ML18066A191
| ML18066A191 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 06/11/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML18066A189 | List: |
| References | |
| 50-255-98-05, 50-255-98-5, NUDOCS 9806170145 | |
| Download: ML18066A191 (24) | |
See also: IR 05000255/1998005
Text
U.S. NUCLEAR REGULA TORY COMMISSION
Docket No:
License No:
Report No:
Licensee:
Facility:
Locati.on:
Dates:
Inspectors:
Approved by:
9806170145 980611
- DR
ADOCK 0,000255
REGION Ill
50-255
50-255/98005(DRP)
Consumers Energy Company
212 West Michigan Avenue
Jackson, Ml 49201
Palisades Nuclear Generating Plant
27780 Blue Star Memorial Highway
Covert, Ml 49043-9530
March 14 through May 6, 1998
J. Lennartz, Senior Resident Inspector
P. Prescott, Resident Inspector
Bruce L. Burgess, Chief
Reactor Projects Branch 6
EXECUTIVE SUMMARY
Palisades Nuclear Generating Plant
NRC Inspection Report 50-255/98005
This inspection involved aspects of licensee operations, maintenance, engineering, and plant
support. The report covers the period from March 14 through May 6, 1998.
Operations.
Plant operations was challenged with continued equipment reliability issues. Specifically,
main turbine stop Valve #1 arid governor Valve #1 were closed and hydraulically isolated
due to inadvertent partial closure and subsequent opening of turbine stop Valve #1. This
resulted in placing the turbine control system in an off-normal, manual mode of operation.
In addition, the licensee had previously taken a turbine generator electrohydraulic control
system pump out-of-service (February 16, 1998) due to a leak in the discharge flow
instrument. (Section 01.1)
The control room access was well controlled which eliminated unnecessary distractions
to the operators. Control room manning exceeded Technical Specification requirements.
The plant was operated in a conservative manner while the turbine control system was in
an off-normaf configuration. The inspectors identified weaknesses in control room log
keeping and noted that licensee management had targeted this as an area which needed *
improvement. (Section 01.2)
The actions taken in response to the unknown status of main turbine stop Valve #1 were
appropriate and ensured positive*control of the valve. Closing and isolating hydraulic fluid
to main turbine stop Valve #1 and governor Valve #1 was considered prudent in
preventfng a potential turbine overspeed condition that could result from ~ failure of
governor Valve #1 to close following a turbine trip. (Section 02)
The control room operators successfully operated the plant while the turbine control
system was restricted to an off-normal, manual mode of operation. Coordination among
crew members was good during those activities performed to shut down the plant for the
scheduled refueling outage. The crew transferred feed to the steam generators from the
main feedwater system to the auxiliary feedwater system during the plant shutdown
without causing an unnecessary transient which reflected improved performance from
past evolutions. (Section 04)
Maintenance
Several examples of maintenance cleanliness and foreign material exclusion issues were
identified by licensee personnel during the early stages of the outage. Individually, the
identified cleanliness and foreign material exclusion issues were considered minor;
however, collectively they indicated that additional management attention in this area was
warranted. (Section M 1.1)
Overall, the inspectors observed, during maintenance and surveillance activities, good
procedure adherence, and maintenance and radiation work practices. (Section M1 .2)
2
The planned work scope for the 1998 refueling outage should not be challenging for the
licensee to safely accomplish. The level of planning and preparation was thorough and
complete. However, the inspectors noted that some longstanding equipment problems
were deferred. (Section M1 .3)
The personnel air lock Technical Specification amendment should benefit the licensee if
personnel air lock operability problems arise in the future. However, the inspectors
discussed with the licensee the need for maintenance and system engineering personnel
to ensure corrective actions adequately address reliability of the personnel and
emergency air locks due to the safety significance of these components regarding
containment integrity as well as personnel safety. (Section M2.1)
The inspectors identi_fied that no foreign material exclusion covers were installed on the
emergency diesel's generator access covers and no maintenance personnel were
present to maintain positive foreign material exclusion controls. Also, the inspectors
identified that inadequate procedural requirements existed for foreign material exclusion
controls pertaining to electrical components which was a violation of regulatory
requirements. (Section M3)
Engineering
Engineering personnel were frequently challenged with emergent equipment reliability
issues. Specifically, engineering personnel had to respond to and support emergent work
pertaining to containment air locks, turbine control systems, and auxiliary feedwater flow
controller operational issues. Engineering personnel responded to and supported these
activities in a timely manner. (Section E 1.1)
The inspectors noted that the follow-up to correct identified deficiencies with inservice
testing requirements was thorough. However, system engineering supervision relied on
engineering personnel to identify errors in the IST program data base. (Section E2)
The licensee relied on vendor representatives rather than in-house knowledge of the
turbine control systems. Also, some licensee engineering personnel did not understand
the operational design for the auxiliary feedwater Yokagowa flow controllers. This
indicated an apparent knowledge weakness on behalf of engineering personnel regarding
auxiliary feedwater flow controllers and the turbine generator control systems.
(Section E4)
Plant Support
The inspectors concluded that radiological practices observed during maintenance
activities and plant daily walkdowns were adequate. (Section R8.1)
3
Report Details
Summary of Plant Status
The plant operated at essentially full power (99.6 percent) from the start of the inspection period
until a partial closure of turbine stop Valve #1 occurred on March 17, 1998. The turbine stop
valve inadvertent partial closure limited reactor power to 96 percent power until the plant was
taken off-line on April 24, 1998, for a scheduled refueling outage. The plant was in hot shutdown
on April 25, 1998, and placed in cold shutdown on April 26, 1998.
I. Operations
01
Conduct of Operations
01.1
General Comments (71707)
Plant operators were challenged with continued equipment reliability issues. Specifically,
main turbine stop Valve #1 and governor Valve #1 were closed and hydraulically isolated
due to inadvertent partial closure and subsequent opening of turbine stop Valve #1. This
condition resulted in the licensee placing the turbine controls in a manual mode of
operation whi.ch was an off-normal lineup. Also, this condition rendered the automatic
runback features associated with the turbine control system unavailable which would
have required a plant trip if a substantial secondary plant transient would have occurred.
