IR 05000259/1998004
| ML18039A470 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 08/07/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18039A469 | List: |
| References | |
| 50-259-98-04, 50-259-98-4, 50-260-98-04, 50-260-98-4, 50-296-98-04, 50-296-98-4, NUDOCS 9808180103 | |
| Download: ML18039A470 (54) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License Nos:
50-259.
50-Z60.
50-296 DPR-33, DPR-52, DPR-68 Report Nos:
50-259/98-04, 50-260/98-04 '0-296/98-04 Licensee:
Tenn'essee Valley Authority Facility:
Browns Ferry Nuclear Plant, Units 1. Z, 8 3 Location:
Corner of Shaw and Browns Ferry Roads Athens, AL 35611
Dates:
Inspectors:
Hay 24, 1998 - July. 11.
1998 L. Wert, Senior Resident Inspector J. Starefos, Resident Inspector E. DiPaolo, Resident Inspector E. Testa, Reactor Inspector (Section Rl)
Approved by:
H. 0. Chri stensen, Chi ef Reactor Projects Branch
Division of Reactor Projects 9808180103 980807 PDR ADOCK 05000259
PDR Enclosure
EXECUTIVE SUMMARY Browns Ferry Nuclear Plant, Units l. 2,
& 3 NRC Inspection Report 50-259/98-04.
50-260/98-04 '0-296/98-04 This integrated inspection included aspects of licensee operations.
engineering, maintenance, and plant support.
The report covers a six-week period of resident inspection and inspection of Radiological Controls by a Region II Division of Reactor Safety Inspector.
~Qerati ons
~
The control room operators responded correctly to the tripped 3B recirculation pump and utilized a conservative approach regarding consideration of the power/flow conditions.
The licensee's use of thermography to assess damage to switchyard ceramic insulators was good (Section 01.1).
The licensee's failure to implement the procedure for returning a loop I Residual Heat Removal (RHR)
pump and heat exchanger to service in an operable loop resulted in an unrecognized entry into a more restrictive Technical Specification Limiting Conditions for Operation.
The licensee's corrective actions were adequate.
Core Spray and RHR procedures were enhanced to address a vulnerability while opening normally closed containment isolation valves (Section 01.2).
~ ~
General material conditions of the Unit 2 Core Spray System were considered good.
The inspector identified that numerous dust covers for GE type HGA relay.
used in various safety system electrical circuits, were not properly reinstalled flush with the cabinets.
The improperly installed covers did not pose an operational concern (Section 02.1).
Maintenance Test equipment was not set up properly and contributed to unnecessary troubleshooting delays in the calibration of the Reactor Core Isolation Cooling (RCIC) system governor.
Maintenance personnel were unfamiliar with test equipment operation although trained to perform the task.
Preliminary licensee investigation efforts were adequately focused on the issues that emerged during performance of the RCIC system governor calibration (Section Ml.1).
The prejob brief for the RCIC System Rated Flow at Normal Operating Pressure test was detailed and instrumental in successfully coordinating the performance of the various post maintenance tests performed during the surveillance.
The operator performing the time-to-rated-flow portion of the test demonstrated a good questioning attitude in questioning the acceptability of an'bnormal system valve lineup.
Control and supervision of the unit operator trainee was good (Section Ml.2).
~
A maintenance worker performed unauthorized work by adjusting valve packing without operations authorization.
Licensee corrective actions were considered good.
Additional motor operated valve testing was performed although not requi red by the as-found condition (Section Ml.3).
~
The licensee effectively performed corrective maintenance on a Unit 3 torus dynamic restraint that had a leaking oil reservoir.
The licensee maintained good control of contractor personnel performing the functional test of the torus dynamic restraint (Section M2. 1).
En ineerin
~
The correction coefficient (TAU) used to adjust the Operating Limit Minimum Critical Power Ratio (OLMCPR) for slow control rod scram insertion times was incorrect for several Unit 2 and 3 operating cycles, however, the corrected OLMCPR was never exceeded.
Weak design controls were in place between the licensee and the contractor performing core reload analysis.
