ML20135E099
| ML20135E099 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 02/28/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20135E089 | List: |
| References | |
| 50-313-96-09, 50-313-96-9, 50-368-96-09, 50-368-96-9, NUDOCS 9703060260 | |
| Download: ML20135E099 (25) | |
See also: IR 05000313/1996009
Text
i
.
,
!
1
ENCLOSURE 2
l
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
l
Docket Nos: 50-313;50-368
l
Report No:
50-313/96-09:50-368/96-09
I
'
l
Licensee:
Entergy Operations, Inc.
Facility:
Arkansas Nuclear One, Units 1 and 2
Location:
1448 S.R. 333
Russellville, Arkansas 72801
l
Dates:
December 22,1996, through February 1,1997
Inspectors:
K. Kennedy, Senior Resident inspector
J. Melfi, Resident inspector
S. 8urton, Resident inspector
Approved by: Larry Yandell, Acting Chief, Project Branch C
Division of Reactor Projects
ATTACHMENT: Supplemental information
l
l
{
l
l
9703060260 970229
ADOCK 05000313
0
.
l
.
EXECUTIVE SUMMARY
Arkansas Nuclear One, Units 1 and 2
NRC Inspection Report 50-313/96-09:50-368/96-09
This routine announced inspection included aspects of licensee operations, engineering,
1
maintenance, and plant support. The report covers a 6-week period of resident inspection.
Operations
Walkdown of the control room ventilation systems revealed that they were properly
aligned, in good material condition, and capable of supplying the required air to the
control room (Section 01.2).
The licensee loaded their second ventilated storage cask in accordance with
e
procedures and met the requirements of the Certificate of Compliance. Lessons
learned from the loading of the first cask were effectively implemented, which
shortened the time needed to complete the activity (Section 01.3).
For the Unit 1 EDG fuel oil system, the associated procedure provided misleading
guidance for determination of diesel operability during degraded fuel system
conditions. Followup and corrective actions were appropriate for the deficiencies
identified (Section 01.4).
A Unit 1 control room supervisor failed to verify that electricians had completed
e
1
work and authorized clearance of a hold card and closure of a breaker while work
on a 480 volt breaker was in progress. This was determined to be a violation.
Although no personnel were injured, this error created the potential for a personnel
injury or fatality. Significant weaknesses were noted in the lack of communications
between the control room supervisor and shift superintendent and the failure of an
auxiliary operator to question the work being performed by the electricians in a
panel that he knew was energized (Section 01.5).
Maintenance
The inspectors found that the maintenance and surveillance activities were correctly
performed in accordance with the applicable procedures and work instructions.
Personnel were knowledgeable and demonstrated effective communications,
self-checking, and peer checking. When conducted, prejob briefs were
comprehensive. Proper radiological work practices were observed (Section M1).
e
Instrumentation and controls technicians properly investigated and diagnosed
circuitry problems associated with a control element assembly timer malfunction
alarm. Technicians utilized a working model, located in the maintenance shop, prior
to actual troubleshooting, to pre-empt problems at the work location. Deficiencies
were properly resolved or dispositioned (Section M1.3).
The inspectors identified a vulnerability in the licensee's independent verification
process in that an individual involved in the closure of a valve also performed the
!
'
,
'
2-
1
independent verification that the valve was closed and locked. As a result, errors
made in the initial component manipulation may not be identified if one of the
individuals performing this manipulation performed the independent verification
(Section M1.4).
e
The licensee incorrectly determined that the f ailure of the Unit 2 reactor coolant
pump breaker to open was not a functional f ailure of the 6.9 kV switchgear system.
The failure did not result in the system exceeding any of its four performance goals
and the licensee stated that the error would have been identified during the next
periodic assessment of the system performance (Section M8.2).
Enaineerina
e
During a period where a Unit 2 containment recirculation sump isolation valve
i
,
bonnet relief valve was out of service, the containment recirculation sump isolation
valve remained operable. A proposed change to the Safety Analysis Report (SAR)
associated with the sump isolation valves was inadvertently fiied and not forwarded
'
for incorporation in the next revision (Section E1.1).
e
The licensee f ailed to update the Unit 1 SAR to incorporate the installation of
fibrous insulation on reactor coolant pumps. This was identified as a violation
(Section E1.2),
e
Implementation of Option 8 to 10 CFR Part 50, Appendix J, waa accomplished in
accordance with the submitted license amendment. Engineering had established
methods to track and identify problems above those required by the scope of their
program. One change updating a reference had not been submitted for the next
revision of the SAR (Section E2.1).
e
The licensee's procedure for setting the underload setpoints on the Unit 1 refueling
mast and spent fuel crane was incorrect and resulted in nonconservative setpoints.
This was determined to be a noncited violation (Section E8.1).
Plant Support
e
The inspectors concluded that personnel demonstrated very good radiological work
practices during the conduct of plant activities, including operator rounds and
maintenance and surveillance activities. The requirements of radiation work permits
were followed, health physics technicians provided support to plant activities, and
proper consideration was shown to maintain dose as low as is reasonably
achievable (ALARA) (Sections M1 and R1).
<
-.
_
..
.
_
.
.
.
.
---
.
.
1
O
l
.
Report Details
1
1
i
l
Summary of Plant Status
Unit 1 began the inspection period at 100 percent power. On January 5,1997, Unit 1
operators reduced power to 88 percent to perform a tu-Sine valve / governor valve test and
i
returned power to 100 percent on January 6. Unit 1 operated at 100 percent power for
l
the remainder of the inspection period.
Unit 2 began the inspection period at 97 percent power, where it remained throughout the
inspection period,
l. Operations
01
Conduct of Operations
01.1
General Comments (71707)
The inspectors reviewed ongoing plant operations. In general, the conduct of
operations was professional and safety conscious; specific events and notewnrthy
observations are detailed below:
01.2 Units 1 and 2 - Enaineered Safety Feature Walkdown of the Emeraency Control
Room Ventilation System
Units 1 and 2 share a common control room, which is required to be maintained
following a loss of coolant accident to minimize doses to control room operators.
The control room air is continuously monitored for high radiation, smoke, and
chlorine. On reaching predetermined setpoints, the control room will be isolated
from its normal supply of air and use the f mergency ventilation system.
Penetrations into the control room are designed and maintained to limit air infeakage
into the control room. Further, a safety-related ventilation system supplies filtered,
conditioned air at a higher relative pressure than surrounding areas to ensure that air
leakage is out of the control room. Both units share equipment that is necessary to
maintain this control room pressurization boundary.
