ML18038B815
| ML18038B815 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 01/27/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B813 | List: |
| References | |
| 50-259-96-13, 50-260-96-13, 50-296-96-13, NUDOCS 9702100334 | |
| Download: ML18038B815 (44) | |
See also: IR 05000259/1996013
Text
-
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License
Nos:
50-259,
50-260,
50-296
DPR-33',
DRP-52,
Report
No:
50-259/96-13,
50-260/96-13,
50-296/96-13
Licensee:
Valley Authority (TVA)
Facility:
Browns Ferry Nuclear Plant, Units 1, 2,
and 3
Location:
Corner of Shaw and Browns Ferry Roads
Athens,
35611
Dates:
November 24,
1996
- January 4,
1997
Inspectors:
Approved, by:
H. Morgan, Acting Senior
Resident
Inspector
.J. Starefos,
Resident
Inspector
G. Walton, Reactor Engineer
(Paragraph
E8.2)
H. 'Lesser,:Chief
- Reactor Projects
Branch '6
'.Division of 'Reactor 'Projects
Enclosure
2
9702i00334 970127
ADOCK 05000259
8
'PDR
41
Cb
EXECUTIVE SUMMARY
Browns Ferry Nuclear Plant, Units 1,
2
8 3
NRC Inspection Report 50-259/96-13,
50-260/96-13,
50-296/96-13
This integrated inspection included aspects of licensee operations,
engineering,
maintenance,
and plant support.
The report covers
a six-week
period of resident inspection
and includes efforts of a regional
reactor
engineer.
0 erations
On December
17.
1996. the 2A Battery Charger
was aligned to restore g2
Hain Battery Bank voltage levels.
The charger would not build-up to
adequate
levels
and was taken out of service.
However,
when the 2B
charger
was used it gave fluctuating amps.
The licensee properly
addressed
and repaired both char gers.
(Section 02.1).
~
On December
17,
1996, the Unit 3 Division II ECCS Inverter power
was
lost due to a fuse failure.
Repairs
were immediately performed,
the
fuse was replaced,
inverter was tested
and placed back into service.
An
ECCS backup supply is scheduled for installation during the Unit 3
outage.
The cause of the inver ter failure was not fully determined.
Inspection Followup Item 296/96-.08-02
discussed
recurring failures of
inverters
and remains
open.
(Section 02.2).
On, December
13,
1996, Unit 3 Operations
experienced
an unplanned,
ar tial
ESF actuation
when an external
120VAC power supply tripped
a
reaker during adjustment of a continuous air monitoring valve limit
switch.
Immediate corrective actions by the licensee
were adequate.
~(Section 02.3).
\\
During the inspection period, the inspectors
reviewed
a licensee
proposal to use Auxiliary Unit Operators
(AUOs) and Site Secur ity
personnel, as. Fire Watches.
The inspectors
found that the use of AUOs
and .Site Security as Fire Watches
was acceptable.
(Section 06.1).
Maintenance
Continued. review of fr eeze protection program activities found that
licensee efforts were adequate to provide necessary
protection.
(Section
H1'.1) .
The inspectors
reviewed licensee
Toolpouch Maintenance efforts.
The
inspectors specifically addressed
use of this Toolpouch Maintenance for
Emergency Diesel
Gener ator
per iodic maintenance.
The inspector s
I!
0
-questioned
the appropriateness
of applying Toolpouch to a Diesel
Generator activity and identified
a potential for adding incorrect
chemicals.
Unresolved Item,
URI 50-259,260,296/96-13-2
was opened.
(Section H1.2) .
~
On December
12,
1996 during
a refuel area tour the inspectors
noted that
a tarpaulin-type cover was erected
over the Unit 2 Spent
Fuel
Pool
(SFP).- The inspectors
found that maintenance
personnel
had failed to
properly implement work control procedures
and thus
an evaluation of
impact on SFP design
and operation
was not performed.
A violation (VIO)
50-260/96-13-01
was identified. (Section H2.1).
~
On November 27,
1996, during a licensee
inspection of Unit 3 SFP cooling
system,
a rag was found in check valve 3-CKV-'078-0545.
On December 4,
1996, prior to eddy current testing,
during an examination of the 2A SFP
cooler
head assembly,
workers found three pieces of non magnetic metal
and
a piece of wire.
All items were analyzed
and determined to have
entered the systems
during outage or construction activities.
The
inspectors
noted that licensee
response to the problem was very good.
~(Section H2.2).
En ineerin
On November 21,
1996, licensee
Reactor Engineering personnel
were
informed by the reactor fuel vendor that there was
a potential input
error in analysis
performed for the Unit 3 Average Planar Linear Heat
Generation
Rate
(APLHGR) which, in turn,
made the APLHGR limits
nonconser vative.
.In a follow-up January,
1997 vendor letter, the vendor
reassessed
the APLHGR calculations
and determined that they had not
calculated
an allowance for fuel pellet densification
effects.'eperformed
calculations
wer e conservative.
Inspector s noted that the
l,icensee
responded
appropriately to these notifications.
(Section E2.1).
During the inspection period, the inspectors
reviewed hourly regular
time and overtime hours for licensee
system/technical
engineering
and
radiological control personnel.
The inspectors
found that personnel
in
these work groups worked very little overtime and hours were well within
times allotted for in .Site Standard Practice procedure
SSP-1.7,
Overtime
Restrictions
- 'Regulatory.
(Section E6.1).
During the inspection period, .the inspectors
noted that twenty-eight
fuse program corrective action items had been presented
in 1996.
After
further review the inspectors
concluded that the high number of issues
was due to a combination of a new initiative f'r field identification of
.fuses
and
a low. threshold for reporting problems including non safety-
related equipment.
(Section E8.1).
Ib
0
0
-J
~
On December
27,
1996, the licensee identified an .uncontrolled -Locked
While the area
was unlocked, AUOs/electrical
maintenance
personnel
entered the area
and received unanticipated
exposures.
