ML18036A702
| ML18036A702 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 04/29/1992 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18036A701 | List: |
| References | |
| 50-259-92-11, 50-260-92-11, 50-296-92-11, NUDOCS 9205190128 | |
| Download: ML18036A702 (48) | |
See also: IR 05000259/1992011
Text
y.
(41PS RE@II'a
UNITED STATES
NUCLEAR REGULATORY COMMtSSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
~w*w+
Report Nos.:
50-'259/92-11, 50-260/92-11,
and 50-296/92-11
Licensee:
Valley Authority
3B Lookout Place
1101 Market Street
Chattanooga,
TN 37402-2801
Docket Nos.:
50-259, 50-260, and 50-296
License Nos.:
Facility Name:
Browns Ferry Units 1, 2, and 3
Inspection at Browns Ferry Site near Decatur, Alabama-.
Inspection Conducted
March
14 - April 17; 1992
t
Inspector: C.. Patt,
or R
ident
spector
e/
Date Signed
Accompanied by:
E. Christnot, Resident Inspector
W. Bearden, Resident Inspector
R. Bernhard, Project Engineer
M. Murphy, Regional Inspector
Approved by:
Paul
Reactor Proje
s, Section 4A
Division of Reactor Projects
SUMMARY
Date Sig ed
~ Scope:
This routine resident inspection included surveillance observation
maintenance
observation, operational safety verification, Unit 1
activities, Unit 3 restart activities, fire protection/prevention pl'ogram,
9205190128
920501
ADOCK 05000259
8
Browns Ferry Nuclear Performance
Plan Post-Restart commitments,
reportable occurrences,
action on previous inspection findings, and
management
changes.
One hour of'backshift coverage was routinely worked during the
week.
Deep backshift inspections-w'ere conducted on March 22 and
March 28, 1992.
One violation with two examples was identified for failure to perform
independent verification, paragraphs two and three.
The first example
was identified by the inspector during the performance of a
surveillance test for the diesel driven fire pump, paragraph two.
Steps
in the body of the procedure required independent verification but the,
entire test was performed before in'dependent verification steps were
completed.
This was thought to be the desired method of performing
the test by personnel performing the surveillance.
The second
example was found when the rod sequence
control system was still
enforcing rod movement constraints after power had been increased
above 30 percent power, the normal bypass point, paragraph three.
Surveillance instruction steps to open the first stage pressure
transmitter isolation valve were not adequately performed.
Independent verification that the valve was opened was performed by
visual observation from outside a controlled surface contamination
area.
Two previous violations were identified during the last two
years concerning independent verification. These were 90-14-05
during cable determination and 91-24-02 during fuse installation.
This
indicates problems with how and when to perform independent
verification.
An unresolved item was identified concerning adequacy of
independent verification steps, para'graph two. Two steps in a diesel
driven fire pump surveillance procedure do not.require independent
verification that control switches were returned to "AUTO" following
system restoration.
Initial discussion with the licensee indicate that
credit may have been taken for clearing of annunciator alarms
following completion of the test.
This item will be unresolved until
this practice and applicability to this procedure are reviewed further.
A violation was identified for failure to take corrective action for a
previous violation, paragraph,.three.
The inspector identified that the
wrong chart recorder paper had again been placed in two control room
recorders required by technical specifications.
This problem was the
reason for part of a previous violation 91-24-01.
The problem
C,
'3
was identified after the licensee had presented
a closure package for
the previous violation.
An inspector followup item was identified concerning Unit 3 circuit
breaker refurbishment, paragraph eight.
This concerned the proper
identification of breakers shipped and used as substitutes.
An
inspector walkdown identified tagging inconsistencies
in the plant.
This item is a concern because
a previous breaker substitution in
1990 resulted in a power supply failure to automatically transfer.
REPORT DETAILS
Persons Contacted
Licensee Employees:
'. Zeringue, Vice President, Browns Ferry Operations
"H. McCluskey, Vice President, Browns Ferry Restart
"J. Scalice, Plant Manager
J. Rupert, Engineering and Modifications Manager
"J. Swindell, Restart Manager
"M. Herrell, Operations Manager
J. Maddox, Project Engineer
"M. Bajestani, Technical Support Manager
R. Jones,
Operations Superintendent
A. Sorrell, Special Programs Manager
"C. Crane, Maintenance Manager
G. Turner, Site Quality Assurance Manager
"R. Baron, Site Licensing Manager
"J. McCarthy, Unit 3 Licensing
"P. Salas, Compliance Supervisor
J. Corey, Site Radiological Control Manager-
A. Brittain, Site Security Manager
Other licensee employees or contractors contacted included licensed reactor
operators, auxiliary operators, craftsmen, technicians, and
public safety
officers; and quality assurance,
design, and engineering personnel.
'RC
Personnel:
1
P. Kellogg, Section Chief
"C. Patterson,
Senior Resident Inspector
E. Christnot, Resident Inspector
"W. Bearden, Resident Inspector
R. Bernhard, Project Engineer
M. Murphy, Regional Inspector
"Attended exit interview
Acronyms and initialisms used throughout this report are listed in the last
paragraph;
Surveillance Observation (61726)
The inspectors observed and/or reviewed the performance of required Sls.
r.
0
The inspections included reviews of the Sls for technical adequacy and
conformance to TS, verification of test instrument calibration, observations
of the conduct of testing, confirmation of proper removal from service and
return to service of systems,
and reviews of test data.
The inspectors also
verified that LCOs were met, testing was accomplished by qualified
personnel, and the Sls were completed within the required frequency.
The
following Sls were reviewed during this reporting period:
The inspector observed the performance of.O-SI-4.11.B.2.a,
Diesel Driven
Fire Pump Operability, Test.
Following completion of the Sl, the inspector
reviewed the completed
Sl and noted the IV steps had not been, signed for
IV. Six steps in the Sl require IV following performance of.the step and prior
to continuing with the next step.
As an example, step 7.2.6.3 closes drain
valves from the fuel tank and requires IV. Another step requires the engine
air cleaner be disassembled,
inspected,
and reassembled
with IV before the
diesel is operated.
When the operator was questioned,
he stated that
another operator would be dispatched to perform the IV. He further stated
that the IV were once performed immediately following completion of the
step but that this philosophy had changed and that now the. Sl is performed
in it's entirety before the IV is performed.
This represents
a fundamental
misunderstanding of IV when required in the body. of a procedure.
This is a
violation of SSP-12.1,
Conduct of Operations, step 3.14.2.B, which requires
that procedures which are not routine, frequently performed (once per shift),
and easily accomplished,
be performed "step-by-step".
Additionally, TS
.6.8.1
requires that procedures
be followed during surveillance and test
activities of safety related equipment.
This is the first example of violation,
259,260,296/ 92-11-01, Failure To Perform Independent Verification. This
event is similar to events associated
with previous violations concerning the
performance of IV and procedural compliance which are documented
as NRC
violations 260/90-14-05,
and 260/91-24-02.
Additionally, the inspector reviewed 3-SI-4.9.A.1.a(3c), 3C DG Monthly
Operability Tests.
In the body of this procedure are IV steps performed
befo're the DG is started.
