate procedural guidance to ensure HP air availability during a
LOCA concurrent with a.loss of power to the HP air compressors. The interim guidance
and training provided to the operating crews was considered appropriate.
04
Operator Knowledge and Performance
04.1
Plant Shutdown For Planned Outage
a.
Inspection Scope (71707)
On February 6 .. 1998, the inspectors observed activities in the control room during the*
plant shutdown for the planned outage.
b.
Observations and Findings
The Control Room Supervisor (CRS) provided oversight of the shutdown from the control
control room. The Shift Supervisor (SS) maintained oversight from the CRS station. The
inspectors observed the following regarding crew performance during the shutdown:
The CRS, at times, did not display appropriate command and control of crew
actions which was especially evident during an evolution to switch from main
feedwater to auxiliary feedwater. The Balance of Plant (BOP) operator secured
Main Feedwater and started Auxiliary .feedwater after tripping the turbine. Th_e
BOP operator then commenced feeding the steam generators at a rate that was
inconsistent with plant conditions. The large increase in feed rate resulted in an
unnecessary rise in steam generator levels and a resultant drop in primary coolant
system average temperature from approximately 533°F to 525.6°F over about a
12 minute period with the reactor critical. Primary coolant system temperature
stopped decreasing and started to increase about the same time the reactor was
9
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subcritical. Therefore, the crew fortuitously did not exceed the Technical
Specification (TS) (3.1.3.a) minimum temperature for criticality of 525°F.
However, during this evolution, the CRS displayed poor command and control by
failing to provide timely direction to the BOP operator to decrease auxiliary
feedwater flow to the steam generators.
The RO communicated all planned changes in reactivity to the CRS before
performing the manipulations. The RO demonstrated good self-checking
techniques and performed all reactivity manipulations in a deliberate manner.
The crew referenced and used appropriate plant procedures during all evolutions.
c.
Conclusions
The CRS positioned next to the RO's control panel during the plant shutdown detracted
from the CRS's ability to maintain plant oversight and contributed to some informal and
softly spoken communications. The CRS displayed poor command and control during the
evolution to switch from main feedwater to auxiliary feedwater following the manual
turbine trip. Appropriate plant procedures were referenced and used during the
shutdown.
04.2
Plant Startup
a.
Inspection Scope (71707)
On February 8, 1998, the inspectors observed activities in the control room during the
plant startup following the planned outage.
b.
Observations and Findings
A reactor startup was commenced on "A" shift (midnights}, February 8, 1998, following
the planned outage. The startup had to be aborted due to CRD 35 problems. With the
reactor in hot standby, Group Ill control rod 35 moved inward from the 4.6" to the 2.6"
withdrawn position when the RO withdrew the control rods while in the "Manual
Sequential" mode on the CRD system. Annunciator EK-09, Window 11, "Rod Position 4
inches deviation," energized at this time. All other control rods moved appropriately. The
crew implemented the alarm response procedure and attempted to withdraw only rod 35
using "Manual Individual" on the CRD system as per the procedure. Control rod 35
moved inward during this withdrawal attempt from the 2.6" to the 2.1" position and*
annunciator EK-09, Window 48, "Dropped Rod" energized .. The crew referenced the
alarm response procedure which directed them to refer to Off N.ormal Procedure
(ONP) 5.1, "Control Rod Drop." .
ONP-5.1, Step 4.1.b, directed the operators to trip the reactor if one or more control rods
dropped with the reactor in hot standby. The crew referenced control rod traces and
control rod position indication available on the plant computer and diagnosed.that control-*
rod 35 had not dropped. Additionally, the crew determined that a control rod at the
2.1" position would energize the "Dropped Rod" annunciator. Further, the crew
diagnosed that the CRD brake was deenergizing but the CRD motor was not energizing
which allowed control rod 35 to "drift" inward during the outward signal from the CRD
system. The on-shift crew consulted with operation's management in the control room.