The inspectors identified two examples of inadequate
procedures
which contributed to the event
and
a violation (VIO) 50-
296/96-13-3
was identified. (Section Rl.l).
0
il
0
R~R
Summar
of Plant Status
Unit 1 remained in a long-term lay-up condition with the reactor defueled.
With the exception of a December
26,
1996,
power reduction to clean unit main
condenser
waterboxes,
Unit 2 operated
at power during the report period.
Also, with the exception of .the periods noted in the following paragraph,
Unit 3 continued its planned
coastdown
as the Unit 3 Cycle 7 outage
approached.
On November 29,
1996,
December
27,
1996,
and January 3,
1997, Unit 3 power was
reduced
from approximately 95'ower to 70'ower
and then returned to highest
allowable power conditions.
These
power variations were performed to adjust
heater configurations.
These feedwater
heater configuration changes
were performed to adjust feedwater temperatures
during thy unit coastdown for
the February 21,
1997, Unit 3 Cycle 7 refueling outage.
I.
rations
02
Operational
Status of Facilities and Equipment
~
~
02.1
Unit 2 Batter
Char er Failures
a.
Ins ection Sco
e
71707
92700
93702-
The inspectors
reviewed the actions taken by the licensee in response to
2A and
2B Battery Charger
Failures.
b.
Observations
and Findin s
On December
17,
1996, while the Unit 2 2A charger
was aligned to restore
the g2 250VDC Hain Battery Bank from a battery discharge test, the
battery would not build-up enough charge nor indicate adequate
voltage
levels.
The 2B charger
(the spare)
was then aligned to the bank.
However,
on December
18,
1996, at .1:00 a.m.,
(CST), after approximately
3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> s of oper ation, this charger displayed fluctuating amper ages.
This portion, of the battery equalizing charge surveillance
was
immediately secured
and the 2B charger
was removed from service for
troubleshooting
and repairs.
The unavailability of the 2A and
2B chargers
presented
a loss of both
Hain Battery Bank $2 power supplies,
and the licensee
enter ed
a 24-hour
Technical Specification
(TS) Limiting Condition for Oper ation
(LCO)
3.9.B.7,
Loss of a Shared
Source of DC Power .
Two other sources of DC
power
(the Unit 2 g3 and g4 char gers),
and three other battery banks
were available throughout testing
and this .event.
Troubleshooting efforts determined the 2B charger
amperage oscillations
were caused
by a failed resistor.
The resistor
was replaced,
the
charger
was tested,
and at about 1:00 p.m.
(CST) on December.
18,
1996,
Ci
0
I
the charger
was 'returned to service.
Unit 2 Hain Battery Bank
survei1lance testing
was then completed.
During rep1acement
of the resistor; the inspector
observed that. craft
personnel
were attentive to their repair activities.
They had noted
that the replacement
resistor required suitable
and appropriate
dedication prior to use in the charger
because this resistor could no
longer be purchased
nor obtained
as
a safety item.
Additionally, a
capacitor
was replaced in the 2A charger.
Licensee-approved
component
dedication activities were performed in a satisfactory
manner,
the
resistor
was properly qualified for use,
and repairs were performed.
Conclusions
The inspectors
determined that the licensee properly addressed
the
failures and subsequent
unavailability of both chargers.
Licensee
notification of the event
was both timely and accurate.
Although
evidence of the problem was almost negligible (variations in amperage
initially observed
by the craft were slight)
a call for repair was
immediately made
and subsequent
charger troubleshooting
and repair
efforts were quickly performed.
Unit 3 Emer enc
Core Coolin
S stem
Division II Inverter Failure
Ins ection Sco
e
71707
92700
93702
The inspectors
reviewed actions taken by the licensee in response to a
Unit 3 Division II ECCS ATU Inver ter power failure.
Observations
and Findin s
On December
17,
1996, Unit 3 Division II ECCS ATU Inverter
power
was
lost due to a fuse failure.
This inverter supplies
power to two of four
channels of drywell pressure
and the reactor water level sensors.
These
sensors
supply both divisions of initiation logic for RHR/CS,
and the
EDGs.
Other sensors for reactor pressure,
containment
and HPCI
are also supplied by this inver ter
.
Because the other channels of ECCS instrumentation
are powered by the
Division I inverter, the logic of all
ECCS divisions would have been
initiated, if required.
With the exception of HPCI and Division II
input into the Anticipated Transient Without Scram
(AVOWS)/Recirculation
Pump Trip (RPT) logic, all systems
would have performed their design
function.
Because this ATWS/RPT logic was inoperable,
a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
LCO (TS 3.2.L) .was entered.
The Division I ATWS/RPT logic was operable
and
would have performed
as designed.
Approximately two and one-half hours after the inverter was lost, the
fuse was replaced
and other circuitry items; i.e., the SCR/Diode,
control board
and capacitor;
were checked in accordance
with work order
(WO) 95-022182-001.
The inverter was subsequently
tested
and performed
4l
0
C.
02.3
a.
b.
'atisfactorily.
The
LCO was exited and the inverter was placed
back in
service:
All ECCS systems
were restored to pre-event conditions.
There have been other recent Unit 3
ECCS Division I inverter failures
(See
IR 96-08, Section 02.2 and IR 96-12, Section 02.2).
A descr iption
of these Division I failures is presented
in Unit 3 LER 296/96-004,
Revision 2 and Unit 3 LER 296/96-006.
The licensee
has issued Unit 3
LER 296/96-008 to describe this Division II inverter failure.
Conclusions
A licensee analysis to determine the exact cause of both the Division I
and II inverter failures is on-going.
The licensee is implementing
a
backup source of uninter ruptable
("DC-to-DC") power to the Division I
and Division II circuitry.
The inspectors
have reviewed
DCN T39853A;
which documents installation of this power supply modification in the
upcoming February
1997 Unit 3 refueling outage.
The inspector s
determined that the licensee's
actions are appropriate
and this backup
source of logic power will mitigate the effect of similar failures.