To keep the control room supplied with filtered, conditioned air following an
accident, there are two 100 percent capacity filtration trains and two 100 percent
capacity cooling trains. Unit 1 has one filtration train and Unit 2 has the other
filtration train. Each filtration train has a roughing filter, high efficiency particulate
air filter and carbon filter, and a ventilation supply fan. Each train has an air
flowrate into the control room of 2000 cfm, of which 1667 cfm is recirculated from
the control room and 333 cfm is makeup from outside air. The makeup air assures
that air leakage through the control room pressurization boundary is out of the
control room.
The cooling for the control room is supplied by separate cooling trains, located in
j
the Unit 2 side of the control room. The cooling units receive air from the control
room, cool it, and recirculate 9900 cfm back into the control renm.
'
...
--
_
.
.__ --
-.
-
.
-
.
-
\\
.).
'
l
a.
inspection Scope (71707)
The inspectors performed a detailed walkdown of accessible portions of the control
room emergency ventilation system to verify its operability.
b.
Observations and Findinas
The inspectors walked down accessible portions of the control room ventilation and
cooling systems. The inspectors found that the system was aligned correctly, the
system appeared to be wel! maintained, and hangers and supports were made up
properly.
i
The power to various f ans, valves, and other components is supplied by a
combination of Units 1 and 2 safety-related power. The inspectors reviewed the
power sources and determined that a single failure of a power supply would not
,
degrade the system effectiveness.
The inspectors noted that the Seismic Category i Fan 2VSF-9 emergency filter unit
had an unsecured, wheeled charcoal filter hopper cart stored on top of the cabinet.
The inspectors asked to review the seismic qualification test for the emergency filter
unit to determine if this was an analyzed configuration. The licensee was not able
i
to locate the qualification report and, rather than continue looking for the test
report, evaluated the condition in Engineering Request 973696E301. The
evaluation determined that nothing would be adversely affected from the cart failing
off of Fan 2VSF-9. The licensee intends to secure the hopper , srt to the cabinet to
preclude it from rolling off.
c.
Conclusions
1
The inspectors concluded that the control room ventilation systems were proparty
,
aligned, in good material condition, and capable of supplying the required air to the
control room.
01.3 Loadina of Second Ventilated Storaae Cask
a.
Insoection Scope (60855)
'
The inspectors observed portions of the loading of the second ventilated storage
cask with Unit i spent fuel to verify that the cask was loaded in accordance with
procedural and Certificate of Compliance requirements. The licensee began loading
the cask on January 19,1997, and placed it on the storage pad on January 28.
b.
Observations and Findinas
The inspectors observed that the licensee followed their procedures and satisfied
the Certificate of Compliance requirements during the process of cask loading and
_. .
.
i
J-
movement. The inspectors found that the licensee effectively incorporated lessons
learned from the loading of the first cask, resulting in a more efficient process which
allowed them to complete the movement of the second cask in a shorter period of
time. The licensee was not able to significantly reduce the time it took to
!
vacuum-dry the cask, which took approximately 3 days to complete, and planned to
evaluate the process further.
i
c.
Conclusions
The licensee loaded their second ventilated storage cask in accordance with
procedures and met the requirements of the Certificate of Compliance. Lessons
learned from the loading of the first cask were effectively implemented, which
shortened the time needed to complete the activity.
01.4 Unit 1 - Emeraency Diesel Operability
a.
Inspection Scone (71707)
On December 26,1996, during the inspector's review of the Unit 1 control room
i
turnover sheet, it was noted that the Emergency Diesel Generator A fuel oil return
sight glass was observed by operators to be half full. The normal condition for this
i
sight glass is full. The inspectors were concerned that the loss of level was caused
i
by leakage of fuel into a cylinder which could damage the diesel during a diesel start
,
or result in a loss of prime to the fuel oil pump which would delay the diesel from
starting in the required amount of time. Inspection was conducted to assess the
licensee's evaluation of diesel generator operability.
b.
Observations and Findinas
The system engineer was interviewed to assess the impact of a loss of level in the
l
fuel oil sight glass on diesel operability. Procedure 1104.036, Revision 36,
" Emergency Diesel Generator Operation," indicated that while shutdown the diesel
would be considered inoperable and a condition report (CR) written "if there is no
fuel in the ' return fuel' sight glass."
l
The inspectors questioned the system engineer about two standpipes within the
sight glass and asked if the sight glass was effectively empty when the level was at
i
'
the top of the standpipes. The inspectors were concerned that, in the event of a
leak in the fuel oil system, the level in the sight glass would only drop to the top of
the standpipes and would not result in an empty sight glass. Thus, there would
i
l
always be some indication of fuelin the sight glass and the operability guidelines
contained in Procedure 1104.036would not be correct. The system engineer
'
investigated this and concurred that the sight glass would be effectively empty
when fuel oil was at the top of the standpipes, which corresponded to a sight glass
level of 3/4 full.
l
l
--
.
- _ .
_ _
_--
-
~_- .
.
,
l
-4
l
The inspectors noted that the operations shift turnover sheet indicated that the
sight glass was 1/2 full. The system engineer had been monitoring the
accumulation of bubbles in ti.a sight glass but was not aware of the indications
reported on the shift turnover sheet. During interviews with the operator, the
inspectors found that, although operations was reporting the level as 1/2 full, the
level was actually above the top of the standpipes. Operators believed that the
accuracy of the level report was not critical since the procedure indicated that diesel
generator operability was not affected until the sight glass was empty.
To address the level decrease in the sight glass, operators periodically operated the
fuel oil priming pump to refill the sight glass. No records were kept as to the
l
amount of leakage or the frequency for repriming the fuel oil system. System
engineering was not aware of how frequently operators were priming the fuel oil
system. The periodic operation of the fuel oil priming pump was not controlled or
logged as an operator work around.
In response to the inspectors' findings, the licensee revised Procedure 1104.36 to
require the diesel to be declared inoperable if fuel oil level in the return sight glass is
at the top of the standpipes and cannot be restored with the priming pump.
l
l
The inspectors observed the fuel oil level in the supply sight glass and confirmed
the slow accumulation of air bubbles in the dome. Subsequent observations by the
inspectors indicated no significant loss of level. The inspectors reviewed the
system design and possible leakage paths with the system engineer. Although the
licensee had not identified the source of the fuel oilleakage by the end of the
inspection period, they determined that fuel oil was not leaking into the cylinders.
Further investigation was planned to locate the source of the leak. The inspectors
concurred with the system engineer that the diesel remained operable because fuel
was not found to be leaking into the cylinders, only minor leakage was observed,
,
and the priming pump was able to restore level in the sightglass.
c.
Conclusions
The associated procedure provided misleading guidance for determination of diesel
operability during degraded fuel system conditions. Followup and corrective actions
were appropriate for the deficiencies identified.