In addition, the licensee had previously taken a turbine generator electrohydraulic control
(EHC) system pump out-of-service (February 16, 1998) due to a leak in the discharge
flow instrument. This resulted in the EHC system not having any standby pump
capabilities which would have required a turbine trip if any subsequent problems emerged
with the operating EHC pump.
01.2
Control Room Observations
a.
Inspection _Scope (71707)
The inspectors routinely toured the control room, reviewed control room logs, reviewed
system status as indicated on the control panels, and occasionally observed shift
meetings. In addition, the inspectors observed control room activities while the plant was
being operated when the turbine control system was in an off-normal, manual mode.
Observations and Findings
The inspectors noted that the minimum crew manning requirements per Administration
Procedure (AP) 4.00, "Operations Organization, Responsibilities and Conduct," of three
Senior Reactor Operators and three Reactor Operators were always satisfied. This
manning augmentation exceeded Technical Specification (TS) requirements. In addition,
the inspectors noted that the control room was free of unn~cessary traffic and activities.
The five individual on-shift crews were combined into two crews for the outage. Each
crew was scheduled to work 12-hour shifts and was sufficiently staffed to allow "extra"
individuals on crew to relieve crew watchstanders. This provided on-shift management
with the necessary resources to provide days off for individual crew members and to
4
provide coverage for unexpected absences. A shift meeting was held before each shift*
to discuss outage activities and scheduled evolutions. The meeting included all on-shift
operations personnel as well a representative from the Work Control Center outage
management team. The meeting was utilized to align resources for upcoming activities
as well as to review problems encountered during the pr~vious 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Licensee management decided to close and isolate main turbine stop Valve #1 and
governor Valve #1 following the problems experienced on March 17, 1998, when the stop
valve inadvertently closed partially and subsequently reopened. This limited plant power
to 96 percent. The turbine control system was placed in an off-normal, manual mode with
the three remaining governor valves operating in "single v,alve" mode. The control room
crews operated the plant in a controlled and deliberate manner without causing any
unnecessary perturbations on the plant while this off-normal condition existed.
The inspectors noted that some log entries did not contain the level of detail which would
fully describe the circumstances surrounding an issue. When questioned by the
inspectors, control room operators demonstrated that they were knowledgeable of the
details surrounding the issues by providing answers to the inspectors' questions. Based
on discussions with licensee management, the inspectors noted that control room log
keeping had been targeted as an area which needed improvement. Also, a condition
report was subsequently generated (C-PAL-98-0795) by the licensee's Nuclear
Performance *Assessment Department (NPAD) pertaining to NPAD's observations
regarding inconsistent control room log keeping*practices. That condition report included
a recommended action to review expectations regarding log keeping requirements with all
operations personnel to ensure consistent information was recorded.
Conclusions
The control room access was well controlled which eliminated unnecessary distractions
to the operators. Control room manning exceeded TS requirements. The plant was
operated in a conservative manner while the. turbine control system was in an off-normal
configuration. The inspectors observed weaknesses in control room log keeping and
noted that licensee *management had targeted this as an area which needed
improvement.
02
Operational Status of Facilities and Equipment
a.
Inspection Scope (71707) *
The inspectors observed the management review board, and reviewed the applicable
condition report (C-PAL-98-0424) regarding the inadvertent closure of turbine stop
Valve #1. The inspectors also reviewed condition reports regarding a turbine generator
EHC pump flow sightglass leak.
b.
Observations and Findings
Main turbine stop Valve #1 partially closed (approximately 30 percent) from the normal full
open position on March 17, 1998, while the plant was operating at 99.6 percent power.
The valve subsequently went full open during troubleshooting efforts. The licensee's
engineering group and vendor representatives could not definitively determine the status
5
of stop Valve #1 without conducting intrusive maintenance. Therefore, there was no
assurance that the valve would close on a turbine trip. This could have resulted in a
turbine overspeed condition if governor Valve #1 also failed to close following a turbine
. trip. Based on discussions between the licensee's engineering department and vendor
representatives, the licensee concluded that no adverse consequences to the main
turbine would occur if the turbine was operated with turbine stop Valve #1 and governor
Valve #1 closed. Based on that conclusion, main turbine stop Valve #1 and governor
Valve #1 were closed and the hydraulic control fluid to the valves was isolated. This
turbine valve configuration limited power to approximately 96 percent until the plant was
shutdown for the scheduled refueling outage on April 25, 1998. Necessary repairs to
turbine stop Valve #1 were added to the scheduled outage's work scope.
In addition, the turbine EHC system was previously degraded due to removing one EHC
pump from service on February 16, 1998, due to a leak in the discharge flow indicator.
This resulted in the EHC system not having any standby pump capabilities which would
have required a turbine trip if any subsequent problems emerged with the operating EHC
pump. Licensee management evaluated the situation and decided not to conduct repairs
while the plant was on-line to avoid the potential for introducing contaminants into the
EHC fluid.
c.
Conclusions .
The actions taken in response to the unknown status of main turbine stop Valve #1 were
appropriate and ensured positive control of the valve. Closing and isolating hydraulic fluid
to main turbine stop Valve #1 and governor Valve #1 was considered prudent in
preventing a potential turbine overspeed condition that could result from a failure of
governor Valve #1 to close following a turbine trip.
04
Operator Knowledge and Performance
a.
Inspection Scope (71707)
The inspectors observed licensed operator crew performance during: 1) routine power
operations; 2) plant operational activities surrounding turbine stop Valve #1 problems; 3)
plant shutdown for the scheduled refueling outage; and 4) plant cooldown and initiation of
b.
Observations and Findings .
As a result of the main turbine stop Valve #1. problems experienced on March 17, 1998,
the turbine generator controls were limited to manual. Due to the stop Valve #1
problems, governor Valve #1 and turbine stop Valve #1 were also closed and isolated
which required the three remaining governor valves to operate in the "single valve" mode.
This was an abnormal operating condition for the turbine. The.control room crews
operated the plant during this condition in a controlled and deliberate manner without
causing any unnecessary perturbations to the plant.