Because
a specific cause of the Unit 3 Division I and II failures have
.not yet been determined
by the licensee (test results are expected in
late February
and ear ly Harch) the issues will remain open
and continue
to be addr essed in Unit 3 Inspection Followup Item (IFI) 296/96-08-02,
Emergency Core Cooling System Inverter Failures.
Un lanned Unit 3
H dro en/Ox
en Anal zer Valve Isolation
Ins ection Sco
e
71707
92700
93702
The inspectots
reviewed actions taken by the licensee in response to an
unanticipated partial Unit 3 Engineered Safety Features
(ESF) Actuation
and
a subsequent
inadvertent isolation of the Hydrogen/Oxygen
(H,O,)
analyzers.
Observations
and Findin s
On December
13,
1996, Unit 3 operations
experienced
an unplanned,
partial-ESF actuation
when adjustment of a limit switch for continuous
air monitoring valve (FSV-84-8D) caused
an external
120VAC power supply
Iinstrumentation
and control
(I8C) panel g9-9] breaker
f336 to trip.
During these
adjustment activities, the primary containment isolation
system
(PCIS) breaker
f336 opened,
which deenergized
PCIS valves
and
positioned the
Hz0 valves to their fail safe position (both divisions
oi'he drywall anrf torus
H,O, sample/return line valves closed).
Operators took proper
immediate actions in response to the isolation and
the unit continued at full power operation throughout the event.
Because
both divisions of the
H,O> analyzers
were isolated,
Technical
Specification
(TS) Limiting Condition for Oper ation
(LCO) 3.7.H.3 was
entered
which required the licensee to have the reactor
in Hot Shutdown
in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Licensee Operations
determined that the root cause of'he
0
event
was weak planning of a step-text
work order
(WO).
During work
planning activities,
WO steps
were not sequenced
in accordance
with
expected activity practices.
The tripped panel
breaker
was immediately
reset,
the
H,O, analyzer valves were reopened,
and the
LCO was exited.
c.
Conclusions
The inspectors
determined that the work planning did not meet the
licensee's
expectations
and corrective actions were appropriate.
The
inspectors,
Region II, and
NRC Headquarters
personnel
were promptly
notified'f the partial-ESF actuation.
A licensee
event report
(LER 96-
007-00)
was submitted in accordance
with 10 CFR 50.73(a)(2)(iv).
06
Operations Organization
and Administration (71707)
06. 1
Use of Auxiliar Unit 0 erators
and Securit
Staff as Fire Watches
a.
Ins ection Sco
e
71707
64704
The inspectors
reviewed licensee
plans to use
AUOs and Security
personnel
as Fire Watches to determine if these
proposed activities
would be performed in accordance
with guidance contained in SSP-12.1,
Conduct of Operations,
Revision 30; the Site Security Plan;
and Licensee
Fire Protection Report
(FPR), Section I-L, Revision 2.
b.
Observations
and Findin s
The inspectors
reviewed
a licensee
plan to use
AUOs and Site Security
personnel
as Fire Watches.
The plan. indicated that AUOs would be used
as Roving Fire Watches
and that in this capacity the
AUO would have no
other duties which impacted their fire watch function.
The plan also
indicated that extra AUOs, those not assigned to perform standard
duties,
would be tasked
by the Shift Hanager to perform Roving Fire
Watch functions.
The inspectors
determined that the licensee's
program has the following
requirements:
Fire watch personnel
must have training in performance of the
Roving Fire Watch function and use of FP equipment.
A documented
record of such, training must be available/accessible.
AUO personnel
performing .the Roving Fire Watch function must
accomplish their assigned
Roving Fire Watch tasks
and log/record
FP task completion within the
FPR designated/approved
time frames.
Any personnel
performing the function of a Roving Fire Watch must
not have any other responsibilities
which could have
an impact
upon their assigned fire watch duties.
0
C.
08
08.1
The inspectors,
during their review of the licensee's
proposal,
noted
a
potential conflict in responsibilities
as delineated in SSP-12.1
and the
FPR.
According to SSP-12.1,
an
operator 's primary responsibility is the
proper
and safe operation of the plant, whereas,
according the
FPR, the
fire watch has
a primary responsibility of watching for and responding
to fires or potential fire hazards.
This apparent difference in basic
watchstanding responsibilities
was brought to the attention of the Fire
Protection
and Operations
Hanagement.
The inspectors
understand that
.clarification of AUO/Roving Fire Watch responsibilities,
in the form of
a SSP-12.1 revision, is on-going and is planned for completion in
February or Harch,
1997.
The inspectors
also reviewed
a licensee
proposal to use Site Security
personnel
as Continuous Fire Watches whi'le they are also being used to
control access
to normally closed/locked vital areas.
The inspectors
discussed this with licensee
management
and noted that the licensee
intended to use posted
guards in the following manner:
~
Site Security personnel
are to stay on station
and at their
assigned
posts.
~
On-Station Site Security personnel's
only actual fire watch
function is maintaining awareness
of actual or potential fire
hazards.
~
If personnel
are unable to view all zones
from the open door area,
they must request
assistance
to perform the fire watch function.
~
If an actual
hazard exists, Site Security will immediately;
1)
inform personnel
in the area being watched to evacuate,
2) close
the door to the area,
and 3) call for fire brigade assistance.
The inspectors
also noted that the three previously specified Fire Watch
~ requir ements for the AUOs are also required for Site Security personnel
performing the Continuous Fire Watch function.
Conclusions
The inspectors
found that the licensee's
plan to use
AUOs as Roving Fire
Watches
and Site Security personnel
as Continuous Fire Matches (while
such personnel
are stationed at their assigned
security posts)
.was
acceptable.
The inspectors
also found that the planned February/Harch
1997 revision to SSP-12.1,
to be performed in or der to clarify AUO
Roving Fire Watch responsibilities,
once implemented, will be
acceptable.