01.5 Unit 1 -Imorocer Clearance of Hold Card (71707)
l
a.
inspection Scope
The inspectors conducted a review of the circumstances surrounding the improper
clearance of a hold card from an electrical breaker which created the potential for a
personnel injury or fatality. The inspectors reviewed paperwork associated with the
actual hold card, conducted interviews, and reviewed CRs related to hold card
issues for the last 2 years.
,
.
.
-5-
b.
Observations and Findinas
On January 13,1997, electricians were preparing to perform a scheduled
maintenance activity to remove and recalibrate Breaker B-1415, a 480 volt breaker,
which provides power to a main chiller. The lead craftsman entered the Unit 1 shift
superintendent's office at approximately 7:15 p.m. and requested that operators
hang the necessary tag to de-energize the power supply to Bus B-14. The lead
craftsman exited the office while operators tagged open Breaker A-104. At
approximately 8:15 p.m., the lead craftsman returned to the shift superintendent's
office to sign the Hold Card Authorization form, signifying that he considered the
system adequately isolated. The shift superintendent placed the Hold Card
Authorization form on his desk. The lead craftsman then left the office to
commence work on the breaker with two other electricians.
Concurrent with the lead craftsman signing in on the authorization form, the control
room supervisor entered the shift superintendent's office from the control room and
saw the lead craftsman signing the form. Because he thought that the lead
craftsman had previously signed in on the authorization form, the control room
supervisor believed that he was witnessing the lead craftsman sign the form to
release control of the hold card, signifying that tags were no longer required for the
work activity. There was no communication between the control room supervisor
and the shift superintendent or the lead craftsman. The control room supervisor
retrieved the hold card authorization form from the shift superintendent's desk and
took it into the control room to authorize the removal of the hold card. The shift
superintendent assumed the control room supervisor had retrieved the authorization
form to place it in the hold card book located in the control room. Because the
control room supervisor assumed that he had just witnessed the lead craftsman sign
for the release of the hold card, he did not adequately review the Hold Card
Authorization form and thus did not identify that the " Released By Lead Craftsman"
signature block had not been signed. The control room supervisor authorized
removal of the hold card from Breaker A-104 and directed operators to close the
breaker from the control room. Procedure 1000.027, Revision 22, " Hold and
Caution Card Control," Step 6.9.2, required the shift superintendent / control room
supervisor to verify that the " Released By Lead Craftsman" signature block was
completed prior to authorizing the removal of the hold card and system restoration.
The electricians had begun work on the breaker and removed one bus bar bolt from
the breaker when they saw an auxiliary operator taking voltage readings on the
switchgear in which they were working. The electricians also heard the humming
sound at the transformer. The electricians determined that the bus was energized
as indicated by the 500 volt reading on the bus voltage meter and with
measurements using their own voltmeter. The electricians stopped their work and
notified the control room that the bus on which they were working was energized.
No personnel were injured. The control room supervisor notified the shift
superintendent of the error. CR 1-97-009 was wntten to document the error.
,
..
.
_ . .
.
.
.
6-
in response to this event, night orders were issued to Units 1 and 2 operators, who
,
discussed the event and added a requirement to obtain a second verification that
the " Released by Lead Craftsman" signature block was properly completed prior to
authorizing clearance of the hold cards.
The licensee established an Event investigation Team to determine the root cause
j
for the event and recommend corrective actions. The inspectors reviewed the
findings of the team and found them to be thorough and comprehensive. The team
determined that the root cause was the failure of the control room supervisor to
follow Procedure 1000.027in that he did not verify that the lead craftsman had
signed the Hold Card Authorization form to release the hold card. The team
identified additional weaknesses in the hold card process, communications, and
personnel work practices. The inspectors found that the lack of communications
between the control room supervisor and shift superintendent, and the failure of the
auxiliary operator to question the work being performed by the electricians in a
panel that he knew was energized, were significant weaknesses.
The investigation team recommended, and the licensee planned to implement, a
number of corrective actions to address the root cause of the event and the
additionalidentified weaknesses. These included revising Procedure 1000.027 to
'
permanently implement a second verification that the craft had released the hold
card; evaluating the use of additional controls in the hold card process; conducting
all hands meetings to discuss the event and the potential consequences; and
discussing the event during continuing training with the appropriate personnel. In
addition, the team recommended reviewing the hold card process to identify all
single failure points in the hold card process which could result in an error and
determining the appropriate actions to address these single failure points.
The inspectors reviewed licensee CRs written in the last 2 years and did not identify
any corrective actions taken as a result of previous hold card issues which would
have precluded this event from occurring. The inspectors did note that, of the CRs
reviewed,11 were classified as significant by the licensee. The inspectors
categorized these significant CRs as: (1) personnel failing to verify the adequacy of
hold cards prior to commencing work; (2) inadequate hold card boundaries
established for work activities; (3) and failure to properly position components when
establishing hold card boundaries. Although the licensee had taken corrective
actions for these previous CRs, the inspectors found similarities between
weaknesses identified during this recent event and those identified in previous CRs.
These similarities included inadequate communications, auxiliary operators unaware
of activities occurring in their areas, and inadequate self-checking. The inspectors
found that, at the time of this inspection, the licensee was continuing to implement
corrective actions in response to previous CRs.
The inspectors determined that the failure of the control room supervisor to verify
that the lead craftsman had signed the Hold Card Authorization form, signifying
-
._
-. -
'
'
-7-
.
release of the hold cards for his work activity, as required by Procedure 1000.027,
Revision 22, " Hold and Caution Card Control," Step 6.9.2, was a violation of Unit 1
Technical Specification (TS) 6.8.1(50-313/9609-01).
c.
Conclusions
A Unit 1 control room supervisor f ailed to verify that electricians had completed
work and authorized clearance of a hold card and closure of a breaker while work
on a 480 volt breaker was in progress. This was determined to be a violation.
<
Although no personnel were injured, this error created the potential for a personnel
injury or fatauty. Significant weaknesses were noted in the lack of communications
between the control room supervisor and shift superintendent and the failure of an
I
auxiliary operator to question the work being performed by the electricians in a
panel that he knew was energized.
01.6 Unit 2 - Tour With Auxiliarv Operator
On January 22 the inspectors accompanied the Unit 2 waste control operator on a
tour of the auxiliary building. The inspectors found that the operator was very
)
'
knowledgeable, conducted a thorough tour of the auxiliary building, and took the
required logs. The operator maintained awareness of activities performed in his
1
watch station by questioning personnel he encountered to determine the activities
they were performing.
01.7 Review of Institute of Nuclear Power Operations (INPO) Evaluation (71707)
The inspectors reviewed the results of an INPO evaluation performed in July and
August ~
6 and found that the results were consistent with the NRC's evaluation
of licensee performance. Based on this review, no additionalinspections were
planned.