-
-
-* -
The plant was taken off-line on April 24, 1998, for the scheduled refueling outage. The
inspectors noted that the control room operators coordinated well with each other during
the plant shutdown. Also, for the most part, the Control Room Supervisor provided the
6
c.
appropriate amount of oversight and direction. The evolution to transfer from main .
feedwater to auxiliary feedwater following the manual turbine trip was accomplished
without any unnecessary cooldown of the primary coolant system.
Conclusions
The control room operators successfully operated the plant while the turbine control
system was restricted to an off-normal, manual mode of operation. Coordination among
crew members was good during those activities performed to shut down the plant for the
scheduled refueling outage. The crew transferred feed to the steam generators from the
main feedwater system to the auxiliary feedwater system during the plant shutdown
without causing an unnecessary transient which reflected improved performance from
past evolutions.
08
Miscellaneous Operations Issues (92700 and 92901)
08.1
(Closed) LER 50-255/95003-00: Main feedwater pump transient resulting in a reactor trip.
On May 22, 1998, with the plant operating at 46 percent power, both main feedwater
pump turbines K-7A and K-78 tripped. While preparing to reduce reactor power, K-7A
tripped. The reactor operator responded to the K-7A trip in accordance with Off Normal
Procedure (ONP) - 3, "Loss of Main Feedwater." However, the '8' steam generator level
reached the high level override setpoint, which caused immediate closure of the
feedwater control valve (CV-0703) as designed. This caused an immediate drop in load
for turbine K-78 which subsequently tripped on overspeed. The operator then manually
tripped the reactor. The cause of the event was failure of the locknut on the layshaft
assembly of K-7A which allowed the layshaft gear to move down the shaft. Also, the
moving gear worked against a lockwasher which failed and increased gear movement.
The lockwasher appeared to have been reused.
The inspectors reviewed the actions* that were taken to improve maintenance practices
on the main feedwater pump (MFP) turbine. Those actions included: *1) the vendor
recommended practice of a tight tolerance band between the shaft and gear was
implemented; 2) the maintenance process no longer allowed reusing lockwashers; and 3)
torquing requirements were added for the lockwasher.
- Additionally, the licensee identified that the MFP governor gain control setting is set as
low as possible. As a result, the MFPs are slow to respohd to a speed control signal.
Therefore, operator action is required to take the MFP speed control to manual and *
increase pump speed to provide the feedwater flow required to compensate for the loss
of an MFP. The high MFP speed, coupled with the automatic shift of the feedwater
regulator valves to manual, assures that ample feedwater is maintained for core cooling.
However, this also requires operator action to manually trip both MFPs on a reactor trip to
prevent overcooling the primary coolant system. System engineering personnel
determined a modification to the MFP governor would be required to correct the .slow
response problem. Licensee management concluded that the gain in safety did not
warrant the cost_ of a modification. The inspectors concluded that the actions taken were
- adequate; therefore, this item is closed .
7
II. Maintenance
M 1
Conduct of Maintenance *
M1 .1
Cleanliness Practices
a.
Inspection Scope (62707)
The inspectors reviewed condition reports, .conducted plant tours, and discussed
maintenance cleanliness controls with licensee management and chemistry personnel.
b.
Observations and Findings
Licensee personnel identified several examples of maintenance cleanliness and foreign
material exclusion (FME) problems during the early stages of the outage. The examples
included: 1) a washer, socket, and socket adaptor were dropped into the* screen house
basin; 2) three pieces of duct tape were found floating in the reactor side tilt pit; 3) debris
was found in the reactor cavity; and 4) approximately one gallon of penetrating oil dripped
into the main condenser hotwell during turbine blading inspections. A condition report
was generated for each of these occurrences and, with the exception of the penetrating
oil, the materi.al was retrieved. The penetrating oil that dripped into the main con~enser
was "blue dotted" and therefore considered acceptable for the secondary system. The
inspectors questioned licensee chemistry personnel regarding the penetrating oil's affect
on secondary chemistry. Chemistry personnel calculated that the resultant sulfates would
be 5.47 ppb which would exceed the normal steam generator sulfate levels of 2-3 ppb.
However, no action level values would be exceeded. The assumption used in the
calculation was that the contaminants were instantaneously inje,:ted into the steam
generators with no prior cleanup which was conservative.
c.
Conclusions
Several examples of maintenance cleanliness and FME issues were identified by licensee
personnel during the ea.rly stages of the outage. Individually the identified cleanliness
and FME issues were considered minor; however, collectively they indicated that
additional management attention in this area was warranted.
M1 .2
Observed Activities
a.
Inspection Scope (62707 and 61726)
The inspectors observed all or portions of the following work activities:
Work Order No:
24712659
24811180
24810163
P-10A, heater drain pump: Replace all flexible hoses
CV-0847, service water supply to containment: Repair
instrument air line break
Right channel containment hydrogen monitoring panel
EL-162: Replace hot box wiring and pressure regulators
8
Surveillance Activities
M0-7A-1
Q0-5
DW0-13
Q0-42
FHS-M-10
Emergency Diesel Generator 1-1 (K-6A)
Valve Test Procedure (includes containment isolation
valves)
Local Leak Rate Tests (LLRn for Inner and Outer
Personnel Air Lock Door Seals
Section XI Testing of Shutdown Cooling Control Valves
High Pressure Safety Injection Train 1 and 2 and Safety
Injection Tank System Class 2 System Functional/lnservice
Test
New Fuel Receipt
b.
Observations and Findings
C.
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
appropriate radiation control measures in place .
Conclusions
Overall, the inspectors observed, during maintenance and surveillance activities, good
procedure adherence, and maintenance and radiation work practices. *
M1 .3
1998 Refueling Outage Preparations
a.
Inspection Scope (62707)
The inspectors reviewed the licensee's preparations and.work scope for the upcoming
1998 refueling outage. Discussions were held with the director of maintenance and
planning, outage planning supervisors, and outage planners. Planning meetings were
attended. The pre-outage work scope and the work that was canceled for the outage,
since the work scope was frozen, were reviewed.*
b.
