ML18033B718
| ML18033B718 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 05/28/1991 |
| From: | Imbro E, Koltay P, Norkin D Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML18033B719 | List: |
| References | |
| 50-260-91-202, NUDOCS 9106050264 | |
| Download: ML18033B718 (30) | |
See also: IR 05000260/1991202
Text
U.S.
NUCLEAR REGULATORY COMYiISSION
OFFICE
OF NUCLEAR REACTOR REGULATION
Division of Reactor Inspection
and Safeguards
NRC Inspection
Report:
50-260/91-202
License
No: DPR-52
Docket Nos:
50-260
Licensee:
Valley Authority
6N38 A Lookout Place
Chattanooga,
TN
37402-2801
Facility Name:
Browns Ferry Nuclear Plant Unit 2
Inspection
Conducted:
April 15-19,
1991
Inspection
Team:
NRC Consultants:
Peter S.,Koltay,
Team Leader,
John
V. Kauffman,
Wayland
R. Bennett,
Senior Resident
Inspector,
RIV
David C. Lew, Resident
Inspector,
RI
David E. kills, Senior Resident
Inspector, RIII
4
Daniel
C. Ford, Parameter,
Inc.
Rene Vogt-Lowell, Parameter,
Inc.
Prepared
by:
Reviewed by:
Approved by:
Peter
.
ay,
Team Leade
Team Inspection
Development Section
A
Special
Inspection
Branch
Division of Reactor Inspection
and Safeguards
fice of Nuclear Reactor Regulation
0
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~
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1 e
Team Inspection
Development Section
A
Special
Inspection
Branch
Division of Reactor Inspection
and Safeguards
Office of Nuclear Reactor Regulation
ugene
.
m ro,
>>e
Special
Inspection
Branch
Division of Reactor Inspection
and Safeguards
Office of Nuclear Reactor Regulation
ate
ate
0
f06050264 9)0530
ADOCK 05000260
9
0
4
EXECUTIVE SUMMARY
The
NRC operational
readiness
assessment
team
(ORAT) conducted
a followup
inspection at Browns Ferry Nuclear Power Plant from April 15 through April 19,
1991.
The objective was to continue to independently
assess
the Tennessee
Valley Authority's (TVA's) operational
readiness
to safely restart
and operate
the Browns Ferry Nuclear Plant, Unit 2.
The team focused its efforts in three
areas:
1.
Operations
and operations
support activities;
2.
The unit separation
program
and its field implementation;
3.
TVA's corrective actions in response
to restart
concerns identified during
the
ORAT inspection.
In the area of operations
and operation support,
the team's
assessment
remained
positive.
Licensee
personnel
performed activities both inside the control
room
and in the field professionally
and conservatively.
Operators
demonstrated
good
use of system operating
procedures,
except for several
minor deficiencies
which
were attributed to lack of attention to detail.
Examples
were failure to
initial to confirm completed steps,
and failure to observe
a radiation control
sign.
Continued
management
attention in this area is required in order to
reduce
the
number of those minor errors.
In one instance,
the shift supervisor failed to adequately
assess
plant condit-
ions prior to authorizing
a surveillance which, if carried out, would have
inadvertently
caused
a technical specification requirement to be violated.
Open
Item 50-260/91-202-01
concerns
the licensee's
corrective actions to (I) discuss
with shift supervision
the importance of properly assessing
plant status prior
to authorizing surveillances
and (2) revising the surveillance
procedure.
The Browns Ferry Unit 2 separation
program represented
a significant effort on
the part of the licensee
regarding
design reviews,
drawings identifying unit
separation,
system
and component labeling,
and installation of temporary bar-
riers.
At the time of the inspection,
corisiderable effort remained
in order to
assure
that this program would be thoroughly and effectively implemented.
Approximately 300 Unit 3 control devices
remained to be labeled.
The licensee
committed to complete the labeling of the control devices prior to Unit 2
restart after the team determined that the unit separation
program did not
include requirements for labeling of control devices
which actuate
Units I and
3
equipment required for Unit 2 operation.
Additionally, only 125 of 590 drawings
required for the program
had been
issued
and only 20 of these
had been partially
field verified by engineering
personnel.
"Significant work remained with regard
to the drawings, control device labeling,
and the training of plant personnel
on
program requireoients.
Subsequent
to the inspection,
the
NRC Resident
Inspector
verified the completion of this program.
Within the scope of its review, the team did not identify any issues that
would prevent it from recommending restart of Unit 2.
The team verified that
approprfate
corrective actions
were
implemented
by the licensee
to address
the
restart
concerns
which had been identified in the original
ORAT inspection.
However,
Open Item 260/91-201-03,
concerning
the fuel handling event,
remains
open pending
NRC review of the final incident investigation report.
