ML18038B744
| ML18038B744 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 08/15/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B742 | List: |
| References | |
| 50-259-96-06, 50-259-96-6, 50-260-96-06, 50-260-96-6, 50-296-96-06, 50-296-96-6, NUDOCS 9608270475 | |
| Download: ML18038B744 (80) | |
See also: IR 05000259/1996006
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License
Nos:
50-259,
50-260,
50-296
DRP-52,
Report Nos:
50-259/96-06,
50-260/96-06,
50-296/96-06
Licensee:
Valley Authority
Facility:
Browns Ferry Nuclear Plant, Units 1,
2
5
3
Location:
Corner of Shaw and
Browns Ferry Roads
Athens,
35611
Dates:
June
9 July 20,
1996
Inspectors:
Approved by:
L. Mert, Senior Resident
Inspector
J.
Hunday,
Resident
Inspector
R. Husser,
Resident
Inspector
K. O'Donohue,
Resident
Inspector
Development
Program Participant
J.
Canady,
Resident
Inspector,
Plant Hatch
(paragraphs
Hl.4, El.3,
and Fl.l)
B. Holbrook, Senior Resident
Inspector,
Plant
Hatch (paragraph
E1.2)
D. Jones,
Senior Radiation Specialist,
(paragraphs Rl.l, R1.2, Rl.3,
R7. 1,
R 8.1)
J. Starefos,
Project Engineer,
G. HacDonald,
Reactor Inspector,
(paragraphs Hl.l, H3.1,
H7)
J. Milliams, Project Manager,
(paragraph
El. 1)
F. Wright, Senior Radiation Specialist,
(paragraphs
R1.4,
R1.5,
R2.1,
R7.2)
H. Lesser,
Chief
Reactor
Projects
Branch
6
Division of Reactor Projects
Enclosure
2
9608270475
'760815
ADOCK 05000259
8
Oi
ili
i
EXECUTIVE SUMMARY
Browns Ferry Nuclear Plant, Units 1,
2 5 3
NRC Inspection
Report 50-259/96-06,
50-260/96-06,
50-296/96-06
This integrated
inspection
included aspects
of licensee
operations,
engineering,
maintenance,
and plant support.
The report covers
a six-week
period of resident
inspection including the efforts of several
resident
inspectors
from other facilities. In addition, it includes the results of
announced
inspections
by two regional radiation specialists,
a regional
reactor inspector
(maintenance),
a regional projects engineer,
and the
project Manager.
~0e
Ltto~s
~
Overall, the conduct of operations
was professional
and focused
on
safety.
Specifically, the inspectors
noted continued
good use of
response
procedures
and control
room communications
(Section
01).
The quality of the control, room logs significantly increased
in recent
months, with more comprehensive
and detailed entries
(Section Ol).
~
.
0
Assistant Unit Operators
were professional
and thorough during plant
tours.
Overall housekeeping
conditions were satisfactory
(Section
01.2).
A non-cited violation was identified.
A Unit Supervisor identified that
a Unit 2 control rod was not correctly positioned after
exercise test.
Corrective actions
were prompt and thorough (Section
01.3).
The inspectors identified a violation involving a disabled control
room
annunci'ator.
The annunciator is described
in the Final Safety Analysis
Report
and was disabled without a safety evaluation
(Section 03.1).
The recently initiated Operations self assessment
program
was reviewed.
The program is new and implementation of the specific checklists is
expected to improve.
The program resulted in clear promulgation of
management
expectations
and the identification of performance
issues
(Section 07).
During observation of a Standby Liquid Control system test,
the
inspectors identified that coordination
between
some of the work groups
was not strong
and that Operations
personnel
did not follow the
procedure
in sequence.
This was addressed
as
one example of a
procedural
adherence
violation (Section Ml.3).
~
~
il'
ten
ce
~
Several electrical preventive maintenance
items
and degraded grid relay
tests
were observed to be performed with good attention to detail.
Strong coordination
and communications
were also noted during those work
activities (Section Hl.l, Hl.4).
~
During observation of Standby
Gas Treatment
testing,
the inspectors
identified that procedural
requirements
were not
met.
These
issues
were addressed
as two examples of a procedural
adherence
violation.
Previous
inspection reports discussed
examples of
procedural
adherence
deficiencies
associated
with maintenance
activities.
During this report period, the inspectors
noted that most
maintenance
workers demonstrated
deliberate effort toward full
procedural
compliance.
Maintenance
management
emphasized
the importance
of procedural
compliance.
Although some
improvement
was noted,
additional
progress
is needed
(Section Ml.2, H3).
~
A non-cited violation was identified associated
with a failure to
perform testing of an excess
flow check valve (Seciton H8.2).
ee in
0
The inspectors identified that
a safety evaluation
was not completed for
a planned design
change modification.
The safety analysis incorrectly
concluded that
a safety evaluation
was not required.
The modification
was not implemented.
This was addressed
as
an example of a procedural
compliance violation.
The inspectors
also identified that procedural
guidelines for determination of an unreviewed safety question did not
address all relevant design requirements
(Section El.l).
~
The inspectors identified that
a surveillance
procedure
was utilized
informally during verification of control
room emergency ventilation
system air flows (Section El.2).
~
During observation of repair activities involving an important
electrohydr aulic control system circuit and
an Emergency
Core Cooling
System instrumentation inverter,
good performance
was noted.
Coordination
between
work groups
and the pre-job briefings were
particularly strong (Section E1.3).
lant
S
ort
~
The licensee
implemented
an effective program to monitor and control
liquid and gaseous
radioactive effluents.
The projected offsite doses
from effluents were well within the limits specified in the Technical
Specifications
(TS), Offsite Dose Calculation
Manual
(ODCM), and Title
40 Code of Federal
Regulations
Part
190 (Paragraph
Rl. 1).
The licensee
complied with the sampling, analytical
and reporting
program requirements
and the radiological environmental
monitoring
i
program was effectively implemented.
The licensee's
overall performance
in the
EPA cross-check
program demonstrated
that
an effective quality
assurance
program was maintained for analysis of environmental
samples
(Paragraphs
Rl.2 and R7).
One Noncited Violation (NCV) was identified for failure to adequately
follow procedures
for receipt of radioactive material
(Paragraph
Rl.3).
~
The Radiation Protection
(RP) program was adequately
managed;
internal
and external
exposure
control programs
were effectively implemented with
all radiation exposures
within 10 CFR Part 20 limits (Paragraph
Rl.4).
Tour of licensee facilities showed generally
good radiological
housekeeping
and controls
(Paragraph
Rl.5).
Effective implementation of As Low as Reasonably
Achievable
(ALARA) dose
reduction principles, the operation of Units 2 and 3,
and reductions
in
refueling outage durations
on Unit 2 have contributed in the reduction
of site collective doses
(Paragraph
Rl.6).
Overall performance
during
a diesel driven fire pump test
was good.
However, the inspector noted
a recurring problem with the engine
heat
exchanger
has not been adequately
resolved.
Some workers did not
understand
the engine cooling water flowpath.
Subsequent
corrective
actions
by the Fire Protection
Hanager
were prompt and effective
(Section F1.2).
~i
Oi
O~
0
Re ort Details
S
mm
o
P
nt Stat
s
Unit
1 remained in a long-term layup condition with the reactor defueled.
Units
2 and
3 operated
at power during this report period.
On July 17,
1996, at 12:58 p.m., the Unit 3 Emergency
Core Cooling System
(ECCS), Division I Analog Trip Unit (ATU) inverter was declared
following the clearing of a fuse.
The appropriate, Technical Specification
(TS) limiting conditions for operation
(LCOs) were entered
and at 5:00 p.m.
a
controlled shutdown initiated.
The licensee notified the
NRC in accordance
with 10 CFR 50.72.
The affected inverter was repaired
and declared
at 5:57 p.m.
Subsequently,
the unit was returned to full rated power.
On
July 19,
power was reduced to 50 percent for condenser
waterbox cleaning,
control rod testing,
and steam valve leak repairs.
The unit was returned to
full rated
power on July 20 and operated at power for the remainder of the
reporting period.
I. 0 erations
1
01
Conduct of Operations
01.1
Gene al
Comments
71707
Using Inspection
Procedure
71707, the inspectors
conducted frequent
reviews of ongoing plant operations.
In general,
the conduct of opera-
tions was professional
and safety-conscious;
specific observations
are
detailed in the sections
below.
In particular,
the inspectors
noted
that significant improvement
was
made in the overall quality of the
Operating logs.
Previous
NRC inspections
and other assessments
noted
that the logs should
be improved.
In recent
months,
the inspectors
noted that entries
were
made
on pertinent information and the level of
detail applied to most of the entries
was significantly improved.
The
inspectors
also noted that alarm response
procedure
adherence
and
control
room communications
continued to be strong.
01.2
0 erator
Rounds
a.
Ins ection
Sco
e
71707
On several
occasions
during the report period, the inspectors
reviewed
performance of plant tours
by Operations
personnel.
The following
procedures
and attachments
were reviewed:
~
O-GOI-300-1, Operations
Routine Sheets,
Revision
37
ili
il~
~
O-GOI-300-1, Attachment 7, Unit 2 Reactor Building Tour and
Turnover Checklist
~
O-GOI-300-1, Attachment 8, Unit 2 Turbine Building Tour and
Turnover Checklist
O-GOI-300-1, Attachment 9, Unit 3 Reactor Building Tour and
Turnover Checklist
O-GOI-300-1, Attachment
10, Unit 3 Turbine Building Tour and
Turnover Checklist
~
O-GOI-300-1, Attachment
11, Units
1 and
2 Control
Bay Checklist
The inspectors
accompanied
assistant
unit operators
(AUOs) on Units
1
and
2 control
bay rounds,
Unit 3 Reactor Building rounds,
and Unit 3
Turbine Building rounds.
One of the inspectors
walked down the Unit 2
Reactor Building rounds
area after the
AUO completed the rounds for that
shift.
Observations
by the inspector included performance of the
rounds,
general
area
awareness,
and follow up actions
on items
identified during the performance of the rounds.
b.
Obse
tions
and
i din s:
Each
AUO was observed
from turnover through downloading of the rounds
information to the computer.
The following items were observed
during
the performance of 0-GOI-300-1 attachments:
The verbal turnover between
the
AUOs was informal and
unstructured.
While some
AUOs checked with control
room personnel
prior to starting the rounds,
others did not.
However, the
inspectors
did not identify any pertinent information that was not
adequately
described
in the turnovers.
Data required to be collected in the handheld
computers
and data
required
by the hard copy oF the procedure
was inconsistent.
For
instance:
Attachment
10, Unit 3 Turbine Building Tour and Turnover
Checklist calls for 250V Battery Board
6 Ground Indicator readings
during each shift. The computer did not include that requirement
for the day shift rounds.
The hard copy and the computer version
should
be identical since they are
used interchangeably.