08
Miscellaneous Operations issues
08.1
(Closed) Inspection Followun item (IFI) 50-368/9602-01." Unexpected Drop in Fuel
Pool Level" (92700)
,
On March 20,1996, a mechanical failure of a Unit 2 spent fuel pool purification
filter drain valve resulted in a loss of level in the fuel pool. This followup item was
opened to track the resolution of the generic concern associated with other valves
used in the plant made by the same manuf acturer. The licensee wrote
CR 2-96-0129 to address the concern about generic valve f ailure and remote (reach
rod) operators. The licensee determin3d that the valve f ailure was caused by a
broken stem nut. Corrective actions incbded: (1) identifying critical valves and
reach rods; (2) defining management's expectations for initiating valve or reach rod
maintenance; (3) discussing expectations for acceptable performance and initiation
of maintenance on valves or reach rods; and, (4) modifications to reach rod position
i
.
.
-8-
indications susceptible to malfunction or inaccurate readings. The inspectors
concluded that actions taken to address the issues associated with the valve failure
were appropriate.
08.2 Review of TS Interoretations (92901)
The inspectors conducted a survey of the licensee's TS interpretations and
determined that none of the documents contained informal references to NRC
review and approval. The inspectors emphasized to the licensee that any informal
reference to NRC review and approvalin a TS interpretation is not recognized by the
Commission and is not an acceptable practice,
11. Maintenance
M1
Conduct of Maintenance
M 1.1 General Comments
a.
inspection Scope (62707)
The inspectors observed all or portions of the following work activities:
Unit 1 - Job Order 00958408," Replacement of NNI Signal Conditioner,"
performed on January 7,1997.
Unit 1 - Job Order 00959141," Bearing flush of P7-B Outboard Bearing and
Bolt Torque Check," performed on January 28.
I
Unit 1 - Job Order 00959946," Troubleshoot DROPS System," performed on
January 29.
Unit 2 - Job Order 00958216," Repair Gas Collection Header Flush
Connection Valve 2GH-5008," performed on January 10.
.
Unit 2 - Job Order 00958001," Troubleshoot Control Element Assemblies,"
performed on January 14.
Unit 2 - Procedure 1412.001, Revision 8, " Preventive Maintenance of
Limitorque SB/SMB Motor Operators," performed on Valve 2CV-5076-2,the
safety injection system header Number 2 shut-off isolation valve. This
maintenance was conducted en January 23 under Job Order 00958306.
b.
Observations and Findinas
'
The inspectors found that the maintenance activities were correctly performed in
accordance with the applicable procedures and work instructions. Personnel were
.
.
-9-
knowledgeable and demonstrated effective communications, self-checking, and peer
checking. When conducted, prejob briefs were comprehensive. Proper radiological
work practices were observed.
In addition, see the specific discussions of maintenance observed under
Sections M1.2 and M1.3, below.
M1.2 Unit 2 - Repair of Gaseous Radwaste Flush Connection isolation Valve
a.
Inspection Scoce (62707,71750)
On January 10,1997, the inspectors observed maintenance performed on Gas
Collection Header Flush Connection isolation Valve 2GH-5008in accordance with
Job Order 00958216. Maintenance was performed because the valve would not
close and was believed to be clogged with resin beads that accumulated during
system operation. Mechanical maintenance and radiological practices were
observed.
b.
Observations and Findinas
The prejob briefing included a discussion of the tools and equipment necessary for
maintenance, radiological concerns, contamination, and cleanliness aspects of the
activity. Unexpected mechanical and radiological conditions were also considered.
A 55 gallon lined drum was stationed to collect the contents of the piping when the
l
valve flange was opened. Health physics established containment bags to direct
any resin or liquids into the 55 gallon drum. The inspectors determined that the
mechanics appropriately considered pipe sizes and lengths to determine the volume
of water and foreign material that would need to be collected. Health physics
personnel were questioned about the possibility of unknown radiological conditions
in the piping and what precautions would be taken if the radiological conditions
changed during the maintenance. Health physics personnel stated that the piping
had only been surveyed as high as someone could reach and that, if radiological
conditions changed, the job would be terminated and personnel would leave the
area and conditions re-evaluated. Subsequent to the inspectors' questions, a
survey was conducted to determine the radiological conditions in the c,verhead
)
piping. The survey indicated no abnormal radiological conditions and that dose
rates due to the resin clog ended about 4 feet up the pipe from the valve.
Precautions were taken by operations, maintenance, and health physics in
anticipation of a ventilt
ilineup change that could affect airborne radiological
conditions. Mechanics and health physics showed concern for ALARA during
anticontamination clothing changing, maintenance prestaging, and the performance
of maintenance as indicated by discussions about radiological postings, staging
locations, and other health physics questioning. The inspectors observed that the
valve maintenance was performed in accordance with the work package.
__
_
_.
_ _ _ .
- _ _
__
_
_
.
..
.
l .
- 10-
!
c.
Conclusions
'
Maintenance of the gaseous radwaste flush connection isolation valve was
conducted safelv and in accordance with approved procedures. Proper radiological
precautions were taken to minimize the spread of contamination and ALARA was
considered during all aspects of the maintenance. However, initial radiation surveys
of the affected piping were conducted only as high as a technician could reach and
conditions in the overhead piping were not assessed.
M1.3 Unit 2 - Troubleshootina of Control Element Assembly (CEA)
,
a.
Insoection Scoce (62707)
On January 14,1997, the inspectors observed instrument and control technicians
troubleshoot CEA's under Job Order 00958001 to determine the cause of an
intermittent timer failure alarm.
b.
Observations and Findinas
inspectors observed the technicians investigate the circuitry associated with the
affected CEA. Troubleshooting methods were practiced in the shop on a working
model of the circuitry before field troubleshooting was accomplished. Additional
j
l
testing was conducted in the shop to determine if oscilloscope grounds would
l
affect the circuitry when used in the field. Technicians worked with system
'
l
engineering to utilize controlled wiring diagrams to investigate possible sources for
I
the f ailure. An integrated circuit card was believed to be the cause of the timer
failure alarm and it was replaced. The new card did not resolve the problem and
further troubleshooting revealed that an intermittent ground in the circuitry caused
the new card to f ailin the same manner. The intermittent ground could not be
reproduced. The integrated circuit card was again replaced and it functioned
correctly. The system was returned to service and a job order written to investigate
the circuitry when the system is out of service during the upcoming outage. The
inspectors observed peer checks, three-way communications, and a good
questioning attitude throughout the troubleshooting process.
l
c.