O~servations and Findings
The refueling outage started as planned on April 24, 1998, and was scheduled for
32 days. This was the licensee's shortest planned refueling outage. Th~ last outage was
scheduled for 51 days. A primary reason for the shorter refueling outage was the lack of
facility changes that were scheduled for ttie outage. Contingency time was built into the
outage schedule. There was a 12-hour window for management to perform an outage
review prior to leaving cold shutdown and 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> for hot shutdown mode testing .
9
..
Licensee management had made several improvements in the area of outage planning
and execution. One example included "scripting" the schedule. This provided a brief
description of the specific action with each work order schedule item and was intended to
aid departments in determining the reason an action was being performed.
The operations department was changing to two 12-hour shifts to better maintain
continuity of ongoing evolutions. Outage management had discussed all outage-related
operations department evolutions prior to the start of the outage. Also, the majority of
tagging activities were completed well in advance of the outage.
Outage planning areas that appeared improved were the ability to merge different
department outage schedules and the use of "single points of contact" for outage issues.
"Single points of contact" were developed to foster. better ownership of outage work
items. Maintenance management had addressed a weakness identified in the last refuel
outage in the area of contractor control. This was accomplished by assigning an
experienced licensee maintenance manager to directly overview contractor work. The
inspectors and licensee management do not view this refueling outage to be challenging
based on the approximately 1,000 work orders scheduled. To reduce the workload on
engineering staff and to allow more time for engineering personnel to review various
options, licensee management deferred several safeguards high pressure air system
upgrades to the 1999 refueling outage. These included four pressure control valve
replacements and six filter relocations. Also, the licensee plans on completing the
modification to replace the lubrication oil coolers on primary coolant pump P-SOC only,
instead of modifying all four pumps.
c.
Conclusions
The planned work scope for the 1998 refueling outage should not be challenging for the
licensee to safely accomplish. The level of planning and preparation was thorough and
complete. However, the inspectors noted that some longstanding equipment problems
were deferred.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1
Containment Air Lock Door Problems
a.
Inspection Scope (62707 and 37551)
The inspectors reviewed recent maintenance and surveillance issues concerning the
personnel air lock and to a lesser extent, the emergency escape air lock. Maintenance
and surveillance procedures were reviewed. Portions of the associated surveillance test
were observed. Discussions were held with maintenance and engineering personnel.
Applicable TS and design bases documents were also reviewed.
b.
Observations and Findings
On March 19, 1998, a m~intenance crew was unable to exit containment through the
-* - -- -personnei-air lock. The handwheel on the inner door spun freely and would not open the
door. The crew then attempted to exit containment through the emergency escape air
lock. The.technician operated the ert'lergency door handwheel in the direction he thought
was correct. However, the inner door was not opening and the technician identified, via
10
the door observation port, that the emergency air lock outer door had opened. The
technician then tried to close the outer door but the gear mechanism which connected the
hand wheel to the door had jumped out of timing and the door jammed. Another
maintenance crew then entered the emergency escape lock to repair the door. The lead
engineer overseeing the maintenance mentioned that the problem had occurred several
times before. The gears were realigned and the doors tested satisfactorily.
Mechanical maintenance personnel later performed troubleshooting and repair activities
on the personnel air lock inner door. The door failed to operate properly due to
misalignment of the handwheel shaft gears and the latching mechanism gears. The
apparent cause of the misalignment was a loose locking collar that allowed the
handwheel shaft to move. System engineering personnel contacted the vendor to
discuss the problem and were informed that this problem had occurred with other doors
of a similar design. The inspectors noted that there was a periodic scheduled visual *
inspection of the handwheel door gear mechanism for the personnel and emergency air
locks. However, fastener tightness checks were not performed. Also, the i'nspectors
noted that the directions for operating the emergency escape air lock were hand-written
on the air lock doors and not very noticeable or explicit.
On April 8, 1998, a full barrel test, which pressurizes the space between the two
personnel air lock doors, was conducted. The personnel air lock failed the surveillance
test. Excesstve leakage was identified on the inner door and the door was declared
inoperable. Operations personnel entered the appropriate TS action statement which
required that the plant be placed in hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Also, the outer door
was locked closed as required. The licensee's TS required full personnel air lock
operability. However, the licensee, based on management's interpretation of the TS,
would not allow repairs to the inner door because the outer door was required to be
locked closed.
Subsequently, a TS amendment was approved by the NRC and issued on April 8, 1998.
The amendment incorporated a note to allow opening an operable air lock door to
perform repairs on inoperable air lock components.
The personnel air lock passed the full barrel test following repairs to the inner door.
However, problems were encountered following restoration of the inner door.
Strongbacks were installed on the in.ner door as part of the test setup. Some of the
strongback bolts were found to .be galled while removing the strongbacks. Based on
subsequent investigation by maintenance and system engineering personnel, the
licensee identified that not all eight strongbacks aligned as well as others in certain
locations. Maintenance and system engineering personnel reviews for corrective actions
regarding the strongback issue were ongoing.
c.
Conclusions
The TS amendment should benefit the licensee if personnel air lock operability problems
arise in the future. However, the inspectors discussed with the licensee the need for
maintenance and system engineering personnel to ensure corrective actions adequately
address reliability of the personnel and emergency air locks due to the safety significance
of these components regarding containment integrity as well as personnel safety.
11
M3
Maintenance Procedures and Documentation
\\'
- a.
Inspection Scope
The inspectors observed ongoing Emergency Diesel Generator maintenance activities
during routine plant tours. Also, the inspectors reviewed Administrative Procedure
(AP) 5.09, "Maintenance Cleanliness Standards," Revision 6, dated August 29, 1996, as
well as the applicable work order package.
b.
Observations and Findings
On April 26, 1998, the inspectors observed that Emergency Diesel Generator (EDG) 1-1
generator end screens were removed for maintenance and that a drop light was hanging
inside the generator. However, no maintenance personnel were in the EDG room
performing any maintenance activities. The inspectors questioned licensee maintenance
personnel regarding FME controls for the EDG. Licensee maintenance personnel stated
that leaving the generator covers off did not meet expectations but was not contrary to
AP 5.09 cleanliness requirements.