No TS
required indications were affected.
All observed
operators
performed their rounds in a professional
manner.
Generally,
housekeeping
conditions were adequate,
except for
several oil leaks.
Oil. absorption
pads
were not changed
out
during the performance of the rounds. 'n two occasions,
the
inspector returned to particularly large oil leaks later in the
same shift and verified that the saturated oil absorption
pads
il~
0
il
C.
01.3
were replaced with fresh pads
and that the general
area
around the
equipment
was cleaned.
Conclusions
Observed
rounds
were performed adequately.
General
condition of the
units was good.
The AUOs followed through
on items identified in their
areas of responsibility during the performance of the rounds.
Adequate
communications
between the control
room and the
AUO performing the area
rounds were observed.
The licensee initiated corrective actions to
address
minor differences
between
the handheld
computer required
. parameters
and procedure
requirements.
Control
Rod Not Correctl
Re ositio ed Fol owi
od
xerc'se
est
Observations
and Findin s
At ll:30 a.m.
on June
17,
1996, the Unit 2 Unit Supervisor
noted that
control rod 58-19 was at position
46 instead of position 48.
Subsequent
investigation indicated that the rod was not returned to
position 48 after the performance of 2-SI-4.3.A.2, Control
Rod Drive
Exercise Test.
The reactor engineer
was contacted.
The rod was
returned to the correct position and Problem Evaluation Report
960792
was initiated.
One of the inspectors
reviewed Operating Instruction 85,
Control
Rod Drive, and verified that the condition did not require
actions
as
a mispositioned control rod.
The inspector reviewed the
control
room logs
and noted that the testing
was completed at 10:45 a.m.
on June
15.
Several shift turnovers
and numerous control board
walkdowns were completed after the error occurred.
Specific
verification of each control rod position is not expected
at each shift
turnover.
The inspector
noted that at least
one other rod was correctly
positioned at 46 and concluded that this may have contributed to the
issue not being identified more promptly.
Corrective actions included
counseling of the involved individuals.
Additionally, SI-4.3.A.2 was
revised to require
independent verification that control rods are
returned to correct positions after exercising.
(Previously,
the
procedure
required comparison of the rod positions
by the test
performer.)
The inspector verified that the procedure
was revised.
The
licensee attributed the cause of the incident to failure to follow
procedure.
This licensee-identified
and corrected violation is being
treated
as
a Non-Cited Violation, consistent with Section VII.B.I of the
NRC
E forcement Pol'c
.
This issue is identified as Non-Cited Violation
96-06-03,
Control
Rod Not Correctly Positioned After Testing.
il~
i
03
Operations
Procedures
and Documentation
03.1
Disabled Control
Room Annunciators
71
07
a.
I s ection
Sco
e
On June
17,
1996, the inspector reviewed the licensee's
disabled
program.
The Unit 2 and Unit 3 disabled
logs
were reviewed,
control
room operators
were interviewed,
and both control
rooms were walked down.
The inspector reviewed the following:
~
Operating Instruction O-OI-55, Revision
10, "Annunciator System"
~
Attachment
6 of O-OI-55, "Disabling Annunciator Input Form", dated
January ll, 1995
~
Fina'l Safety Analysis Report
(FSAR) Chapters
7.7 and 7.8
b.
Observat'o
s
and F'nd
n
s
Thirteen Unit 2 disabled
alarms
and five Unit 3 disabled
alarms
were
reviewed.
Each disabled
window, listed in the disabled
annunciator log, was appropriately
marked
by a plastic outline to
indicate the disabled condition.
The control
room operators
were aware
of all disabled
alarms
on the assigned unit.
The compensatory
actions for the disabled
alarms
are listed as part of
Attachment
6 to OI-55.
The following was noted during the review of the
compensatory
actions:
~
Compensatory
actions
were inconsistent
between Unit 2 and 3.
Both
Unit 2 and Unit 3 had
some inputs to the annunciator for control
rod drive unit temperature
high disabled.
The Unit 2 compensatory
action stated
"Points will be monitored
on
ICS and recorder".
For
the
same annunciator,
Unit 3 compensatory
action was listed as
"none".
~
The compensatory
action, listed on Unit 2 for the disabled control
rod drive unit temperature
high annunciator,
could not be
performed for all the drives.
The stated action was that
temperatures
would be monitored
on
a recorder.
Because
several
thermocouples
were actually open circuits, there would be no input
to the recorders
or
ICS,
and the points could not be monitored.
~
A simple entry of "None" was used,
in some cases,
to indicate
no
compensatory
action would be taken without indicating why
compensatory
action
was not necessary.
Unit 2's Alarm panel
2-XA-55-4B, annunciator
window 1,
Rx Vessel
Head
Seal
Leak Off Pressure
High 2-PA-3-189,
was disabled.
The annunciator
inputs are 2-LS-3-189
and 2-PS-3-190.
2-LS-3-189 was disabled
on
~i
i
~
i
April 25,
1996
and 2-PS-3-190
was disabled
on April 30,
1996.
The
associated
Disabling Annunciator Input Forms indicated inaccurately that
the annunciator
was not required
by the
FSAR; therefore,
no safety
assessment
or safety evaluation
was completed for disabling this
This was incorrect since
FSAR 7.8-8 specifically describes
this alarm.
0-OI-55 provided general direction for completion of the Disabling
Annunciator Input Form.
However, the OI did not supply details
regarding expectations
of the information to include in the form.
PER 960821
was written to further address
disabling of alarms
and the
associated
safety assessments
and safety evaluations
performance.
Operations
management
indicated that revisions to OI-55 would be
evaluated.
C.
Conc usio
s
07
07.1
The documentation of compensatory
actions for disabled
was
not strong.
One annunciator,
which is described
in the
FSAR,
was
disabled without completion of a safety evaluation.
10 CFR 50.59 {b)(l) requires
the licensee to maintain records of changes
in the facility made pursuant to that section to the extent that these
changes
constitute
changes
in the facility as described
in the safety
analysis report.
These records
must include written safety evaluations
which provide the bases for the determination that the change
does not
involve an unreviewed safety question.
Failure to perform a safety evaluation prior to disabling
Rx Vessel
Head
Seal
Leak Off Pressure
High annunciator
2-PA-3-189 is
a violation of 10 CFR 50.59 requirements
and is identified as
VIO 260/96-06-02,
Failure to
Perform
a l0 CFR 50.59 Evaluation Prior to Disabling Annunciator.
guality Assurance in Operations
0 erations Self Assessment
Pro
am
a ~
Ins ection
Sco
e
40500
71707
On June
26,
1996,
a resident inspector reviewed records
and other
information associated
with the Operations Self Assessment
Program.
The
following documents
were referenced
during the review:
Operations
Section Instruction Letter
(OSIL) 72,
Operations Self
Assessment
Process
Site Specific Procedure
12.1 {Revision 27), Conduct of Operations
Documented records
such
as completed checklists
and monthly
reports for the period February
1996 through Hay 1996
Oi
0
4I
b.
Observ t'ons
and Findin
s
The Operations Self Assessment
Process
was initiated in February
1996.
The primary intent was to provide self critical assessment
of Operations
activities.
The process
contains detailed checklists
which address
specific important activities.
The completed checklists
are reviewed
by
checklist "owners"
as well as Operations
management.
Monthly and
quarterly reports
are developed that summarize
the results of the
checklists,
incorporate Operations
performance
data from other reviews,
provide quality indicators,
and
recommend
areas that should
be
emphasized
for improvement.
The inspector noted the following:
~
The process
was still relatively new and will be revised to
improve usefulness.
~
Not all completed checklists
were signed
by the individual being
observed.
This signature is intended to indicate that feedback
was provided.
~
A quarterly report was not yet issued.
~
Several
of the checklists
were lengthy and effort was required to
accurately
complete the checklists.
Although the majority of the
reports
were not critical, indications were that personnel
were
making significant effort to properly complete the checklists at
the frequency
recommended
in the OSIL.
Approximately 100
checklists
were completed during each of the monthly periods
reviewed.
~
Checklist
CL OP.
1.7 was not yet completed.
OSIL 72 Table
2
recommends
completion monthly.
This checklist is to be completed
by Operations
management
as
an evaluation of shift management
coaching.
~
The checklists clearly promulgate
management
expectations
to the
Operations
workers.
This was
an area
noted previously as not
strong.
The inspector's
discussions
with some operators verified
that the checklists
were providing communications of expectations.
The inspector
concluded that the Operations self assessment
efforts
resulted in clear communications of management
expectations.
The
program is still new and
some refinement is expected.
The program
resulted in identification of some adverse
performance
issues
which are
currently being addressed.
For example,
PER 960726
was initiated to
address
several
events involving balance of plant components
which were
not fully positioned to their correct position.
0
il~
II. Naintenance
Nl
Conduct of Naintenance
Ml. 1
Observation of Maintenance
and Surveillance Activities
a.
s ection
Sco
e
62703
61
26
Selected
surveillance
and maintenance activities were observed to
determine if the activities were performed in accordance
with procedural
and regulatory requirements.
The inspection
scope
included observation
of surveillance activity 1-SI-4.2.A-20,
Reactor
Zone Isolation Logic
System Functional Test,
and observation of portions of the following
maintenance activities:
W096007400000
Electrical Maintenance
Troubleshoot
480
V (Volt) RHOV
Board
2A Turbine Bearing Lift Pump
W096000567000
Electrical Preventive
Maintenance
and Testing of
Alternate Feeder to 480
V Control
Bay Vent Board
B
W096005807000
Electrical Preventive
Maintenance
and Testing of Motor
Control Center
(HCC) for OffGas Building Exhaust
Fan
B
W096005805000
Electrical Preventive
Maintenance
Bridge Megger and
High Potential
Test
on 4160
V Common Board
B Auxiliary
Raw Cooling Water
Pump
1B
b.
Observations
and Findin
s
The observed
surveillance activity, 1-SI-4.2.A-20 was satisfactory.
Procedures
were verified for use
and were followed.
Work was done per
the SI and
SSP 8.1,
Conduct of Testing.
Work documents
and the SI were
actively in use
and the test
was appropriately controlled.
The pre-test
briefing was adequate
and all acceptance criteria were met except for
one damper limit switch which had
a pre-existing
open work request.
A
test deficiency was initiated for this item.
The maintenance activities observed
were required to meet the applicable
requirements
of SSP 6.2, Maintenance
Management
System
and the specific
instructions
as listed below:
W096007400000
W096000567000
EII-O-OOO-TCC106, Troubleshooting
and Configuration
Control of Electrical
Equipment
EPI-O-OOO-BKR020, Testing
and Troubleshooting of 250
VDC and 480
VAC Power Circuit Breakers
and Trip
Devices
EPI-O-OOO-BKR003,
GE Type AK-15/25 Circuit Breaker
and
Switchgear Maintenance
Oi
il~
ili
W096005807000
EPI-O-OOO-HCC001,
Maintenance
and Inspection of 480
VAC and 250
VDC MCCs
W096005805000
EPI-O-OOO-TSTOOI,
Bridge Hegger
and High Potential
Testing
on Electrical
Equipment
The maintenance activities observed
were satisfactorily performed.