10
Due to the diagnosed rod "drift," the crew aborted the reactor startup and manually
inserted all the control rods. The crew's diagnosis of a "drifting" rod vice a dropped rod
was validated following the manual reactor trip signal that was inserted by the operators
to place the plant in hot shutdown. Following the reactor trip signal: control rod 35's trace
and rod position indicated that the rod had moved inward from the 2.1" position to the
core bottom.
Plant startup was recommenced on "C" (evenings) shift following the maintenance
activities concerning CRD 35. (CRD 35 is further discussed in Section M.4, "Maintenance
Staff Knowledge and Performance," of this report.) The startup was completed without
any additional plant equipment problems.
Two different control room crews were observed performing the reactor startups. The
inspectors noted the following regarding the crews' performance:
c.
Conclusions
The ROs performed all reactivity manipulations in a controlled and
deliberate manner, and displayed good self-checking techniques.
The CRS positioned next to the RO detracted from crew communications
in that the RO and* CRS often spoke only to each other. Other crew
members could not hear the communications and therefore were not
always kept cognizant of ongoing activities.
Appropriate plant and reactor startup oversight was provided by both
crews. However, the two crews conducted supervisory oversight
differently. One crew had the CRS positioned next to the RO during the
startup while the other crew's CRS maintained oversight from the CRS
normal work station. The CRS positioned at the CRS's normal work
station maintained plant oversight, and control room command and control
functions. The SS provided plant oversight on the crew that had the CRS
positioned by the RO. However, the CRS maintained command and
control functions regarding directing control room activities.
The crew's diagnosis of control rod 35 "drift" was accurate and timely. The RO's
displayed good self-checking techniques during the reactivity manipulations which were
performed in a deliberate and controlled.manner. Positioning of the CRS next to the RO
during the startup detracted from the CRS's ability to maintain.control room _oversight due
to*being narrowly focused on the startup. Communications between the CRS and RO
were very softly spoken due to close proximity of the two watchstanders which could
preclude an independent crew member from questioning and correcting incorrect
information; however, the inspectors did not observe any examples of this. Also, the soft
communications detracted from the authoritative demeanor that should be displayed by
the CRS. The SS's responsibility of maintaining the broadest perspective of operational
conditions affecting the plant was impacted on the crew that had the CRS positioned next
to the RO due to being more narrowly focused on control room oversight. .
11
04.3
Inadvertent Containment High Radiation Signal
The inspectors observed the control room crew on February 17, 1998, following an
inadvertent containment high radiation signal and resultant containment isolation signal.
The crew utilized appropriate procedures to mitigate the event. Crew communications, at
times, were informal and softly spoken between individual crew members. However, the
informal communications did not preclude any required actions from being completed.
The inspectors concluded that the crew used procedures appropriately and that the
mitigation actions were timely; however, crew communications, at times, were weak.
07
Quality Assurance in Operations
07.1
Licensee Self-Assessment Activities
a.
Inspection Scope (40500)
The licensee's Nuclear Performance Assessment Department (NPAD) performed an audit
(PA-98-03) of Operations during February 16 through 27, 1998. T.he inspectors attended
the exit meeting on February 27, 1998, and reviewed the audit team findings.
b.
Observations and Findings
Audit PA-98-03 was initiated by the licensee in response to issues identified regarding the
breakdown in the conduct of operations during CRD 38 maintenance activities (Inspection
Report No. 50-255/97014(DRS)). The audit team was composed of eight individuals.
Five audit team members were not associated with the licensee's NPAD or Operations
organizations. The audit team members all had at least 20 years nuclear experience in
areas which included Quality Assurance, Operations, and work control. "Four strengths
'
were identified which included professionalism in the Operations Department and the
morning meetings' effectiveness in providing plant status and coordination amongst work
groups. One weakness, which was viewed as a "significant problem," was identified
regarding operations department's procedural content and procedure revision backlog.