The licensee corrective actions were prompt and complete (Section fl.l).
Plant Su ort
~
Radiological facility conditions in radioactive waste storage areas.
health physics facilities and Turbine and Reactor Buildings were found appropriate and the areas were properly posted and material appropriately labeled.
Personnel dosimetry devices were appropriately worn.
Radiation work activities were appropriately planned.
Radiation worker doses were being maintained well below regulatory limits and the licensee, was maintaining exposures ALARA.
A special team was aggressively planning the U3 drywell cleanup.
The Whole Body counting
'program was performed as procedurally required (Section Rl).
Re ort Details Summar of Plant Status Unit 1 remained in a long-term lay-up condition with the reactor defueled.
Unit 2 operated at or near full power with the exception of scheduled downpower activities.
Unit 3 operated at or near full power with the exception of a power decrease on June 27 due to the 3B recirculation pump motor generator trip (Section 01.1),
a power decrease on June 24, 1998.
when a switchyard problem caused voltage perturbations on the condensate demineralizer system (Section 01. 1).
and scheduled downpower and end of core life activities.
~l-tl ti
Conduct of Operations Ol. 1 0 erational Transients Affectin Unit 3 a.
Ins ection Sco e
71707 61726 The inspectors reviewed the licensee's actions to address two transients which aff'ected Unit 3 during the inspection period.
b.
Observations and Findin s At 5:48 p.m on June 27.
1998. the 3B recirculation pump motor generator tripped.
This placed Unit 3 in region 2 of Technical Specification (TS)
Figure 3.5.H-l.
The control room operators responded to the event and promptly initiated control rod insertion to exit region 2.
As of 6:07 p.m.,
power and flow conditions were such that region 2 had been exited.
The senior resident inspector responded to the site several hours after the incident and verified that the actions required by TS for single loop operations had been completed.
The inspector verified that plant conditions were being maintained clear of region 2.
The inspector examined completed Surveillance Instruction 3-SI-4.5.H. l.b, Core Thermal Hydraulic Stability Flow Decrease and noted that the power/flow conditions had been just on the edge of region 2.
Core flow was recorded as 45 percent of rated.
The operator actions were in compliance with procedures 3-AOI-68-1. Reci rc Pump Trip/Core Flow Decrease and 3-GOI-100-12A, Unit Shutdown for Power Operation to Cold Shutdown and Reductions in Power During Power Operations.
A 24-hour TS Limiting Condition for Operation (LCO) had been entered.
The recirculation pump motor generator set tripped due to a loss of field on the exciter.
Arcing had caused damage to the exciter brushes and brush holder assembly.
The licensee used parts from a Unit 1 motor generator set to replace the damaged equipment.
The inspector observed
that work order 98-007252-000 and procedure EPI-0-068-TST001.
Maintenance and Testing of the Recirculation M/G Sets and Associated Pump Motors, were present at the work site and being used during the work.
Numerous engineers were assisting with the recovery of the motor generator.
The recirculation pump was restored to operation on the afternoon of June 28.
1998.
On June 24.
1998, Unit 3 experienced voltage perturbations on the condensate demineralizer system that were caused by switchyard problems.
The Maury 500 kV line tripped and reclosed when a potential transformer device in the switchyard exploded.
Several adjacent ceramic insulators were damaged.
The licensee used thermography to assist in assessing the damage to some of the more severely affected insulators.
The voltage perturbations on Unit 3 condensate demineralizer system shutdown the programmable logic controllers.
This should have caused the effluent flow control valves (E-valves) for each demineralizer to lock in position; however, four of the vessels E-valves closed, isolating the vessels.
Low condensate booster pump suction alarms were received and power was decreased to compensate for the lower net positive suction head.
Unit 3 power was decreased to approximately 84%.
An additional demineralizer isolated and the resultant differential pressure across the vessels caused the demineralizer bypass valve to opens which relieved system differential pressure and cleared the booster pump alarms.
The licensee initiated a problem evaluation report to address the condensate demineralizer E-valve problems.