Conclusions
Instrument and control technicians properly investigated and diagnosed circuitry
problems associated with a CEA timer malfunction alarm. Proper use of three-way
communications, peer checks, and a questioning attitude were observed throughout
i
!
the maintenance process. Technicir.as utilized a working model, located in the
maintenance shop, prior to actual trc'ubleshooting to pre-empt problems at the work
location. The inspectors verified that a failure of the CEA timer would not affect the
ability of the CEA to trip into the core. Deficiencies were properly resolved or
dispositioned.
'
l
_
-
- - . - . - - - . - - __- - - - . - - .
.
-11-
M 1.4 General Comments on Surveillance Activities
a.
' Inspectino Scope (61726)
The inspectors observed all or portions of the following surveillance activities:
Unit 1 - Procedure 1104.036, Revision 36, "DG1 Monthly Test," performed
on January 6,1997.
Unit 1 - Procedure 1104.004, Revision 60, Supplement 1, " Low Pressure
injection (Decay Heat) Pump (P-34A) & Components Quarterly Test,"
performed on January 9.
Unit 2 - Procedure 2304.237, Revision 0, " Calibration of Emergency
Feedwater Flow and Pressure Inst. Red Channel," performed on January 6
and 7.
Unit 2 - Procedure 2104.036, Revision 41, " Emergency Diesel Generator
Operations," Supplement 18, "2DG1 Month ly Test (Slow Start), performed
on January 8.
Unit 2 - Procedure 2104.005, Revision 36, " Containment Spray System,"
Supplement 1, "2P-35A Quarterly Test With SDC Secured," performed on
January 9.
Unit 2 - Procedure 2106.006, Revision 44, " Emergency Feedwater System
Operations," Supplement 7, " Quarterly EFW Check Valve Test," performed
on January 10.
b.
Observations and Findinas
The inspectors found that the surveillances were correctly performed in accordance
with the applicable procedures. Personnel were knowledgeable and demonstrated
effective communications wlf checking, and peer checking. When conducted,
prejob briefs were compreber sive. Proper radiological work practices were
e
observed.
During the performance of Procedure 2104.005, Revision 36, " Containment Spray
System," Supplement 1, "2P-35A Quarterly Test With SDC Secured," the
inspectors observed the operators perform valve manipulations as set forth in the
procedure. Due to the size of some of the valves, two operators were used to
reposition the valves. The inspectors observed the operators close Valve 2SI-5A,
as required by the procedure. The inspectors observed self-checking and peer
checking used to verify that they were manipulating the correct valve and that the
j
valve was properly closed and locked. At the completion of the test, the procedure
required independent verification that the valve was in the locked closed position.
.
.
_.
_
_
__
.
_
_
_
.
.
-12-
The inspectors noted that the operator who assisted in closing the valve, but did
not sign the initial verification, was going to perform the independent verification
required by the procedure. He was going to leave the area of the valve to perform
another step of the procedure, then return to perform the independent verification.
It did not appear to the inspectors that this practice would provide an independent
verification of valve position since the operator was involved in the initial closure of
the valve.
The inspectors found that Procedure 1015.035," Valve Operations," which provided
guidance on how to perform independent verification, did not prohibit this method
of independent verification. The procedure stated that independent verification was
the act of confirming, by an independent means or by a second individual at a
i
separate time other than the initial verihcation, that actions were correctly
performed. The licensee stated that the method of independent verification used
during the surveillance was acceptable. Although the inspectors concluded that the
independent verification was done in conformance with Procedure 1015.035, they
determined that the practice observed during the performance of this test created a
vulnerability in the independent verification process in that errors made in the initial
component manipulation may not be identified if one of the individuals performing
i
this manipulation performed the independent verification.
M1.5 Conclusions on Conduct of Maintenance
The inspectors found that the maintenance and surveillance activities were correctly
performed in accordance with the applicable procedures and work instructions.
Personnel were knowledgeable and demonstrated effective communications,
self-checking, and peer checking. When conducted, prejob briefs were
,
comprehensive. Proper radiological work practices were observed.
,
The inspectors identified a vulnerability in the licensee's independent verification
process in that an individual involved in the closure of a valve also performed the
independent verification that the valve was closed and locked. As a result, errors
eJe in the initial component manipulation may not be identified if one of the
fividuals performing this manipulation performed the independent verification.
-
M8
Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Violation 50-313/9512-01033." Installation of the Cy.e Suocort Assembly
Was Not Classified as an Infreauentiv Performed Test or Evolution"
(Closed) Violation 50-313/9512-01043."A Comotete Briefina includina All
Personnel Involved With the Replacement of the Core Support Assembly Was Not
Conducted Prior to Performina the lift"
(Closed) Violation 50-313/9512-01053." Failure to Establish the Reauired Fuel
Transfer Canal Water Level Prior to Movina the Core Suocort Assembiv"
-
.
._ _
_ - - -
_
_
-
. _
.
I
-
t
-13-
(Closed) Violation 50-313/9512-01063 "Inadeauate Procedure for the Removal and
Replacement of the Core Suocort Assembiv"
(Closed) Violation 50-313/9512-01073," Personnel Exceeded Overtime Limits
Without Plant Manaaer Acoroval"
The inspectors verified the corrective actions described in the licensee's response
letter, dated August 16,1995, to be reasonable and complete.
'
M8.2 (Closed) Unresolved item (URI) 50-368/96008-01," Failure of RCP Breaker to Open"
s
a.
Inspection Scoce
NRC Inspection Report 50-313/96-08; 50-368/96-08 described the licensee's
response to a failure of the Unit 2 Reactor Coolant Pump (RCP) 2P-32A breaker to
open from the control room on November 17,1996. The licensee determined thit
the breaker failed to open due to grease hardening, which resulted in the binding of
the breaker's trip latch roller bearing, A URI was opened pending review of this
breaker f ailure with respect to the maintenance rule.
b.
Observations and Findinas
,
The inspectors found that the 6.9kV switchgear system was included in the
licensee's maintenance rule program. However, the licensee had not classified the
f ailure of the RCP breaker as a functional failure. In response to questions by the
inspectors, the licensee reviewed this decision and determined that the failure
should have been classified as a functional f ailure due to the fact that the breaker is
.
'
required to trip to provide containment penetration overcurrent protection. The
licensee reclassified this f ailure as functional . failure; however, the failure did not
l
cause the 6.9kV switchgear system to exceed any of its four system performance
,
critena.
System performance and maintenance rule evaluations are normally conducted by
the cognizant system engineer. The licensee found that, due to vacation, the CR
,
describing the RCP breaker failure was reviewed by someone other than the system
engineer for the 6.9kV switchgear. This contributed to the error. In discussions
with the inspectors, the system engineer stated that he would have identified the
error during his next periodic assessment of system performance conducted at the
end of the current cycle. The inspectors verified that the scope of the periodic
assessment, as described in the "ANO System Engineering Desk Guide," included a
review of system performance against the performance criteria. The inspectors
verified that the assessment of system performance included a review of CRs
written on the systems. The inspectors also found that the licensee had
incorporated industry experience into their maintenance plans for the
6.9kV switchgear.