(The inspectors had also identified a concern regarding operations' procedures backlog
which is discussed further in Section 03, "Operations Procedures and Documentation," of
this report.) The audit team initiated condition report C-PAL-98-0311 regarding the
significant weakness.
c.
Conclusions
. An independent team completed an audit in the area of operations. Overall, the audit
team concluded that the operations department at Palisades was functioning effectively.
The team reviewed individual procedure weaknesses and concluded they were minor.
However, the number of outstanding procedure changes was a concern. The audit
team's observations regarding procedures validated the inspectors concerns in this area
12
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II. Maintenance
M1
Conduct of Maintenance
M1 .1
Observed Activities
a.
Inspection Scope (62707 and 61726)
The inspectors observed all or portions of the following work activities:
Work Order No:
24810347
24713876
24810451
24713836
24810476
24810556
24613645
24714775
"24810717
Surveillance Activities
R0-128
Q0-1
T-384
Level control valve (CV)-6001, Steam generator blowdown
level control valve: lncapsulate and inject sealant foi valve
body hole
Low pressure safety injection Pump P-678 breaker *
152-111 : Perform preventive maintenance on breaker
Solenoid valve (SV) - 0612 Bleeder trip valve: Solenoid
valve replacement for FW heater E-3A
VOP-3198, LPSI Pump P-67A Suction valve: Preventive
maintenance on valve operator and change out incorrect
operator
Motor operated valve (MOV)-3189, LPSI Pump P-678
suction valve: Replace valve to adaptor bolting
Temperature recorder and alarm (TRA)-0150, CRD leakoff
temperature recorder: Raise alarm setpoint from 200°F to
220°F for CRD mechanism 45
Feedwater purity air system to instrument air system
crosstie modification
Control valve (CV)-3070, HPSI pump P-668 Subcooling
valve: Static VOTES test
Emergency diesel generator 1-1: Repair leaks on fuel
injection pump for cylinders 9R, SR and 9L
Emergency Diesel Generator 1-1 24-Hour Load Run
Safety Injection System
CV-3018 Differential Pressure Test
13
Ml-39
Auxiliary Feedwater Actuation System Logic Test
SOP-8
Testing of Main Turbine Valves/Protective Trips
b.
Observations and Findings
A work order package to change the alarm setpoint on TRA-0150 was reviewed. This
temperature recorder was used in the control room to monitor CRO seal leakoff
temperatures. Control rod drive mechanism (CROM) 45 seal leakoff alarm setpoint was
changed from 200° F to 220° F by a temporary modification. This change was required
due to leakage by the seal into the CROM housing which resulted in the alarm for
CROM 45 seal leakoff being energized continuously. With the alarm energized, any
further degradation of the CROM would be masked. The inspectors noted that the post
maintenance test was to only verify that the alarm cleared after the setpoint was
changed. The inspectors questioned why the new alarm setpoint was not verified as
being properly set. The instrumentation and control supervisor for the job appropriately
revised the work order's post maintenance testing following discussions with the
inspectors.
The inspectors observed performance of surveillance Ql-25, Thermal Margin Monitor
Constants Check." The inspectors also reviewed the procedure and noted a wording
disparity in section 3.4, "System Conditions." The procedure stated that the TM/LP and
variable high power (VHP) trip functions shall all be operable prior to performing this test
unless below 70 percent power per TS 3.17. Based on discussions with the licensee, the
applicable TS was 3.17.1.3.b, which stated_, "If two power range nuclear instrument
channels are inoperable, limit power to less than 70 percent power within two hours."
The power range nuclear instruments were an input to TM/LP and VHP trips. The TM/LP
and VHP trips are required below 70 percent power. The state~ent implied that TM/LP
and VHP trips did not have to be operable if below 70 percent power. The licensee
reviewed the inspectors' concern and generated a procedure change request to remove
the statement. The inspectors viewed this as a procedure enhancement, which did not
impact performance of the surveillance or operability of the trips.