Conclusions 01.2 The control room operators had responded correctly to the tripped 3B
.recirculation pump and utilized a conservative approach regarding consideration of the power/flow conditions.
The licensee's use of thermography to assess damage to switchyard ceramic insulators was good.
Failure to Follow Procedure Durin Fill and Vent Ins ection Sco e
71707 The inspector reviewed the licensee's actions when operators did not use the correct procedure to fi11 and vent an inoperable portion of the Loop I Residual Heat Removal System (RHR).
In additions the inspectors walked down portions of the pressure suppression chamber (PSC)
head tank and supply piping to the RHR discharge and questioned the control of normally closed containment isolation valves from the condensate storage and supply system to the RHR discharge pipin Observations and Findin s On Nay 25, 1998, while veri fying that the RHR system was filled and vented following maintenance which affected the 3A RHR pump and heat exchanger, the licensee noted that the RHR loop discharge pressure dropped below the TS required pressure of 48 psig.
Upon further investigation, the licensee determined that discharge pressure had also decreased below the required minimum on the previous shift during fill and vent activities.
The licensee declared RHR Loop I inoperable and entered a 24-hour TS LCO.
The licensee documented the event in a problem evaluation report.
Discussions with the licensee indicated that the initial fill.and vent was performed while the tagout was being lifted and that the*operators did not use the appropriate procedure for fill and vent while returning a loop I RHR pump and heat. exchanger to service in an operable loop.
Specific guidance is available in Operating Instruction 2-0I-74.
Residual Heat Removal System, Section 8. 1.3.
The. operators did not recognize that this specific guidance was available and attempted to use other methods to fill and vent.
This procedure specifically cautioned the user that close coordination is required to prevent operable Core Spray(CS)
and RHR loops discharge pressures from dropping to less than 48 psig and that a TS LCO may result if discharge pressure is allowed to drop below 48 psig.
The operators also did not identify that the 7-day LCO for the out of service pump and heat exchanger had become a more limiting LCO when the pressure dropped below 48 psig and the loop became inoperable during the initial fill and vent.
Since this was recognized by the next shift during the subsequent fill and vent, and the LCO was entered including the time frame of the initial pressure drop, the allowed outage time for the LCO was not exceeded.
The licensee's corrective actions included each Shift Manager discussing this event in detail with his respective crew.
The involved Unit Supervisor wi 11 be required to prepare a presentation which will include the errors committed during this evolution, lack of meeting management expectations, importance of using proper documents, consequences of lack of awareness and sensitivity to the status of safety systems, and importance of adequate pre-job briefings.
The licensee's failure to implement the procedure for returning a loop I RHR pump and heat exchanger to service in an operable loop is a failure to follow procedure violation.
This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.
This non-cited violation is identified as 296/98-04-01, Failure to Follow Procedure for RHR Fill and Ven The inspector reviewed several previously recorded problems with LCO documentation.
Upon review. the inspector determined that the allowed outage time was exceeded in only one case.
That specific example was addressed as a severity level IV violation in NRC inspection report 259,260.296/97-10 (see section 08.4 for closure documentation).
The inspector determined that the root cause of the previous violation was not consistent with the cause of the current example and corrective actions for the previous violation would not have prevented the present violation.
While reviewing this event, the inspectors walked down portions of the PSC head tank and associated piping which maintains the RHR and CS system discharge piping full.
This PSC system supplies water to the system discharge piping through two IST tested check valves which perform the primary containment isolation function.
The condensate supply and storage system also supplies a source of water to the RHR and CS system discharge piping through normally closed manual isolation valves.
The inspector questioned the control of those valves and upon discussion with the licensee, it was identified that the normally closed valves were allowed to be opened by Operating Instructions OI-74.
Residual Heat Removal System and OI-75. Core Spray System while primary containment was required.
The licensee has enhanced the procedures to post an operator at the valve to close the valve if primary containment isolation is necessary.
In addition, the licensee is reviewing other procedures which may be affected by this vulnerability.