The 20 cylinder tests valves are opened and IV
perform'ed.
Next, the engine is manually rolled and fluid drainage checked.
The test cylinder valves are closed and IV'performed before running the DG
It was also n'oted that steps 7.3.8.9 and 7.3.12.5 did not require IV. These
steps place the Diesel Driven Fire Pump Strainer Backwash Control Switch
and Pump Controller Selector Switch, respectively, in the normal standby
lineup following it's use during performance of the Sl.
These actions align
the system for automatic'operation
in the event it is needed.
SSP-12.6,
Independent Verification, step 3.1
~ 2, states that IV is required for all valves,
breakers, and other components
in safety-related
or fire protection systems
I
3
where an inappropriate positioning could adversely affect system operation
'r
the ability to supply extinguishing media to the fire. These issues were
discussed with the Fire Protection Manager and Operations Superintendent
immediately after the Sl was performed on April 15, 1992.
Initial
discussions with the licensee indicated that credit may be taken for clearing
of annunciator alarms as the IV steps.
This approach and the acceptability
of the circuits involved will be unresolved until further review. This will
tracked as URI 259,260,296/92-11-02,
Missing Independent Verification
Steps.
One violation was identified in the Surveillance Observation area.
3. 'aintenance
Observation (62703)
Plant maintenance activities were observed and/or reviewed for selected
safety-related systems and components to ascertain that they were
conducted in accordance with requirements.
The following items were
considered during these reviews:
LCOs maintained, use of approved
procedures, functional testing and/or calibrations were performed prior to
returning components or systems to service, QC records maintained,
activities accomplished
by qualified personnel, use of properly certified parts
and materials, proper use of clearance procedures,
and implementation of
radiological controls as required.
Work documentation
(MR, WR, and WO) were reviewed to determine the
status of outstanding jobs and to assure that priority'was assigned to safety-
related equipment maintenance
which might affect plant safety.
The
inspectors observed the following maintenance
activities during this
reporting period:
a
e
Failure to Open a Valve and Perform Independent Verification
0
.
WO 92-49879-00,
was written during power ascension
on March 2,
1992, to correct a problem with the RSCS.
The RSCS restraint was
still active at greater than 30% power which restricted control rod
movement to group notch mode, thereby slowing power'ascension.
During work activities associated
with this work order, instrument
maintenance
personnel identified that the isolation valve for pressure
transmitter, 2-PT-85-61B, was closed.
This transmitter senses
turbine
first stage pressure which is an indicator of reactor power.
With this
valve closed the pressure transmitter was effectively out of service,
resulting in the RSCS restraint not being bypassed at 30% power
even though actual power was greater than 30%.
The inspector
reviewed II.Report, II-B-92-018, which documented the licensee's
investigation into the circumstances
associated
with this event.
In
that report the licensee attributed the event to a failure to adequately
perform IVfollowing a routine surveillance performed on February 25,
1992.
The valve was closed in step 7.11.5 of 2-SI-4.2.C-SFT,
Instrumentation that Initiates Rod Blocks/Rod Sequence
Control
.
System Restraint Functional Test.
The valve was left closed following
that portion of the testing.
Valve position restoration and verification
was provided for in steps 7.13, 7.14, and 7.23.
These steps were
initialled as being performed.
The inspector noted that in this. case the
individual that signed for IV had relied on the observed actions of an
individual located within the contamination zone that was actually
performing, the task, i.e., the individual did not enter the contamination
area and physically verify the actual valve position rather that
individual remained outside and observed the effort to operate the
valve.
Furthermore the individual responsible for perfor'ming the IV
had been an actual member of the crew performing the work rather
than a qualified individual not involved in the work activity. These
actions are in violation of SSP-12.6,
Independent Verification, steps
2.2 and 3.1.8.A.
This event should have been prevented by the
corrective actions associated
with previously identified problems with
performance of IV by licensee personnel
~ These separate
events are
documented
in NRC violations 260/90-14-05
and 260/91-24-02.
This is the second example of VIO 259,260,296/92-11-01,
Failure to
Perform Independent Verification.
Use of Incorrect Chart Paper
During observation of maintenance
activities associated
with control
room recorder, 2-RR-90-272CD, the inspector noted that the recorder
had the incorrect chart paper installed.
Usage of incorrect chart paper
in this recorder had been previously identified by the inspector as part
of violation 260/91-24-01
and had been due to use of an unverified
and incorrect operator aid.
The incor'rect chart paper contains a range
of MR/HR rather than R/HR as required.
Use of the incorrectly scaled
. paper could result in a non-conservative interpretation of containment
radiation levels during an accident. This previous violation is discussed
in greater detail in paragraph
10 of this report.
The'Division II
recorder, 2-RR-90-273CD, also contained the same incorrect paper.
These multipen recorders provide the high range containment radiation
level indication required by TS Table 3.2.l- and NUREG 0737.
The
inspector informed the onshift SOS of this condition and the chart
paper in both recorders was immediately replaced with the correct
chart paper.
During a subsequent
meeting with licensee management
the. inspector was informed that the use of the incorrect chart paper
~
7
~
had occurred due to storage by operations of the older incorrect chart
paper in the same locker location as the newer correct paper.
The
'controlled chart paper cross reference developed for the Unit 2 control
room was not used to verify the chart paper taken from the-locker
prior to use.
Although this item would normally be considered
a non-cited violation,
it does not meet the criteria since it is an example of failure by the
licensee to carry out corrective action for a previously identified
discrepancy. This constitutes VIO 260/92-11-03, Ineffective
Corrective Action on Control Room Radiation Monitors.
C.
Rosemount Transmitter Replacements
The inspector reviewed several ongoing work activities associated
with replacement of existing Rosemount Model 1153 transmitters
with refurbished transmitters.
This replacement effort was performed
to resolve problems identified by NRC Bulletin 90-01.
The inspector
, observed that adequate
controls were in place to insure that the work
activity did not interfere with operability of an'other safety rela'ted
system or component..
The work instructions contained sufficient
details to allow for satisfactory performance of the intended work
activity. Additionally the inspector noted that each work instruction
contained
a precaution that stated that each of the transmitters
should be replaced one at a time to prevent possible unplanned
actuation during the work. Specific work activities reviewed included
the following:
WO 91-27777-00 was issued to replace Drywell High Pressure
Transmitter, -2-PT-64-58B.
The inspector noted that LCO 2-92-96-
3.2.B was entered at 9:05 am on April 6, 1992, and that the LCO
was exited at 4:04 pm on the same date after performance of post
maintenance testing.-
WO 91-27778-00 was issued to replace Drywell High Pressure
Transmitter, 2-PT-64-58C.
The inspector reviewed the work package
and determined that it appears adequate for the planned work activity.
However, this work activity was delayed due to other work.
WO 91-29043-00 was issued to replace Drywell High Pressure
Transmitter, 2-PT-64-67.
The inspector noted that LCO 2-92-97-
3.2.F was entered at 1:15.am on April 7, 1992, and that the LCO
was exited at 6:20 am on the same date after performance of post
maintenance testing.
d.
HFA Relay Replacement
WO 92-51112-00 was issued to troubleshoot/repair
a problem with
Main Steam Line "C" Relief Valve Handswitch, 2-HS-1-30A; light
indication.