Hiscellaneous
Operations
Issues
(92901)
(Closed)
LER 50-296/96-004:
Unplanned
ESF Actuation Following Transfer
of 480VAC Shutdown Board 3A To Its Alternate Supply.
This
LER was
submitted
due to an event .that resulted in an automatic actuation: of
ESF.
After a licensed operator
had mistakenly transferred the 3A 480VAC
P
0
i~
Shutdown Board power .from an energized
source of power to a'eenergized
power
source
a half-scram
was received
on Reactor Protection
System
(RPS)
Bus 3A.
This action, in turn, initiated an
ESF signal
and the
unit then experienced
an inadvertent
and unexpected
actuation of the
standby gas treatment
system
(SGTS), the control
room emergency
ventilation system
(CREVS),
and the primary containment isolation system
(PCIS).
The root cause
was determined to be personnel
er ror.
Based
upon the inspector-observed
satisfactory completion of the licensee's
immediate corrective actions
and tHe completed corrective actions
designed to prevent recurrence,
this
LER is closed.
Conduct of Maintenance
II. Maintenance
Continued Ins ection of the Licensee's
Freeze Protection
Pro ram
Ins ection Sco
e
71714
92902
The inspectors
continued to review activities related to the licensee's
freeze .protection program
(See IR96-12, Section
H8 ~ 2) to determine if
activities were conducted in accordance
with BFN procedure
0-GOI-200-1
Freeze Protection Inspection,
Revision 25 and
WO $96009582000,
Annual
Inspection
and Preventative
Maintenance of Freeze Protection
Systems.
Observations
and Findin s
From December
16 to December
20,
1996, the inspectors
toured various
plant areas,
(specifically, the condensate,
demineralized
water
and
chemical
storage tank areas),
and continued
an on-going inspection of
licensee
freeze protection activities.
Many of the inspector -identified
items involved minor discrepancies
(i.e., inadequately lubricated valves
and missing .screws
on var ious heat trace
compartment
doors)
and these
items were immediately brought to the attention of licensee
management
personnel.
The inspectors
also noted that heat tracing thermostat
adjustment
covers (for the condensate
storage
tank and the demineralized
water tank thermostats)
had been left open after
adjustments to the
thermostats
were made by BFN'lectrical Maintenance
(EH) personnel.
By
EH personnel
leaving the covers
open, the thermostat internals were
exposed to various environmental effects
such
as moisture,
cold
temperatures,
and rain/ice conditions.
Such conditions could have
affected designed tank thermostat operation.
This issue
was also
immediately reported to EH supervisory personnel
and licensee
management.
When low temperature
conditions (less than 25 degrees
F) were reached,
the inspector s toured tank and circulating water/RHRSW intake areas
and
noted that appropriate
heat trace lighting, indications were present.
The inspectors
also verified proper heat tracing measurements
(circuitry
ohm measurements)
during a review of BFN Freeze Protection documentation
0
4l
~O
EP I-0-000- FRZ003,
Fr eeze Protecti on Progr am for Miscellaneous
Yard Areas
Buildings and Systems.
c.
Conclusions
Licensee efforts were effective and identified several
issues (i.e.
a
grounding problem with ¹5 condensate
storage tank heat trace).
Continued inspector review of licensee
freeze protection procedures
and
on-going
BFN freeze protection program field activities revealed that
current licensee efforts are adequate
to provide necessary
protection to
guard against cold weather conditions in the area.
H1.2
Use of Tool ouch Maintenance for EDG Maintenance
a.
Ins ection Sco
e
62707
The inspectors .reviewed aspects of Toolpouch Haintenance
on the
emergency diesel
generators
and aspects of the process for ensuring
correct chemistry in the jacket water cooling system.
The inspector s
reviewed the records
and Information Management
computer system
(RIHS);
reviewed SSP-6.2,
Maintenance
Management
System,
Revision 21,
Appendix T, Implementing Toolpouch Maintenance;
reviewed Integrated
Materials System data;
examined
Power Stores Transaction
System data;
reviewed Chemistry Instruction CI-628.
NALCO-39 (Rust Inhibitor),
Revision 3; reviewed chemistry data;
and reviewed SSP-13.1,
Chemistry
Program,
Revision 14, Appendix C, Table of Bulk Chemicals
Used at BFN.
b.
Observations
and Findin s
Work Order 96-012915-000
was.reviewed
from the computer tr acking system
(Enterprise-HPAC).
The inspectors
determined that
WO action indicated
that Toolpouch Haintenance
was performed to raise the diesel
coolant
expansion tank level.
The work description stated
"Added demin water to
bring level
up to 9 1/4, about
5 gal" and the
WO status indicated
"complete to document control" (CD).
The inspectors
searched
the RIHS
(Records
and Information Hanagement)
computer system to determine if
documentation
from,the
WO and
Wor k Request
WRNRepair Tag were archived
on microfiche.
No records
were found.
A lack of physical
documentation of the
WO is consistent with closure of
work using Toolpouch Haintenance.
Licensee
procedure
SSP-6.2
Haintenance
Hanagement
System,
Revision 21, Appendix T, states in
associated
notes .that
"No documentation of work activities is required
for work performed
as Toolpouch Haintenance;"
however, the inspectors
questioned
whether
use of Toolpouch Haintenance
was acceptable
for the
work described in the
WO.
The licensee is currently evaluating whether Toolpouch Haintenance
was
appropriate for adding demineralized
water to the emergency diesel
generators
(EDGs) cooling system.
The licensee
has also initiated a
PER
(BFPER961761) to document this evaluation.
Licensee
management
has also
indicated that Toolpouch Haintenance will not be used for the indicated
0'
41
C.
H2
H2.1
a.
example until the licensee
has addressed
this issue.
An Unresolved
Item
will be opened to follow their evaluation
(URI 50-259,260,296/96-13-02).
The .inspectors
questioned if the addition of demineralized
water
affected the coolant chemistry.