TABLE OF CONTENTS
~Pa
e
1.0
INTRODUCTION ......................................................1
1.1
1.2
ackground ................................................
B
Inspection Objective and Scope ............................
~ ~ ~ 1
~ ~ ~ 1
.0
OPERATIONS ........................................................1
2
2.1
2.2
2.3
2.4
2.5
Obser vation of Control
Room Activities and Watchstanding
P ractices .................................................
Observation of Field Activities ...........................
Observation of Surveillance
and Maintenance Activities ....
System Walkdowns ........................;.................
Concluslons
~ ~ ~ o ~ s ~ ooo ~ ~ o ~ ~ o ~ oo ~ ~ ~ oo ~ ~
~ ~ ~ ~ ooo
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ o ~
~ ~ ~ 1
~ ~ ~ 2
~ ~ ~ 3
~ ~ ~ 4
~ ~ 04
3.0
UNIT SEPARATION
PROGRAM
~ ~ o4
3.1
3.2
3.3
3.4
Review of System Drawings .................................
I.I~
System halkdowns ..........................................
Review of Training and Plant Personnel ....................
nt r
4
Conclusion
4
~ ~ ~ 5
~
~ ~ 6
~ ~ ~ 7
~ ~ ~ 7
t
4.0
FOLLOWUP ON RESTART
ISSUES
4.1
Determination of Responsibility for Communications
Between
Unit 2 and Unit 3 (Open Item 50-260/91-201-01) ............
4.2
Plant Operations
Review Committee
(PORC) Membership
(Open Item 50-260/91-201-02)
4.3
Power Ascension Test Program Procedures
(Open Item
50-260/91-201-06
and 50-260/91-201-07) ....................
4.4
Unit 1 Components
Required to be Functional
(Open Item
50 260/91
206 08)
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~
4.5
Rosemount Transmitter
Covers
(Open Item 50-260/91-201-11)
.
4.6
Incident Investigation Reports
(Open
Items 50-260/91-201-03
and 50-260/91-201-04) ..................,..................
~ ~ o7
~ ~ ~ 7
~ ~
~ 8
~ ~ ~ 8
~ ~ ~ 9
~ ~ ~ 9
~ ~
~ 9
4.6.1
Paint
Removal ............
4.6.2
Followup of Fuel Movement
Report (IIR)..............
~
~
~ ~ ~ ~ ~ ~ ~ ~ ~
~
~
~ ~ ~ ~ ~ ~ ~ ~
~
~ ~ ~ ~
Incident Investigation
~ ~
~ 9
~ ~ ~ 9
4.7
CGnclus 1 ons
~
~
~
~ ~ ~ ~
~ s
~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ i ~ ~ ~ ~ ~ ~
~
~
~
~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ oil
5.0
EXIT MEETING .........................
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 11
APPENDIX A - Personnel
Attending Exit Meeti
9
o ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ oA
1
n
0
0
1.0
INTRODUCTION
1.1
Background
The
NRC operational
readiness
assessment
team
(ORAT) completed
a 2 week inspec-
tion effort at the Browns Ferry Nuclear
Power Station
on March 1, 1991.
The
results of the inspection
were detailed in NRC Inspection Report
No.
50-260/91-201
dated April 12, 1991.
The report
and
a letter to the licensee
dated
March 15, 1991, identified concerns
requiring corrective actions before
the restart of Unit 2.
Due to the plant status
during the previous inspection,
the team
recommended
a return visit to observe additional activities in an operational
environment.
The few activities that were evaluated
during the previous inspection,
specifically refueling and paint removal, did not in all cases
demonstrate
to
the team that all licensee activities would be conducted
in a conservative
manner.
Therefore,
NRC management
directed the team to return before restart
to continue its assessment
of Tennessee
Valley Authority (TVA) management's
control over the conduct of activities that affect plant operations.
The team
conducted its followup inspection from April 15 through April 19,
1991.
1.2
Inspection Objective and Scope
During the followup inspection the
team continue) with its independent
assess-
ment of TVA's operational
readiness
to restart Unit 2.
The team's efforts
focused
on three areas:
observation of activities affecting operations,
inside and outside the
control room, including watchstanding
and the conduct of maintenance
and
surv ei 1 lance
an in-depth assessment
of the unit separation
program including program
adequacy
and implementation
an evaluation of TVA's corrective actions in response
to concerns
identi-
fied by the
ORAT that required resolution before Unit 2 restart
2.0
OPERATIONS
During this inspection,
the team assessed
the implementation of the licensee's
requirements
and procedures for the conduct of operations
during
a 72-hour
continuous evaluation of shift activities in the control
room and throughout the
plant.