.-
.
.
-14-
c.
Conclusions
The Unit 2 6.9kV switchgear was included in the licensee's maintenance rule
program. The licensee incorrectly determined that the failure of a Unit 2 RCP
breaker to open was not a functional failure. However, the licensee stated that the
error wLuld have been identified during the next periodic assessment of system
performance at the end of the current refueling cycle.
Ill. Enaineerina
E1
Conduct of Engineering
E1.1
Unit 2 - Containment Recirculation Sumo isolation Valve
a.
Insoection Scope (37551)
On December 14,1996, the low pressure safety injection suction header was
pressurized during the performance of a routine surveillance. This caused the
overpressurization of the bonnet area of containment recirculation sump isolation
Valve 2CV-5649 and resulted in Bonnet Relief Valve 2PSV-56031ifting. The
licensee subsequently found that Valve 2PSV-5603 leaked and isolated the valve.
Bonnet Relief Valve 2PSV-5603 was installed to address concerns related to
'
pressure locking of containment recirculation sump isolation Valve 2CV-5649. The
inspectors reviewed the effects of isolating Valve 2PSV-5603 on the operability of
the containment sump isolation valve. The inspectors were also concerned about
the potential for Valve 2PSV-56031eakage during accident conditions.
t
b.
Observations and Findinas
i
The inspectors were concerned that, with Valve 2PSV-5603 isolated, the
containment recircu!ation sump isolation valve would be susceptible to pressure
locking / thermal binding and could be rendered inoperable. Interviews with
engineering and reviews of operability analysis demonstrated that the sump isolation
valve would remain operable during periods when the relief valve was isolated.
The licensee determined that the relief valve was leaking due to debris in the valve.
Maintenance history indicated that Valve 2PSV-5603 was in a location that
contained debris which could cause the valve to stick open upon actuation. The
'
inspectors questioned the susceptibility of the relief valve to open during accident
conditions and subsequently leak, resulting in increased off-site doses. The licensee
indicated that Valve 2PSV-5603 was susceptible to lifting when Valve 2CV-5649
stroked to the closed position, but not when stroked to the open position, its
required position during the recirculation phase. Thus,it was unlikely that the relief
valve would leak during accident conditions and affect off-site doses. Plant Impact
Evaluation (PIE) 95-0057 determined that water maintained in the header between
the sump and the isolation valve was sufficient to preclude pressure loc. king of the'
i
!
..
_
_ .
___._
. ._ -- _ _ _.____ _ _ __
_ . .
._ _ _ _ _
_. _
..
.
-15-
valves. In addition, the licensee's calculations demonstrated that increases in room
temperature would not cause pressure locking of the valves. The licensee installed
the relief valves to increase the margin to prevent pressure locking of the valves.
The inspectors reviewed the Safety Analysis Report (SAR) to determine what
revisions were made as a result of the modification to add the relief valves to the
containment recirculation sump isolation valves. The inspectors found that a
proposed change to the SAR, written in response to an action item from a previous
condition report (CR 2-95-0116),had not been incorporated in the SAR. The
proposed revision to SAR Section 6.2.2.2.1, " Containment Spray System," stated
that water was required to be maintained in the piping between the sump isolation
valve and the recirculation sump to preclude pressue locking / thermal binding.
Although the change was not required to be made until the next revision of the
SAR, the licensee could not locate the proposed change. Subsequently, the
licensee determined that the proposed change had been inadvertently filed with the
closure documentation for the CR. As a result of the inspectors' questions, the
licensee included this change in the next amendment package.
c.
Conclusions
During a period when the containment recirculation sump isolation valve bonnet
relief valve was out of service, the containment recirculation sump isolation valve
-I
remained operable. Recommended revisions to facility documentation and
I
procedures associated with the original mod;fication were properly incorporated
with one exception. A proposed revision to the SAR, which the licensee had
intended to incorporate, was inadvertently filed and not fcrwarded to licensing.
E1.2 SAR Discrecancy Associated with Reactor Coolant System (RCS) Insulation
,
a.
jnspection Scoce (92903)
Inspection was performed to followup on a discrepancy identified in the Unit 1 SAR,
i
Section 4.2.2.7, " Reactor Coolant Equipment Insulation."
i
b.
Observations and Findinas
During walkdowns of the RCS following a fire in the Unit 1 reactor building on
October 17,1996, the licensee identified fibrous insulation installed on the bowls of
,
l
RCPs A and B (see NRC Inspection Reports 50-313/96-07:50-368/96-07and
50-313/96-27:50-368/96-27). The inspectors later discovered Section 4.2.2.7 of
the Unit 1 SAR stated that "due to fire protection concerns, fiberglass insulation
materials are not permitted on, adjacent to, or immediately below the RCP bowls."
i
i
5
i
-
.
-
--
-
-
e
.
-16-
The inspectors determined that Limited Change Package (LCP) 92-5005A installed
this fibrous insulation around the RCP bowls, and the SAR was not updated due to
the timing of the review of LCP 92-5005A. The following table shows the relevant
timeline.
1
Date
Description
Mar 92
LCP 92-5005, "RCS Insulation Upgrade," installed, adding new fibrous
1
insulation on the RCS to improve thermal performance. As part of
,
LCP 92-5005, SAR change to Section 4.2.2.7 was drafted, noting new
'
insulation and adding a caution not to have fibrous insulation around
the RCP bowls.
Jun 93
LCP 92-5005A, " Install RCS Insulation," written to add fibrous
insulation to RCPs.10 CFR 50.59 review of LCP 92-5005 A performed.
Jul 93
SAR updated from LCP 92-5005
Nov 93
LCPs 92-5005 and 92-5005A closed
LCP 92-5005 upgraded insulation around the RCS during Refueling Outage 1R12
(March 1992)to improve thermal performance of the RCS Mirror insulation was
placed around RCP A and B bowls. The RCP bowl fibrous insulation was installed
during Refueling Outage 1R13 (October 1993) per LCP 92-5005A. When
LCP 92-5005A was in final review (June 93), the SAR had not yet been updated for
l
the changes from LCP 92-5005. When performing a 10 CFR 50.59 review for
'
LCP 92-5005A,the reviewer did not look at pending SAR changes, and the SAR did
'
not prohibit the use of fibrous insulation on the RCP bowls. The 10 CFR 50.59
evaluation did conclude that fibrous insulation was acceptable for use on the RCP
,
bowls due to the existence of the RCP oil collection system.