The problem'was found to be with relay 2-RLY-1-2E-K33
which was replaced.
The inspector observed portions of the ongoing
work activity including various controls in place during the ongoing
work. The inspector noted that ECI-O-OOO-RLY004, Replacement of
HFA Relay Components-and/or
Calibration of HFA Relays, was
referenced for use by the WO for specific instructions for removal and
replacement of the relay.
EMI-106, Troubleshooting and
Configuration Control of Electrical Equipment, was also used to
'-control wirelifts and reterminations.of all lifted leads.
No problems
were identified during the inspectors review of this work activity.
Two violations were identified in the Maintenance Observation area.
4.
Operational Safety Verification (71707)
The NRC inspectors'followed the overall plant status and any significant
-safety matters related to plant operations.
Daily discussions were held with
plant management
and various members of the plant operating staff.
The
inspectors'made
routine visits to the control rooms.
Inspection observations
included instrument readings; setpoints and recordings, status of, operating
systems, status and alignments of emergency standby systems, verification
of onsite and offsite power supplies, emergency power sources available for
automatic op'eration, the purpose of temporary tags on equipment controls
and switches; annun'ciator alarm status, adherence to'procedures,
adherence
to LCOs, nuclear instruments operability, temporary alterations in effect,
daily journals and logs,'stack monitor recorder traces, and control room
manning.
This inspection activity also included numerous informal
discussions with operators and supervisors.
General plant tours were conducted.
Portions of the turbine buildings, each
reactor building, and general plaht areas were visited.
Observations included
valve position and system alignment, snubber and hanger conditions,
containment isolation alignments, instrument readings, housekeeping,
power
supply and breaker alignments, radiation and contaminated
area controls, tag
controls on equipment, work activities in progress,
and radiological
protection controls.
Informal discussions
were held with selected plant
personnel in their functional areas during these tours.
0
a.
Plant Status
During this period the unit operated continuously at power. without
any significant'problems.
At the end of the report period the unit had
been on. line 47 days.
b.
Plant Tours
During a routine tour of the plant on April 7, 1992, the inspector
observed the following:
1.)
A local open indication light for RHR injection valve
2-HS-74-67B was not illuminated. This was discussed
with the
SOS and the valve indicated open in the control room.
A plant
operator was dispatched to check the light bulb.
2.)
A hold order tag 2-92-0333-2 had been placed on 480 volt
reactor building ventilation board 2B, Refueling Floor Supply Fan
2A, compartment 2B, on the inside of the cabinet with the-
cabinet door left open.
This was'discussed
with the SOS.
Normally, hold order tags are placed on the outside and the
cabinet doors closed for protection of an inadvertent water
intrusion into the breaker cabinet.
=
3.)
A health physics technician on the refuel floor had a red dot on
his plant access
badge.
About a year ago all red dots were
removed from the badges.
The red dot was to permit
emergency access into the TSC and control room without
logging entries into these areas.
The technician thought the red
dot was for vital area access
and was not clear of the purpose
of the red, dot.
He stated his badge had not been updated for
several years and no expiration date was visible on the badge.
This was discussed
with the Site Security Manager.
The
technician was a TVA employee and their plant badges have an
indefinite expiration period.
Security flagged the technician's
badge for update.
Plans to change all the site access
badges to
a new system within the next several months was discussed
by
Site Security.
E
4.)
Minor housekeeping
items were identified.
Dirt and dust was in
the 2A and 2C CS pump corner room.
A ladder, hose, spray
can of cleaner, poly bags, and a roll of tape under the torus..
8
Painting of valves in the overhead near the RCIC instrument,
rack resulted in paint dripping down on the instruments.
5.) 'he 'A'uel pool. cooling system was noted to be noisy. The
sound appeared to be caused by cavitation.
This was
discussed with the SOS.
6.)
On 480 volt RMOV BD 3A and 480 volt SD BD 3B several
circuit breakers had been removed for maintenance.
The circuit
breaker cabinet compartments
were labeled but the labeling
- was inconsistent.
On some, the label was a printed form and
on others a handwritten form.
Some breakers were. apparently
tagged as removed and taken to the shop but were installed.
Two breakers had been interchanged.
Although these were
labeled, the inspector questioned-if the controls were
acceptable.
A previous problem with breaker substitution was
identified in II-B-90-124. Two electrical boards failed to
automatically transfer because of incompatible breaker
substitution.
'.)
During tours of the Unit 3 plant area, many components were
tagged with six to eight hold order tags.
The inspector
questioned if a simpler system tag out might be acceptable
instead of trying to control numerous, hold orders for the same
item.
All of these items were discussed
with plant management
in a weekly
exit on April 9, 1992.
Unit 3 management
did not attend the weekly .
exit.
c.
The inspectors followed the licensee's activities associated
with the
March 5, 1992, event in which the Unit 1 Main Transformer "B"
Phase high side shorted to ground.
An explosion resulted which
severely damaged the transformer.
This transformer is normally used
through backfeed
as, a source of offsite electrical power for the unit
during an outage.
This failure was originally discussed
in IR 92-05.
~
To date licensee activities, in this area have been limited to
preparations for replacement of the damaged transformer.
A spare
transform'er located on site will be moved into place and will replace
the damaged transformer.
The inspector noted that licensee con'trois
of the activities in the switchyard have been very good.
An SRO has
been assigned to directly control all related ongoing work. Access
9
into the area was strictly controlled.
Personnel were briefed on recent-
industry switchyard events prior to performing any work. The
replacement transformer is not scheduled to be in, place until late in
May 1992.
The 1A and 1C Main Transformers,
.1A and 1B Unit
Station Service Transformers,
and Unit 1 Isophase
Bus were inspected
and electrically checked for damage.
No dama'ge was identified.
The inspector reviewed the final event report for Incident-
Investigation, II-B-92-019, which documented the licensee's
investigation associated
with this failure. The licensee report states
that the transformer failed due to'an electrical fault resulting in a
sudden high pressure transient (instantaneous
thermal expansion)
from the rapid heating of the transformer insulating oil. This resulted
in overpressurization of the transformer tank, destruction of two
bushings, and the activation of the sudden pressure relay.
Although
the investigation is complete the actual cause of the fault has not
been determined.
According to this report the cause of the failure is
to be determined by ASEA-Brown Boyeri after the failed transformer is
removed.
Although the report states that the immediate response to
the event by licensee personnel was good, several potentially adverse
findings were "identified. These findings include the following:
In addition to the Sudden Pressure
Relays which operates to
deenergize the transformer, the transformers are also equipped with a
Gas Operated Relay.
This relay is designed to alert operations of
overheating or a developing fault. This relay provides an annunciator
and can close a second set of contacts which would deenergize the
transformer if gas continued to accumulate.
This protective option
had been defeated through use of a selector switch on the relay.
This
function if used shares the same protective circuity that is used by the
sudden pressure relay.
The licensee's Technical Support Section was
assigned to determine why this function was disabled and whether to
operate in this manner.
At 11:54 a.'m. on the day before the event, the "Transformer Gas
Press High or Low" annunciation was received in the Unit 1 Control
Room.