Section 6.1. 7 of AP 5.09 stated, in part, that after system integrity has been broken
(i.e, a valve r~moved from a pipeline or a pump casing opened) an acceptable covering
shall be used on system openings to prevent foreign matter from entering the system or
equipment. Maintenance personnel stated that AP 5.09, Section 6.1.7, was for
mechanical or piping systems and that it did not cover electrical systems. Maintenance
personnel also stated, after further questioning by the inspectors, that FME requirements
for electrical components were unclear. Subsequently, a condition report
(C-PAL-98-0861) was generated by the licensee regarding unclear.FME requirements for
electrical components.
The inspectors noted that cleaning and inspecting the generator following the
maintenance was included in the work order package. This activity was documented in
the work package as being completed. Cleaning and inspecting would reduce the
potential for leaving any foreign material in the generator that may have been introduced
while the generator end was uncovered. Based on a review of the FME procedural
requirements that were in place, it appeared that the requirements were met. However,
procedure AP 5.09 was inappropriate to the circumstances in that the procedure did not
- have adequate specific FME requirements for safety-related electrical components, such
as the emergency diesel generator. The failure to specify adequate FME requirements
for safety-related components is a violation of 10 CFR Part 50, Appendix B, Criterion V,
"Instructions, Procedures, and Drawings." (VIO 50-255/98005-01).
c.
Conclusions *
The inspectors identified that no FME covers were installed on the EDG generator access
covers and no maintenance personnel were present to maintain positive FME controls.
Also, inadequate requirements existed for FME controls pertaining to electrical
components which was a viol~tion of regulatory* requirements.
12
M8
Miscellaneous Maintenance Issues (92902)
M8.1
(Closed) Violation 50-255/97005-01: Unauthorized Code repair performed on main steam
isolation valves (MSIVs), CV-0501 and CV-0510. This violation was issued due to the
failure of the initial valve repairs to meet the original Code of Construction, ASA 83.1. On
December 20, 1996, with the plant in hot shutdown, both MSIVs were leaking steam from
the plugged stuffing box leakoff points. A pipe plug was supposed to be installed and
seal welded for both valves. On CV-0501, a plug replacement was required because the
temporary leak injection plug hole was leaking. However, this plug was not removed.
The hole was seal welded after the hex head was ground down and the original plug was
not removed. The plug on CV-0510 also was modified prior to seal welding the plug by
grinding the hex head. The original plug did not get replaced as planned because it could
not be removed. A lab report later indicated that the pipe plug was cast iron versus
forged steel. Subsequently, the plug experienced fractures which led to the leaking.
These containment isolation valves were designed to isolate the steam generators. The
leakage represented a potential release path of radiation in the event of a steam
generator*tube leak. Subsequently, both leaking pipe plugs were permanently repaired by
installing 3000 psi, forged steel one inch pipe plugs. All work was approved and
inspected by engineering staff and no new steam leaks have developed since completion
of the repairs. Therefore, this item is closed. Closeout of Violation 97005-03 will address
the procedural and human performance issues identified during review of this issue .
. M8.2
(Closed) Violation 50-255/97005-02: Failure to submit a licensee event report (LER) in
30 days as required by 10 CFR 50. 73. The licensee failed to submit an LER within
30 days after the discovering degraded stuffing boxes on the main steam isolation
valves (MSIVs). Condition Report (CR) C-Pal-97-007 documented the
December 20, 1996, MSIV leaks. The licensee based operability on information
contained in the CR cover page. The CR did not contain any information about the
potential for a piping code violation. Licensing personnel considered the steam leak to be
similar to those seen during other plant startups and determined that it was not
reportable.
On March 6, 1997, during the management review board to discuss this CR,
management realized the issue was potentially reportable. The evaluator was requested
to brief licensing personnel and make another reportability determination. The condition
was subsequently determined to be reportable and LER 97-005 was initiated. The LER
was submitted to the NRC on March 21, 1997.
The inspectors reviewed the corrective actions that were taken. Those actions included:
1) the licensing department was reorganized in February 1997, to place responsibility for
operability determinations in one group under a regulatory response supervisor; 2) the
offices of the regulatory response supervisor and licensing manager were relocated
adjacent to each other in order to facilitate the flow of information; 3) the licensing
department started quarterly self-assessments of the reportability process; and 4) lessons
learned training on this issue was conducted at the June 1997 licensing department
standdown meeting.
- -
The corrective action process was also modified. Copies of operability redeterminations
are routed to licensing. Also, the operability redetermination form was revised to provide
a prompt for the shift supervisors and engineering supervisors to check if new information
13
affects reportability. The inspectors determined that the corrective actions were
adequate; therefore, this item is closed.
M8.3
(Closed) Violation 50-255/9700~03: Failure to perform main steam isolation valve
(MSIV) repairs in accordance with 1 O CFR Part 50, Appendix B. requirements. The seal
welds on CV-0501 and CV-051 O were not performed as described in the weld inspection
checklists in the work order packages. Also, the work order packages were not in use at
the work site as required by Administrative Procedure 5.01, Attachment 2, "Work Order
Scheduling, Performance, and Completion." *
The following corrective actions were taken to prevent recurrence of this incident:
On March 6, 1997, all three maintenance groups stopped work and held
standdown meetings. The operations manager discussed expectations for job
performance and the consequences of not doing maintenance work well. The
lead supervisors also went over the lessons learned. from the MSIV work, which
included procedure adherence, roles and responsibilities, work scope control,
communications, use of self-checking, and conservative decision making.
Additionally, the maintenance manager issued a memorandum to all maintenance
and planning department supervisors on the consequences of a weak pre-job
brief.
The licensee added an item to the maintenance department Action Plan after
recognizing the need to identify multi-discipline tasks and assign a single point of
contact. Also, readiness reviews and pre-job briefs were targeted for
- improvement. The inspectors noted that using a single point of contact in
subsequent maintenance outages has been effective.
This event and the associated lessons learned were incorporated into the
continuing training program for maintenance and engineering personnel.
The proper use of sketches within the weld inspection checklist process,
particularly pertaining to seal welds, was clarified in Procedure 5.06,
Attachment 1, "Preparation of Welding/Inspection Checklist."