Work
was accomplished
per the work documents
and the work package
instructions
were actively in use.
Drawing and procedure revisions were
verified prior to use.
Personnel
qualifications were checked for
W096000567000
and W096005807000
and the personnel
performing the wor k
were task qualified.
Personnel
were knowledgeable
on the equipment
and the procedures.
Minor
problems that occurred
were brought to supervision
and appropriately
addressed.
Measuring
and Test Equipment
(HSTE) was verified to be in
calibration.
Problems with high polarization index value were noted
on
W096005805000
and the test equipment
was checked.
Alternate test
equipment
was obtained
and the polarization index value met the
acceptance criteria of g 2.0.
The questionable
megger set
was tagged
and sent to be checked
by the calibration lab.
During the breaker trip testing portion of W096000567000
the work was
delayed
due to problems with the breaker test set.
The first test set
was not operating properly, current values
were unstable.
The second
test set obtained
was out of calibration.
A third test set
was obtained
to complete the activity.
The inspector did not observe the final
testing of this breaker.
During observation of maintenance,
the inspector
noted examples of PVC
jacketed cable potentially exuding plasticizer.
This was noted
on
cables
in trays
HB and
PU near Unit Board
2B on elevation
604 in the
Unit 2 turbine building.
The plasticizer
was not in a location where it
could impact plant equipment.
The inspector discussed
the issue with
electrical
maintenance
supervision,
and determined that, electrical
maintenance
was
aware of the issue
and
had guidance to look for this
problem in the electrical
Preventive
Maintenance
(PH) program.
The
inspector
noted blank Work Request
cards
attached
to Westinghouse
HG6
relays in the Unit
1 Auxil-iary Instrument
Room.
The licensee
determined
that the tags were to require relay inspections
in accordance
with
Problem Evaluation Report
(PER) 951697.
The licensee initiated action
to correct the tags.
Conclusions
The maintenance
and surveillance activities observed
were satisfactorily
performed in accordance
with licensee
procedures.
The minor problems
that occurred were brought to supervision
and appropriately
dispositioned.
0
Ml.2
t
db
Gas Treatment Testin
a.
I s ection
Sco
e
62703
On July 17,
1996
an inspector
performed detailed observation
of several
surveillances
on the
A train Standby
Gas Treatment
System.
The
activities observed
included overall control of surveillance testing,
the control of M&TE equipment,
and procedure
adherence.
Licensee
documents
included:
~
O-SI-4.7.8.4,
Standby
Gas Treatment
System In-place
Leak Test of
High Efficiency Particulate Air (HEPA) Filter Banks,
(Revision 7)
~
O-SI-4.7.B.5,
Standby
Gas Treatment
System In-place
Leak Test of
Charcoal
Absorber Stage,
(Revision
11)
~
O-SI-4.7.B.7,
Standby
Gas Treatment
System
Flow Rate Test,
(Revision 8)
~
O-SI-4.7.B.8,
Standby
Gas Treatment
(SBGT) Train Housing
Door
Seal Test,
(Revision 4)
b.
Observation
and Findin s
Mechanical
maintenance
personnel
were observed
performing O-SI-4.7.B.4,
O-SI-4.7.B.5,
O-SI-4.7.B.7,
and O-SI-4.7.B.8
on
SBGT train A.
The
following was noted during the observed activities:
The coordination
between operations
and maintenance
personnel
was
adequate
and independent verification was performed correctly.
All mechanical
maintenance
personnel
involved in the surveillances
appeared
knowledgeable
and well versed
on the surveillance
activities.
e
M&TE equipment
used
was correctly marked
and within calibration.
O-SI-4.7.B.5 contained
several
steps
which were unclear.
The
surveillance instructions did not have
a step which placed the
detector toggle switch in the required test position.
O-SI-4.7.B.4,
Attachment 2, Standard Dioctyl Phthalate
(DOP)
Equipment Setup
and Operation,
did not include setup steps for the
digital detector.
The maintenance
personnel
were trained
on the
use of the digital detector
and were using notes
from the training
course to setup the detector.
When the inspector questioned
the
use of notes,
instead of the procedure,
the workers explained that
they had
been told a
PER had been written and it would be
acceptable
to use the training notes until the procedure
was
revised.
Subsequently,
the test
was halted
and then restarted
using the older and less accurate
DOP detector
because
the
surveillance
procedure
did not address
the digital
DOP detector.
0
10
~
Training was contacted
and training personnel
confirmed that there
was
a
PER written against the procedure.
While reviewing the
PER,
dated January
17,
1996, the inspector
noted that O-SI-4.7.B.4
was
listed
as requiring revision.
It is not clear why the current
procedure revision did not address
the
new equipment.
A new
PER
was written to address this issue.
c.
Conclusions
Although the surveillance instructions
were designated
as continuous
use,
there
were several
weaknesses
which inhibited step-by-step
performance.
The personnel
performing the surveillances
had sufficient
knowledge
and experience
to accomplish
most of the intended tasks with
the instructions
as written.
However, during the performance of 0-SI-
4.7.B.4 maintenance
personnel
failed to follow procedural
requirements
by using the training notes for setup of the
DOP detector instead of the
steps
provided in Attachment 2.
This issue is an example of Violation
260,296/96-06-01,
Failure to Follow Safety Related
Procedures.
M1.3
Standb
Li uid Control
S stem Testin
a.
Ins ection
Sco
e
71707
6)726
0
On June
10,
1996, at 8:00 a.m., the inspector
observed
the performance
of surveillance testing
on the Unit 3 standby liquid control
pumps.
The
activities observed
included overall control of surveillance testing,
coordination
between operations
and maintenance,
the control of -METE
equipment, first use validation of a surveillance,
and procedure
adherence.
Licensee
documents
included:
~
3-SI-4.4.1.A,
(Revision 5),
(SLC)
Pump
Functional Test"
~
MCI-0-063-ACC001,
(Revision 4),
"SLC Accumulator Maintenance"
~
Drawing 3-47E854-1,
(Revision 7), "Flow Diagram Standby Liquid
Control System"
b.
Observation
and Findin
s
The surveillance
performance
required operations,
mechanical
maintenance
and electrical
maintenance
personnel.
During the inspection the
following items were noted:
Operations
did not ensure all personnel
participating in the
surveillance
attended
the pre-job brief.
Mechanical
maintenance
was not prepared to perform this
surveillance
and appeared
unfamiliar with their role in the
performance of the surveillance.
0
~
Although the surveillance
procedure called for two HKTE gauge
and
valve assemblies,
only one
H&TE gauge
and valve assembly
was used.
~
Section 7.6, of 3-SI-4.4.1.A,
was performed prior to Section 7.4.
The inspector noted that this resulted in SLC being inoperable for
a longer period than necessary.
~
The electrical
maintenance
support personnel
required for the
surveillance vibration readings
were readily available.
Two test deficiencies
noted
by operations
personnel
were
appropriately
itemized in post-test
remarks.
~
Although the first use validation comments
included requests
for
some non-intent procedure
changes,
there
was
no reference
to the
use of one or two gauge
and valve assemblies.
c.
Conclusions
Poor coordination
between operations
and mechanical
maintenance
personnel
led to the performance of Section 7.6 prior to 7.4.
This
resulted in a safety significant system being inoperable for a longer
time frame than necessary.
The surveillance
would have
been
performed
in a more timely and controlled manner
had mechanical
maintenance
personnel,
who performed the work, attended
the pre-job briefing.
After
the observations
were discussed
with Operations
management,
the licensee
performed
a case
study of this activity, identifying lessons
learned
and
ensuring the appropriate
personnel
were made
aware of these
items.
Management
expectations
regarding
performance of procedure
sections/steps
in sequence
were promulgated.
10 CFR 50, Appendix B, Criterion
V states that activities affecting
quality shall
be prescribed
by documented
instructions,
procedures,
or
drawings of a type appropriate to the circumstances
and shall
be
accomplished
in accordance
with these instructions,
procedures
or
drawings.
Site Standard
Practice 2.1, Site Procedures
Program,
states that the
each
procedure
step is performed
as written and in the exact
sequence
specified.
Failure to perform 3-SI-4.4.1.A as written and in exact
sequence
was
a violation of this requirement
and is identified as
an
example of Violation 260,296/96-06-01,
Failure to Follow Safety Related
Procedures.
il
12
De raded
Vo ta
e Rela
Ca ibr tion Testin
a ~
b.
I s ection
Sco
e
62703
The inspectors
observed portions of Surveillance Instruction (SI) 1/2-
SI-4.9.A.c(I),
"4160V Shutdown
Board A and
B Under/Degraded
Voltage Time
Delay Relay Calibration.
Only the sections
related to the phase-to-
phase
degraded
voltage relay calibration were performed.
Obse vations
and
indin
s
c ~
On July 16 the inspectors
observed
two individuals from the Customer
Group perform calibration tests for degraded
voltage relays located
on
the A and
B 4160V Shutdown Boards.
These individuals verified that the
correct relay was removed for calibration testing
by ensuring that the
labeling associated
with the relay being removed matched that specified
in 1/2-SI-4.9.A.c(I).
Additionally, a procedural
step required
a
signoff by an independent verifier after the relay was returned to its
location.
The inspectors
observed that independent verification was
performed in an appropriate
manner.
A total of six relays were
procedurally tested for calibration.
The as-found
"drop out" and
"pickup" voltages for the six relays
wer e within the acceptance
criteria
band specified
by 1/2-SI-4.9.A.c(I) and the settings
were left as found.
The inspectors verified that the appropriate
LCO was entered for the
removal of each degraded
voltage relay.
Consistency
between the
acceptance
criteria values indicated in 1/2-SI-4.9.A.c(I)
and Technical
Specification Table 4.9.A.4.C was verified.
A review of the
related to degraded
voltage relays
(Chapter 8.5) revealed
no
discrepancies.
The data
package
was reviewed
on July 18. This review
verified the accuracy of calculations
and that recorded
values
were
within the appropriate
acceptance criteria band.
The inspectors
also
verified calibration dates for the test equipment
were current.
Conclusions
Ml.5
The degraded
voltage relays were tested for calibration according to the
instructions provided by 1/2-SI-4.9.A.c(I).
The calibration team
members
were professional
and exhibited
an excellent safety perspective.
Operations
entered
the appropriate
LCO as required.
Coordination
between
the Customer
Group personnel
and Operations
was excellent.
Overall
Conc usions
on Conduct of Maintenance
and Surveillance
Activities
Overall, the activities were performed satisfactorily.
The observed
electrical preventive maintenance
items
and degraded grid relay testing
was performed with good attention to detail.