The inspectors observed portions of the preventive maintenance on the low pressure
safety injection pump P-67 A and 8 suction motor operated valves. * In preparation for the
task, a mechanical maintenance technician verified bolt size for application of proper
torque values as listed in maintenance procedure MSE-E-38, "PM/EQPM of Safety
Related Limitorque Type SMB Actuators." The valve actuator to valve yoke bolts were
checked for proper torque values.. The maintenance technician identified that the bolts in
place were a smaller size for the torque specifications given. This suggested that a
higher torque value for a larger bolt may have been incorrectly applied in the past. A
subsequent engineering inspection revealed that the actual bolt material was different
than that specified in the associated drawing. Heat treated 88 bolts were required;
however, Stainless Steel 87 bolts were in place. An operability determination performed
by engineering identified that the torque requirements for a 88 bolt did not exceed the bolt
material yield strength of the 87 bolts. The stainless steel 87 bolts were subsequently * **
replaced with heat treated 88 bolts and torqued to the proper specification. The
- inspectors noted a good questioning attitude on the part of the mechanical maintenance
technician .
14
c.
Conclusions
The inspectqrs continued to note examples of weaknesses in post maintenance testing
and procedures. A mechanical maintenance technician displayed a good questioning
attitude which resulted in identification of incorrect bolts used in the low pressure safety
injection pumps motor operated suction valves' actuator to valve yoke. The deficiencies
did not affect equipment operability.
M4
Maintenance Staff Knowledge and Performance
M4.1
Control Rod Drive (CRO) 35
a.
Inspection Scope (62707)
b.
The inspectors observed the CRD 35 rod "drift" problems experienced during the plant
startup on February 8, 1998, and reviewed Work Order 24810449 and the applicable SS
logs. Also, the inspectors discussed CRD 35 problems with plant management and
control room operators.
Observations and Findings
Maintenance troubleshooting activities identified that one of the movable contacts in* the
"up" contractor for Control Rod 35 was off center and therefore would not allow the CRD
motor to energize. This contactor had been removed during the planned outage on
February 7, 1998, to clean the contacts. However, the maintenance technician
apparently bumped the moveable contact when reinstalling the contactor. This resulted
in the contact not being aligned with the center indent on the contact assembly. With the
contact misaligned, each time the rod got an outward signal the . .contact moved further
off-center and away from its associated fixed contact. After the contact moved far
enough off-center, it could not make-up with its associated fixed contact to allow the CRD
motor to energize. Therefore, during an outward demand signal, the CRD brake would
deenergize releasing the control rod. However, the CRD motor would not energize and
with the CRD brake deenergized, the rod would slowly "drift" into the core. In response to
Control Rod 35 problems, the licensee inspected all the CRD contactors that had been
removed for cleaning during the planned outage. No similar problems were identified.
The inspectors noted that post maintenance testing (PMT) had been performed following
CRD 35 contactor cleaning which required control rod 35 to be withdrawn five inches and
then inserted. Control rod 35 moved satisfactorily during the PMT. Also, the inspectors
noted that control rod 35 had successfully moved outward a total of three separate times
before the rod "drift" was experienced during the plant startup on February 8, 1998.
c.
Conclusions
CRO contactor problems have been a recurring problem. Past CRD problems were
associated with dirty contacts; however the CRD 35 problems experienced during this
startup were directly related to human error in maintenance practices. This delayed plant
startup for approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. Post maintenance testing for CRD 35 was
considered appropriate.
15
Ill. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1
Emergent Work Support
During this inspection period, a number of emergent plant equipment problems required
engineering support. System and Design Engineering groups were consulted regarding
various emergent issues which included the containment radiation monitors and CRD 35
rod "drift." The containment radiation monitors' deficiency resulted in an inadvertent
containment high radiation signal and subsequent containment isolation. The inspectors
noted that the engineering review of the containment high radiation monitor's deficiency
(as discussed in Section E7, "Quality Assurance in Engineering Activities") was very
thorough. The inspectors noted that the engineering groups responded to requests for .
support iri a timely manner.