The inspector verified that this new guidance remained in the latest version of the Unit 2 and 3 OI-74 and OI-75 procedures.
Conclusions The licensee's failure to implement the procedure for returning a loop I RHR pump and heat exchanger to service in an operable loop resulted in an unrecognized entry into a more restrictive TS LCO.
The licensee's corrective actions were adequate.
CS and RHR procedures were enhanced to address a vulnerability while opening normally closed containment isolation valves.
02.1 Operational Status of Facilities and Equipment Unit 3 Core S ra S stem Walkdown Ins ection Sco e
71707 The inspector performed a detailed walkdown of the Unit 2 CS system.
The inspector reviewed the FSAR, TS, plant procedures.
and the Unit 2 Probabilistic Risk Assessment Individual Plant Examination system notebook for the CS system in preparing for the inspectio b.
Observations and Findin s General material conditions of the CS system appeared to be good.
No problems were found with the lineup of system valves, breakers.
switches or instrumentation.
While inspecting system instrumentation in the Unit 2 Auxiliary Instrument Room, on June 6.
1998. the inspector found that numerous dust covers for GE type HGA relays, used in various safety system electrical ci rcuits. were not fully inserted.
Closer examination of the relays showed that the covers were not installed properly.
These covers are removed by operations and maintenance personnel during system testing'nd maintenance.
When properly installed the dust covers are held in place with metallic retention springs located on the relay housing which clip into a recessed groove on the inside of the dust covers.
The dust covers were reinstalled with the retention springs wedged on the outside of,the covers.
This resulted in the covers not being able to be fully inserted.
Many of the retention springs were found to be broken off.
This may have been due to the stresses placed on the springs with the springs on the outside surface of the covers.
The inspector informed the licensee of this condition.
The licensee initiated a Problem Evaluation Report (BFPER98-006418-000).
The licensee-determined that the improperly installed covers did not pose an operational concern since they were not required for seismic support of the relays.
The inspector examined the interior of a sample of the ECCS instrumentation cabinets with the aid of an operator.
No broken retention spring parts were found inside the cabinets.
The inspector determined that, due to the equipment arrangement, no obvious problems would have resulted if the metallic retention spring parts fell in the interior of the cabinets.
Material conditions were generally good.
In one cabinet, part of a broken wire raceway cover was found resting on interior cabinet wiring and was removed by the operator.
Conclusion
08.1 General material conditions of the Unit 2 CS system were considered good.
The inspector identified that numerous dust covers for GE type HGA relay, used in various safety system electri.cal circuits, were not properly reinstalled flush with the cabinets.
'The improperly installed covers did not pose an operational concern.
Miscellaneous Operations Issues (92901)
Closed Violation 296/97-05-01, Failure to Reset Locked Scoop Tube.
This issue was reviewed in Inspection Report 259,260.296/98-03 and closed as 260/97-05-01.
This entry administratively closes the issue for Unit '
Closed Unresolved Item 260/97-010-02.
Technical Specification Requirements During Control Rod Drive (CRD) Accumulator Maintenance.
This item was unresolved pending additional review to ensure that regulatory requirements for inoperable CRD accumulators and entry into TS LCO were met.
The Unresolved Item addressed two major issues; operability of the CRD accumulators during normal operations when an accumulator low pressure alarm actuates, and operability of the accumulators during a previous Unit 2 work activity in which the accumulators were rendered inoperable (one at a time) for calibration of the pressure and level switches during operations.
Res onse to accumulator low ressure alarms:
The licensee closely reviewed the actions being taken on an accumulator low pressure alarm.
During review of related Problem Evaluation Reports (PERs)
~ the inspector noted that PER 970094 contained a technical evaluation that indicated that the control rod drive would be able to fulfillits safety function with accumulator pressures as low as 895 psig.
Since the low pressure alarm setpoint is greater than or equal to 940 psig, the control rods would usually be expected to perform their safety function with low pressure alarms provided that the accumulator remains above a specified minimum pressure.
However, licensee management has decided that the practice of declaring accumulators inoperable on low pressure alarms will continue.