Strong coordination
and
communications
were noted during those work activities.
During
observation of the
SBGT and
SLC system testing,
the inspector identified
that procedural
requirements
were not met.
Coordination
was not strong
during the
SLC testing.
These
issues will be addressed
as two examples
0
~,
13
H3
M3. 1
of a procedural
adherence
violation.
Previous inspection reports
discussed
examples of procedural
adherence
deficiencies
associated
with
maintenance activities.
During this report period, the inspectors
noted
that most maintenance
workers demonstrated
effort to improve procedural
compliance.
Maintenance
management
has
been
emphasizing
the importance
of procedural
compliance.
Although these
two examples
indicate that
additional progress
is needed,
some
improvement
has
been noted.
Haintenance
Procedures
and Documentation
Review of Com leted
Wor
0 ders
a ~
Ins ection
Sco
e
62703
Completed
work orders
were reviewed to determine if the completed
work
met applicable procedural
requirements
and to determine
the degree to
which the activity was documented
in the work order.
The following work
orders
were reviewed:
95002249000
96004178001
96003226000
96000079000
96005620000
95021666000.
96000079001
96002905000
96000079003
96000844000
b.
Observations
and Findin
s
c ~
The documentation
reviewed
showed that Post Maintenance Testing
(PHT)
and Foreign Materials Exclusion controls were satisfactory for the work
performed.
The inspector noted that W096004178001
did not contain
signatures
documenting
completion of the pre-evolution briefing and
verified for use.
This was not
a safety related work order.
The
initial PHT signatures
on W095002249000
were not signed prior to
starting work.
The
PHT performed for this work order was adequate
for
the work scope.
No documentation
sheets
from procedure
HCI-0-000-
TUB001, Compression Fittings Disassembly
(ALL), Inspection (All), Rework
and Reassembly,
were included in
WOs 96000079001,
and 96000079003.
The
description of actual
work completed sections of these
two non-safety
related work orders
documented that tubing connections
were
made
up snug
tight per procedure
HCI-0-000-TUB001 and tubing connection leak checks
per procedure
PMT-O-OOO-HEC001,
Leak Checks
On Tube Fittings, Threaded,
Flanged
Or Bolted Connections,
were satisfactory.
The documentation
showed that,
except for the items mentioned,
work was done according to
the procedural
requirements.
Conclusions
The level of detail of work documentation
was adequate
but not thorough.
Documentation errors
were noted
on four of the ten work orders
reviewed.
0
Cl
~
Nl
N7.1
'a ~
14
guality Assurance in Naintenance
(92902,
40500)
Rev'ew of Main Steam Relief Valve
MSRV Pilot Cartrid
e
ns ection
Sco
e
40500
The inspector reviewed
PER 960377 to determine if corrective action
was
adequate.
b.
Obse vations
and Findin
s
PER 960377
was
a level
-C
PER written to document
an incorrectly oriented
NSRV pil'ot cartridge received
from Target
Rock Corporation.
The
PER
evaluation
concluded that the issue resulted
from an apparent
factory
assembly
problem.
The vendor corrected
the pilot cartridge orientation.
Vendor documentation
was reviewed to verify no valve functions would be
affected
and vendor certification was still valid.
The
PER adequately
controlled the extent of condition for the issue.
Corrective actions
for
PER 960377 were adequate.
N7.2
eview of ECCS
Room Cooler Leaka
e
PERs
a 0
ns ection
Sco
e
40500
The inspector reviewed
PERs
960653
and
960651 to determine if corrective
actions
were adequate.
b.
Obse vations
and Fn
s
PER 960653
was
a level
B PER written to document tube leakage of the
2B
RHR room cooler.
The issue
was previously identified by trend package
A920024.
The failure trend evaluation,
performed
September
17,
1992,
indicated that the leakage
was due to copper corrosion
due to continuous
chlorination chemical treatment of the Emergency
Equipment Cooling Water
(EECW) system.
The licensee
changed to a Calgon chemical
treatment
system approximately
two years
ago.
The latest failed cooler was in
service for approximately six years.
The previous cooler failure
occurred after approximately three years of service.
The inspector
reviewed corrosion rate data from system test
coupons
and
observed pictures of the Reactor Building Closed Cooling Water
(RBCCW)
heat exchanger inlet tubesheets
in 1994 and
1996,
and noted significant
reduction in heat exchanger fouling due to the
new chemical
treatment.
Visual observation of a portion of the failed cooler tubing showed
little evidence of significant corrosion.
The initial trend package
was
not conclusive.
Licensee actions to reduce
system corrosion
appeared
to
increase
cooler life.
PER 960651
was
a level
C
PER written to document
damage to a tube in the
2B Residual
Heat
Removal
(RHR) room cooler which occurred while cleaning
the cooler area which initially required repair.
The inspector
reviewed
i
15
M8
H8.1
M8.2
the
PER and corrective actions
and determined that the corrective action
was satisfactory.
Corrective actions for PERs
960651
and
960653 were
adequate.
Miscellaneous
Maintenance
and Surveillance
Issues
(92902,
92700)
C osed
LER 50-259 95001:
Emergency
Equipment Cooling Water
pump auto
started during performance of a surveillance instruction due to wrong
jumpered relay contacts
as
a result of personnel failure to perform
verification
during
a drawing and
a procedure
change.
Details of this
event were documented
in Inspection
Report 95-38.
A violation
concerning this event
was issued
and subsequently
closed in Inspection
Report 95-60.
Additional corrective actions
completed
by the licensee
that were not discussed
in those
two reports
included
a review of other
safety related drawings for similar wiring errors.
This review did not
identify any additional errors.
In addition, training on this event
was
provided to the appropriate
organizations.
Closed
LER 50-260 95006:
An excess
flow check valve was not tested
per Technical Specification requirements
due to a drawing deficiency.
On
August 14,
1995, the licensee
determined that
an instrument line excess
flow check valve,
2-ECKV-3-240A, which was part of the primary
containment
boundary,
was not tested
pursuant to Technical Specification 4.7.D.l.d.
On discovery of this condition, the licensee
isolated the
line in accordance
with the Technical Specification.
The licensee
determined that the root cause of the event
was the valve not being
documented
on the appropriate plant drawings,
which were used to
identify the primary containment
boundary.
The valve was later tested during the Unit 2, Cycle 8 refueling outage.
As additional corrective action, the licensee
ensured that other excess
flow check valves were added to the appropriate
drawings
and
surveillance
procedures.
The inspectors
determined that this event constitutes
a violation of
Technical Specifications.
This licensee identified and corrected
violation is being treated
as
a Non-Cited Violation (NCV), consistent
with Section VII.B.I of the
NRC
This item is
identified as
NCV 260/96-06-04,
Excess
Flow Check Valve Not Tested
Per
Technical Specifications.
ll'
III. En ineerin
Conduct of Engineering
10
50.59
Pro ra
Ins ection
Sco
e (37701)
The
NRR Project Manager conducted
an inspection of the licensee's
program implementing
This regulation controls what
changes,
tests,
and experiments
can
be performed
by a licensee without
prior
NRC approval.
Changes that require prior approval
are referred to
as unreviewed safety questions
(USgs).
Changes to license requirements,
such
as technical specifications,
are controlled by 10 CFR 50.90,
50.91,
and 50.92,
and are not within the scope of this review.
The inspector reviewed procedures
used for development of Safety
Assessments
(SAs)
and Safety Evaluations
(SEs).
SSP-12. 13 provides
criteria for SAs and
SEs predominately for engineering activities,
such
as plant modification.
SSP-2.3
provides criteria for safety
assessment
of procedure
changes
and can require
a safety evaluation per SSP-12.13
if required
by the SA.
SSP-6.2 requires
a safety evaluation for certain
maintenance activities involving safety-related
or quality-related
components if instructions
are not developed
from previously-approved
materials,
or when work is performed
on plant process
equipment that is
not removed from service.
The inspector
reviewed audits
and other reviews conducted
as part of the
licensee's
quality review of the
10 CFR 50.59 program.
Recent
PERs
on
10 CFR 50.59 issues
were reviewed.
A number of recent safety
assessments
and safety evaluations
prepared
pursuant to SSP-2.3
and SSP-
12.13,
and work orders
prepared
pursuant to SSP-6.2
were also reviewed.
bservat'ons
and 'in s
The licensee's
process to determine whether
a US( is created
by a
proposed activity consists of two major activities.
First,
a safety
assessment,
or SA, is performed.
This process
screens activities to
determine if they fall within the scope of 10 CFR 50.59.
If the
determines
that
10 CFR 50.59 is applicable,
then
a safety evaluation,
or
SE, is performed.
The
SE explicitly addresses
each of the criteria set
forth in 10 CFR 50.59 to determine whether
an US( exists.
During review of SSP-12.13, it was noted that accident
consequences
were
discussed
exclusively in terms of offsite dose
consequences.
This
restriction does not account for other regulatory requirements,
such
as
Loss of Coolant Accident
(LOCA) acceptance
criteria given in 10 CFR 50.46, or operator
dose restrictions of General
Design Criterion
(GDC)
19.
In addition, the procedure
does not clearly address
requirements
such station blackout
and anticipated transients
without scram.
On this
il
17
basis,
the inspector
concluded that the procedure
does not clearly
implement all regulatory requirements.
Examples of problems that could be caused
by this issue
were observed in
a safety evaluation for Design
Change Notification (DCN) 20899A, which
noted that changes
to Motor Operated
Valves
(MOVs) affected
Environmental gualification (Eg), Generic Letter (GL) 89-10,
and
10 CFR 50 Appendix
R requirements.
However, the
USA determination
only
addressed
a change in the stroke time of a valve that was described
in
the
FSAR.
The ability of components
to perform as intended for design
basis
events
could be adversely affected if criteria such
as
Eg was not
implemented.
Therefore,
the inspector
concluded that the US(
determination for thi's
DCN did not comprehensively
address all relevant
design requirements.
Another example of this issue
was noted
by the licensee's
Nuclear Safety
Review Board SA/SE subcommittee
as documented
in PER 96016,
where
a
Change
Request to Licensing Document
(CRLD) did not address
Emergency
Core Cooling
(ECCS) methodology
changes.
A similar example
was observed
in a safety evaluation which stated
accident
consequences
were not increased
since they were within bounding
main steam line break
(MSLB) results.
However, the
SE also states
other
events,
such
were potentially affected
by the
proposed activity.
The evaluation did not recognize that acceptance
criteria for anticipated operational
occurrences,
such
as loss of
offsite power,
can
be more limiting than for a design basis
accident,
such
as
a MSLB.
This result could be symptomatic of an emphasis
on
offsite dose
consequences,
when other criteria may be more relevant for
a given aspect of an activity.
A significant change in the quality of SAs for procedure
changes
was
observed
since
a revision was
made to SSP-2.3
in late March 1996.
The
revision deleted
requirements for a summary description explaining why a
change
was appropriate.