This single annunciator can originate from either the Gas
Operated Relay or a separate transformer relief device. Additionally it
can alarm based on conditions in several different transformers,
making it difficultto determine the source of the alarm. At 8:30 p.m.
on that date maintenance
personnel verified that the alarm was
originating in the 1B Main Transformer, but did not verify the validity.
by use of test equipment.
Had this determination been made and the
alarm found to be valid, the control room would have been alerted
0,
.10
that the transformer was already in the process of failing. The report
was critical of troubleshooting performed by licensee personnel in this
area.
Potential problems identified included delays in troubleshooting
which resulted from inadequate
planning, delays in determining alarm
validity, and limited results from the troubleshooting that was
performed.
The licensee committed to revise existing procedures to
increase the priority on work orders of this nature and to evaluate the
need to develop a standard text for annunciation validation.
A deficiency was noted in the operations training program in that
confusion existed over the source of the alarm.
Operations has
committed to train personnel on the event and conduct refresher
training on transformer" protective devicesalarm responses,
and an
overview of diagnostic tools available in this area.
The Alarm
Response
Procedure for this alarm was inadequate.
Operations
'committed to revise the ARP.,
The existing annunciator design associated
with the transformer,
switchyard and cooling towers is susceptible to grounds resulting in a
system that experiences
numerous false alarms.
Troubleshooting.
problems with this system is complicated by presence, of numerous
parallel contacts in the alarm circuity. This has res'ulted in a lack of
credibility and reduced sensitivity to those annunciators.
The transformer relief semaphores
are not painted a uniform color and
the 1B 'semaphore
was difficultto see, since it blended in with the
transformer paint.
The licensee committed to paint all semaphores
a
high visibilityyellow.
The inspector noted that the licerisee's final event report appeared to be
thorough and provided a good self assessment
of various conditions which
could have possibly contributed to the transformer failure. The inspectors
will continue to follow the licensee's
r'epairs to the 1B Main Transformer and
corrective actions associated
with the various findings identified in the
report.
Unit 1 Activities
j
The inspector reviewed and observed the licensee's activities involved with
the Unit 1 reactor-vessel.
This included reviews of procedures and records;
observations of field work, QA/QC, operations and contractor personnel
activities; and discussions with licensee and contractor
supervisors,
engineers,
and skilled craft personnel.
The reactor vessel disassembly
continued with the removal of shield plugs, drywell head, drywell ventilation
package, reactor vessel head, steam dryer, and steam separator.
The
contractor personnel detected
an unexpected amourit of rust on the drywell
flange face and water with sludge in the inner bellows.
All items were taken
care of and the work activities proceeded.
The inspector concluded from
these reviews and observations that all activities were adequately controlled.
6.
Unit 3 Restart Activities (30702)
The inspector reviewed and observed the licensee's activities involved with
the Unit 3 restart.
This included reviews of procedures, post-job activities,
and completed field work; observation of pre-job field work, in-progress field
work, and QA/QC activities; attendance
at restart craft level, progress
meetings, restart program meetings, and management
meetings; and
periodic discussions with both TVA and contractor personnel, skilled
craftsmen, supervisors, managers
and executives.
a.
Pilot/Prototypical Program
The inspector observed and reviewed the activities involved with the
Unit 3 Pilot/Prototypical program.
The specific areas reviewed
involved, the condenser upgrade, the first DCN issued to the field
DCN W17045, Unit 1 panel 3-9-2), the first CRDR design change; the
drawing, enhancement
program, and the integrated DCN, which was
tentatively identified an electrical cable DCN.
The inspector observed the ongoing activities involved with the
condenser upgrade and reviewed the drawing enhancement
program.
The licensee determined that prior to Unit 3 restart, deficiencies with
the accuracy arid legibility of the Unit 3 As-Constructed and
Configuration Control Drawings had to be corrected.
Drawing
restoration, drawing update, drawing enhancement,
and drawing
utilization are to be performed as coordinated effort. The program
was started by the licensee on January 6, 1992, and had an expected
duration of 18 months.
The program was staffed with a proper mix
of technically qualified individuals to ensure
a quality product.
The licensee performed a review during the Unit 3 Discovery Phase to
determine the scope of the Drawing Enhancement
Program.
This
review examined the requirements necessary to satisfy Unit 3 drawing
concerns as well as satisfy drawing enhancement
needs.
An
examination of the Unit 2 Drawing Enhancement
Program was
performed to determine the scope for Unit 2. The initial Unit 2 effort
identified 1600 drawings to be enhanced.
The 400 drawing
difference betwe'en Unit 2 and Unit 3 was due to the need for
common as well as a number of Unit 1 and Unit 3 drawings being-
required for support of Unit 2 operation.
The following represents the total drawing quantities associated
with
Unit 3, and the scope to be considered on the Unit 3 Drawing
Enhancement
Program:
o
750 Primary and Critical Drawings
o
450 High Use Secondary Drawings
, o
1200 Total Drawings to be Enhanced
In the program'the licensee plans to reproduce drawings in the CADD
format with the most up-to-date information obtainable from the
Document Control/Change Management System.
The drawings will
be updated and put in a Shadow file, so that as needs rise the
drawing. will be available.
The, shadow file for each of the 1200
drawings will be continually updated as the various inputs become
available from=walkdowns, completed designs,
PDDs, and scrubs.
The shadow file at any one time will provide the best latest
information on the drawings.
When all programs and the affected
system are in the SPOC/SPAE process, the drawing will be officially
issued for use by plant operations, maintenance,
technical support,
and design.
The inspector reviewed a technical assessment,
No. EE-0040, dated
March 23, 1992, performed by TVA Unit 3, Design Control involved
with drawing improvement.
The inspector noted that four
prototypical drawings were reviewed (3-47E3847-1, 3-47E610-32-1,
3-45E-614-9, and 45N620-7), and all outstanding change paper was
adequately identified.
The inspector observed the activities of the Bechtel drawing
improvement group and noted no deficiencies.
The use of the
shadow file and the issuance of the CCD when the various systems
are returned to service will continually prove the acceptability of the
Drawing Enhancement
Program.
Design Activities
The inspector reviewed the design activities associated
with the
pilot/prototypical program involving the return to service of cooling
13
towers 1, 5, and 6.
A total of four DCNs were reviewed.
DCN
W17581A, affected flow element FE-27-147 and flow monitor
FM-27-147, which were not wired per vendor recommendation; flow
indicator, FI-27-147, on 'panel 25-258'located
in the radwaste
building, range indication changed, from 20,000 - 200,000 GPM to 0-
200,000 GPM; and flow switch FS-47-147 set point changed from
50,000 GPM decreasing to 60,000 GPM decreasing.
This
modification, impacting TS 3/4.8.A would insure proper radwaste
dilution during both the closed loop and helper mode of operation for
the cooling towers.
The additional DCNs reviewed were DCN W17703A, which impacted
the emergency bearing lube water supply pumps no. 1, 2, and 12
flow control valves 0-FCV-25-49A-1 through 6 and 0-FCV-25-49B-1;
DCN W17748A, which impacted pipe support under the 79-02/14
program for the Unit 3 vacuum breakers on the discharge conduits to
the hot water channel; and DCN W-17771A, which impacted control
panel 0-9-56, Cooling Tower Control Panel and affected five areas.