Licensee management appointed an experienced maintenance manager as
Construction Supervisor to more effectively implement contractor control.
The inspectors determined ttiat the corrective actions were adequate and have not
identified any similar occurrences. Therefore, this item is closed.
M8.4
(Closed) Violation 50-255/97011-01: Inappropriate maintenance procedure resulted in
personnel contamination .. A waste gas compressor room area monitor high radiation
alarm was received during maintenance on Waste Gas Compressor C-50A. The licensee
subsequently identified that radioactive gases were leaking from the waste gas system
header as a result of the gag that was installed on Relief Valve (RV)-1114. The method
for gagging the relief valve resulted in the waste gas surge tank header and tank being
open to the atmosphere, causing contamination of the maintenance crew.
A procedural weakness and failure to follow procedures were two identified root causes
for this event. A fluted tap, vice a bolt as required by the procedure, was used to gag the
14
relief. System integrity was maintained; however, gagging the relief valve with the fluted
tap allowed a pathway from the volume control tank to the compressor room due to the
tap's design characteristics. Also, the procedure did not provide for breeching a
radioactive gas system or have a step to identify to operations personnel and the
maintenance technicians that the waste gas system would be breeched during
cqmpressor testing.
Licensee management took the following corrective actions to prevent recurrence.
The technicians that were involved led discussions.on the expectations for
procedural compliance with all maintenance department personnel.
Administrative Procedure 4.10, "Personnel Protective Tagging," had a new section
added to address tagging of relief valves.
The applicable maintenance procedure, Waste Gas System (WGS)-M-2, was
revised to eliminate the need to gag RV-1114 in order to perform the component
checkout test.
The inspectors reviewed the corrective actions and determined that they were adequate.
Therefore, thi:; item is closed.
Ill. Engineering
E1
Conduct of Engineering
E 1.1
General Comments
Engineering personnel were frequently challenged with emergent equipment reliability
issues. Specifically, engineering personnel had to respond to and support emergent work
pertaining to containment air locks, turbine control systems, and auxiliary feedwater flow
controller operational issues. Engineering personnel responded to and supported these
activities in a timely manner.
E2
Engineering Support of Facilities and Equipment
a.
Inspection Sco.pe (37551, 61726 and 37551)
b.
The inspectors reviewed the follow-up action by licensee engineering personnel regarding
an NRC architect-engineering (AE) design inspection finding that pertained to inadequate
inservice testing of valves, as required by TS and American Society of Mechanical
Engineers (ASME),Section XI. The inspectors reviewed condition reports, attended
management review boards, held discussions with system engineers, observed portions
of the valve testing, and reviewed applicable TS requirements and inservice inspection
piping diagrams.
Observations and Findings
On November 10, 1997, the licensee determined, based on an evaluation by engineering
personnel of an NRC AE inspection finding, that two check valves (CK-ES3339 and
15
CK-ES3340) in the minimum flow recirculation piping from the discharge of each high
pressure safety injection pump, were not periodically tested to confirm closure capability.
Operators appropriately declared the valves inoperable. The check valves were
subsequently tested satisfactorily within th~ time allowed by TS.
A licensee event report (LER 97-013) and supplement were issued. Licensing personnel
determined that this condition was reportable as a violation of TS 6.5.7. The
administrative TS referenced in the LER required that a program provide controls for
inservice inspection and testing of ASME Class 1 through 3 components. The inspectors
noted that system engineering personnel had a program in place. Also, five additional
valves subsequently identified by system engineering personnel as lacking testing were
- specified in TS Table 3.6.1, "Containment Penetrations and Valves." Therefore, the five
valves were reported as required.
In April 1988, procedural upgrades to EM-09-02, "lnservice Testing of Plant Valves," were
completed to ~nsure that required valve functions identified in the Palisades Equipment
Database were incorporated into the inservice testing (ISD program. Licensee system
engineering personnel identified, during their review of the database, the inservice
inspection piping diagram, and TS, that the following valves had inadequate test
requirements:
- *
Check Valve CK-DMW400 had a safety function to open and allow water flow
from the primary water tank to the condensate storage tank. The database
incorrectly identified the open position as non-safety-related.
Charging pump line to safety injection test line isolation valve (M0-3072) had a
passive safety function to remain closed. Although the closed safety position of
the valve was verified, a position indication check was required. However, the
valve was removed from the surveillance testing procedure in error. This was
caused by an inadequate consideration of all available information when
determining the IST requirements.
Air space purge fan (V-46) discharge isolation valves (CV-1813 and CV-1814) had
a passive safety function to remain closed during any postulated accident
occurring above cold shutdown. These valves are electrically locked closed per
TS during power operations and therefore were capable of performing their design
function.
The valves may be opened during cold shutdown and were required to close* on a
containment high radiation.signal. However, since containment isolation was not
assumed during the postulated fuel handling accident, no credit was taken for
valve closure and the active safety function to close was not included in the IST
program. When the IST program was updated in 1995, licensee engineering
personnel failed to add these valves for required position indication testin.g. This
was caused by an inadequate consideration of all the available information when
determining the IST scope for these valves. Prior to that update, the code did not
require position indication testing for valves that have a passive function and
. _therefore, the valves were not included in the program.
Containment steam heating return and supply valves (CV-1501, CV-1502 and
CV-1503) may be opened to provide heating to containment if needed (the heating
16
..
function has not been used in several years). The valves are required to close on
- a containment high pressure signal or a containment high radiation signal. In this
case, the valves have an active safety function to close. However, since
containment isolation was not assumed during a postulated fuel handling
accident, no credit was taken for valve closure and the active safety function to
close was not included .in the IST program.
When the IST program was updated in 1995, licensee engineering personnel
failed to test the valves for stroke time and position indication. This was caused
- by an inadequate consideration of all the available information when determining
the IST scope for these valves.
In addition, system engineering personnel noted that the database was deficient.
However, based on the effort that would be required to update and maintain the
database, system engineering personnel determined it would be more effective to rely on
a questioning attitude on the part of the engineers in identifying errors. Therefore, the
database and component/system basis documents will only be updated as errors are
identified. Potential enforcement actions pertaining to the AE findings will be addressed
in Inspection Report 50-255/98004 (DRS).
c.