E2.2
Instrument Air System Reliability
a.
Inspection Scope (37551 and 62707)
The inspectors reviewed condition reports, work requests, quarterly system health reports
and observed portions of recent maintenance on the instrument air system. The
inspectors also discussed recent instrument air system performance with the system
engineer.
b.
.Observations and Findings
The inspectors were concerned with several recent material condition problems noted
with the instrument air system. On November 17, 1997, instrume-nt air compressor C-2A
was found not loading and C-2C was fully loaded, maintaining the plant air load. The
loader/unloader relay was found worn. The relay was original plant equipment and no
preventive maintenance had ever been performed. The relays were replaced for both
instrument air compressors. On December 9, 1997, instrument air compressor C-2A was
again not loading. The C-2A loader/unloader valve was found rusted closed, not allowing
the compressor to load. It was noted that service water was being supplied to the
compressor jacket cooler even though the compressor was not running. Sole.noid valve
(SV)-0801 was found leaking by due to debris on the valve seat. Continuous service
water flow caused condensation to form in the C-2A compressor h~ad which contributed
to rusting of the loader/unloader valve.
In January 1998, the jacket water cooler and aftercooler were found plugged with silt
following an inspection after the control room received a high temperature alarm. The
quality of the service water has been a concern of the system engineer. The licensee
instituted a periodic and predetermined activity control (PPAC), (CAS-098 and. CAS-099),
to change out the aftercoolers periodically, rather than fix the root cause of the plugging
caused by silt. The feedwater purity air compressors, which can supply the instrument air
system on a loss of the instrument air compressors, has also had silting problems with
the coolers.
On February 5, 1998, bearings for the C:2B air compressor motor were being greased .
The maintenance technicians noted the grease in the bearings was different from the
16
.*
grease being added. It was identified that.there were three different greases with the
same stock numbers from the same vendor. The bearings were replaced and the grease
identification problem was corrected. The inspectors examined the bearings and. found
them degraded.
The inspectors have noted some improvements with the instrument air system including a
significant reduction in. system leakage. This is evidenced. by the operation of either C-2A
or C-2C, which comprise one train of instrument air. Either compressor is now capable of
carrying system load individually. Another recent improvement included the ability to
adjust the feedwater purity air Compressors C-903A, B load/unload setpoint nearer to
instrument air system pressure. Also, the feedwater purity air system cross-tie pressure
control Valve (PCV)-1221 was adjusted to maintain feedwater purity pressure coincident
to the instrument air system pressure requirements. This addressed an operations
department concern.
c.
Conclusions
The inspectors noted that .the redundancy capability for the instrument air system was
good. However, reliability of the compressors appeared to be a problem due to service
water silting problems, which have not been directly addressed by the licensee.
E7
Quality Assurance in Engineering Activities
a.
Inspection Scope (37551)
The inspectors reviewed the condition report (C-PAL-98-0252) and observed the
management review board (March 5, 1998) regarding a deficiency associated with the
containment high radiation (CHR) monitors.
b.
Observations and Findings
An inadvertent CHR signal and resultant containment isolation occurred on February.17,
1998, during maintenance on the containment radiation monitoring system. The
containment radiation monitoring system, as described in FSAR Section 7.3.3, was to
include two separate actuation channels which are activated by four independent circuits. *
The containment isolation signal is initiated by a two out of four logic system. The left
channel consisted of RIAs 1805/1807 and the right channelconsisted of RIAs 1806/1808.