During review of Integrated
Haterials
System data,
the inspectors
determined that
a corrosion
inhibitor (TIIC MANX-359P) and
a liquid antifreeze,
ethylene glycol
(TIIC KBG-732L) could be issued for any of the eight
EDGs.
The
inspectors
questioned
whether the liquid antifreeze
was acceptable
for
use in the
EDGs.
The licensee initiated
PER
(BFPER970056) to address
whether TIIC gCBG-732L (liquid antifreeze)
can be added to the
contrary to SSP-13.1.
SSP-13.1,
Chemistry Program,
Revision 14,
Appendix C, Table of Bulk Chemicals
Used at BFN, described the use of
Diesel
Generator
Jacket Cooling Corrosion Inhibitor in the
EDGs.
Ethylene Glycol was not addressed
by SSP-13-1
as acceptable
for use in
the
EDGs.
The inspectors will also address this issue in the Unresolved
Item (URI 50-259,260,296/96-13-02).
The inspectors
also reviewed the
Power
STORES Transaction History for
the issuance of the liquid antifreeze
(TIIC CBG-732L).
The
documentation did not indicate that the liquid antifreeze
had been
issued for use
on an
EDG.
The inspectors
reviewed chemistry data for all eight emergency diesel
generator s from January
1995 through November 1996.
Chemistry
Instruction CI-628,
NALCO-39 (Rust Inhibitor), Revision 3, determines
the concentration of rust inhibitor
(NALCO-39) in the diesel
generator
cooling system.
The procedure
addr esses
the minimum required
concentration
as 2.2 ounces/gal.
Based
upon the data reviewed, the
concentration did not drop below the procedure required concentration of
2.2 ounces/gal.
Conclusions
The inspector will followup on the concerns identified through
Unresolved
Item (URI 50-259,260,296/96-13-02).
Although the possibility
existed for the liquid antifreeze
(TIIC CBG-732L) to be issued for the
review did not indicate that liquid
antifreeze
has
been
used in the Emergency Diesel Generators.
Haintenance
and:Haterial
Condition of Facilities and Equipment
A
Placement of a Unit 2 S ent Fuel
Pool Cover Without Pro er Work Control
Ins ection Sco
e
62707
92902
The inspectors
examined work control activities associated
with the
placement of a tarpaulin-type cover over the Unit 2 Spent
Fuel
Pool
(SFP) to determined if they were conducted in accordance
with licensee-
approved work control practice procedures.
II
~li
b. "Observations
and Findin s
On December
12,
1996, during
a routine tour of the spent fuel pool area,
the inspector s observed that
a tailored, reinforced-plastic,
yellow,
tarpaulin-type,
cover had been erected
over and around the upper
surface
area of the SFP.
The inspector s determined that this cover had
apparently
been placed over the
SFP for FHE purposes.
Upon further
inspection,
the inspectors
discovered that this SFP modification had not
been properly processed
through
a licensee-approved
work control
process.'y
not performing approved work control processes,
this change
to the original
SFP design
was not thoroughly evaluated
by Operations
nor Licensee Engineering for impacts
on SFP operation
and design.
As stated in licensee-approved
procedure
SSP-7.1,
Work Control,
Revision 15, this procedure is to be performed for all activities that
change or have the potential to change
a component,
system or unit
configuration.
Section 3.2.1.A of SSP-7.1
notes that
an initiator of a
work activity is to prepare
a work request for activity performance
and
after review by the initiator's supervisor,, this request is to be
forwarded to Operations for further review.
Operations
review,
according to Section 3.2.1.B of SSP-7.1,
affords unit operations
an
assessment
of potential
impacts of the activity (and related
system
change)
on unit operations.
Operations
and engineering
were not afforded opportunities to assess
the
cover's
impact on the designed operation of the pool.
An engineering
evaluation of the cover's
impact upon original design of the
SFP was not
performed.
The SFP cover's configuration was not evaluated
by licensee
engineering for effects
on designed
SFP heat dissipation,
influence on
designed
SFP ventilation air exchanges
or for any impacts
upon
SFP water
purity, or operational
impacts
and controls such
as fire loading;
inspections -etc.
C.
H2.2
Conclusions
The inspectors
concluded that licensee
maintenance
personnel
failed to
adequately
implement licensee-approved
work control procedures.
By not
implementing these
procedures,
licensee
personnel
failed to provide
Operations
and Engineering
an opportunity to evaluate the impact of this
cover
on SFP design
and operation prior to installation of the cover.
This issue is identified as Violation (VIO) 50-260/96-13-01,
Failure to
Implement Licensee-Approved
Work Controls for Changes to the SFP.
Forei
n Haterial
'Exclusion
FHE
Issues
a.
Ins ection Sco
e
62707
92902
The inspectors
examined activities associated
with the discovery and
subsequent
removal of a rag located in a Unit 3 SFP cooling system check
valve (3-CKY-078-0545).
The inspectors
also reviewed licensee
discovery
and subsequent
licensee
removal activities involving three pieces of
0
10
non-magnetic
metal
and
a piece of wire found in the inlet/outlet head
area of the Unit 2 cooler/heat
exchanger
(2-HEX-78-758).
Observations
and Findin s
On November 27,
1996, during
a licensee
inspection of SFP cooling system
check valve 3-CKV-078-0545,
a rag was found in the valve.
Plant
maintenance
personnel
removed the rag during performance of WO 95-03507-
00 (as
par t of the licensee's
on-going safety system check valve
inspection efforts)
and sent it to their laboratory for analysis.
Based
upon actual
appear ance .and condition of the rag fibers, the rag was in
the system we)l before the 1995 Unit 3 restart/recovery
peri'od.
The
licensee further presumed that the rag may have hooked itself upon
system
component internals
and/or piping during past system flushing
efforts.
Because of this hooking action, the rag was, therefore,
not
expelled .from the piping as expected.
They also determined,
by lack
of'ignificant
variance
from expected
flow during system operation, that
the rag did not affect check valve operability.