SAs issued prior to that revision were superior
in that it was
much easier to follow the preparer's critical thought
processes.
The licensee
recognized this problem as well, and is
considering alternatives
to improve this process.
An SA for a change to procedure 2-SI-4.10.A.I., dated
March 20,
1996,
was reviewed where
a conclusion
was drawn that the change did not
increase
the consequences
of any previously analyzed accident.
Such
a
conclusion is outside the scope of an SA.
Conclusions of this type are
properly found in SEs.
One safety assessment
was reviewed which should
have led to preparation
of a safety evaluation.
DCN T38901A was prepared to allow replacement
of the core shroud
access
hole covers
(AHC).
The
SA noted that the
new
design introduced
new core bypass
leakage for normal operations
and for
post-LOCA conditions.
The
SA concluded
no
SE was required.
However,
FSAR section 3.3 states that reactor vessel
internals "Maintain
partitions between
regions in the reactor vessel..."
and
"The reactor
~,
18
vessel
internals shall
be arranged to provide
a floodable volume."
Both
of these criteria were potentially affected
by the
new AHC installation.
One question required
by SSP-12. 13 is "Does the proposed activity affect
significantly (directly or indirectly) any information presented
in the
SAR...?"
The
SA stated that
"The replacement
AHC does not change
the
operational
performance of any reactor internals described
in the SAR."
This was
an incorrect statement,
since both the
FSAR criteria discussed
above were affected
by the change.
Further,
the
SA checklist from SSP-
12. 13 includes
an item regarding safety injection/core cooling, which
was checked
N/A.
The text of the
SA clearly stated
LOCA analyses
were
affected,
so the
SA conclusion for this item was also erroneous.
DCN
A39811A was completed to document the
10 CFR 50.59 safety evaluation
and
FSAR changes for the
AHC modification.
Although the
new design
had not been
implemented yet, the inspector
concluded
an
SE was required for this activity.
The licensee
agred with
this conclusion,
and initiated
a
PER to resolve the problem.
The
failure to follow procedures
is
a violation of 10 CFR 50, Appendix B,
Criterion
V and is addressed
as
one example of Violation 260,296/96-06-
Ol, Failure to Follow Safety Related
Procedures.
Several
recent "step-text" work orders
developed
per SSP-6.2
were
reviewed to determine whether procedural
requirements for US/
determinations
were followed.
The work orders
were not reviewed to
assess
whether the given actions
and sequence
of activities were
appropriate.
Aside from a minor documentation
problem,
no discrepancies
were identified in these
work orders.
Conclusions
A number of discrepancies
were found in the limited sample of items
examined,
including an example of a procedure violation cited
as part of
Violation 260,296/96-06-01.
While the licensee's
10 CFR 50.59 program
is generally adequate,
additional effort by the licensee
could improve
performance
in this area.
Control
Room Emer enc
Ventilation Flow Heasurements
Ins ection
Sco
e (61723)
The inspectors
reviewed licensee activities
on the Control
Room
Emergency Ventilation System which occurred
on July 5,
1996.
Reviewed
activities included surveillance
performance,
troubleshooting
and job
control.
Reviewed licensee
documents
included:
~
O-SI-4.7.E.6,
Control
Room Emergency Ventilation System
10 Hour
Operability Test,
Revision
8
O-SI-4.7.E.5.B,
Control
Room Emergency Ventilation System
Flow
Rate Test,
Revision
10
Site Standard
Practice 6.2, Haintenance
Hanagement
System
il~
0
19
Observation
and Findin
s
Operations
personnel
performed O-SI-4.7.E.6,
Control
Room Emergency
Ventilation
(CREV) System
10 Hour Operability Test,
Revision 8.
During
the test,
a flow rate below the allowed range of 2700 to 3300 cfm was
indicated
on
CREV B flow gauge 0-FI-031-7213.
This was not an
acceptance
criteria step for O-SI-4.7.E.6,
however it did cause
an
operability concern.
Because
0-FI-031-7213
had
a history of being out
of calibration, Operations
requested
the gauge to be calibrated.
Flow gauge 0-FI-031-7213
was calibrated in the
H&TE shop
and
reinstalled.
Operations
performed O-SI-4.7.E.6
a second time during
which the flow rate still indicated low.
A work request
was written to
investigate
and repair the low flow rate.
Technical
support personnel
measured
the flow by inserting
a pitot tube
directly into the duct work.
This work was completed
as minor
maintenance
without step text to supply specific direction.
The
inspectors
inquired about the level of instruction used to trouble shoot
a safety system.
Technical
support explained that they had
used
selected
steps
from O-SI-4.7.E.5.B,
Control
Room Emergency Ventilation
System
Flow Rate Test,
Revision 10.
Site Standard
Practice 6.2, Haintenance
Hanagement
System,
section 3.3.c
requires
step by step planning when other than skill of the craft steps
are required
and do not exist in pre-approved
procedures.
It allows for
a work sequence
to be created
by using various steps
from pre-approved
procedures.
The step text for a work order would include the work
sequence
steps.
Since the work was performed
as minor maintenance
rather than troubleshooting
no detailed work plan was written.
The inspectors verified that the system status
was such that the flow
rate measurements
taken
by technical
support were valid.
The proper
placement of the flow test
caps
were also verified.
Conc usions
The flow rate determination
was performed
as minor maintenance,
therefore
no instructions
were required.
An indicated low flow for the
Control
Room Emergency Ventilation System is an operability concern.
Although the flow rate
was adequate,
operability issues of safety
systems
were not determined
in a more controlled
and documented
manner.
Electro-H draulic Control
Circuit Board Problems
Ins ection
Sco
e
37551
On July 22, the inspector discussed
EHC circuit board problems with the
system engineer.
Pressure
occurred
on Unit 3 on three
separate
occasions
due to a suspected
faulty 'logic card in the
'B'hannel
of the turbine speed control circuit.
A new logic card was
placed in the "B" turbine control circuit during Harch
as
a result of a
0
0
20
unit scram
on February
29.
The scram was also caused
by
EHC logic card
problems.
IR 50-259/260/296/96-03
discusses
this unit scram.
A
historical review of the
EHC system performance
revealed that the
pressure
associated
with the
EHC room chillers trips did not
occur prior to the installation of the
new frequency to voltage card in
March.
The suspected
faulty turbine control logic card was replaced
on
July 25 with a tested
and properly calibrated
card from Unit l.
Observ tions
and Findin
s
Discussions
with the system engineer for the
EHC System indicated that
a
faulty frequency to voltage card in the turbine speed control circuit of
the Unit 3
EHC system
caused
reactor pressure
when the
temperature
in the room increased
due to the tripping of the room
chiller units.
The pressure
were the result of the control
valves receiving signals to travel in the close direction.
The Unit 3
EHC logic was duplicated
on Unit 1 for testing
and troubleshooting
purposes.
Unit
1 is not currently operating.
On July 24, the inspector observed
the performance of testing
and
troubleshooting activities
on Unit
1 using the duplicated logic of
Unit 3.
A jumper was .install'ed in the 'B'urbine speed control circuit
to defeat the logic for a loss of speed
signal that would result from
removing the logic card.
An Integrated
Computer System
(ICS) was
used
to monitor the effects of signals
going to the turbine control valves
and the intercept valves.
The logic card was
removed
and subsequently
replaced.
This removal
and replacement activity did not cause
any
substantial
perturbation in the signals.
The results of this testing
and troubleshooting
provided Technical
Support
and plant management
sufficient confidence for removing the suspected
faulty card with Unit 3
on line and replacing it with a tested
and calibrated
card from Unit 1.
The removal
and replacement
of the turbine speed control card
on Unit 3
was performed
on July 25.
Additionally, a decision
was
made
by
management
to install
a logic card associated
with the 'B'hannel
pressure
control section of the
EHC logic circuit.
This card was
removed in May as
a result of a pressure
perturbation
caused
by
logic malfunctions.
Two pre-job briefs were conducted to discuss
and
coordinate these
work activities.
One pre-job brief was held for
management
and the other for operations.
The inspectors
attended
both
of these pre-job briefs.
One inspector observed
control
room activities
and the other inspector
observed
the exchange
and installation of the
EHC logic cards.
Due to
the high risk nature of the work activity for a unit scram, .the Shift
Manager
had instructed all persons
not directly involved in the work
activity to remain at the back of the control
room.
Specific jobs were
assigned
to persons
involved in the work activity and the importance of
good communication
was stressed.
Technical
support
and instrumentation
personnel
performed the exchange of the turbine speed control card
and
installed the pressure
control card
on Unit 3 without incident.
These
activities were performed with the unit on line at
100 percent.
II
c ~
E8
21
The inspectors
performed
a review of Special
Instrument Instruction SII-
O-XX-3014, Troubleshooting
and Configuration Control of Instrumentation,
Revision
10; Site Standard
Practice
SSP-6.2,
Haintenance
Hanagement
System,
Revision
18 and the Work Order (96-009649-000) for the turbine
speed control logic card exchange.
A review of the documentation
indicated that work activities were conducted
in compliance with plant
procedures.
Co c
sions
The pre-job briefs were thorough
and personnel
leading the briefs
appeared
to be well organized
and prepared.
Hanagement's
attention to
the high risk work activity was quite evident.
The prior testing
and
troubleshooting
on the shutdown unit demonstrated
an excellent safety
attitude for preventing or minimizing unnecessary
challenges
to safety
systems.
Coordination
between operations,
technical
support
and
maintenance
was good.
Niscellaneous
Engineering
Issues
E8.1
S
R
eviews
1707
40500
A recent discovery of a licensee
operating their facility in a manner
contrary to the Final Safety Analysis Report
(FSAR) description
highlighted the need for a special
focused review that compares
plant
practices,
procedures
and/or parameters
to the
FSAR description.
While
performing the inspections
discussed
in this report, the inspectors
reviewed the applicable portions of the
FSAR that, related to the areas
inspected.
One inconsistency
was noted
between the wording of the
and the plant practices,
procedures
and/or parameters
observed
by the
inspectors.
Paragraph
03.1 describes
an instance in which a control
room annunciator
described
in the
FSAR was disable without a safety
evaluation
being completed.
This issue is addressed
as
a violation.
No
other inconsistencies
were identified by the inspectors.
The licensee
is continuing
an extensive
FSAR review.
IV. Plant
Su
ort
Rl
Rl. 1
Radiological Protection
and Chemistry Controls
dioactive Eff uent Contro
Pro ram
a ~
Ins ection
Sco
e
8 750
The inspectors
reviewed the overall results of the radioactive effluent
control program
as documented
in the Annual Radioactive Effluent Release
Report for 1995.
The amounts of radioactivity released
and resulting
radiation doses for the years
1992 through
1995 were tabulated
from the
annual
reports to evaluate
long term performance of the effluent control
program.