The importance of completing the actions required by TS 3.3.A.2 such as.
evaluation to ensure that the rod is not within a 5X5 array of another inoperable rod, was emphasized to the operators.
In addition to the NRC inspector's observations that the 5X5 array requirements were not being rigorously reviewed with each inoperable control rod, the licensee's quality assurance had initiated Problem Evaluation Report 980045 addressing a similar issue. 'n recent months. the resident inspectors have noted that this particular factor is being evaluated by the operators during responses to accumulator low pressure alarms.
The operators are expected to declare the rod inoperable.
evaluate the 5X5 criteria, and initiate corrective actions.
The inspectors have observed that, in most cases'he low pressure alarm is cleared in less than
minutes.
Discussions with the NRR Project Manager and NRC management indicated that since there is not a specific time in which the actions to ensure shutdown margin are required to be completed, these actions were acceptable and in compliance with requirements.
Inspection Report
98-03 describes
NRC observation of recharging of two accumulators.
No
significant deficiencies
were identified.
The inspectors
noted that the Improved Standard
Technical
Specifications,
expected to be implemented in July 1998, contain more
specific guidance
on accumulator pressure
and operability of the control
rods.
Specifically,
an accumulator
can be inoperable for an hour before
the
CRD must be declared
Additional review was conducted
regarding the requirements
for'tracking
of TS LCOs.
Revision ll of Alarm Response
Procedure
(ARP) 2-ARP-9-5A.
Control
Rod Drive Accumulator Pressure
Low/Level High added specific
requirements
for entry into a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
LCO and evaluating
5X5 array
requirements.
The ARP also specifically requires entries into the
operating
logs describing those actions.
The inspectors
have observed
that log entries
have
been
made to address all control rod inoperability
periods,
even before the
ARP contained specific requirements to do so.
(juality assurance
has completed
reviews focused
on logging of TS LCOs.
In recent
months,
no significant deficiencies
were identified.
Additionally, the inspectors
have found that the Unit Supervisors
are
consistently
aware of the
LCOs that the units are in.
The inspectors
concluded that the method of tracking the inoperable control
rods is
adequate
and meets regulatory requirements
for LCO monitori'ng.
Problem Evaluation Reports
have also been initiated regarding repetitive
low pressure
alarms
on
HCUs which were not addressed
by work requests
and other problems with the alarms.
The inspector
reviewed these
PERs
and concluded the corrective actions were adequate.
Calibration of Accumulator Pressure
Switches
Durin
0 erations:
The inspector
reviewed the work orders utilized for approximately
switch calibrations
performed during the period September
21 to
September
24.
1997.
The work was performed
on one control rod hydraulic
control unit at
a time with the reactor
at power.
Each work order
contained appropriate
precautions
and referenced
approved
procedures
for
the work.
Review of log entries indicated that typically, the
LCO for
an inoperable control rod was entered for about
15-20 minutes to
complete the work.
No single accumulator
was inoperable for greater
than
one hour.
Standard
Program
and Process
(SPP)
-7. 1,
Work Control Processes.
approved in January
1998. contains
guidance
r egarding risk assessment
for on-line maintenance activities.
The inspector
noted that Section
3.2. 1 contains
some guidance
regarding recurrent entry into a
LCO for
multiple activities.
SPP-7. 1 replaced Site Standard
Practice
SSP-7. 1.
The inspector
reviewed the revision of SSP-7. 1 in effect at the time
that the work was performed.
SSP-7. 1 did not contain
a discussion
regarding
multiple LCO entries.
Browns Ferry implements the SSP-7. 1 schedule risk assessment
through
Technical Instruction O-TI-167,
BFN Dual Unit Maintenance.
The Control
Rod Drive pumps are listed on the maintenance
matrix but the hydraulic
control units are not since the. matrix does not address
specific plant
equipment at that level.
The inspectors
concluded that no regulatory requirements
were violated
during the maintenance activities
on the accumulators.
The above review
indicates that the licensee's
actions in response
to accumulator
low
pressure
alarms were reasonable
and met regulatory requirements.