The team evaluated
operating philosophy, shift staffing,
and observed
shift turnover, shift operations, shift communications,
control
room access
and
personnel
conduct
and practices
associated
with operator plant tours
and
inspections.
2. 1
Observation of Control
Room Activities and Matchstanding Practices
The operating
crews demonstrated
a high level of professionalism,
enthusiasm,
and confidence
and were eager to return to power operations.
Shift personnel
strictly controlled access
to the control
room operating
area to exclude
workers not directly involved in ongoing or planned activities.
For example,
in one instance
a cleaning
crew was asked to leave the control
room horseshoe
area
so that it would not distract
a unit operator
responding
to a half scram.
0
II
Operator
response
to alarms
was timely and in accordance
with procedures,
and
communication to supervisors
was clear,
prompt,
and well understood.
Operator
knowledge of plant status
and reasons for alarms
was good.
The interaction
between control
room operators
and field personnel
during the performance of
surveillance
and maintenance activities was good.
Personnel
performed
normal
activities
such
as removal of a main turbine turning gear oil pump and bypassing
of a reactor water cleanup demineralizer in accordance
with the applicable
procedures.
All shift turnovers
observed
by the team during the 72-hour continuous
evalua-
tion of shift activities were detailed
and comprehensive.
Turnover briefings
were well conducted
and were attended
by plant operations
support personnel.
The shift staffing requirements
in the technical specifications
were met during
the observed shifts.
Logs were well written and
had the proper amount of
detail.
All required readings
were properly taken
and all required reviews
were performed
and documented
on the appropriate
logs.
The limiting conditions
for operations
(LCO) tracking program was properly implemented
during the
removal from service of the Unit 2 secondary
containment
and standby
gas treat-
ment systems.
The licensee
also effectively implemented activities outside the control
room
that could affect plant operations,
such
as the ongoing system draining and
realignment that were necessary
as
a result of the recently completed reactor
pressure
vessel
hydrostatic test.
These realignment activities were conducted
in accordance
with Procedure 2-SI-3.3.1.B,
"ASME Section
XI Hydrostatic Pressure
Testing of the Reactor
Pressure
Vessel
and Hain Steam Piping," and constituted
a
major portion of the activities during the period of this inspection.
The team observed
control room personnel
response
to two consecutive half scrams
caused
by
a spiking intermediate
range monitor
( IRH) in the neutron monitoring
system.
The licensee
had experienced
previous
problems with the neutron moni-
toring system
and was taking steps
to determine
the
cause
and to address
the
spiking problem.
This particular
IRM could not be bypassed
at the time of the
because
another
IRH in the
same reactor protection
system
channel
was already
bypassed.
The team noted that the unit operator
used the applicable
response
procedures,
verified that all required
alarms
had been
received,
and promptly contacted onshift instrument technicians
who responded
to
the control room.
The operator also sent
an auxiliary unit operator
(AUO) to
check for plant activities in the area of the
IRN preamplifiers that might
affect the instruments.
The team observed
good interactions
between
the shift
operations
supervisor,
his assistant
and the operations
superintendent.
2.2
Observation of Field Activities
The team observed
AUO rounds
and completion of corresponding
logs.
The
were knowledgeable of the equipment
and demonstrated
good watchstanding
prac-
tices.
Cooeunication
between
AUOs and control
room personnel
was clear.
The
AUOs attended
turnover briefings and were knowledgeable of plant status.
Morale
appeared
to be good
among the AUOs.
Valve lineups after the hydrostatic testing
were completed in accordance
with
the hydrostatic testing procedure.
Good communications
between
the
AUOs in the
field and control
room personnel
were noted
by the team.
Removal,
accounta-
bilityy
and independent verification of configuration control tags were in
~
~
~
~
accordance
with plant procedures.
Coordination with health physics
personnel
with respect to the observed activities was adequate.
During the observation of shift activities, the team noted minor inconsisten-
cies in the implementation of procedural
requirements
and management
expectations.
During the performance of his rounds,
the
AUO did not have in his posses-
sion the
key required to open
an Emergency
Operating Instructions locker
located adjacent to the hydraulic control units.
The operations
superin-
tendent
informed the team that the
AUO should
have
had the
key in his
possession
during his rounds
and that this policy would be reiterated
during subsequent shift turnover meetings.
A number of items
( ladders,
welding rigs,
empty standby liquid control
barrels,
compressed
gas bottle carts,
MOVATS testing cart, etc.) found in
the reactor building lacked the required "llaterial In Use" tags.
The team
pointed these
out to the AUO.
A door with a "High Radiation - Door Must Be Locked
When Unattended"
sign
leading into the outboard
main steam isolation valve area
was open,
and
the area
was unattended.