On December
4,
1996, prior to performance of a preventive maintenance
inspection
and eddy current testing of the 2A SFP Cooler (2-HEX-78-758)
three pieces of metal
(squares of about 3/4 inch
X 1/4 inch)
and
a piece
of what appeared to be bailing wire (approximately
3 inches long) was
removed from the inlet/outlet head of the cooler.
After removal this
material/debris
was sent to the licensee's
corporate
laboratory for
analysis in order to determine material
makeup
and origin.
The licensee
determined that the squares
were non-magnetic
and appeared
to be pieces of a tool or possible
shim pieces.
The wire was that of a
type used .to tie-off scaffolding.
The licensee
presumed that the metal
squares
and the wire entered the
SFP heat exchanger
head area during
revious maintenance
on the
SFP cooler/heat
exchanger
and probably had
een in the head area for greater than 2 years.
Conclusions
The inspectors
noted that licensee
maintenance
personnel
had properly
prepared for the possibility of having foreign material in the cooler
upon initially opening
up the head for eddy current testing.
Personnel
were very good in finding this material,
and they were also very prompt
and thorough in their follow-up analysis.
The licensee
also was
thorough in their analysis of the rag and their determination of source.
The inspector s determined that the licensee's
actions in response to
discovery of this foreign material in each instance
was appropriate.
E2.1
a.
b.
C.
11
III. En ineerin
Engineering Support of Facilities and Equipment
Vendor's
Fuel Calculations for Unit 3
Ins ection Sco
e
37551
The inspectors
examined licensee activities related to the discovery of
what the licensee's
fuel vendor initially thought was
a non-conservative
calculation of the Average Planar Linear Heat Generation
Rate
(APLHGR).
Observations
and Findin s
On November
21,
1996, licensee
Reactor Engineering personnel
were
notified by the fuel vendor of a potential
input error in the Loss of
Coolant Accident
(LOCA) analysis
performed for the Unit 3, Cycle 7 fuel.
The licensee's
fuel vendor initially thought that. their error might have
resulted in non-conservative
APLHGR limits for some of the licensee's
long-lived fuel designs; i.e., the latest version vendor fuel used in
mixed fuel configurations.
The vendor initially estimated that this
error could have resulted in a non-conservative limit error of up to
three percent.
The licensee's
Reactor
Engineering group reviewed the
calculations for Unit 3, Cycle 7 to determine if ther e were any
instances
where limits could have been exceeded.
They determined that
relevant limits had not been
exceeded
throughout the operating cycle.
In a follow-up January,1997
vendor letter to the licensee,
the vendor
stated that they had re-analyzed their November calculations
and noted
that they had not adequately
adjusted the previous
November calculations
to account for (allow for) fuel pellet densification
as the fuel was
operated
throughout the cycle.
By factoring in this item, the original
conservative limit.estimates for APLHGR proved to be just as valid and
just as conservative
as originally designed
and calculated.
Conclusions
The inspectors'noted
that the l,icensee's
Reactor
Engineering/Hanagement
ersonnel
had responded
appropriately to the initial vendor notification
y immediate (historical) verification that
APLHGR limits had not been
exceeded
during operation of their latest vendor-designed
fuels.
The inspectors
also noted that upon receipt of the vendor 's November
notification the licensee's
follow-up response to the notification was
prompt, reasonable
and was considered
adequate.
The licensee's
response
was also adequate
considering that Unit 3 was in coastdown condition
(for a February outage)
and the unit was not in a full-rated power
conditions.
0
0
0
E6.1
a.
12
Engineering Organization
and Administration
En ineerin
Staff Over time
Ins ection Sco
e
37551
As a part of routine core inspection activities, the inspectors
reviewed
hourly regular
time and overtime records for licensee
system/technical
engineering
and radiation control
(RADCON) group personnel.
b.
Observations
and Findin s
During the inspection period the inspectors
reviewed
a selected
week of
data during the month of September
1996 hourly regular time/overtime
work records for licensee
system/technical
engineering
and
RADCON
personnel.
The inspectors
noted that
BFN system engineering
group
personnel,
on average,
worked approximately 47 hour5.439815e-4 days <br />0.0131 hours <br />7.771164e-5 weeks <br />1.78835e-5 months <br /> s per. week.
This
average
was slightly higher
than that experienced
by most of the
engineers
in the group (approximately 42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br /> per week)
due to one
individual working about
66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br /> in one week whjle another worked about
62 hours7.175926e-4 days <br />0.0172 hours <br />1.025132e-4 weeks <br />2.3591e-5 months <br />.
Two other
system engineers
worked about
53 hours6.134259e-4 days <br />0.0147 hours <br />8.763227e-5 weeks <br />2.01665e-5 months <br /> during the
selected
week in September.
The inspectors
also noted that technical
engineering
department
personnel
worked approximately 41 hours4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> per week.
A minimal amount of overtime was used by the technical
engineering
group
personnel.
The inspectors
noted that
RADCON personnel
used very little
overtime and on average
worked
=a straight 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />
per
week.
C.
Conclusions
The inspectors
.found that licensee
personnel
in the above work groups
used very little overtime.
The "40-hour work week" appeared to be the
norm for most personne1
in the identified -groups.
None of the reviewed
records presented
any indications nor evidence that licensee-approved
overtime limitations, .as presented
in SSP-1.7,
Overtime Restrictions-
Regulatory,
(this SSP implements elements of NRC Gener ic Letters 82-12
and 83-14),
had been exceeded.
The inspectors
found that licensee
'ystem engineering,
technical
engineering
and
RADCON personnel
weekly
working hour averages
were not out of the ordinary and over time to be
adequately controlled.
E8 Miscellaneous
Engineering
Issues
E8.1
Fuse
Pro
ram Activities
a.
Ins ection Sco
e
37551
The inspectors
reviewed activities associated
with the licensee's
fuse
program.
The inspectors
also performed
a follow-up inspection of
identified-fuse modification drawing discrepancies,
fuse identification
issues,
and past problems of incorrectly identified fuse installations.