0
22
bse vations
and Findin
s
The amounts of activity (fission and activation products, tritium, and
dissolved
and entrained
gases)
released
in liquid effluents during 1995
were generally consistent with amounts released
during 1994.
Less than
one curie of fission and activation products
was released
in liquid
effluents during 1994
and 1995, which was less
than half of the amounts
released
during the two previous years.
The amounts of activity
releases
as fission and activation gases
in gaseous
effluents
has
decreased
significantly since
1992, i.e.,
from >16000 curies in 1992 to
24 curies in 1995.
The elevated level in 1992 was due to leaking fuel in
Unit 2 and high offgas flows.
The leaking fuel was replaced
during the
1993 Unit 2 Refueling Outage
(RFO)
and the amounts of activity
subsequently
released
in the effluents decreased
sharply.
The annual
per
unit average radiation doses resulting from radioactivity in the- liquid
and gaseous
effluents released
during
1995 were less than
one percent of
their respective limits.
Selected
licensee
records
were examined to independently verify the
reported value for the amount of activity released
as fission and
activation products in liquid effluents during the fourth quarter of
1995.
The amounts of Co-60,
and Na-24 listed in permits for
selected
releases
were compared to a licensee
provided tabulation of
those quantities for all releases
during that period.
The reported
sums
of those quantities
and the
sum of all fission
and activation products
were also verified.
No inconsistencies
in those data were noted
by the
inspector.
The effluent release
report indicated that there were
no abnormal
releases
during 1995
and that one liquid effluent monitor was inoperable
for greater
than
30 days.
The Unit 3 Residual
Heat
Removal Service
Water
(RHRSW) monitor (3-RM-90-134D) was inoperable
from November 3,
1995 to December
5,
1995 while the piping to the monitor was being
modified for improved efficiency.
Conclusions
Based
on the above reviews, it was concluded that the licensee
had
implemented
and maintained
an effective program to monitor and control
liquid and gaseous
radioactive effluents.
The projected offsite doses
resulting from those effluents were well within the limits specified in
the Technical Specifications
(TSs), Offsite Dose Calculation
Manual
(ODCM), and Title 40 Code of Federal
Regulations
Part
190 (40
CFR 190).
ad'olo ica
Environmenta
Monitorin
ro ram
ns ect'o
Sco
e
84750
The inspectors
reviewed the overall results of the radiological
environmental
monitoring program
as documented
in the Annual
Radiological
Environmental
Operating
Report for 1995.
23
b.
C.
Observations
and Findin
s
The inspectors
noted that, in accordance
with the
TS and
ODCH, the
report included
a description of the program,
a summary
and discussion
of the results for each
exposure
pathway,
analysis of trends
and
comparisons
with previous years
and preoperational
studies,
and
an
assessment
of the impact
on the environment resulting from plant
operations.
The report also included
a tabulation of the summarized
analytical results for the samples
collected during 1995.
From a review
of those data,
the inspector determined,
for selected
exposure
pathways,
that the sampling
and analysis
frequencies
specified in the
ODCH was
met.
The inspector also verified by direct observation that selected
sample collection sites
were located
as indicated in the
ODCH.
As
indicated in the conclusion section of the report, the radioactivity
detected
in the plant environs
was primarily the result of fallout and
natural
background radiation,
and any activity which may be present
as
a
result of plant operations
does not represent
a significant contribution
to the radiation exposure of members of the public.
Co cl sions
~
Rl. 3
Based
on the above reviews
and observations, it was concluded that the
licensee
had complied with the sampling, analytical
and reporting
program requirements
and that the radiological environmental
monitoring
program was effectively implemented.
ece'
of Radioactive Haterials
a ~
Ins ection
Sco
e
86750
b.
The inspectors
reviewed the licensee's
procedures
and selected
records
for receipt of radioactive materials.
The review included records for
receipt
and inventory of nonexempt
byproduct
and source materials
(BSN).
Observations
and Findin
s
Procedures
SSP-5.3,
SSP-10.2,
STD-10.2,
RCI-7,
and O-SI-4.8.E were
reviewed
and found to be consistent with the requirements
in 10 CFR 20,
10
CFR 30 and the
TS for receipt,
storage,. leak testing,
and inventory
of nonexempt
BSN.
Records for the three most recent inventories of
nonexempt
BSN indicated that the inventories
had
been performed at the
required frequency.
The most recent inventory change report indicated
that
a 100 millicurie Cm-244 source
(BFNP ID¹ 565)
had been
added to the
inventory on June
20,
1996.
The Air Bill for the transport of that
source indicated that the source
was shipped
from Langhorne,
Pa.
on
April 30,
1996,
but the exact date of delivery to the site was not
known.
It is assumed that the delivery date
was
on or about
Nay 2,
1996.
The source
was located
on June
20,
1996, at the inplant Nuclear
Stores
Customer, Service Center.
In accordance
with DOT requirements
the
package
containing the source
was not marked or labeled
as radioactive
material.
The packing list was stamped to indicate that the package
conformed to the conditions
and limitations specified in 49
CFR 173.422
il~
0
24
for excepted radioactive materials,
instruments,
and articles.
The
packing list, which was in a blister pack attached
to the package,
had
been folded such that the marking was not visible.
The licensee
subsequently
issued
a Problem Evaluation Report
(PER) for this issue
and
characterized
the
PER as
a level
B, which requires corrective action.
Section
7.1 of RCI-7 stipulates that the Nuclear Stores
Supervisor or
his designee
shall inspect
packages
or shipping papers to determine if
radioactive material is present
and notify the
BSM Controller when
BSM
is received.
Section 3.1
C of STD-10.2 also stipulates that responsible
receiving personnel
shall determine if a shipment contains radioactive
material,
examine the shipping documentation for packages
containing
radioactive material
and identify the contained radioisotope(s),
and
notify immediately the
BSM Custodian if the radioactive material is a
source.
TS 6. 10.2 requires that
a complete inventory of radioactive
materials in possession
shall
be maintained current at all times.
The
inspectors
determined that the licensee
had not adequately
examined the
shipping documentation
upon receipt to determine whether the package
contained radioactive material.
This
NRC identified violation is not
being cited because criteria specified in Section VII.B of the
NRC
Enforcement Policy were satisfied.
This issue is identified as
(NCV 50-
259,
260, 296/96-06-05)
onc
sions
One
NCV was identified for failure to adequately follow procedures
for
receipt of radioactive material.
Occu ational Radiation Internal
and Externa
Ex osure
Co t ol
Ins ection
Sco
e
83750
This area
was reviewed to verify personnel
radiation exposures
were
within regulatory limits and the licensee
was implementing proper
internal
and external
exposure control measures.
Observations
and Findin
s
The inspectors
reviewed current. personnel
exposure reports
and found all
internal
and external
personnel
exposures
were below regulatory limits.
Tours of the Radiation Control Areas
(RCAs) were
made to verify that
radiological
areas
were properly posted
and controlled.
Locked high
radiation areas
throughout the facilities were found properly secured.
The inspectors
reviewed selected
licensee radiation surveys
and
made
independent
radiation surveys in those
areas
to verify radiological
conditions were properly identified and posted.
The inspectors
reviewed selected
skin dose calculations resulting from
skin contaminations
in 1996.
The inspectors,
using the licensee's
procedures,
calculated the skin dose
and found that the calculations
had
been performed in accordance
with the licensee's
procedures.
All skin
doses
were well within the regulatory limits for skin dose.
No concerns
with the licensee's
skin dose methodology were identified.
i
0
25
In general,
the licensee
appeared
to be implementing effective
.radiological: controls to minimize personnel
exposures
to internal
and
external radiation sources.
No concerns with the licensee*s
internal or
external
exposure control programs
were identified.
Rl.5
o trol o
Radioactive
ateria1s
and Contaminat'o
a ~
s
ct o
Sco
e
83750
The inspectors
toured licensee facilities, examined licensee controls
for contaminated
areas
and equipment,
and discussed
controls with
Radiation Protection
(RP) personnel.
b.
Observations
and Findin s
During tours of the licensee's facilities the inspectors
found
housekeeping
was generally good.
At the time of the inspection the
licensee
was meeting the goal for contaminated
square
footage
by
averaging less than approximately
one percent of the total
RCA as
contaminated.
No uncontrolled .containers
of contaminated
or radioactive
material
were identified during the facility tours.
The licensee
reported that use of long sleeve
scrubs
and the
establishment
of clean islands within the
RCA had helped increase
worker
efficiency during the Unit 2 (U2) Re-Fueling
Outage
(RFO) 8.
The clean
islands
were clean
areas within the
RCA where workers could take breaks
and lunch, which reduced travel times to other areas
outside the
RCA.
Clean islands with whole body friskers were established
on the Refueling
Floor and the Turbine Deck.
Long sleeve
scrubs
were used with boot and
glove Protective Clothing
(PC) in the turbine bui.l'ding where
contaminated
levels were less
than 10,000 dpm/100 cm'.
Radiation
workers exiting these
areas
removed the gloves
and boots
and wore the
scrubs to a whole body frisker for personnel
contamination monitoring.
If the frisker did not identify any contamination the worker could
continue to wear the scrubs, if needed,
for additional work within the
RCA.
The licensee
reported the process
saved time in repeated
donning
of PCs
and
PC cleaning resources.
The inspectors
concluded
these
licensee
procedures
could save resources
and were not
a contamination
control problem with effective and diligent contamination monitoring
procedures.
No concerns with the processes
were identified by the
inspectors.
Licensee controls of contaminated
or radioactive materials
were found to
be adequately
implemented.
0
26
R1.6
ta'ccu
ational
Ex osure
a.
Ins ection
Sco
e
83750
The inspectors
reviewed the status of the licensee's
collective dose for
1996
and the implementation of the
ALARA program.
b.
Observations
and Findin
s
The inspectors
reviewed the collective doses for specific
U2RF08 work
activities with ALARA personnel
and inquired about the application of
dose reduction techniques
and their results
in the outage.
The
licensee's
annual collective dose goals
are established
for Fiscal
Years
(FY) beginning October
1 each year.
A summary of collective doses for
1995
and
1996 (through July 15,
1996) is shown below.
Collective Personnel
Exposures
(Person-Rem)
Annual
Outage
Year
.Actual
Goal
Title
Actual
Goal
Duration
(Days)
1995
850
FY 895
U2RF07
424
350
54, 10/Ol/94 to ll/23/94
409
CY
Forced
4 in 1995
1996
428
FY 510
U2RFOS
241
350
32, 03/23/96 to 04/23/96
334
CY
Forced
12 in 1996
Through the first three quarters of the
1996 fiscal year, the licensee
met collective dose objectives.
The 1995 Calendar
Year
(CY) collective
dose of 409 person
rem was
one of the facility's lowest to date
and the
licensee
has
an opportunity to lower the collective dose further in
CY
1996.
Several
conditions were contributing to the licensee's
collective
dose reductions,
.including:
Shorter
RFO duration;
A good
U2 availability factor;
and
The restart of U3.