Conclusions
The inspectors noted that the follow-up to correct identified deficiencies with inservice
testing requirements was thorough. However, system engineering supervision relied on
engineering personnel to identify errors in the IST program data base.
.* E4
Engineering Staff Knowledge and Performance
/
a.
Inspection Scope
The inspectors observed the Management Review Board and Plant Review Committee
meetings associated with the main turbine stop valve inadvertent movements and
questions regarding operation of the auxiliary feedwater system flow control valve
controllers. Also, the inspectors reviewed condition reports and discussed the specific
issues with licensee engineering personnel.
b.
Observations and Findings
Main turbine stop Valve #1 partially closed (30 percent) inadvertently from its normal full
open position on March 17, 1998. A "level 2" Condition Report (C-PAL-98-0424) was
generated to evaluate the acceptability of operating with the stop valve partially closed.
Licensee engineering personnel consulted with vendor representatives during related
investigative activities. Postulated causes were small hydraulic fluid leaks in the valve
actuator, hydraulic fluid cleanliness problems, and digital electrohydraulic (DEH) .control
signal errors. Subsequently that same day, the turbine stop Valve #1 opened fully without
any operator action. On March 17, 1998, the turbine stop Valve #1 and governor
Valve #1 were closed and hydraulically isolated based on recommendations from the
vendor regarding the unknown status of turbine stop Valve #1. However, the DEH control
system was in the procedurally directed "auto testD mode following the closure of the
valves which precluded automatic response of the turbine control system. A
Management Review Board was held on March 20, 1998, to discuss turbine control
17
c.
options. Licensee engineering personnel again consulted with vendor representatives.
Based on these discussions, the decision was made to place the DEH controls in manual,
which was accomplished without any system perturbations. This meant that only manual
turbine control would be available to the operators.
The inspectors noted that licensee engineering personnel relied extensively on vendor
representatives for specific turbine generator control system operational knowledge. The
licensee contracted the vendor to maintain the turbine and turbine control systems and a
vendor representative was retained on site. Therefore, licensee engineering reliance on
the vendor representative was expected.
- The licensee identified, during bench testing of new Yokagowa flow controllers for the
auxiliary feedwater system, that the controller would not automatically transfer to the
"cascade" mode from the "manual" mode if an auxiliary feedwater actuation signal was
received. A condition report (C-PAL-98-0634) was generated. This was contrary to
system engineering's understanding of how the controllers worked. In the "cascade"
mode, the controller was designed to automatically set auxiliary feedwater flow to the
minimum needed, 165 gpm, for decay heat removal following a plant trip regardless of
what the flow controller was set at before. The controllers were to be installed during the
outage as an upgrade to the auxiliary feedwater system. Two of the four auxiliary
feedwater sy$tem flow controllers presently installed are Yokogowa. The licensee,
. therefore, intends on replacing the other two.
The inspectors questioned licensee training personnel and control room operators
regarding Yokogowa controller operation. The inspectors noted that the simulator
modeled the controllers correctly. The simulator modeling was changed to reflect the
actual operation due to a simulator deficiency report which was generated in March 1994.
Also, the operators that were questioned believed that the controllers would not
automatically transfer to the "cascade" mode if they were in "manual" and an auxiliary
- feedwater actuation signal was received.
Conclusions
The licensee relied on vendor representatives rather than in-house knowledge of the
turbine control systems. Also, some licensee engineering personnel did not understand
the* operational design for the auxiliary feedwater Yokagowa flow controllers. This
indicated an apparent knowledge weakness on behalf of engineering personnel regarding
auxiliary feedwater flow controllers and the turbine generator control systems.
E8
Miscellaneous Engineering Issues (92903 and 92700)
EB.1
- (Closed) LER 50-255/96007-00: Inadequate Appendix R emergency lighting and
ventilation in post-fire safe shutdown areas. Two areas of noncompliance with
Appendix R requirements were identified by licensee system engineering personnel. The
first noncompliance was identified during plant walkdowns to verify adequate emergency
lighting for post-fire safe shutdown actions. The walkdown identified 12 loc.atjons where--
existing emergency lighting was inadequate. The second noncompliance was identified
during completion of support calculations to determine if the loss of ventilation in post-fire
safe shutdown areas would result in excessive temperatures during a fire related plant
shutdown. The licensee determined that the control room and cable spreading room
18
required temporary ventilation. The use of portable fans was considered acceptable.
However, current plant procedures .for post-fire safe shutdown did not instruct plant
personnel to use the existing portable fans for cooling the two areas.
The inspectors reviewed the following corrective actions that were taken:
Ten existing emergency lighting units (ELUs) were re-aimed based on walkdown
recommendations.
A third headlamp was installed on seven existing ELUs, three new ELUs were
installed, and one ELU was lowered, based on walkdown recommendations.
A high pressure safety injection valve inside containment was modified to allow
local manual control of the valve from outside containment instead of installing an
ELU in containment, due to concerns with maintaining equipment inside
containment.
Off-Normal Procedure (ONP)-25.1, "Fire Which Threatens Safety Related
Equipment," was revised to identify the need to use portable ventilation units to
provide cooling to the control room and cable spreading room based on actual
room ~emperatures.
The inspectors determined that the corrective actions taken were adequate and therefore,
this item is closed.
EB.2
(Closed) IFI 50-255/96008-05: Potential for calcium carbonate fouling of service water
heat exchangers. On May 31, 1996, maintenance personnel removed a section of piping
downstream of the chlorination system eductor. The inner surfaces of the eductor and
observable downstream piping were coated with a thick layer of calcium carbonate.
Pieces of the coating, approximately three quarters of an inch in diameter, had broken off
in some areas. The inspectors were concerned about the pieces potentially fouling the
. service water system heat exchangers.
The inspectors held discussions with the system engineer. Also, the maintenance history
and the chlorination piping system were reviewed. The chlorination chemical's (sodium
hypochlorite) reaction with. the lake water caused the calcium carbonate to plate out on
the piping walls. The eductor and a section of adjacent downstream piping were
replaced. An inspection of the piping indicated the buildup of calcium carbonate was
most significant nearest the eductor and tapered off further downstream in the piping.