The team verified that,
based
on the current
plant conditions,
a high radiation area did not exist within the subject
space.
However, the posted
requirements
fok this door were apparently
ignored rather
than modified to reflect actual radiological conditions.
2.3
Observation of Surveillance
and tlaintenance Activities
The team observed
several
maintenance
work planning
and status
meetings.
These,
meetings
were well conducted
and they ensured
scheduling,
communication,
and
allocation of resources
between various plant departments.
The team also
observed
and reviewed operations
surveillance
and post-maintenance
tests
and
determined that these activities were generally well conducted.
Personnel
were
knowledgeable
of independent verification program requirements
and independent
verifications were performed
as required.
During the residual
heat
removal service water
(RHRSW) initiation logic sur-
veillance
(Procedure
O-SI-428-67,
Revision 6) the team noted that the unit
operator
stopped
the surveillance
when
he realized that further conduct of the
surveillance
would place the plant in a condition prohibited by the Technical
Specifications.
The operator's
recognition of this discrepant
condition
indicated
a good overall
knowledge of plant status
and requirements.
However,
shift supervision
had performed
an inadequate
review before authorizing the
performance of the surveillance
in that off-normal conditions
had not been
properly considered.
The procedure
directed the operator to place the emergency
equipment cooling water
(EECM)
pump
B3 control switch to the pull-to-lock posit-
ion, thus disabling
pump
B3 and leaving only
EECW pump
D3 to supply the south
EECh header.
Since the emergency
power supply for EECW pump
D3 was inoperable,
this
pump was also considered technically inoperable while the plant was in the
cold shutdown condition.
Technical Specification Table 3.5. 1 required at least
one operable
I
fr
0
The team brought the inadequate
review by the shift supervision to the atten-
tion of the licensee.
The manager of operations
stated that the corrective
action would be two fold, (I) discuss with shift supervision
the importance of
properly assessing
plant status prior to authorizing surveillance activities,
and (2) correct the procedure to assure
that the requirements
of Technical
Specification Table 3.5.1 could not be inadvertently violated during the
surveillance.
The licensee's
corrective actions will be followed as
an open
item (Open Item '50-260/91-202-01).
The team observed additional maintenance
work and post-maintenance
testing to
determine if the activities were being properly conducted
in accordance
with
plant procedures.
Althou'gh these activities were generally well performed,
the
following minor problems
were noted in the work order documentation:
WO 91-28934-00
and
WO 91-24429-00
were modified to remove quality control
(gC) holdpoints.
However, the documentation
did not identify the
gC person
notified of the action,
as required
by Procedure
SDSP-7.6.2,
"Planning Work
Orders" (Revision 11).
A work planner forgot to provide this information to
the job foreman who, in turn, did not question its absence.
Completion of the pre-job briefing and personnel
safety analysis
was not
documented
in
WO 90-23937-00,
as required
by Procedure
SDSP-7.6.5
"Perfor-
mance of Work Orders,"
(Revision 11).
4
After the
team informed the licensee
about these
examples,
the licensee
com-
pleted the required documentation.
2.4
System
Walkdowns
The team performed walkdowns of the standby
gas treatment
system,
Unit 2 core
spray system,
the U>>it I
RHRSW system
and the Unit I residual
heat
removal
system to ascertain
system status
and coridition.
These
systems
appeared
to be
adequately
maintained,
selected
lineups were correct
and selected
clearances
were correctly placed.
The team noted that the locked valve program was
implemented.
Valves required to be locked were verified by the team to be in
the correct position.
2.5
Conclusions
Routine operations shift activities were conducted
in a professional
manner
inside
and outside the control room.
Shift personnel
demonstrated
good under-
standing
and use of procedures.
However, minor problems were indicative of lack
of attention to detail
in several
areas
such
as failure to initial procedure
steps, failure to observe
a radiatiori control sign,
and lack of material
controls in the reactor building.
In one instance,
the shift supervisor failed
to adequately
assess
plant conditions prior to authorizing
a surveillance
which,
if carried out, would have inadvertently
caused
a technical specification
requirement to be violated.
The discrepancies
were brought to the licensee's
attention,
and the licensee initiated prompt corrective actions.
3.0
UNIT SEPARATION
PROGRAM
To assure
operability of technical'specification
equipment
and operational
separation
of the Browns Ferry units, the licensee
has developed
and imple-
mented
a program of unit separation for recovery activities.
The program,
0
which was defined in Site Standard
Practice
SSP-12.50,
"Unit Separation for
Recovery Activities," established
control of personnel
access
and system
operational
interfaces.
The controls were designed
to restrict access
into
Unit 2 operating
areas
by Unit 3 recovery personnel
and to ensure that Unit 3
recovery
and Unit 1 layup activities did not affect Unit 2 systems.