)
10 CFR 50.71(e) states, in part, that each person licensed to operate a nuclear
power reactor shall update, periodically . . . the Final Safety Analysis Report (FSAR)
originally submitted as part of the application for the operating license to assure that
the information included in the FSAR contains the latest material developed . . . .
The updated FSAR shall be revised to include the effects of all changes made in the
facility or procedures as described in the FSAR . . . .
The f ailure to revise the FSAR to incorporate the installation of fibrous insulation on
RCPs A and B was identified as a violation of 10 CFR 50.71(e)(50-313/9609-02).
c.
Conclusions
The licensee f ailed to update the Unit 1 SAR to incorporate the installation of
fibrous insulation on RCPs. This was identified as a violation.
1
r
,
l
.
-17-
l
E2
Engineering Support of Facilities and Equipment
E2.1
Unit 2 - Performance Based Reauirements for Con, ta_inment Leakaae Testina
j
a.
insoection Scooe (37551)
The inspectors reviewed the licensee's implementation of Option B to Appendix J of
10 CFR Part 50 which was incorporated into the SAR and TSs with License
Amendment 176. This option allows licensees to establish performance based
inspection criteria for containment leakage testing. Included was a review of the
applicable TSs and conformance of the new program to Regulatory Guide 1.163,
" Performance-Based Containment Leak-Test Program," September 1996.
The following licensee documents were reviewed for the inspection:
,
Unit 2 SAR
Unit 2 TSs, Amendment 176
HES-02, Revision 4, " Arkansas Nuclear One Engineerina Standard For
Containment Leak Rate Testing Program"
Procedure 2304.015," Arkansas Nuclear One - Unit 2 Electrical Penetration
Local Leak Rate Tests"
Procedure 2104.009," Arkansas Nuclear One - N Systems Operations"
2
CR 2-96-0375," Increased Electrical Penetration Room Leakage"
b.
Observations and Findinas
TSs properly incorporated documentation submitted to NRC for the referenced
license amendment. The SAR did not require any changes to content because TSs
were referenced for local leak-rate test requirements.
HES-02, Revision 4, " Arkansas Nuclear One Engineering Standard for Containment
Leak Rate Testing Program," was reviewed. This procedure referenced the
associated commitments and contained methodology to monitor the performance of
those items previously covered by TSs. In addition to the leak rate testing program,
the licensee had established a database to track and trend associated components.
The database included several methods for trending both frequency of evaluation
and root causes for degradation. In addition, future procedural revisions were
planned to bettet quantify performance and testing frequency requirements.
.
.
-18-
c.
Conclusions
implementation of Option B to 10 CFR Part 50, Appendix J, was accomplished in
accordance with the submitted license amendment. Additionally, engineering had
established methods to track and identify problems above those required by the
scope of their program.
,
E8
Miscellaneous Engineering issues (92903)
E8.1
(Closed) URI 50-313/9607-01:50-368/9607-01,"Cause of Fuel Pin Failure.
Nonconservative Crane Setooints, and Verification of Correct Setooints for Both
Units' Refuelina Masts and SFP Cranes"
a.
Inspection Scone
During the Unit 1 reieeling outage, the licensee identified damage to their fuel
assembly grid straps, damage on one fuel rod, and nonconservative underload
setpoints on the Unit 1 refueling mast and spent fuel cranes. This URI was opened
to review the licensee's actions with respect to these items and also verify the
underload settings on the Unit 2 spent fuel pool mast,
b.
Observations and Findinos
At the start of the refueling outage, the licensee had indications of fuelleakage.
Due to problems at other plants with grid strap movement, the licensee also
inspected the fuel assemblies. As a result of this inspection, the licensee noted
damage on the grid straps' corners and one grid strap that was torn along the side.
i
The licensee also found that one end cap weld on one fuel pin had a full
,
circumferential crack.
The licensee noted that the fuel pin damage was due to an improper weld done by
the fuel vendor (Framatome). The vendor changed their welding procedure to
improve the process and preclude further problems.
!
Most of the damage to the grid straps was on the corners of the grid straps, which
the licensee believed was due to the fuel upender not being vertical. This was fixed
during the previous refueling outage. The licensee also observed that some damage
was not attributable to the upender, which included a torn grid strap on a
once-burned fuel assembly. In conjunction with the torn grid straps, the licensee
identified that the refueling bridge and spent fuel pool mast had underload setpoints
that were approximately 15 pounds nonconservative. The licensee determined that
the underload setpoints on the Unit 1 refueling mast and spent fuel crane were
incorrect due to inaccurate weights of the control rod assemblies used in the
determination of the setpoint. It was not clear whether this slight amount of
nonconservatism could have caused the damage observed. The licensee believed a
_.
. .
. _ _
.-
. . .
-
--
.
_-
.
-
- - .
.-
. - - _ - .
.
.
)
-19-
,
,
)
i
combination of factors caused the grid strap damage and implemented corrective
actions to prevent recurrence. The licensee revised their procedure to include the
j
approprhte underload setpoints.
The licensee found that Procedure 1502.003, Revision 17, " Refueling Equipment
I
and Operator Checkouts," provided an incorrect value for setting the underload
1
setpoints for the Unit 1 refueling mast and spent fuel crane. This was determined
"
to be a violation of 10 CFR Part 50, Appendix B, Criterion V, in that the procedure
was not appropriate to the circumstances. This licensee-identified problem was
promptly corrected and the licensee's corrective actions for the grid strap damage
were appropriate. Based on the above, this is being treated as a noncited violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy (50-313/9609-03).
The inspectors also reviewed the methodology used to set the underload and
.
i
overload limits for the Unit 2 refueling bridge and spent fuel pool. The inspectors
found that the licensee set the Unit 2 underload and overload limits appropriately.
c.
Conclusions
The licens90's procedure for setting the underload setpoints on the Unit 1 refueling
i
mast and spent fuel crane was incorrect and resulted in nonconservative setpoints.
'
This was identified as a noncited violation.
E8.2 (Closed) Licensee Event Reoort (LER) 50-313/94003-00/01."SurveillanceTestina of
,'
Some Enoineered Safeauards Components Did Not Verifv Operability Due to
Procedural Deficiencies" (92700)
1
LER 94-003 was written by the licensee to report inadequate surveillance testing of
,
f-
some engineered safeguards components. These inadequacies were described in
NRC Inspection Report 50-313/94-08;50-368/94-08 and were determined to be a
'
noncited violation. A task force, established as a result of this and similar findings,
identified an additionalinstance of inadequate testing related to the autostart
function of the high pressure injection auxiliary lubricating oil pumps. The
'
inspectors reviewed the licensee's corrective actions and found them to be
thorough and complete.