Throughout the reviews of this item, the inspectors
did not identify any
pressures
that were low enough to affect the control rod
safety function.
The licensee
has indicated to the inspectors that in
the future. it does not intend to schedule
routine calibration of
accumulator switches during power operations.
The unresolved
item is
closed.
Closed
Licensee
Event
Re ort
Unplanned
Manual
Start of an Emergency Diesel Generator
During a Scheduled
Redundant
Start Test.
A control
room operator failed to meet management
expectations
regarding touch Stop.
Thinks Ask, Act. and Review (STAR).
The operator turned
away from the control panel to verify a 'procedure
step
and did not re-perform verification that he was on the correct
switch.
The inspectors
have observed that management
has continued to
emphasize correct implementation of self-checking
and verification
activities since this incident.
Incorrect switch manipulations
by
control
room operators
have been rare at Browns Ferry in recent years.
The inspectors
have observed that overall implementation of these
actions
has continued to be more consistent.
For example,
Inspection
Report 98-03 contains
several
positive observations
of self-checking
and
verification actions during specific evolutions.
The inspectors
have
also noted that the emphasis
on these techniques
during training
sessions
has also been strengthened
in recent
months by management.
This
LER is closed.
Closed
Violation 296/97-10-03,
Failure to Complete
TS Action for
Containment Isolation Valve.
This violation involved the
failure to complete
a
TS action for
a containment isolation valve.
The
licensee
responded to this violation in a letter date
December
23,
1997.
The licensee
determined that the root cause of the violation was that
the operations
crew lacked
a questioning attitude.
The Senior Reactor
Operators
(SROs)
developed
a mind-set regarding the failure mechanism
for the valve problems
and did not fully assess
new information for the
effect on TSs.
The licensee
performed sensitivity training with the
on
LCO entries
and methodology during troubleshooting.
This
violation is close II. Maintenance
Conduct of'Maintenance
Reactor
Core Isolation Coolin
Governor Control
S stem Calibration
Ins ection Sco
e
62707
37551
The inspector
observed
portions of performance of ECI-0-071-GOV001.
Reactor
Core Isolation Cooling (RCIC) Governor Control System
Calibration.
Assistance
in troubleshooting efforts by engineering
personnel
were also observed
when unexpected
results
were obtained
during calibration performance.
Subsequent
Incident Investigation
Team
activities were also reviewed.
Observations
and Findin s
On June
23, the Unit 2 RCIC system
was taken out of service for
scheduled
maintenance.
modifications,
and testing.
On June
24. the
inspector
observed
the performance of portions of the governor control
system calibration.
The RCIC governor calibration is performed by removing the normal
turbine inputs to the governor
and connecting'xternal
test equipment to
simulate turbine conditions.
Governor output voltage is measured.
compared to acceptance criteria and adjusted if necessary.
Problems
were encountered
during system static calibration testing.
RCIC turbine speed
(using
a sine wave generator)
and
pump flow (using
a
DC current source)
were used to simulate operation at low speeds.
Output voltage was expected to be relatively stable,
however,
a
fluctuating output was observed.
The fluctuations were first believed
to be indicative of the need to adjust the governor settings.
The
inspector questioned
the setting of the sine wave generator
voltage.
The procedure called for an output voltage in AC volts root mean square
(RMS).
However, the display on the instrument
appeared to be set
on
peak-to-peak
voltage.
The electrical
mechanics
attempted to change
output voltage function of the sine wave generator
and were unable to
obtain
an
RMS voltage readout.
The electrical
mechanics
then adjusted
output voltage to read the required value as measured
by a portable
digital voltmeter.
This action resulted in an output voltage that was
closer to the required output but did not resolve the voltage
fluctuations*.
Additional troubleshooting
was later performed
by a team of engineering
and maintenance
personnel.
The team initially bel,ieved that the problem
with the fluctuating output voltages
was due to the removal of a wire
lead on
a governor terminal
when installing the test equipment.
This
troubleshooting effort did not resolve the fluctuating output voltage.