Maintenance personnel had scheduled the replacement of a power supply for monitor
RIA 1808. A maintenance technician removed the fuses for RIA 1808 and placed that
circuit in a "tripped" condition as designed. This allowed a containment isolation signal to
be generated if another radiation monitor trip signal were to occur from any one of the
three energized containment radiation monitors. The maintenance technician then
removed wires from terminals one thru six to further isolate RIA 1808 to accommodate
power supply replacement. No problems were noted when wires were lifted from
terminals two through six; however, RIA 1806 tripped when the wire was lifted from
terminal one. When RIA 1806 tripped the required two out of four logic was completed
and the i_nadvertent CHR signal and resultant containment isolation signals were
generated. All equipment actuated as designed which was verified by the operating crew
using the. appropriate procedure checklist.
17
The licensee initiated a level two condition report (C-PAL-98-0252) to determine the root
cause(s) for the event. Engineering and Instrument and Control Technician's review
determined that a common ground existed between RIA 1808 and RIA 1806, wh.ich
electrically tied the two circuits together at terminal one. The common ground caused
RIA 1806 to fail in a tripped condition when the wire from terminal one was lifted. Also,
the licensee determined that a similar common ground existed with the left channel
circuits, RIA 1805 and RIA 1807. Further investigation by the licensee determined that
there was no common electrical connection between the left channel (RIA 1805/1807)
and right channel (RIAs 1806/1808) circuits. However, the common ground that existed
between the left channel circuits and the right channel circuits respectively, failed to meet
the system's design requirements of four independent circuits as described in the FSAR.
The licensee reported this to the NRC via a 10 CFR 50.72, one hour non-emergency
notification on February 8, 1998, as a condition outside design basis.
The licensee's root cause analysis determined that this deficiency was introduced during
an unauthorized design change that was made while installing these containment
radiation monitors in the mid 1980's. It appears that the licensee's last opportunity to
identify this deficient design change was in the 1989 time frame during their configuration
control project (CCP). During their review of design drawings an inconsistency was
. noted. One drawing (E-623, Sheet 1 B, Revision 7) showed the wire that was removed
during the maintenance activity during the event as being connected to terminal one while
another drawing (E-227, Sheet 3, Revision 10) showed the wire disconnected. Further
review of historical drawings identified that E-227, Revision 3, was revised during the
CCP to reflect the radiation monitoring system's as built configuration which was different
than design configuration. However, no other documentation could be located that
approved the design change. Also, no other documentation could be found regarding
actions taken after the CCP found that the drawing did not accurately reflect the as built
configuration. The licensee stated that their current modification practices by the licensee
are designed to. prevent similar problems. The management revlew board concluded
that, based on no history of recurring design problems missed by CCP activities, the high
cost of reviewing other CCP documentation for similar problems was not appropriate for
the little benefit that was expected.
A contributing factor to the event was not installing a jumper to bypass RIA 1808 during
planned maintenance. The jumper would have prevented the inadvertent CHR since
RIA 1808's input to the logic would have been removed but would not have prevented
RIA 1806 from failing in the tripped condition. Use of jumpers had been a common
practice in the past (1989/1990 time frame). Licensee discussions with operations,
engineering, and maintenance personnel during their root cause analysis could not
definitively determine why that practice had been discontinued.
Eight corrective actions were developed which included: (1) review drawings and correct
inconsistencies associated with the containment RIA's (RIA 1805/1806/1807/1808);
(2) modify containment RIAs' circuit wiring to satisfy design requirements; (3) *develop a
permanent maintenance procedure to control a temporary modification to install and
remove a jumper to bypass the containment RIAs during maintenance; (4) evaluate* other.
plant systems without an installed bypass feature (i.e. safety injection system,
recirculation actuation system, contai.nment high pressure input to containment isolation)
for the need to develop similar controls for bypassing a channel during maintenance; and
(5) determine what action is needed to ensure the maintenance planners recognize *the
need to install a bypass during maintenance. The licensee stated that the target date to
18
- '
complete all corrective actions wa*s September 1, 1998, with one exception. The
modification to the circuit wiring to satisfy design requirements was targeted for
completion during the 1999 refueling outage.