,
,
E8.3 (Closed) Violation 50-368/9408-02."Inadeauate Intearated ES Feature Tests"
(92903)
(Closed) LER 50-368/94-004." Surveillance Test of HPSI Pumo Did Not Verifv
Operability by Technical Specifications" (92700)
These two items concern the same issue, and the licensee wrote LER 50-368/94-
004 for this violation of Technical Specifications. The inspectors verified the
corrective actions described in the licensee's response letter, dated December 9,
1994, to be reasonable and complete.
.
_
_
l
'
.
-20-
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
'
R1.1 Unit 2 - Reoair of Leakina inspection Cover on Deboratina lon Exchanaer
1
a.
Inspection Scope (71750)
On January 15,1997, the inspectors monitored radiological practices for the repair
of an inspection cover on the deborating ion exchanger Tank 2T-70, conducted
under Job Order 00942776. Radiological Work Permit 1997-0052 was established
for the maintenance on Tank 2T-70, which was located in a locked high radiation
area.
b.
Observations and Findinas
Prebriefings were held that ensured minimal exposures were received. Rotation of
workers and prestaging of materials ensured that exposure times were minimal.
Health physics technicians showed proper concern for exposure by closely
monitoring entry times and ensuring that maintenance workers remained in low
dose areas while standing by to perform tasks. A dose goal of 0.100 person-rem
l
was set for the performance for this task. Total dose for the performance of this
task was 0.058 person-rem.
c.
Conclusions
The inspectors concluded that radiological work practices conducted for the repair
of the inspection cover on the deborating ion exchanger were conducted in
<
accordance with the radiological work permit. Proper consideration was shown for
ALARA and the total dose for the performance of the task was less than the dose
goal.
F2
Status of Fire Protection Facilities and Equipment
F2.1
Units 1 and 2 - Self-Contained Breathina Apoaratus (SCBA)
.
The inspectors conducted annualinspections of SCBAs. The SCBAs were checked
for test dates and supply bottle inspections. All apparatus were within their
inspection dates and bottles were Deing checked on a monthly basis as required.
T.
.
,
,
!
SUPPLEMENTAL INFORMATION
,
ATTACHMENT
PARTIAL LIST OF PERSONS CONTACTED
I
1
.
Licensee
P. Allen, System Engineering, Unit 2
i
C. Anderson, Plant Manager, Unit 2
J. Clement, Assistant Manager, Unit 1 Operations
,
D. Denton, Director, Support
i
P. Diet rich, Superintendent, Unit 1 Mechanical Maintenance
j
R. Edington, General Manager Plant Operations
B. Gordon, Supervisor, Unit 2 System Engineering
R. Hutchinson, Vice President, Operations
R. Lane, Director, Design Engineering
D. McKenney, Acting Manager, Unit 1 System Engineering
D, Millar, Supervisor, Unit 2 Operations Standards-
D. Mims, Director, Licansing
T. Mitchell, Manager, Unit 2 System Engineering
j
F. Philpott, Superintendent, Reactor Engineering
i
T. Russell, Manager, Unit 2 Operations
M. Smith, Supervisor, Licensing
A. South, Licensing
J. Veglia, Supervisor, Modifications
D. Wagner, Supervisor, Quality Assurance
C. Zimmerman, Plant Manager, Unit 1
Framatome Technoloaies. Inc.
D. Scott, Resident Engineer
NRC
S. Burton, Resident inspector
K. Kennedy, Senior Resident inspector
J. Melfi, Resident inspector
i
!,
.
-2-
INSPECTION PROCEDURES USED
37551
Onsite Engineering
61726
Surveillance Observations
62707
Maintenance Observations
71707
Plant Operations
71750
Plant Support Activities
92700
Onsite Followup of I.ERs
92901
Followup - Plant Operations
92902
Followup - Maintenance
92903
Followup - Engineering
ITEMS OPENED CLOSED, AND DISCUSSED
Ooened
50-313/9609-01
Clearance of Hold Card Prior to Completion of Work
50-313/9609-02
Failure to Update SAR Due to the inadequate Design
Package Closecut
50-313/9609-03
NCV inadequate Procedure For Setting the Underload
Serpoints on the Unit 1 Refueling Mast and Spent Fuel
Crane
Closed
50-368/9408-02
Inadequate integrated ES Feature Tests
50-313/94003-00/01
LER
Surveillance Testing of Some Engineered Safeguards
Did Not Verify Operability Due to Procedural
Deficiencies
50-368/94-004
LER
Surveillance Test of HPSI Dump Did not Verify
Operability by TSs
50-313/9512-01033
Installation of the Core Support Assembly was not
Classified as an Infrequently Performed Test or
Evolution
_ _
.
.
e
.
3-
50-313/9512-01043
A Complete Briefing including All Personnel involved
!
with the Replacement of the Core Support Assembly
was not Conducted Prior to Performing the Lif t
i
f
50-313/9512-01053
Failure to Establish the Required Fuel Transfer Canal
Water Level Prior to Moving the Core Support Assembly
50-313/9512-01063
Inadequate Procedure for the Removal and Replacement
,
of the Core Support Assembly
'
50-313/9512-01073
Personnel Exceeded Overtime Limits without Plant
Manager's Approval
50-368/9602-01
IFl
Unexpected Drop in Fuel Pool Level
50-313:368/9607-01
Cause of Fuel Pin Failure, Nonconservative Crane
,
Setpoints, and Verification of Correct Setpoints for Both
Units Refueling Masts and SFP Cranes
50-368/9608-01
Failure of the RCP Breaker to Open from the Control
Room
50-313/9609-03
NCV Inadequate Procedure For Setting the Underload
Setpoints on the Unit 1 Refueling Mast and Spent Fuel
Crane
i
,
4
i
L
I
.
)
o.
.
-4-
)
)
. LIST OF ACRONYMS USED
l
t
i
as low as is reasonably achievable
j
control element assembly
.
CR
condition report
i
-FSAR.
Final Safety Analysis Report'
l
IFl .
inspection followup item
!
Institute of Nuclear Power Operations
.
LCP-
Limited Change Package
LER
Licensee Event Report
noncited violation
reactor coolant pump
' Safety Analysis Report
self-contained breathing apparatus
spent fuel pool
TS
Technical Specification
Unresolved item
violation
VSF
ventilation safety fan
i
, r
I
i
E
I
!
i
i
'
1
$
,
k
4
0
i
J
4
i
l
'
4
1
i
i
i
1
<
, . _
. . _ _ _ _ , . _ _ -
. . . _ _ . . - ,
, _ . . , .
.
,,
,
.m_
. .-. , _ _ , _ . . ,