The chlorination system piping goes to the bottom of the service water bay to a section of
diffuser piping with 5/16 inch perforations. Divers inspect and clean the service water bay
every refueling outage. The divers also rod out the diffuser's 5/16 inch perforations to
remove trapped pieces of calcium carbonate. The inspectors noted that the diffuser
would trap any significant pieces of calcium carbonate, thus preventing the piece.s from
getting trapped in the service water system heat exchangers. Therefore, this item is
closed .
19
IV. Plant Support
R1
Radiological Protection
RB.1
Refueling Outage and Daily Radiological Work Practices (71750 and 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
technicians were visible at the job sites. Also, the technicians took appropriate actions
and surveys in accordance with good AL.ARA practices. The inspectors concluded that
radiological practices observed during the maintenance activities and routine plant
walkdowns were adequate.
R8
Miscellaneous Plant Support Issues (92700 and 92904)
RB.1
(Closed) LER 50-255/97006-00: Overtime limits exceeded for radiation protection
technicians. On April 12, 1997, licensee personnel identified three occasions in 1997
when the overtime limitations of Administrative Procedure 1.00 and TS 6.2.2.e.2 were
exceeded. In each case, radiation protection technicians who worked both days of the
weekend, wofked more than 24-hours in a 48-hour period. Based on further review, the
licensee identified a total of seven similar occurrences in 1996 and 1997. These
occurrences were considered to represent a significant administrative breakdown of the
overtime limitations policy and therefore were reportable to the NRC.
The following corrective actions were taken: 1) the scheduler for chemical and
radiological services took immediate action to ensure technicians were not scheduled for
more than one weekend or holiday shift in any 2 day period; 2) overtime limitation
responsibilities and expectations were communicated to supervisors; 3) personnel in the
human resources group started to perform 100 percent audits of overtime on a monthly
basis for all non-salaried and salaried employees; and 4) overtime waivers were trended
on a monthly basis and published as a performance indicator in the management
performance monitoring reports. The corrective actions taken were considered adequate
and therefore, this item is closed.
RB.2
(Closed) URI 50-255/97005-04: Inability to determine sensitivity of criticality monitors.
The ability to safely load new fuel into the new fuel storage racks was indeterminate
because a criticality monitor that met the requirements of 1 O CFR 70.24, "Criticality
Accident Requirements" had not been installed. Specifically, 10 CFR 70.24(a)(2) requires
that the radiation monitoring system be capable of detecting a critical condition in the new .
fuel array which generates radiation levels of 300 rem/hour, one foot from the source of
radiation. However, 10 CFR 70.24(d) states that an exemption may be requested with
appropriate justification.
Licensing department personnel requested an exemption by a letter dated July 2, 1997.
The Commission's technical staff reviewed the submittal and determined that the
licensee met the criteria for prevention of inadvertent criticality.
- the purpose of the criticality monitors required by 10 CFR 70.24(a) was to ensure that if a
criticality were to occur during the handling of new fuel, personnel could be alerted to that
fact and would take appropriate action. The NRC staff determined that it was extremely
20
unlikely that such an accident could occur. Also, radiation monitors were in place in the
fuel storage and handling areas as required by General Design Criteria 63. These
monitors should alert personnel to excessive radiation levels and allow them to initiate
safety actions. The low probability of an inadvertent criticality, together with the
licensee's adherence to General Design Criteria 63, constituted appropriate justification
for the exemption to the requirements of 10 CFR 70.24(a). The licensee received the
exemption on October 27, 1997. Based on receipt of this exemption, this item is closed.
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.
V. Management Meetings
X1
Exit Meeting
The inspectors presented the inspection results to members of licensee management at
the conclusion of the inspection on May 6, 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, 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, PalisaQes Project Manager, NRR
- --**------ ------
22
INSPECTION PROCEDURES USED
IP 37551:
IP 61726:
IP 62707:
IP 71707:.
IP 71750:
Onsite Engineering
Surveillance Observations
Maintenance Observation
Plant Operations
IP 92700:
Plant Support Activities
Licensee Event Reports
IP 92901:
IP 92902:
IP 92903:
- *Follow-up Operations
Follow-up Maintenance
Follow-up Engineering
Opened
50-255/98005-01
Closed
50-255/96007-00
LER
50-255/96008-05
IFI
50-255/95003-00
LER
50-255/97005-01
50-255/97005-02
50-255/97005-03
50-255/97006-00
LER
50-255/97011-01
50-255/97005-04
ITEMS OPENED AND CLOSED
Lack of adequate specific FME requirements for electrical
components.
Inadequate Appendix R emergency lighting and ventilation
in post-fire safe shutdown areas
r
Potential for calcium carbonate fouling of service water
heat exchangers
Main feedwater pump transient resulting in a reactor trip
Unauthorized Code repair performed on main steam
isolation valves
Failure to submit a licensee event report in 30 days as
required by 10 CFR Part 50.31
Failure to perform main steam isolation valve repairs in
accordance with 10 CFR Part 50, Appendix B requirement
Overtime limits exceeded for radiation protection
technicians
Inappropriate maintenance procedure results in personnel.
contamination
Inability to determine sensitivity of criticality monitors.
23
AE
A LARA
CFR
CK
CR
DWO
FHS-M
IFI
LER
MO
NRC
ONP
QO
RV
TS
WGS
LISTOFACRONYMSUSED
Architect Engineer
As Low As Reasonably Achievable
American Society of Mechanical Engineers
Code of Federal Regulations
Condition Report
Digital Electrohydraulic
Division of Reactor Projects
Division of Reactor Safety
Daily/Weekly Operations
Electrohydraulic Control
Emergency Lighting Unit
Fuel Handling System-Maintenance
High Pressure Safety Injection
Inspection Follow-up Item
lnservice Test
Licensee Event Report
Main Feedwater Pump
Monthly Operations
Nuclear Regulatory Commission
Off Normal Procedure
Public Document Room
Quarterly Operations
Refueling Test
Relief Valve
Technical Specifications
Unresolved Item
Violation
Waste Gas System
24