The areas affected by DCN W-1771A were:
disable towers 2, 3, and
4 input to common alarms to prevent masking inputs from tower 1, 5,
'nd 6; disable automatic mode from swanson control, on panel
0-9-56, to prevent inadvertent equipment operation; disable cooling
tower fan control capability for cooling towers 1, 5, and 6 from the
swanson controls, this leaving only manual forward operation of
cooling tower 1, 5 and fans at the local stations and the 480 volt unit
substation motor control centers;.disable
the pump bearing lube water
valve lights on panel 0-9-56; and disable the cooling tower 4160 volt
switchgear A, B, C, D and bus tie breaker control functions and
indications from panel 0-9-56.
Construction Activities
The licensee completed the first modification of the CRDR program on
Unit 3 panel 3-9-10.
Additional construction activities involved the
condenser upgrade project, initial drywell steel work plan writing,
cooling tower refurbishment, drywell blowers, offsite fabrication
facility, and initial drywell chiller modification schedule reviews.
Maintenance Activities
The inspector reviewed the licensee's circuit breaker overhaul
program.
This processes
were setup using the Unit 2 program plus
lessons learned.
The 4KV and 480 volt breaker rebuild project initially
shipped 28 breakers off site to GE for rebuild.
One return shipment
14
was received and an. additional shipment was sent off. The inspector
expressed
a concern about properly identifying the status of the
, breakers as they are shipped and what type breakers were being used
as substitutes,
see paragraph 4.b.
This item is identified as an
inspector followup item IFI 259, 260, 296/92-11-04,
Proper Tracking
of Circuit Breakers During Refurbishment
The licensee started
a walkdown of both 4 KV. and 480 volt electrical
switchgear.
This walkdown was conducted to ensure the tagging of
the breakers was consistent, verify.the breaker name plate data,
ensure that they are consistent with Unit 2, and proper use of PDDs
~
to correct any breaker, switchgear and drawing miss-matches.
The
inspector accompanied
licensee representatives
in the field and
observed work activities.
Pre-Operational/Return
to Service Activities
The licensee indicated the operability of Unit 3 systems
is dependent
on the controls established
over construction type testing, pre-
operational type testing, and system line-up statusing.
These controls
will ensure that the systems are capable of performing their design
.
functions.
This will be accomplished by the Unit 3 SPOC/SPAE
process.
A change from the Unit 2 SPOC/SPAE had been made and is
documented
in site procedure SSP 12.55, Unit 3 System
Pre-'perability
Checklist.
Cooling towers 1, 5, and 6 were scheduled to be returned-to-service
and a prototypical plan be implemented to validate its adequacy.
Return-of the cooling towers will allow Unit 2 to go into the helper or
closed mode of operation during periods of elevated river
temperatures.
Systems impacted by cooling -tower return-to-work were:
0
27
o
27C
o
25
0,
77
o
205
0
232
o
246
o
24
Condenser Cooling Water
Cooling Towers 1,5, and 6
Raw Service Water
Rad waste
4KV Cooling Tower Electrical Switch
Gear'80V
Cooling Tower Electrical Boards
Cooling Tower Transformers
Raw Cooling Water System, (Auxiliary RCW
Pumps)'he
inspector noted that the SPOC of cooling towers would not be
15
typical of the SPOC process.
Typically, all supporting systems
received their SPOC before the main system.
This cannot be done for
the cooling towers.
Consequently, the cooling towers along with
portions of the, supporting systems will be included in this SPOC.
Because this is not a typical SPOC, technical support developed
detailed boundary drawings to assist in identifying SPOC scope.
The SPOC process provides the licensee with a systematic method for
evaluation items and issues which potentially affect the ability of
systems to perform as designed, determining their status, and
. ensuring completion of those items which impact system return-to-
service for restart.
The SPOC, process differs from that used for Unit
2 in that it will be accomplished
in two phases.
Phase
I SPOC
addressed
the system testing milestone and established system status
control by operations.
Completion of the Phase
I SPOC process
constitutes
a technical support recommendation that the system is
ready for pre-operational testing and that the affects of system testing
upon the operating unit have been considered and addressed.
Phase
II
SPOC completion constitutes
a technical support recommendation for
system operability in support of Unit 3 restart.
System operability will
be declared by operations at the appropriate point after necessary
surveillance instructions have been performed, pre-operational
deficiencies have been adequately addressed,
and all support systems
are available.
The inspectors will continue to observe and review the return-to-
service process for the cooling tower.
Additional Activities
The inspector observed and monitored the Unit 3 integrated
scheduling meetings.
These meetings consisted of a weekly meeting-
at the Athens, Alabama, Bechtel office and a planned weekly meeting
at the onsite SWEC constructors facility. The Bechtel meeting
discussed, progress, problems, and a look ahead for the work of
producing design documents.
The SWEC meeting was planned to
discuss progress, problems, and looked ahead for the work of
implementing the design changes specified by the design documents.
The. Athens meeting was attended by supervisors, project managers,
and executives.
The inspector concluded that, except for the circuit breaker rebuild area, the
licensees Unit 3 restart activities observed and reviewed appeared to be in
accordance
with approved procedures,
group coordination appeared to be
-16
effective, and technical issues appeared to be in the process of resolution.
Fire Protection/Prevention
Program (64704)
The purpose of this inspection is to evaluate the overall adequacy of the
.
licensee's fire protection/prevention program and to determine that the
'icensee
was implementing the program in conformance with regulatory
requirements, technical specifications, and industry guides and standards.
P
a.
Program Review
The inspector reviewed the unit technical specifications, and the
- administrative procedures which constitute the approved fire
protection program.
The procedures reviewed were:
SSP,-12.15,
"Fire Protection," Revision 1, dated March 2, 1992
FPP-1, "Fire Protection Plant," Revision 6, dated March 2,, 1992
FPP-2, "Fire Protection-Attachments,"
Revision 7, dated March
2, 1992
FPP-3, "Fire Emergency Response
Organization and Pre-Fire
Plans," Revision 3, dated March 2, 1992.
This review verified that the licensee had technically adequate
procedures to implement the fire protection program.
Procedural
guidance was provided to control combustible material and reduce fire
hazards.
Administrative procedures also provided for maintenance
and surv'eillance of fire barriers, fire barrier penetrations, fire
suppression,
fire detection, and other support equipment.
Personnel
training, qualifications, and responsibilities were provided.
Maintenance evolutions that significantly increase fire risk were
properly controlled.
b.
Implementation
A tour of accessible
areas of the plant was conducted by the
inspector, accompanied
by licensee representatives,
to assess
general
area conditions, work activities in progress, and the'visual conditions
of fire protection systems and equipment.
Combustible materials and
flammable and combustible liquid and gas usage were restricted or
'properly controlled in areas containing safety-related equipmerit and
components.
Items checked included the position of selected
suppression
system valves; fire, barrier conditions, hose stations, and
fire extinguisher'for type, location, accessibility, and condition.
There was some light construction in process in the toured areas.
There were no welding, cutting, or use of open flame ignition sources
found in the areas toured.