The duration of the
U2RF08 was approximately
22 days shorter than the
duration of the U2RF07.
The planned duration for the
U2RF08 was
28
days.
The actual
outage duration
was approximately
32 days.
To shorten
the length of U2RFOS the licensee
performed
some maintenance activities,
typically performed during outages,
prior to the start of the
RFO.
The
total collective dose for the outage
was approximately
241 person
which included the pre-outage
work dose of 29 person
rem.
Another
reason
the collective dose for U2RF08 was
so much lower than
U2RF07 was
reduced level of Inservice Inspection (ISI) work.
The ISI work in
4l
27
U2RF07
(155 person-rem)
included
10 year ISI activities
and was greater
in scope
than the ISI activities conducted
in U2RF08
(14 person-rem);
The availability factor for Unit 2 was good, operating approximately
257
of the first 293 days of 1996
FY.
There
was
one brief shutdown of
approximately
4 days
and the 32 day
RFO during that period.
Unit 3 start-up
on November
19,
1995, effectively took the licensee
out
of an "longterm outage" that the licensee
had
been in for several
years.
Following the startup,
the availability on
U3 had also
been
good.
Unit
3 had three brief outages totaling about
8 days
and operated
approximately
236 of the
244 days following its restart.
The
U2RF08. outage
dose
was approximately
109 person-rem
below the goal.
The licensee
had over estimated
the work hours
needed to complete
27 of
the 32 tasks
having
ALARA planning activities.
Of these
27 tasks,
approximately
16 had actual
hours within 20 percent of the estimated
hours.
However,
7 (approximately
22 percent) differed from the estimate
by 40 percent or more.
These significant differences
in estimated
and
actual
hours indicated additional attention
was needed for more accurate
work estimates
necessary
in effective dose reduction planning
and'rocesses.
The inspector verified that the worker comments
and other lessons
learned
and documented
in U2RF08 ALARA Planning Reports
were receiving
management
attention.
Issues
were identified in the licensee's
corrective action program
and in ALARA/Radwaste Committee Action Items
list.
C.
Conclusions
R2
R2.1
The licensee
was effectively reducing site collective doses.
Additional
attention
and improvement in predicting the work hour estimates for
tasks
appeared
appropriate.
However,
no significant collective dose
problems
were identified during the reviews.
Facilities
and Equipment
(83750)
Continuous Air Honitors
a ~
Ins ection
Sco
e
92904
The inspectors
reviewed the status of the licensee's
Continuous Air
Nonitors.
b.
Observations
and F'ndin
s
Inspection
Report 96-05 described
a resident inspector's
observations
of
an inoperable
CAN (Continuous Air Honitor) in the Unit 2 reactor
building in Hay 1996.
Mork Request
C308169 indicated that 2-RH-90-58
failed to source
check in December
1995.
Compensatory
actions
were in
effect.
The resident
inspector discussed
the apparent
delay in
28
repairing the
CAM with radiological controls management.
PER 960618
was
initiated on the issue.
CAN 2-RN-90-58 was returned to service
on Nay
23,
1996.
The licensee's
extent of condition review conducted
on Nay
15,
1996 identified that
a total of nine
CANs were out of service.
Several
of the 'CAMs did not have scheduled
repair dates
and
some
had
been out of service for many months.
Compensatory
actions
were in
effect for the inoperable
CANs. The inspector
noted that although the
compensatory
actions
adequately
monitor the area radioactivity, there is
not an alarm function in the
CR as with the
CAMs.
A review by the
resident
inspectors
indicated that
CAN information was not relied upon
for
Emergency Operating Instruction entry conditions.
The licensee's
investigation
concluded that repairs to
CAMs with compensatory
actions
in place were not being scheduled for repairs in a timely manner.
Corrective actions
were initiated to ensure that inoperable
received the appropriate level of attention
by radiological controls
management
and scheduling
personnel.
During this report period,
two Region II senior radiation specialists
conducted additional
review of the
CANs.
The inspectors
noted that most
of the
CAMs located in Unit
1 were inoperable.
Some of the Unit
1
had'een
installed to replace
aging CAHs'ut were not declared
following their installation.
Others were installed
and declared
operational
but were removed from service.
Licensee staff subsequently
reported that there
was
no safety significance involved with the Ul CAMs
since the fuel was removed from that unit.
The inspectors
determined that three
CAMs (I-RH-90-54, 2-RN-90-51,
and
2-RH-90-59)
had problems that were not repaired for several
months.
The
inspectors
determined that the licensee
had work orders to fix various,
problems
on the three
CAMs that were inoperable for three to seven
months.
The inspectors verified that the
CAHs were not scheduled
to
receive maintenance until September,
1996.
The inspectors
discussed
maintenance activities with the Radiation Monitoring System Engineer
and
learned the system rating on Unit 2 was trending
down in FY 1996.
It
appeared
that the Radiation Monitoring System
needed
a higher priority
for preventive
and corrective maintenance.
The licensee
approved
a change to the
FSAR dated
June 6,
1996,
removing
some of the detail concerning
7. 13.5.3. 1, "Air
particulate Monitoring Subsystem."
Licensee
documentation
states
that
the change
was
made to "Revise
FSAR Commitment for
the number of CAMs associated
with Units
1 and
3 and their functional
status."
The revised description states
in part, that
CAHs are located
in the reactor turbine
and radioactive waste buildings.
Conclusion
The inspectors
determined that the licensee
was in compliance with
revised
FSAR section 7.12.5.3.1.
Although rarely needed,
CAMs can
provide one of the earliest indications of abnormal or changing airborne
and plant conditions.
The
CAHs role as
an early warning device serves
a
~,
R7
R7.1
29
useful
purpose
in the radiation control
and plant operation
programs
during abnormal
occurrences
that can not be replaced with continuous or
grab air samplers.
In general,
the inspector
found the conditions of
most
CAMs on Unit 2 and
3 satisfactory.
However, additional
maintenance
and attention
was
needed to return all of the
CAMs to fully operational
status.
The inspectors
concluded that although the inoperable
CAMs were not
receiving appropriate attention,
compensatory
actions
were in place
and
no regulatory requirements
were violated.
The licensee's
corrective
actions
appear
adequate
to address
the issue.
guality Assurance in Radiological Protection
and Chemistry Activities
I te laborator
Com arison
Pro ra
a 0
s ection
Sco
e
84750
The inspectors
reviewed the results of the licensee's
participation in
the Environmental
Protection Agency's
(EPA's) Interlaboratory
Comparison
Program
as documented
in the Annual Radiological
Environmental
Operating
Report for 1995.
b.
Obse vat'ons
and Findin
s
The inspectors
noted that the report included descriptions of the
various types of samples
analyzed
and the analyses
performed,
and
an
evaluation of the analytical results.
The
EPA provided
14 samples of
various environmental
media
and
a total of 41 analyses
were performed.
Statistical
evaluation of the program data indicated that the licensee's
analytical results
were within the
EPA control limits.
c.
Conclusions
R7.2
Based
on the licensee's
overall performance
in the
EPA cross-check
program, it was concluded that
an effective quality assurance
program
had been maintained for analysis of environmental
samples.
o ram Sel
Assessment
'a ~
s ectio
Sco
e
Title 10 CFR 20. 1101(c) requires that the licensee periodically review
the
RP program content
and implementation at least annually.
The
inspector's
review was
made to verify the performance of self assessment
activities, identify significant
RP issues
and to determine if
applicable corrective actions
were appropriately
documented
and
completed.
30
c ~
Obse vations
and Findin s
The licensee's
independent self assessment
program for the
RP program
consisted of formal audits per TS requirements,
observations
and
surveillances.
The inspector reviewed the results of self assessments
completed in the period of January
through June,
1996.
All of the
reviewed
assessments
concerning the licensee's
radiation protection
(RP)
program were conducted
by personnel
within or under the direction of the
Quality Assurance
(QA) or Licensing staff.
The assessments
made in the
RP area during this period were limited in scope
and addressed
regulatory issues,
observations,
and trends in
RP performance
as
appropriate.
Regulatory issues
were identified in, the licensee's
corrective action process for resolution.
No significant concerns with
the
RP program were identified during the assessments.
The licensee recently (July 1996) established
a self assessment
process
for the
RP staff to use in assessing
regulatory compliance
and
performance.
The program was described
in Field Operation
Implementing
Procedure
No.
20 "Radiological Control Self Assessment
Program."
The
procedure
required the development of checklists for nine
RP program
areas.
Each program area
was to have
a compliance
and performance
checklist.
The licensee
conducted
one self assessment
and it was not
documented
at the time of the inspection for the inspectors to review.
The inspectors
noted that the proposed
frequency of self assessments
appeared
adequate.
Co c usions
R8
R8.1
The inspectors
concluded the licensee
was performing periodic
assessments
of RP activities
and no adverse
trends
were identified in
those reviews.
Adverse conditions were placed into the licensee's
corrective action system for resolution.
Miscellaneous
Radiological Protection
and Chemistry Issues
(92701)
Closed
Unresolved
Item 50-259
260
296 96-001-02:
Method for
determination of drywell
CAM setpoint.
During December
1995 the
inspectors
noted that the Unit 2 Primary Containment
Leak Detection
(PCLD) Continuous Air Monitor (CAM) was in constant
alarm due to a
slight increase
in drywell leakage rate.
In accordance
with 2-TI-24,
the alarm setpoint
was increased
to correspond with the increased
background activity concentration
in the drywell.
The inspectors
noted
that the indicated drywell activity concentration
was approximately
microcuries per cubic centimeter
(pCi/cc)
and the alarm setpoint
was
approximately 1.18E-8 pCi/cc, which was
much higher than three times
the average
background
as required
by TS Table 3.2.E.
This issue
was
deemed
an unresolved
item pending further
NRC review of the technical
justification for the method of setpoint determination.
In order to
evaluate this issue the vendor manual for the instrument
and setpoint
calculations
provided
by the licensee
were reviewed.
The vendor manual
indicates that the instrument not only has the capability of monitoring
0
il
ik
31
count rate in .units of counts per minute
(cpm) but also
has the
capability to monitor activity concentration
in units of pCi/cc when
a
fixed filter is used.
The manual further indicates that "with these
units the program automatically differentiates
the incoming count rate
to account for the cumulative buildup on the filter since it was last
changed.
Data from particulate
and Iodine channels
then
becomes
the
increase
in activity on
a filter for a given time interval,
and alarms
may be determined
on
a level of concentration
instead of a level, of
filter activity."
The licensee
provided example calculations for
setpoints
in units of concentration
(pCi/cc)
and units of count rate
(cpm).
Those calculations clearly demonstrate
that the instrument would
alarm much quicker when the instrument is monitoring concentration
rather than count rate.
Based
on these
reviews, it was determined that
the licensee's
method for detecting
an increase
in drywell leakage rate
was more conservative
than required
by TS Table 3.2.E.