The team's
review of this program included
an overview of personnel
training;
interviews with plant personnel;
an assessment
of the development,
approval,
distribution,
and verification of interface drawing;
and the walkdown of
several
plant systems
to assess
labeling of boundary
and unit interfaces
and
personnel
access
barriers.
The review of SSP-12.50
showed that the licensee's
program provided
a compre-
hensive
approach
to unit separation.
Particular
emphasis
was placed
on con-
trols that limited access
of nonessential
personnel
into Unit 2 operating
areas.
Special
provisions were
made for badging, training,
and qualification of
personnel
who would require access
to these
areas
during Unit 2 operation.
The
team considered restrictions established for personnel
access
to be adequate if
properly implemented.
The program also established
requirements for the
identification and control of system operational
interfaces.
3. 1
Review of System Drawings
To identify plant systems physically located in Units
1 and
3 and required to
support Unit 2 operation,
the licensee
issued
a Series of system drawings that
indicated unit boundaries for systems
shared
between units.
The drawings
did not represent
a change
in configuration of plant design, but applied
a
system of color coding to assist plant personnel
in identifying operational
interfaces
between units.
The team reviewed the licensee's
process for development,
approval
and distri-
bution of interface drawings.
The process
incorporated
input from system
engineers
and operational
personnel
in order to identify system boundaries
and
plant operational
interfaces.
Design reviews included
an assessment
of flow
diagrams,
schematics,
single line electrical drawings,
and electrical
power
supply requirements for plant interface systems.
Drawings annotated
to reflect
the above were then forwarded to nuclear
Engineering for review and approval
before the production of computer assisted
design
(CAD) enhancements.
Following
CAD development
the drawings received additional consistency
reviews before they
were distributed.
Once the drawings
have
been
issued,
engineering
personnel
verified by physical
walkdown that affected plant systems
and components
were
labeled in accordance
with drawing and procedural
requirements.
The licensee's
verification was being accomplished
in two phases.
Phase
One covered piping and
Phase
two covered
components.
At the time of the inspection,
20 drawings
had
been partially verified (Phase
One)
and
none
had been fully verified.
Additi-
onally, the plant design
change control program was modified to ensure that unit
separation
was considered for future plant modifications.
To determine
the effectiveness
of this program,
the team reviewed
17 drawings
that
had
been
issued
and partially verified by the licensee.
The review showed
that the licensee's
program for development,
approval
and distribution of these
drawings
was accomplished
in accordance
with program requirements.
The team
also noted that the drawings were sufficiently detailed
and clear to enable
plant personnel
to readily identify operational
interface points.
Although most
programmatic
aspects
of this process
were adequate,
of the approximately
590
0
4
I]
fi
e
drawings required for this effort, only 125 had been
issued at the time of this
inspection.
Of these,
only 20 had been partially field verified by engineering
personnel,
as indicated
above.
Subsequent
to the inspection,
the
HRC Resident
Inspector verified implementation of this program.
3.2
System Walkdowns
The team performed walkdowns of several
systems
using
17 system drawings
issued
and partially verified by the licensee.
The walkdowns focused
upon aspects
of
system
and component
labeling required
by the unit separation
program.
The team
compared
drawing requirements
with the labeling of piping, instrumentation,
electrical,
mechanical,
and support systems.
Labeling consisted
of orange
tape
that was applied to system piping and equipment,
and of Unit 2 operation caution
tags that were applied to electrical panels, circuit breakers
and various other
equipment.
In general,
the plant systems
were labeled
as required
by the
drawings.
The labels provided distinct identification of interfacing
compo-
nents.
However,
two valves in the generator
system
had interface
boundary labels which were not required
by applicable
system drawings.
Since
labeling for these
valves
was recorded
in the manual
log which was kept for all
labels installed in the field, the licensee's
verification program would have
reasonably
been
expected to identify this error.
The team examined portions of the
125
VDC system.
Drawings for this system
had
not been
issued formally, but were provided as "jnformation only" for the
purpose of this inspection.
In general,
the affected
components
were labeled
as required.
However, the control devices
which actuate
Unit 3 and Unit I
equipment required for Unit 2 operation
had not been
labeled to restrict their
use.
These devices
included
hand switches for the Unit 3 diesel
generator air
compressors
and diesel
room essential
exhaust fans,
and
a pushbutton
station'or
a Unit I standby
coolant system valve.
During subsequent
discussions
with
engineering
personnel,
the team found that the unit separation
program did not
include requirements for labeling control devices.
The team concluded that
this inconsistency
in labeling could lead to the improper manipulation of the
control devices
by plant personnel.