Some maintenance work and surveillance
testing was noted.
Accessibility'to suppression system controls, hose
stations, and fire extinguisher was being maintained.
General
housekeeping
conditions were found to be very good.
The inspector reviewed the following completed surveillance
inspections:
O-SI-4.11.B.2.a,
"Diesel Driven Fire Pump Operability Test,"
Revision 9, April 13, 1991, performed March 18, 1992
O-SI-4.11.G.2.b, "Daily Fire Door Inspection,'" Revision 4,
May 16, 1991, performed March 19, 1992
O-SI-4.11.B.1.a, "Electric Fire Pump Op'erability Test,"
Revision 5, January 17, 1992, performed March 18, 1992
O-SI-4.11.B.3.a, "Weekly Check for Diesel Fire Pump Batteries
1 and 2," Revision 6, November 25, 1991, performed March
18, 1992
O.-SI-4.11.B.1.e,
"High Pressure
Fire Protection System Valve
Cycling," Revision 4, April 9, 1991, performed December 9,
1991
O-SI-4.11.B.4, "Raw Service Water Logic System Functional,"
Revision 1, April 8, 1991, performed September
13, 1991
O-SI-4.11.E.1.b, "Inspection and Reracking of Fire Hose
Stations," Revision 2, June 8, 1990, performed October 22,
1991
O-SI-4.11.B.1.g, "High Pressure
Fire Protection System'Flow
Test," Revision 1, June 6, 1989, performed June 7, 1989
O-SI-4.11.B.1.e,
"High Pressure
Fire Protection System Valve
Cycling," Revision 4, April 9, 1991, performed December 9,
1991
2-SI-4.11.A.1, "Semiannual Smoke Detector Functional Test,"
Revision 8, October 30, 1991, performed November 11, 1991
18
O-SI-4.11.G.1.a(1),
"Visual Inspection of Fire Wraps," Revision
0, January 7, 1991, performed January 14, 1991
O-SI-4.11.G.1.a,
"Visual Inspection of Fire'Rated Barriers,"
Revision 3, November 30, 1990, performed January 3, 1991
O-SI-4.11.G.2, "Semi-Annual Fire Door Inspection," Revision 6,
May 24, '1991, performed October 28, 1991
Fire protection systems and equipment installed for protection of
'afety-related areas were found to be functional and tested in
accordance with requirements specified in the TS.
The inspector reviewed fire brigade training and drill records.
The
records were in order and "confirmed that training and drills were being
conducted at the specified intervals.
Fire brigade equipment, including
emergency breathing'apparatus,
was found to be stored and
maintained properly.
.The licensee's fire watch training and administrative controls were
reviewed by the inspector.
The training was found to be
comprehensive
and conducted in accordance
with the licensee's
approved schedule.
Administrative controls for fire watch
assignment,
and tracking were found to be acceptable.
The licensee's
revised definition of "Roving" and "Continuous" fire watch duties.has
effectively clarified technical specification requirements and clearly;
established that the term "Continuous" does allow movement, but
within a well defined area.
There were no problems identified in this
area.
The inspector reviewed the licensee's last quality assurance
audit,
BFA91104 of April 25, 1991, in the fire protection area and
characterized
as the annual and biennial audit.
The scope of this audit
included an inspection of plant areas, evaluation of fire brigade and
operations personnel performance during an unannounced fire drill,
review of fire brigade training and a programmatic review of program
procedures.
Discrepancies identified were formally presented to the
affected organizations.
Responses
were tracked to close out, and
actions taken were reviewed for adequacy.
e,
19
BFNPP Post-Restart
Commitment Status
The inspector reviewed'the post restart status of the BFNPP open items for
. Unit 2.
Prior to restart, the status of BFNPP items was summarized
in a
letter from TVA to the NRC dated April 16, 1991, "Browns Ferry Nuclear
Plant - Completion Status of Corrective Actions identified for Unit 2,restart
in Browns Ferry Nuclear performance Plan." This letter indicated some
BFNPP items would not be completed prior to restart and an implementation
schedule for those items would be provided 120 days after restart.
A letter
dated September 20, 1991, and a supplemental letter dated December 24,
1991, provided the implementation schedule and a status for these items.
At the time of this inspection there were 30 open items remaining open as
- post restart commitments.
Fifteen are currently scheduled to be completed
prior to restarting from the Unit 2 Cycle 6 outage.
In addition, six are on
hold pending NRC issuance of SERs on these topics.
Another item is
- complete and the package
is being reviewed for closure, two have schedule
dates in 1992, five have 1993 dates, and one item is scheduled for
completion prior to restart for the Unit 2 Cycle 7 outage.
For those items scheduled for completion in 1992 or in the Unit 2 Cycle 6
outage, the inspector verified planning was in place for their implementation.
Where activities are committed for completion by outage end, but are not
constrained by operational concerns, much of the work is scheduled for
completion prior to the outage.
The PRA scheduled for a September
1,
1992 completion, has work ongoing.
The level
1 portion of the PRA will be
complete, but the containment analysis has the bulk of its work yet to be
performed and the inspector could not verify it would meet'its scheduled
commitment. dat'e.
Four of the items awaiting SERs are issues concerning USI A-46. The SER
is in final draft and is expected to be issued soon.
However, implementation
of the SER may not be complete for three or four years, as permitted by the
SER.
Therefore those issues dealing with long term seismic qualifications
will probably stay open for- several years.
The inspector found that all the items sampled had ongoing management
attention and were included as part of the normal planning/scheduling
process.
0
~
20
Reportable Occurrences
(92700)
The LERs listed below were reviewed to determine if the
information'rovided
met NRC requirements.
The determinations included the
verification of compliance with. TS and regulatory requirements,
and
addressed
the adequacy of the event description, the corrective actions
taken, the existence of potential generic problems, compliance with
reporting requirements,
and the relative safety significance of each
event.'dditional
in-plant reviews and discussions with plant personnel,
as
appropriate, were conducted.
a.
(CLOSED) LER 260/91-10, Technical Specification Violation When 24
Hour Limiting Condition for Operation Expired Without Declaring
Affected Systems
0
0
This LER reported to the NRC an event that occurred on May 14,
1991, where licensee personnel failed to declare systems inoperable
that were affected by a reactor vessel water level transmitter.
This
failure occurred when RPV water level transmitter, 2-LT-3-58D, could
not be calibrated during performance of a routine surveillance, 2-Sl-
4.2.B-1(D) and the incorrect LCO entry time was recorded by
operations personnel in the Unit 2 LCO Log.
The licensee investigated the circumstances
associated 'with this
failure which are documented
in final event report, II-B-91-111. The
inspector reviewed the licensee's investigation and determined that
the failure occurred due to miscommunication between personnel in
the licensee's operations and maintenance
groups.
The instrument
ha'd been originally valved'out of service at 2:38 pm on May 14,
1991. At 5:20 pm on the same day instrumentation personnel
determined that repairs were required before calibration could be
'erformed.
Operations was inform'ed of the problem at 6:20 pm and
'he
LCO was entered at 6:28 pm. At 3:50 pm the following day the
Unit 2 RHR, CS and DG.were declared inoperable.