This item is
closed.
Fl
Fl. 1
Conduct of Fire Protection Activities
Review of Fire Protection
Re uirements for 0 en
EDG Doo
a ~
Ins ection
Sco
e
71750
b.
The inspectors
observed
on July 22 that the fire door to the outside for
Emergency Diesel
Generator
3D was blocked
open during painting
activities within the
3D
EDG room.
Followup reviews were performed to
determine whether the door was blocked open in compliance with the Fire
Protection
Report.
Observ tions
nd Findin
s
F1.2
A copy of the completed Attachment
F Implementing
Form was obtained
from
the
SSS office. It was verified that the compensatory
actions required
by the Fire Protection
Report were taken.
The inspector questioned
the
painter providing fire watch duties
about the responsibilities of the
The painter responsible for providing fire watch was
familiar with the duties
and responsibilities of the fire watch.
Appropriate compensatory
measures
were taken in compliance with the Fire
.Protection
Report.
Security was posted at the door
as
a compensatory
measures
which was appropriate.
Diesel driven
ire
Pum
0 erabilit
Test
'a ~
I s ection
Sco
e
71750
61726
On June
13,
1996,
one of the resident
inspectors
observed
the monthly
operability testing of the diesel driven fire pump.
In certain fire
scenarios
and .emergencies,
this
pump could
be required to play an
important role.
The following documents
were referenced
during the
preparation,
observation,
and review:
32
~
Procedure
O-SI-4.11.B.2.a,
Diesel Driven Fire
Pump Operability
Test (Revision 20)
~
Volume
1 of the Fire Protection
Report
(The
FSAR references
this
document
as the description of the
BFN fire protection
program)
~
Controlled drawings
1-47E836-1,
1-47E850-1
and
2
Observ tions
and
indin s
The inspector verified that the positions of numerous
valves
and
controls in the vicinity of the fire pump were
as depicted
on the
drawings.
No deficiencies
were identified.
The inspector verified that the copy of the SI being
used
was the
correct revision.
One of the workers continuously referenced
the
procedure
during the test
and ensured that all steps
were completed in
order.
The equipment required for the testing
was
on hand.
The
inspector observed that the workers
seemed familiar with the test
procedure.
A hand
pump and several
drums were used to add fuel to the
diesel fuel tank before
and after the test, with care taken to prevent
spillage.
Independent verification steps
were performed properly.
Step 7.3.7.4, of the O-SI-4.11.B.2.a,
required verification that "the
diesel fire pump raw cooling water system is operating properly by
observing flow out the discharge
pipe into the reservoir"
The inspector
identified that the workers did not fully understand this step
and,
consequently,
did not correctly complete it.
Flow from the fire pump
discharge is routed through
a heat exchanger to remove heat from the
engine coolant
and then is discharged
into the reservoir (canal) via a
small pipe.
The workers observed that the fire pump discharge
was
flowing into the canal
instead of looking at the engine
raw cooling
water discharge
pipe.
When the diesel
was secured
at the conclusion of the test,
engine
coolant leaked out of the cap
on the top of the heat exchanger.
The
workers indicated that this had occurred during previous tests.
When
the
pump is secured,
cooling water flow through the heat exchanger
is
lost and the coolant expands
out the heat
exchanger
cap to the floor.
The inspector questioned
the cause of the problem,
what level of coolant
is necessary
for the heat exchanger to function,
and whether coolant
level
had decreased
below that level.
The inspector noted that the
procedure did not require checks of engine coolant level before or after
operation of the pump.
The fire protection group manager
reviewed the issue including contact
with the diesel
vendor.
The cause of the problem was determined to be
that the cap
on the heat exchanger
was broken
and, consequently,
was not
holding in the coolant.
The cap was replaced.
Subsequently,
the
pump
was operated
and
no coolant flowed out of the heat exchanger
when the
engine
was secured.
Information indicated that the level
was not
decreased
below the minimum required for operability of the
pump.
il~
il
33
The fire protection group manager
intends to revise procedures
to
address
the heat exchanger
water level issues.
He stated that training
would be held to inform workers of the engine cooling water flowpath.
The inspector
concluded that overall control of the testing
was good.
The testing
met the requirements
of Section 9.4. 11.8.2.a of Volume
1 of
the Fire Protection
Report.
Procedural
steps
were followed in sequence.
The activities associated
with adding fuel were performed with an
emphasis
on safety
and spill prevention.
Although the heat exchanger
coolant loss issue
was not resolved effectively in the past,
the fire
protection manager
was responsive
on this occasion
and promptly
initiated corrective actions regarding
both deficiencies.
F8
Niscellaneous
Fire Protection
Issues
F8.1
tenance of Fire Protectio
Doors
a.
ns ection
Sco
e
62703
64704
The inspectors
reviewed
some aspects
of maintenance
and testing
associated
with fire protection doors to verify that the activities were
being performed with proper controls
and qualified personnel.
In recent
months,
the licensee
has
been vigorously pursuing correction of fire
impairments
which require compensatory
actions.
Haintenance
of the fire
doors is being transferred
from a craft worker group to the Fire
Protection
Group.
The following documents
were referenced
during the
preparation
and. inspection:
Fire Protection Report,
Volume 1, Fire Protection
Plan
and Fire
Hazards Analysis (Revision 6)
Procedure
0-SI-4. 11.G.2,
Semiannual
Fire Door Inspection
(Revision
18)
Hechanical
Preventive Instruction HPI-0-260-DRS001,
Inspection
and
Haintenance of Doors.
Site Specific Procedure
(SSP) 6.2, Haintenance
Hanagement
System
(Revision
18)
~
Site Specific Procedure
3.2,
Augmented
gA Program
b.
Obse vations
and
indin s
The inspectors
determined that the licensee's
documentation clearly
indicated the classification of the fire doors
and the listed
classifications
met the requirements
of the controlling procedures.
The
inspectors
concluded that many of maintenance activities performed
on
fire doors could be categorized
as minor maintenance
as described
in SSP
Ib
34
C.
3.2'.
Nore extensive
maintenance
on doors,
such
as replacement,
is
required to be performed
by task trained maintenance
craftsman.
The inspectors
discussed
the overall status of .fire doors
and details of
several
ongoing door repairs with the fire protection manager.
He
stated'hat
all repairs to fire doors were currently being performed
by
a dedicated
mechanical
maintenance
craftsman with fire group personnel
assisting.
The intent is that the craftsman train the fire group
personnel
in maintenance
of the doors
and eventually door repairs will
be the responsibility of the fire protection group.
The .manager
explained that detailed task qualification training is being developed
for the fire group. workers.
Procedures will be revised to permit the
fire group workers to perform limited work on the doors
as deficiencies
were identified.
The manager stated that fire protection group workers
will not perform repairs to fire doors until they are formally qualified
to complete
such repairs.
The inspectors
reviewed maintenance
department
records
and determined
the specific task qualifications .associated
with fire door
repair/testing.
The inspectors
then verified that the dedicated
mechanical
maintenance
worker had completed those task qualifications.
Discussions
with workers indicated'hat
the craftsman is considered
"an
expert"
on door repairs at
BFN.
The inspectors
reviewed the licensee's
actions to address
several
recent
test deficiencies
which had
been generated
due to recurring problems
on
several fire doors.
The inspectors
noted that the .required
administrative actions
were being rigorously completed.
For example,
failures of fire doors to close/latch
properly during daily checks
were
noted in the applicable SI, addressed
as test deficiencies,
and work
requests
were initiated.
The problems
were tracked to closure
by
"attachment
F" forms
(Volume
2 of the
FPR, Fire Protection
System/Equipment
Removal
From Service)
which was also
used to ensure
compensatory
actions
were implemented for the deficient doors.
The
inspectors
also reviewed the work orders for several fire doors which
were scheduled
to be replaced
and verified that the appropriate
worker
task qualifications were listed in the work orders.
Conclusions
The inspectors
concluded that fire door maintenance
and testing
activities of fire doors were being adequately controlled.
V. Nana
ement Neetin
s
X1
Exit Neeting
Summary
The inspectors
presented
the inspection results to members of licensee
management
at the conclusion of the inspection
on July 19,
1996.
The licensee
acknowledged
the findings presented.
ik
0
0
35
The inspectors
asked the licensee
whether
any mater'ials
examined during the
inspection
should
be considered
proprietary.
No proprietary information was
identified.
Licensee
PARTIAL LIST OF
PERSONS
CONTACTED
J.
Corey, Radiation
and Chemistry Manager
C. Crane, Assistant
Plant Manager
R. Jones,
Operations
Manager
R. Machon, Site Vice President,
Browns Ferry
E. Preston,
Plant Manager
P. Salas,
Licensing Manager
T. Shriver,
Nuclear
Assurance
and Licensing Manager
H. Williams, Engineering
and Materials Manager
IP 37700:
IP 40500:
IP 61726:
IP 62703:
IP 71707:
IP 83750:
IP 92700:
IP 92901:
IP 92902:
IP 92903:
IP 92904:
IP 93702:
IP 86750
INSPECTION
PROCEDURES
USED
Design
Changes
and Modifications
Effectiveness of Licensee Controls in Identifying, Resolving,
and
Preventing
Problems
Surveillance
Maintenance
Observation
Plant Operations
Occupational
Exposure
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
Followup - Operations
Followup - Engineering
Followup Maintenance
Followup Plant Support
Prompt Onsite
Response
to Events at Operating
Power Reactors
Radioactive
Waste Treatment,
and Effluent and Environmental
Monitoring
Solid Radioactive
Waste
Management
and Transportation of
Radioactive Materials
Followup
il
~0ened
36
ITEHS OPENED,
CLOSED,
AND DISCUSSED
Status
Desc
tio
and
e e
e ce
VIO
NCV
~Cosed
260,296/96-06-01
Open
260/96-06-02
260/96-06-03
260/96-06-04
259,260,296/
96-06-05
Failure to Follow Safety Related
Procedures
(paragraphs
Hl.2, Hl.3
and El.l)
Failure to Perform
a
Evaluation Prior to Disabling
Annunciator (paragraph
03.1)
Opened
and
Return Control
Rod Not Correctly
Closed
Positioned After Testing
(paragraph
01.3)
Opened
and
Excess
Flow Check Valve Not Tested
Closed
per Technical Specifications
(paragraph
H8.2)
Opened
and
Failure to Follow Procedure for
Closed
Receipt of Radioactive Haterials
(paragraph
R1.3)
LER
LER
Item Number
259/95001
260/95006
Status
Closed
Closed
50-259,260,296/
Closed
96-01-02
Descri tion and
Re e ence
EECW Pump Auto Started
(paragraph
H8.1)
An Excess
Flow Check Valve was not
Tested
Per Technical Specifications
(paragraph
H8.2)
Drywell
CAH Setpoint
(paragraph
R8.1)
il~
il'l,