The failure of the containment radiation monitoring system to consist of four independent
circuits as described in the FSAR is a Violation of 10 CFR Part 50, Appendix B,
Criterion Ill, "Design Control." However, this issue was identified by the licensee and
prompt appropriate corrective actions were developed. Therefore, this was a Non-Cited
Violation consistent with Section Vll.B.1 of the Enforcement Policy
(NCV No. 50-255/98002-03).
c.
Conclusions
The licensee's review and root cause analysis of the circumstances surrounding the
inadvertent CHR event were rigorous. The proposed corrective actions were considered
thorough. This deficiency would cause the radiation monitors to fail in the tripped
condition which was considered conservative. The safety consequences related to this
deficiency would be an unnecessary challenge to a safety system due to the inadvertent
signal and resultant containment isolation.
IV. Plant Support
RS
Miscellaneous RP&C Issues
R8.1
Radiological Posting On 2400 volt electrical Bus 1 C
a.
Inspection Scope (71750 and 62707)
The inspectors observed electricians performing preventive maintenance on the low
pressure safety injection pump P-67B breaker, 152-111.
b.
Observations and Findings
Breaker 152-111 is located in 2400 volt electrical Bus* 1 C. In the early 1980s, the spent
fuel pool overflowed and contaminated the floor and cubicles of 2400 Volt electrical
Bus fC. **Two signs on the outside of 2400 volt electrical Bus 1 C stated that the inside
breaker cubicles were internally contaminated. The sign directed personnel to contact
health physics if entry into the bus cubicles was necessary.
The preventive maintenance was at the point where the breaker was to be put back into
the cubicle. The lead electrician was preparing to open the cubicle door and the
inspectors questioned if health physics should be notified. The lead electrician was
unsure if health physics had surveyed the cubicle when the breaker was removed the
previous shift. Therefore, the lead electrician decided to contact health physics prior to
installing the breaker back into the cubicle. The inspectors found that when
breaker 152-111 was removed, the cubicle was surveyed, but this was not discussed in
the electricians' turnover. Discussions following this incident revealed that expectations
for radiological requirements of working inside the bus were not clearly understood. The
inspectors discussed this with licensee management .
19
Health physics management took prompt action to clarify the radiological requirements for
maintenance personnel working inside the cubicle. The individuals involved were
counseled by health physics on the radiological requirements for 2400 volt electrical Bus
1 C. Guidance was issued to all supervisors to discuss this issue with their personnel.
New placards have been made which were to be posted on the front and rear door of
each cubicle. Placards were also made to post inside the cubicles. In addition, health
physics, in discussions with engineering, have developed a plan to survey the cubicles in
the upcoming outage for possible release of th.e cubicles from the current radiological
requirements.
c.
Conclusions
The inspectors identified a common misunderstanding among licensee personnel for the
posted radiological requirements applicable to 2400 volt electrical Bus 1 C. However, the
licensee responded promptly to correct the problem. The inspectors noted that the
corrective actions taken were thorough.
PS
Staff Training and Qualification in Emergency Planning (EP)
a.
Inspection Scope (71750)
The licensee conducted an emergency plan drill on the morning of February 27, 1998.
The inspectors monitored activities in the Technical Support Center (TSC) and the
simulated Control Room. The subsequent drill critique was also observed in the TSC.
b.
Observations and Findings
Licensee Emergency Planning personnel simulated a security drill which involved a bomb
.
'
explosion in track alley, an injured contaminated individual, and no radioactive releases.
The drill was designated as "practice," had well defined objectives, and was not
considered an evaluated drill. The drill scenario was the same one that was run on a
different team of licensee emergency response personnel last year in order to determine
if corrective actions for an identified weakness (Report 50-255/97013) regarding timely
search and rescue efforts were effective.
The inspectors noted that the operators in the simulated control room referred to
appropriate emergency plan implementing procedures and that the TSC was manned in a
timely manner. The Site Emergency Director (SEO) conducted briefs regarding pl~nt and
emergency status on a regular frequency and displayed sound command and control.