Due to the
discrepancy that existed between the times that the instrument was
actually taken out of service, the actions required by TS 4.2.B to be
performed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> were not taken.
The level transmitter'as
replaced and the calibration completed later that day.
The affected.
unit was in cold shutdown for the entire period of the event.
The
licensee attributed the failure to miscommunication caused by an
inadequate
procedure that did not require notification-to operations'of
the specific time that the required equipment is removed from service.
21
The inspector reviewed documentation provided by the licensee to
verify that the affected procedure was revised to include a
requirement to inform licensee personnel of the specific time that
required equipment is removed from service.
Additionally the licensee
reviewed 208 other Sis for which the electrical and instrumentation
sections have responsibility to determine the need for a similar
requirement.
The inspector also verified by review of training
attendance
records that the event was reviewed with site
maintenance
personnel.
The inspector determined that based on the
above completed corrective actions that recurrence of this problem
should not occur.
(CLOSED) LER 260/91-15,
High Pressure
Coolant Injection System
Did Not Fulfill Its Safety Function Resulting From Low Suction
Pressure
Condition During a Fast Start-up.
During HPCI System performance testing on July 31, 1991,
conducted as part of the Unit 2 power ascension
program the HPCI
turbine tripped from a low suction pressure transient.
Although the
HPCI trip signal automatically reset after 10 seconds
and the HPCI
syste'm successfully was restarted, the licensee declared the system
inoperable and determined the event to be reportable. under 10 CFR 50.73 as a coridition that could have prevented the HPCI System from
. fulfillingits intended safety function. The system failed to meet the
FSAR requirement to attain rated flow within 30 secon'ds.
The licensee determined that the event was due to a problem not
anticipated in design.
Based on information provided by the vendor,
TVA learned that the system was susceptible to momentary suction
pressure transients capable of tripping the HPCI turbine, and that
installation of'a time delay in the low pressure trip circuitry was one
possible option to correct the problem.
As immediate corrective
actions the licensee declared the system inoperable and installed a
temporary time delay relay in the low pressure trip circuitry. This
temporary relay was tracked under a TACF and the HPCI system
performance test was satisfactorily completed on August 1, 1991
~
Th'e inspector, reviewed documentation provided by the licensee to
verify that a permanent
5 second time delay relay was installed in the
Unit 2 HPCI circuitry under DCN W17015A.
Additionally, the
inspector noted that TACF 2-91-3-73, which was used to track the
temporary relay, was removed and closed.
The licensee has
committed to install similar relays in Units
1 and 3 prior to restart of
those units.
No similar events
of, this nature have occurred since the
22
licensee made this modification to the system.
(CLOSED) LER 260/91-19, Automatic Reactor Scram Following a
Turbine Trip Which was a Result of an Unexpected
Fuse Failure.
An unplanned automatic reactor scram occurred at 11:20 pm on
December 8, 1991, on Unit 2 from 80% power in conjunction with a
turbine trip and'unexpected
loss of one of the offsite power supplies.
This trip occurred when a Gould-Shawmut fuse failed. This fuse was
associated
with the 500KV Bus
1 Section
1 potential transformer
output and re'suited in a loss of restraint potential to the generator
backup impedance relay causing the relay to actuate.. Actuation of
this relay caused the Unit 2 main generator breaker and associated
supply breakers to trip. The relay also initiated an exciter field breaker
trip and subsequent
turbine trip. The various electrical boards
automatically transferred to their alternate power supplies and all
safety systems functioned as expected during the event.
The licensee
replaced the failed fuse and all existing 500KV Bus Potential
Transformer secondary fuses to minimize the possibility of spurious
relay operations due to any potential generic fuse failures.
As the
result of this event, TVA committed to evaluate the existing design at
Browns Ferry to determine if reconfiguring that design to eliminate the
possibility that a loss of the relaying potential from a single bus should
be accomplished.
Additionally, the licensee committed to further
investigate the spurious tripping of the Trinity 1 line during the event
and correcting any deficiencies.
The inspector reviewed documentation provided by the licensee to
verify that adequate corrective actions were carried out.
The licensee
decided to add a second generator backup relay for each unit that
senses
potential from the bus PTs opposite to those supplying the
existing relay for each respective unit, 'and logic requiring two-out-of-
'wo logic for operation of the respective relays.
This modification
was accomplished for Unit 2 under DCN W17480 during a recent
outage.
This modification is to be accomplished under DCN W17479
(Unit 1) and DCN W17481 (Unit 3) prior to restart of those units.
The
inspector noted that the licensee determined during the subsequent
investigation that the relaying logic associated
with the Trinity 1 line
operated properly and no further corrective actions were needed.
Based on the above review the inspector determined that the licensee
had taken adequate
corrective actions to preclude recurrence'of
a
'imilar
event.
0
e
~
~
~
23.
d.
(CLOSED) LER 296/92-01,
Engineered Safety Feature Actuation
Caused by a Failed Relay Coil.
An unplanned
ESF actuation occurred at 7:20 am on January 25,
1992, on the Unit 3 PCIS when a relay coil, GE type CR-120, failed.
This relay was associated
with the primary containment atmosphere
control valve logic charm'el A and resulted in an isolation of,the Unit 3
reactor building and refueling floor ventilation systems,
and actuation
of the B and C SBGT trains and B CREV train.
The licensee replaced
the failed relay coil and reset the associated
ESF actuation within
seven hours.
The licensee determined during a subsequent
evaluation that the relay
'oil
failure was a random failure due to end of life caused by thermal
aging of the rel'ay coil. This and other relay coils are now approaching
an average life of 15 years. Industry data indicates that the expected
service life of these type relays in the normally energized applications
is approximately 15-20 years. Based on this and other recent events
associated
with relay coil failures the licensee has planned the
following corrective actions:
The licensee has evaluated the affected relays for Unit 2 and
determined that 12 relays have a high potential for resulting in a
plant shutdown.
Replacement of these relays is planned for the
spring of 1992.
GE CR-120 relay coils used in the normally energized safety
related application are to be replaced in Unit 2 prio'r to startup
from the Cycle 6 refueling outage.,
GE CR-120 relay coils used in the normally energized safety
related application are to be replaced in Units
1 and 3 prior to
restart of each respective unit.
The inspector determined that the licensee has taken or'lanned
adequate corrective actions to justify closure of this
LER.'0.
Action on Previous Inspection Findings (92701, 92702)
a.
(CLOSED) IFI 259, 260, 296/90-03-01,
Review of Facility Operating
Licenses,
DPR-33 and DRP-52, for Appendix R versusSection X
requirements.
1,
24
During a review of NOV 88-20-01, example d, it was noted the BFNP
Unit 2 Facility Operating License, DPR-52, stated in section 2.c.(5),
"The facility may be modified as described in Section X of "Plan for
Evaluation, Repair, and Return to Service of Browns Ferry
1 and 2
(March 22, 1975 Fire)" dated April 13, 1975, and revisions thereto."
This review indicated that Section X of this plan may be in variance
with 10 CFR 50, Appendix R requirements thus requiring a licensee
review of Facility Operating Licenses, DPR-33 and DPR-52 for
Appendix R versusSection X requirements.