After consulting the technical
manual
for the sine wave generator,
which
was not originally present at the job site. the troubleshooting
team
found that the initial settings for the sine wave generator
were
incorrect (i.e., sine wave voltage offset and wave symmetry).
Removal
of these functions alleviated the voltage fluctuations.
The inspectors
reviewed the training requirements
for maintenance
personnel
to perform. the governor calibration.
The inspectors
found
that the personnel
involved with the task
had completed the training.
The licensee initiated
a
PER due to the problems encountered
during RCIC
testing.
The licensee
appointed
an Incident Investigation (II) team to
evaluate
the
RCIC testing.
This was due to the similarities of the
problems encountered with past problems during testing of the High
Pressure
Coolant Injection system
(see
M1.4 of IR 97-05)
and the Standby
Gas Treatment
system
(see Ml. 1 of IR 98-02).
At the end of the inspection period the II team had not completed their
review.
The inspector
reviewed the preliminaries findings of the team.
Some of the more significant findings were as follows:
~
The maintenance
workers were trained with test equipment that was
different than that used during the
RCIC governor calibration
surveillance.
~
Knowledge retention
by the personnel
performing the RCIC governor
calibration
may not have
been sufficient due to the time interval
between training and task performance.
Some of the maintenance
workers were found to have been trained
on the task performance
several
years prior to actual
performance.
Due to the similarities of the maintenance
and test equipment
problem
encountered
during this RCIC system governor calibration
as
compared
with past problems, this is identified as
an Inspection.Follow-up Item
(IFI) 260,296/98-04-01,
Use of Maintenance
and Test Equipment.
This IFI
wi 11 focus on the use of maintenance
and test equipment during the
performance of maintenance
and surveillance activities.
c.
Conclusion,
Test equipment
was not set
up properly and contributed to unnecessary
troubleshooting
delays in the calibration of the
RCIC governor.
Maintenance
personnel
were unfamiliar with test equipment operation
although trained to perform the task.
Preliminary licensee
investigation efforts were adequately
focused
on the issues that emerged
during performance of the
RCIC system governor calibration.
RCIC S stem Rated
Flow at Normal
0 eratin
Pressure
Ins ection
Sco
e
71707
61726
The
inspector
observed
the performance of the Unit 2 RCIC system flow
rate surveillance.
The testing
was performed in order to return the
syst'm to operable status
following a period of preventive
and
corrective
maintenance.
Observations
and Findin s
On June
25 and 26,
1998, the inspector
observed the performance of 2-SI-
4.5.F. 1.d,
RCIC System Rated
Flow at Normal Operating Pressure.
This
test is periodically performed to demonstrate operability of the
system in accordance
with TS.
The test
was being performed following a
period of preventive
and corrective maintenance.
All personnel
involved with performing the test or post maintenance
testing attended
the brief.
The prejob brief was considered
instrumental
in good coordination of the various post maintenance
tests
performed during the surveillance.
During the time-to-rated-flow and pressure
portion of the test.
the unit
operator
stopped the procedure
and questioned
why the procedure did not
require opening the minimum flow valve prior to starting
RCIC turbine.
After discussions
with the other operators
and system engineer in the
control
room, the operators
determined that this was acceptable
since
the test
was simulating
an automatic initiation and would not be run at
a low flowrate for any significant amount of time.
During the
performance of the surveillance,
control of the operator trainee
performing the test
was good.
Conclusion
The prejob brief for the
RCIC System
Rated
Flow at Normal Operating
Pressure test
was detailed
and instrumental
in successfully coordinating
the performance of the various post maintenance
tests
performed during
the surveillance.
The operator
performing the time-to-rated-flow
portion of the test demonstrated
a good questioning attitude in
questioning the acceptability of an abnormal
system valve lineup.
Control
and supervision of the unit operator trainee
was goo M1.3
Packin
Ad ustment
on Hi h Pressure
Coolant In ection
S stem Steam
Admission Valve
Ins ection
Sco
e
62707
The inspector
reviewed the licensee's
actions
when
a maintenance
worker
adjusted the packing on High Pressure
Coolant Injection (HPCI) system
steam admission valve without work order authorization or operations
approval.