0
~ ~
~
b.
Observations
and Findin s
13
During the inspection period, inspectors
followed-up on 28
PERs which
dealt with various fuse program activities in order to determine the
significance of the licensee identified problems.
All 28
PERs
had been
written since January
1996.
During 1996 the following fuse-related
PERs appeared:
~
Nine blown fuses.
Two of these
were related to problems with the
Unit 2 Shutdown Board
(SBD)
Room chiller fuses.
The remaining
seven failures were unrelated,
isolated events.
~
Five noted drawing discrepancies;
i.e., the drawi,ngs did not
reflect current/actual
plant configurations.
Equipment
was not
safety-related
and drawings are being revised using normal
licensee-approved
drawing discrepancy corrective action practices.
~
Three involved improperly installed fuses
and six described
incorrectly identified fuses.
Field identification of fuses is
part of a new initiative which is currently being implemented.
The improperly installed fuses involved non-safety equipment.
~
Five described
miscellaneous
fuse issues; i.e., insufficient
stock,
inadequate
stock, inappropriate
design or inaccurate
fuse
labeling issues.
An updating of current fuse stock and purchase
of safety fuses is on-going.
Dedication of non-safety fuses for
use in safety-related
systems is also on-going and appears to be
adequate.
c.
Conclusions
The inspectors
determined that the high number
of. fuse related
PERs are
due to a combination of a new initiative for field identification,
and
a
low threshold for identifying issues
including non safety-related
equipment.
The licensee's
current
PER process appropriately
and
correctly addresses
on-going fuse issues.
E8.2
0 en
VIO 50-260 296/EA 95-220:
This violation identified that on
Fe ruary 2 and 4,
1993, the licensee failed to ensure that provisions
of 10 CFR 50.7 were implemented,
in that, .Stone
and Webster Engineering
- Corporation
(SWEC),
a contractor to the Tennessee
Valley Authority (TVA)
at the Browns Ferry .Nuclear Plant discriminated against
a worker engaged
in protected activities.
A Region II inspector held discussions
and
performed inspections with TVA and. SWEC personnel
to assure
corrective
actions for this violation had been properly implemented.
The inspector
reviewed the following corrective action documents:
~
SWEC Hanagement
memorandum dated September
14,
1993, advising
supervisors
and managers of their responsibility in the area of
employee protection.
Ch
0
14
~
'Documentation of tool box meetings
held September
20,
1993, that
discussed
the employees rights to discuss
and report employee
concerns to SWEC,
TVA or the
NRC.
~
HEADS-UP Bulletin issued
September
20,
1993, to all
personnel.
This Bulletin discussed
SWEC's open door policy and
available
avenue
for employees to express
any safety concerns
without-fear of reprisal.'
Survey results
conducted
by SWEC on October
6-11,
1993,
and
Harch 28,
1994.
In addition to the above listed corrective actions,
the inspector
reviewed documentation
recently issued
by TVA that emphasized
TVA's
continuing support of eliminating harassment
in the workplace.
This
documentation
included
a combined
memorandum
from the Browns Ferry Site
Vice President
and Plant Hanager dated July 29,
1996,
and another
memorandum
from the TVA President,
dated August 7, 1996, that reiterates
that employee intimidation. harassment,
discrimination, or retaliation
for expressing
concerns will not be tolerated.
This violation will remain open pending the outcome of the
SWEC appeal
to the United States
Court of Appeals for the Eleventh Circuit as
discussed
in NRC's letter dated February 14,
1996,
on this subject.
The
inspector's
review determined the licensee's
contractor,
SWEC had
complied with the corrective actions specified in the response to the
violation.
Additionally, the inspector
found the licensee
had also
taken corrective actions relative to notifying TVA employees
and
contr actor personnel
that intimidation and harassment
at the TVA nuclear
facilities will not be tolerated.
IV. Plant Su
rt
Radiological Protection
and Chemistry Controls
Uncontrolled Locked Hi h Radiation Area
Ins ection Sco
e (71707,
71750)
On .December
27,
1996, the licensee identified an Uncontrolled Locked
The inspectors
reviewed the licensee's
Incident
Investigation
Repor t (IIR); Operating Instruction 3-0I-6, Feedwater
Heating and Hisc Drains System,
Revision 9;
and Site Standard Practice
SSP-12.1,
Conduct of Operations,
Revision 30.
Observations
and Findin s
On December
27,
1996, the licensee's
RADCON group identified that
an
uncontrolled Locked High Radiation Area
(LHRA) existed in the Unit 3
3Al/3A2 Heater
Room.
During normal plant operations,
the room is posted
as
a LHRA, but had been de-posted to support maintenance activities when
0
0
15
extraction
steam
had been isolated.
The area
became
a
LHRA again
when
operations
personnel
inadvertently introduced
a radiation source to the
room by manipulating
an extraction
steam valve.
The IIR stated that the
area
remained
as
an uncontrolled
LHRA f'r approximately four hours.
The area
was still posted
as
a contamination
zone
and as such access
was
controlled by a Radiation Work Permit
(RWP).
Although unanticipated
radiation exposures
had occurred,
the maximum individual dose received
by any of the
5 individuals who entered the area during the time frame,
while the uncontrolled
LHRA existed,
was 31 mrem.
The doses
received
did not exceed the alarm setting of 140 mrem integrated
dose
on licensee
electronic dosimeters
worn by the workers,
nor did unexpected
doses
received
by the workers exceed
10 CFR 20.1201 limits.
The. licensee's
IIR indicated that the area
was immediately re-posted
as
a
LHRA by a
RADCON technician
upon discovery,
and the area
was manned
until both accesses
were locked.
The licensee's
IIR identified the following three findings:
~
(Finding gl) Sufficient administrative controls were not in place
to ensure that the
HP heater
room was controlled as
a
LHRA prior
to changing plant conditions.
Proper controls were not in p'lace to
ensure applicable criteria were met.