Other TSC emergency response personnel provided requested information to the SEO in
a timely manner, were knowledgeable of applicable procedures, and conducted
themselves in a professional manner. A search and rescue team was dispatched and
located the contaminated injured individual in a timely manner. This allowed transfer of
the contaminated injured individual to offsite medical facilities without unnecessary delay.
Some minor problems concerning communication equipment were noted. The TSC
communications team was delayed in assuming notifications to state and county officials
due to problems associated with utilizing the TSC phone that had the same extension as
the control room phone. The phone line for communications between the control room
and offsite authorities would be busy when the TSC communications team attempted to
monitor notifications that were being made by the control room communications team .
20
This unnecessarily delayed some of the required offsite notifications to state and local
officials. However, none of the required notifications were missed. Also, the inspectors
noted that the SEO declared that the TSC was activated prior to receiving a turnover from
the Control Room. The inspectors observed the TSC post drill self-critique and noted that
the critique was thorough in identification of numerous minor problems as well as drill
positives. All deficiencies in the TSC that were noted by the inspectors were identified
during the licensee's post drill self-critique.
c.
Conclusions
EP personnel effectively used a drill to accomplish the stated objectives and to conduct
training. The problems associated with timely response of a search and rescue team
identified last year was not evident during this drill.
51
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.
X1
Exit Meeting
The inspectors presented the inspection results to members of the licensee management
at the conclusion of the inspection on March 13, 1998. No proprietary information was
identified by the licensee.
21
- '
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, Acting Manager, Training
P. D. Fitton, Manager, System Engineering
R. J. Gerling, Manager, Design Engineering
K. M. Haas, Director, Engineering
N. L. Haskell, Manager, Licensing
D. G. Malone, 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
22
-~
..... '
IP 37551:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
INSPECTION PROCEDURES USED
Onsite Engineering
Surveillance Observations
Maintenance Observation
Plant Operations
Plant Support Activities
- Cold Weather Preparations
ITEMS OPEN
50-255/98002-01
50-255/98002-02
Failure to ensure watertight door was properly secured
Required operator actions that were permitted by plant
design bases inadequately described in plant procedures
Containment radiation monitor system design deficiency
50-255/98002-03
50-255/98002-02
50-255/98002-03
ITEMS CLOSED
Required operator actions that were permitted by plant
design bases inadequately described in plant procedures
Containment radiation monitor system design deficiency
23
- - .. _:.. .. i .. _
, *-***;.-;;
.;
JIS,
- If
I
l
A LARA
ccw
CFR
CHR
CL
CROM
CRTL
CV
CWCL
080
IP
NPAD
NRC
ONP
PPAC
QO
TM/LP
TMM
VHP
VOTES
LIST OF ACRONYMS USED
As Low As Reasonably Achievable
Axial Offset
Administrative Procedure
Annunciator Response Procedure
Balance of Plant
Configuration Control Project
Component Cooling Water
Code of Federal Regulations
Containment High Radiation
Check List
Control Rod Drive
Control Rod Drive Mechanism
Control Room Supervisor
Condition Review Team Leader
Control Valve
Cold Weather Check List
Design Basis Document
Division of Reactor Projects
Emergency Core Cooling Systems
Emergency Operating Procedure
Emergency Planning
High Pressure
Inspection Procedure
Loss of Coolant Accident
Low Pressure Safety Injection
Motor Operated Valve
Nuclear Performance Assessment Department
Nuclear Regulatory Commission
Off Normal Procedure
Primary Coolant Pump
Pressure Control Valve
Periodic and Predetermined Activity Control
Quarterly Operations (procedure) *
Reactor Operator
Site Emergency Director
Safety Evaluation Plant
Shift Supervisor
Thermal Margin/Low Pressure
Thermal Margin Monitor
--- --- Variable High Power
Violation
. Valve Operations and Testing Evaluation System
24