On April 4, 1988, per GL 86-10, the licensee submitted the Browns
Ferry Fire Protection Report to, the NRC for review and approval and
on April 14, 1989, submitted a license amendment application to add
License Condition 2.C.5(a) and administrative controls necessary to
implement the Units
1 and 2 Appendix R Safe Shutdown Program.
NUREG-1232, "Safety Evaluation Report on Tennessee
Valley
Authority: Browns Ferry Nuclear Performance Plant" (SER),
Volume 3, Supp. 2, was issued on January 23, 1991.
Section 3.1,
Fire Protection, stated that on the basis of previous staff SERs and
inspections, the NRC staff concluded that BFN Unit 2 complies with
Appendix R to 10 CFR part 50, and further stated that the staff must.
still approve before restart the license amendment application of April
14, 1989 (as discussed
in the previous paragraph).
This request was
subsequently
approved by the NRC on March 6, 1991
~
Subsequent to a NRC request for additional information regarding the.
Browns Ferry Fire Protection Report, the licensee found that much of
the information found in this report was out of date.
The report was-
subsequently withdrawn by the licensee on September
19, 1991 and
was updated and reissued for NRC review on January 15, 1992.
A
licensee amendment application to meet GL 86-10 requirements was
forthcoming from the licensee at the end of this inspection period.
Based on the above information this item is considered closed.
(OPEN) VIO 260/91-24-01,
Failure to Correct Containment Radiation
Monitor Problems.
During the Unit 2 restart on May 24, 1991, NRC personnel identified
several problems with control room instrumentation used to monitor
primary containment radiation levels.
The staff determined that these
problems constituted
a violation for failure to promptly identify and
correct'conditions a'dverse to quality. These problems were first
identified by NRC personnel rather than licensee control room
personnel,
in spite of the fact that the condition was readily apparent
on.the associated
recorder and control room personnel had just
responded to the recorder based on an control room annunciator.
The
problems involved drawihg/wiring errors, recorder range labeling
.
problems, and use of incorrect chart paper in control. room recorders
required by TS.
A previous field design change had been issued to
correct at least a portion of the problem but the FDCN had been
canceled without the knowledge of the system engineer.
The inspector reviewed the licensee's
response to the violation dated
September
5, 1991.
In that response the licensee attributed the
incorrectly canceled
FDCN to failure to follow the existing project
instruction covering design change control. Additionally the licensee
"
attributed the use of incorrect chart paper to personnel error when an
uncontrolled chart paper list was not revised to reflect the vendor
serial number of purchased chart paper.
Nuclear Enginee
recorders in the
main control roo
recorders were
I
paper. However
activities in the
incorrect paper
that work activi
inspector determ
been adequate t
pending further
11.
Management Changes
The inspector was informed that personnel involved were counseled
on the event and that licensee had committed, to revise existing
procedures to strengthen controls for drawing deviations.
The
.
inspector noted that SSP-2.11,
Drawing Deviation Program, was
revised to place overall focal point for dispositioning drawing
discrepancies
and Project Instruction, PI-89-06, Design Change
Control, was revised;to. require that the originator be informed
whenever a FDCN is disapproved.
The inspector reviewed completed
S-DCNs No. S17319A and,S1731.9B
which were issued to allow
ring to develop a controlled chart paper list for all
Unit 2 control room.
During subsequent tours of the
m, the inspector observed that the control room
abeled correctly and contained the correct chart
, on April 8, 1992, during observation of maintenance
Unit 2 main control room, the inspector observed the
was again in use in both recorders.
Observ'ation of
ty is discussed
in more detail in paragraph 3.b.
The
ined that the licensee's. corrective actions had not
o preclude recurrence.
This item is will remain open
"
review of licensee corrective actions in this area.
0
Two.management
changes became effective April 1, 1992.
Chris Crane
was named as the Browns Ferry Maintenance Manager.
Mr. Crane was
previously the Maintenance Program Manager.
26
Allen Sorrel was named as the Browns Ferry Program Manager.
Mr. Sorrel
was previously the Maintenance Manager.
He will assist the Plant Manager
and will take a leading role in the Unit 2 Cycle 6 refueling outage.
12.
Exit Interview (30703)
The inspection scope and findings were summarized on April 20, 1992, with
those persons indicated in paragraph
1 above.
The inspectors described the
areas inspected and discussed
in detail the inspection findings listed below.
The licensee did not identify as proprietary any of the material provided to or
reviewed by the inspectors during this inspection.
The Plant Manager stated that he did not see
a violation concerning the
diesel driven fire pump Sl because the Sl was performed and IV performed
with separation of distance and time.
The inspector stated to have uniformity of Sl performance and to ensure IV
steps are perforJned when expected the procedures should be performed
step by step unless specifically stated otherwise.
Item Number
Descri tion and Reference
259,260,296/92-1 1-01
Violation, Failure To Perform Independent
Verification, paragraph two and three.
259,260,296/92-1 1-02
Unresolved Item, Missing Independent
Verification Steps, paragraph two.
260/92-1 1-03
Violation, Ineffective Corrective Action On
Control Room Radiation Monitors, paragraph
three;
259, 260, 296/92-11-04
Inspector Followup Item, Proper Tracking
Circuit Breakers During Refurbishment,
paragraph six.
Licensee management
was informed that 4 LERs and
1 IFI were closed.
13.
Acronyms and Initialisms
0
AUOBD
BFNP
Auxiliary Unit Operators Board
Browns Ferry Nuclear Power Plant
'
0
27
BFNPP
CCD
CFR
CRDR
DCN
FDCN
GL
GPM
IFI
II
KV
LCO
LER
NRC
PDD
PT
RCW
.
RMOV
Sl
SOS
SPAE
Browns Ferry Nuclear Performance
Plan
Computer Aided Drafting
Co'nfiguration Control Drawing
.
Code of Federal Regulations
Control Room Design Review
Control Room Emergency Ventilation System
Design Change Notice
Electrical Maintenance Instruction
Engineered Safety Feature
Flow Control Valve
Field Design Change Notice
Fire Protection Procedure
Final Safety Analysis Report
Generic Letter
Gallons Per Minute
High Pressure
Coolant Injection
Inspector Followup Item
Incident Investigation
Kilovolt
Limiting Condition for 'Operation
Licensee Event Report
Maintenance Request
Nuclear Regulatory=Commission
Nuclear Reactor Regulatio'n
Primary Containment Isolation System
Potential Drawing Disc'repancy
Pressure Transmitter
Potential Transformer
Quality Assurance
Quality Control
Reactor Core Isolation Cooling
Raw Cooling Water
Reactor Motor Operated Valve
Reactor Pressure
Vessel
Rod Sequence
Control System
Shutdown
Safety Evaluation Report
Surveillance Instruction
Shift Operations Supervisor
"System Plant Acceptance Evaluation
t y ('s
1
'c
'e
0
28
TACF
TS
WP
System Pre-Operation Checklist
Site Standard Practice
Stone
&. Webster Engineering Corporation
Temporary Alteration Change Form.
Technical Specifications
Tech Support Center
Valley Authority
Unresolved Safety Issue
Violation
Work Order
-Work Plan
, Work Request
0
0