The procedures
for putting
heaters
in service did not contain adequate
guidance to notify
RADCON when extraction
steam
was to be returned to service.
~
(Finding $2) Inappropriate/incomplete
communications contributed
to the event.
The, Unit Super visor (US) and AUOs did not accurately
communicate
requirements of RADCON involvement.
In addition, pre-
job and
RADCON briefs were incomplete
and inaccurate.
The pre-job
brief did not include
RADCON considerations
and failed to discuss
all planned activities and radiological conditions.
Furthermore,.
the
RADCON brief -for the AUOs/EHs was misleading
and inaccurate,
in that, it stated
expected
doses
should be I to 2 mrem/hr.
~
(Finding g3) Plant personnel
involved in this event were not fully
aware of actual- radiological conditions
nor all work activities in
the 3A1/3A2 feedwater,heater
rooms.
The IIR further states that
personnel
did not exhibit the necessary
"questioning attitude"
and
use of BFN's STA'R concept during this event.
c.
Conclusions
The inspectors
determined that,
as described in licensee finding number
one, Operating Instruction 3-0I-6, Feedwater
Heating
8 Misc Drains
System,
Revision 7, was not adequate to ensure
RADCON was notified of
the changing plant conditions which caused
a rise in area radiation
levels.
This is identified as the first example of an inadequate
procedure violation (50-296/96-13-03).
lh
0
0
16
In addition, the inspectors identified that SSP-12.1,
Conduct of
Operations,
Revision 30,
was inadequate to ensure that radiological
control personnel
were appropriately informed prior to evolutions
or
activities that have
a potential to significantly change radiological
conditions in the plant.
Procedure
SSP-12.1,
Section 3.4.5.G,
Radiological Protection,
states
radio1ogical control personnel
should be
informed prior to evolutions
or activities that have
a potential to
significantly change radiological conditions in the plant.
As worded,
the procedure
was not adequate
to require proper notification to
radiological personnel,
because
the word "should" is defined
as
a
recommendation
in SSP 2.2, Writing Procedures.
Admission of extraction
steam to the feedwater heaters
in an uncontrolled area of the plant was
considered
by the inspectors to be an evolution that significantly
changed radiological conditions in the area.
This issue is identified
as
an second
example of an inadequate
procedure violation
(50-296/96-13-03).
The licensee's
IIR did not address
the inadequate
Conduct of Operations
procedure
described in the second
example of the violation.
In
addition, the licensee's
corrective actions failed to specifically
address
licensee expectations
for pre-job briefings and
how those
expectations
would be conveyed to the licensee's staff.
V. Mana ement Meetin s
Xl
Exit Meeting Sumary
An exit meeting concerning Engineering
and
SWEC (Section E8.2)
was
conducted
on December
20,
1996.
The Region II-based inspector described
areas
inspected
and discussed
in detail inspection results.
A listing
of inspection findings is provided.
Proprietary information is not
contained in this report.
Dissenting
comments
were not received
from
the licensee.
The resident
inspector s pr esented
overall inspection period results to
licensee
management
on January
10,
1996.
The licensee
acknowledged the
findings .presented.
'Proprietary information involving reactor fuel was
reviewed,
and proprietary information. was not included in this
inspection report.
Licensee
PARTIAL LIST OF PERSONS
CONTACTED
T. Abney, Licensing Hanager
J. Brazell, Site Security Manager
G. Bugg, Acting Manager,
Radiological Control
and Chemistry
R. Coleman, Acting Radiological Control
Manager
C. Crane, Acting Plant Hanager
J
~ Grafton, Chemistry Representative
Ik'
II
0
0
'
17
,M. Harding, Concerns Resolution
Program
Manager
(Chattanooga)
J. Johnson,
Site Quality Assur ance
Manager
R. Jones,
Operations
Manager
S.
Kane, Licensing Supervisor
R. Kent-Ryan,
Employee Concerns
Representative
(SWEC)
'G. Little, Operations
Superintendent
R. Hachon, Site Vice President,
Browns Ferry
D..Hatherly, Licensing
Representative'.
Pierce,
System Engineering
Manager
E. Preston,
Plant Manager
T. Shriver,
Nuclear Assurance
and Licensing Manager
K. Singer,
Maintenance
Manager
J.
Thompson,
Employee Concerns Representative
(TVA Browns Ferry)
R. White, Operations Supervisor (Fire Protection)
H. Williams, Engineering
and Materials Manager
IP 37551:
IP. 62707:
IP 71707'P
71750:
IP 92050:
IP 92700:
IP 92901:
IP '92902:
IP 93702:
INSPECTION PROCEDURES
USED
Onsite Engineering
Maintenance
Observations
Plant Operations
Plant Support Activities
Review of Quality Assurance for Extended Construction Delays
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
Followup-Plant Operations.
Followup-Maintenance
Prompt Onsite Response to Events at Operating
Power Reactors
~Oened
ITEMS OPENED
CLOSED
AND DISCUSSED
'VIO
'URI
Item Number
Status
50-260/96-13-01
Open
50-259,260,296/
Open
.96-13-02
50-296/96-13-03
Open
Descri tion and Reference
Failure to Implement Licensee-
Approved Work Controls for Changes
to the
SFP (Section H2.1)
Tool Pouch Issues
(Section M1.2)
Uncontrolled Locked High Radiation
Area (Section R1.1)
0'
'
. "Closed.
T~,
LER
Discussed
IFI
Item Number
Status
50-296/95-004-00
Closed
Item Number
Status
50-296/96-08-02
Open
18
Descri tion and.Reference
Unplanned
ESF Actuation Fol:lowing
Transfer of 480V Shutdown Board 3A
To Its Alternate Supply
(Section 08.1)
Descri tion and Reference
Emergency
Core Cooling System
Inverter Failure (Section 02.2)
50-260,296/
EA95-220
Open
Browns Ferry Discrimination.
Against Worker Engaged In
Protected
Activities (Section E8.2)
~l
~
'
0