In response
to this concern,
the licensee
planned to enhance
the unit separa-
tion program by labeling Unit 3 control devices that might affect Unit 2
operation.
The approximately
300 devices
would be labeled before the restart of
Unit 2.
The
NRC Resident
Inspector
subsequently
verified implementation of
those actions.
Temporarily installed barriers,
designed
and fabricated for the unit separation
program, prohibited the entrance
of unauthorized
personnel
into Unit 2 operat-
ing areas.
The team expressed
a concern that these barriers
could preclude the
movement of auxiliary unit operators
(AUO) during
a response
to abnormal plant
operating conditions.
The licensee
stated that,
based
upon the r~view of plant
and emergency
operating
procedures,
no adverse
impact had been identified.
After further review, the team agreed with the licensee's
conclusion.
3.3
Review of Training and Plant Personnel
The team reviewed the licensee's
general
employee training
(GET) program with
respect
to unit separation.
Corporate
access
training was specified
by
0
course
010, "Nuclear Industrial Training/Retraining."
This course is provided
annually to personnel
requiring access
to Browns Ferry and included
site-specific training for personnel
and
a
15 minute film on the unit separa-
tion program.
Basic aspects
of the program,
including the significance of
color coding, the identification of components affecting Unit 2 operation
and
area
access
controls,
were discussed
iri the film.
Currently,
more than
2300 employees
have viewed the film and approximately
300
personnel
remain to be trained.
Additionally, the licensee
planned to perform
formal classroom training, covering the details of the unit separation
program,
for all operations
personnel
prior to restart.
The classroom training would be
incorporated
into the operator's
requalification trairiing program.
Subsequent
to the inspection,
the
NRC Resident
Inspector verified implementation of this
program.
3.4
Conclusions
The Browns Ferry unit separation
program represented
a significant effort on
the part of the licensee
regarding
design reviews,
drawings identifying unit
separation,
system
and
component labeling,
and installation of temporary
access
barriers.
At the time of inspection,
considerable effort remained in order to
assure
that this program would be thoroughly and effectively implemented.
This
effort involved the labeling of Unit 3 control devices
required for Unit 2 oper-
ation, verification of separation
drawings,
arid detailed training of operations
personnel.
Subsequent
to the inspection,
the
NR0 Resident
Inspector verified
the completion of this program.
4.0
FOLLOWUP ON RESTART ISSUES
NRC inspection report 50-260/91-201 identified open
items that required resolu-
tion before Unit 2 restart.
During this irispection period, the licensee's
corrective actions in response
to the open
items were assessed
by the team.
4.1
Determination of Responsibility for Communicatioris
Between Unit 2
and Unit 3 (Operi Item 50-260/91-201-01)
The licensee
committed to establish
administrative controls delineating
respon-
sibilitiess
for communications
between
the Unit 2 and
3 site organizations
at
management
levels.
The licensee
has initiated the development of a formalized administrative
program to delineate responsibilities
and lines of communication
between
Browns
Ferry (BF) operations
and
BF restart organizations.
The licensee's
memorandum,
dated April 18,
1991 identified (1) the responsibilities of the
BF operations
and restart organizations
management,
(2)
BF operations
and restart organiza-
tions,
and (3) individual restart
issues
and detailed division of resporsibi li-
ties for each of these
issues.
The memorandum also specified the existing
BF hierarchy of site procedure
as it
was applicable to Unit 1 and Unit 3 recovery,
in coordination with the Unit 1
and Unit 3 Restart Project Procedures
Manual.
However, the memorandum
recog-
nized the
need for additional
procedures
in two areas:
(1)
a
new site standard
practice
(SSP 1.5) to clarify the role of the Unit 1 and Unit 3 restart organ-
izations
as part of the
BF site organization
and (2)
a dedicated
series of
procedures
would be issued to address
specific activities identified in the
Restart Project Procedures
Manual.
The licensee
stated that these
procedures
were under development
and would be issued
by June 1, 1991.
Based
on the licensee's
corrective actions,
which established
the administrative
controls delineating
the lines of communication
between
the Unit 2 and Unit 3
site organizations
and the licensee's
commitment to develop additional
procedures
as indicated above,
the team considers this item closed.
The actions
completed
satisfy the team's
concerns for restart.
4.2
Plant Operations
Review Committee
(PORC) Membership
(Open Item
50-260/91-201-02)
The team identified that Technical Specification Section 6.5.1.2 did not
correctly designate
committee
members
by their current titles.
On March 1, 1991, the licensee
submitted
a technical specification
change
which
revised the
PORC composition.
The revision accurately reflected existing
membership titles.
Additionally the licensee
also revised Site Director
Standard
Procedure
(SDSP) 27.4,
PORC, to incorporate title changes,
delineate
membership responsibilities,
and define
a methodology for designation of
alternate
committee memberships.
The team considers this item closed for the
purpose of this inspection.
Review and approval of the license
amendment will
be in accordance
with NRC procedures.
4.3
Power Ascension Test Program Procedures
(Open
Items 50-260/91-201-06
and
50-260/91-201-07)
Several
required items,
such
as functional organization, shift staffing, review
of procedural
references,
and independent
review of test results,
were not
included in applicable Plant Manager Instructions
(PMI) 26.1,
"Power Ascension
Test Program,"
and
PMI- 17.1,
"Conduct of Testing."
Additionally, technical
deficiencies
were identified in several test procedures
of the power ascension
test program.
The team verified that procedures
PMI 26.1
and
PMI 17.1
have
been revised to
incorporate
the above required
items.
The team also reviewed test procedures
and verified that actions
were being taken to correct the technical
deficiencies.
The team considers this item closed.
4.4
Units
1 and
3 Components
Required to be Functional
(Open Item
50-260/91-206-08)
The licensee
has identified the systems
and components
in Units
1 and
3 that
were required to be operable to support Unit 2 operations.
The licensee
indicated that certain
components
in Units
1 and
3 were required to be func-
tional to support the Units
1 and
3 systems
required to be operable.
The team
requested
that the licensee
identify the specific Unit 1 and
3 components
that
have to be functional
and define for these
components
.he requirements
that
have to be met to assure
they are functional.
During this inspection,
the licensee
stated
and the team verified, that the
above referenced
"functional" equipment, e.g.,
the Unit
1 torus which is
required to test the operability of Unit 1 residual
heat
removal
pumps,
continued to remain under the work control programs that were in place for
Unit 2 equipment.
The team considers
that this would ensure
the continued
operability of equipment required to support Units
1 and
3 systems
required to
be operable.
The team considers this item closed.
4.5
Rosemount Transmitter
Covers
(Open Item 50-260/91-201-11)
The team reviewed licensee
actions in response
to the concerns
about excessive
gaps discovered
between
nine Rosemount transmitter electronic side covers
and
housings.
A licensee
review indicated that only one of the transmitters,
2-PT-64-67,
was of concern.
The remainder either were not environmentally
qualified equipment,
and therefore
had
no specific cover torque requirements,
or had not yet been calibrated following installation.
Torque was purposely
not applied during installation because
removing the covers for subsequent
calibration adjustment
before startup would have necessitated
the replacement
of o-rings.
During its review of maintenance
history, the licensee
could not determine
a
root cause for the loose cover on drywell pressure
transmitter 2-PT-64-67.
Documentation
indicated that proper torque
was verified by a
gC holdpoint
during calibration in 1988.
Subsequent
calibration surveillance
did not
necessitate
the removal of the cover because
adjustments
were not necessary.
After the
NRC had identified the problem, the licensee
properly torqued the
transmitter
cover and provided training to instrument technicians
to emphasize
the importance of proper cover torque.
The team determined that the surveil-
lance procedure,
2-SI-4.2.F-3(B),
"Drywell Pressure
Channel Calibration"
(Revision 3), was adequate
in this regard since
a specific torque requirement
was prescribed if the cover was
removed.
The team considers this item closed.
4.6
Incident Investigation Reports
(Open Item 260/91-201-03
and 50-260/
91-201-04)
During the
ORAT inspection
the team noted that in two instances,
paint removal
and initial fuel movement,
the licensee failed to recognize
and assess
the
potential
impact of the activities
on plant safety.
The licensee
stated that
incident investigation reports would be prepared.
4.6.1
Paint
Removal
The team inspected
equipment potentially affected
by dust from the surface
preparations,
i.e., portions of the Unit 2 reactor building and internals of
motor control centers
(tlCCs).
No discrepancies
were identified and the
were clean.
The team reviewed Final Event Report II-B-91-038, "Reactor Building Painting."
The report identified weaknesses
in the applicable
procedure,
t)AI-5.3,
Protective Coatings,
Revision 5, as the root cause for the event.
The
procedure
contained
requirements fur dust control, but did not specify
4
(j
~
~
~
~
~
~
~
lines of responsibility for implementing action
and verification of such
controls.
Subsequently,
the licensee
assigned
responsibility for the implemen-
tation of protective actions to the operation
department.
The team verified
that the lines of responsibility were detailed
in revision
6 of the above
procedure.
The team considers this item closed.
4.6.2
Followup of Fuel Novement Incident Investigation Report
( IIR)
The team reviewed Final Event Report II-B-91-040, "Source
Range Nonitor/Fuel
Load Chamber
Noise Spikes
Occurring
on 2/21/91."
The team noted that the
licensee
was apparently reluctant to expand the scope of the incident investi-
gation beyond the technical
issue of reactor protection
system operability and
justification of the acceptability of licensee
actions during the event.
Accordingly, the
team found that the IIR did not provide (I) a detailed
and
comprehensive
root cause analysis,
or (2) comprehensive
corrective actions to
prevent recurrence.
The team determined that potential failures to "B" SRN during planned fuel
movement were indicated to shift and management
personnel
by erratic
SRN
response
and failure to implement work request
requirements
(WO No. C042091)
for troubleshooting,
repair,
and post-maintenance
testing of the
SRN.
In view
of this situation,
the team concluded that the decision to initiate fuel
movement
was inappropriate
since this potentially inoperable
SRN would have
precluded
compliance with precautions
identified, in procedure
2-GOI-100-3,
"Refueling Operations,"
and requirements for two operable
SRNs
as stated
in
t
Technical Specification Section 3.10.B.1.
The team also noted the following discrepancies
in the data presented
in the
investigation report:
WO PC042091
was written before fuel movement to "troubleshoot
and rework
as required to restore
2-SRN-92-B and/or
FLC to perform as intended."
Subsequently,
the work request
was closed without completing specific
tasks.
The report failed to address
the basis for closing the work
request without completing the work.
The incident investigation report indicated that only "Hi" spikes
were
received
on "B" SRN before the initial fuel movement.
However, written
statements
from two licensed shift crew members
indicated that "Hi Hi"
spikes
were received at the
SRN local panel before
WO PC042091
was initi-
ated
and before initial fuel movement.
These
two crew members,
when
interviewed
by the
ORAT team, maintained that their written statements
were accurate.
However, the team determined that poor control
room log
keeping during this event apparently contributed to the loss of pertinent
information concerning
the above discrepancy,
such
as the type of alarms
received,
the sequence
of events,
the status of shorting links and the
position of the
SRN bypass
switch.
The licensee
acknowledged that the quality of incident investigation reports
needed
to be enhanced
through training of personnel.
In addition, the licensee
1
initiated
a
Human Performance
Enhancement
System
(HPES) evaluation of this
event
and planned to revise the final incident investigation report,
as approp-
riate,
bzsed
on the
HPES evaluatiox.
The team conducted
a preliminary review of
10
0
the
HPES findings and determined that the licensee's
corrective actions
appeared
~
~
~
~
~
~
~
~
to have adequately
addressed
the restart implications of these
issues.
This
item, while no longer
a startup
issue,
remains
open pending
NRC review of the
final incident investigation report.
4.7
Conclusions
The team verified that appropriate
corrective actions
were implemented
by the
licensee
to address
the restart
concerns.
However,
Open Item 260/91-201-03,
concerning
the fuel handling event,
remains
open pending
NRC review of the
final incident investigation report.
5.0
EXIT MEETING
On April 19,
1991, the team conducted
an exit meeting at the Drowns Ferry site.
Licensee
and
NRC representatives
attending this meeting
are listed in
Appendix A.
During the exit meeting,
the team summarized
the scope
and find-
ings of the inspection.
0
. APPENDIX A
Personnel
Attendin
Exit Heetin
NRC
Wayland
R. Bennett,
Senior Resident Inspector,
RIV
Edward F. Christnot, Resident
Inspector,
Browns Ferry
Stewart
D. Ebneter,
Regional Administrator, RII
Daniel
C. Ford, Parameter,
Inc.
Brian K. Grimes, Director, Division of Reactor Inspection
and Safeguards,
Frederick J.
Hebdon, Project Director, Project Directorate II-4, NRR
David E. Hills, Senior Resident
Inspector,
Region III
Gary H. Holahan,
Deputy Director, Division of System Technology,
John
V. Kauffman,
Paul J. Kellogg, Section Chief, RII
David C.
Lew, Resident
Inspector,
RI
Rene Vogt-Lowell, Parameter,
Inc.
Dr. Thomas
E. Hurley, Director,
Donald P. Norkin, Section Chief, SIB, DRIS,
James
G. Partlow, Associate Director for Projects,
Thierry H. Ross, Project Hanager,
Valle
Authorit
t
Hasoud Bajestani,
Technical Support Manager
Paul
R. Baron, Quality Control Hanager
Joe
Bynum, Vice President,
Nuclear Operations
Patrick P. Carier, Site Licensing Hanager
Hax E. Herrell, Plant Operations
Hanager
Hark 0. Hedford, Vice President,
Nuclear Assurance,
Licensing
and Fuels
Dan A. Nauman, Senior Vice President,
Nuclear
Power
John L. Sparks,
Technical
Support
Gerald
G. Turner, Site Quality Hanager
Oswald J. Zerigue, Site Director
F
4