Observations
and Findin s
On June
12,
1998,
a steam leak was found on the Unit 2 HPCI system in
the vicinity of the 2-FCV-73-16 (steam admission valve) packing gland.
This is
a large motor operated
valve that is within the scope of NRC Generic Letter 89-10 and subject to special testing requirements.
Later that day. the steam leak was discussed
at the operations shift
turnover meeting.
Since water was found to be dripping on
a nearby
junction box, the work to be performed
was classified
as Priority 2
This means that work would be performed continuously until completed.
A
maintenance
worker who attended
the meeting discussed
the steam leak
with maintenance
supervision.
The maintenance
worker was then directed
to perform an inspection of the 2-FCV-73-16 steam leak, redirect water
leakage to a catch device,
and to perform inspections of the nearby
electrical junction box.
While inspecting the steam leak, the worker noticed that the packing
gland nuts were loose.
The maintenance
worker tightened the packing
using
a wrench.
However
. the type of packing used
on this valve
requires special
torquing requirements
and
may necessitate
special
valve
testing.
Discussions with maintenance
supervision indicated that the
maintenance
worker believed that adjusting the packing was acceptable
since the work was designated Priority 2 (i.e., urgent)
and had been
discussed
at the operations
turnover
meeting.
A work order was written to check the torque
on the packing gland nuts.
The torque on the packing gland nuts was found to be within
specifications.
Although not required
due to the as found torque, the
licensee successfully
performed motor operated
valve testing to ensure
that the packing adjustment
had not affected the acceptance criteria.
I'he
licensee
conducted briefings with mechanical
maintenance
to discuss
the occurrence
and reiterate the requirements
prior to performing
maintenance
work.
The licensee
also revised
SSP 6.2, Maintenance
Management
System. to require
a control
room pre-job brief before any
maintenance
work is performed
on urgent jobs.
The inspectors
reviewed
SSP-6. 1. Conduct of Maintenance.
and found that the actual
work
performed required approval of operating personnel
prior to work
performance.
This non-repetitive,
licensee-identified
and corrected
violation is being treated
as
a Non-Cited Violation (NCV). consistent
with Section VII.B.1 of the
This
NCV is
identified as 260/98-04-03.
Unauthorized
Work Performed
on Leaking HPCI
Conclusion
A maintenance
worker performed unauthorized
work by adjusting valve
packing without operations
authorization.
Licensee corrective actions
were considered
good.
Additional motor operated
valve testing
was
performed although not required
by the as-tound condition.
Maintenance
and Material Condition of Facilities and Equipment
Unit 3 Torus
0 namic Restraint
Ins ection Sco
e
61726
37551
The inspector
reviewed the licensee's
actions for a leaking torus
dynamic restraint
(snubber)
on Unit 3.
Additionally, the inspector
observed the performance of functional testing of the torus dynamic
restraint following maintenance.
Observations
and Findin s
For several
weeks prior to June 3,
a large Bergen-Paterson
torus dynamic
restraint
(RG-11) located
between the Unit 3 suppression
chamber (torus)
and the reactor building had been leaking oil from the external fluid
reservoir.
The licensee
had been monitoring the oil level
and
periodically added oil as necessary.
Preparations
to replace the
external fluid reservoir with parts
from a Unit
1 torus dynamic
restraint
were initiated.
The inspector
reviewed the basis for snubber operability with a leaking
external fluid reservoir.
A previously completed engineering
analysis
was provided which indicated that an oil addition frequency greater
than
3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> supported
operqbi lity.
The leakage rate basis
ensured
no air
would infiltrate the snubber
main body during
a design basis
loss of
coolant accident.
The inspector
concluded that the evaluation
adequately
supported
snubber operability.
On June 3,
1998. operations
declared the snubber
based
on
visual level
and snubber
temperature,
although the level'had not dropped
to the point where air could have been introduced to the main body of
the snubber.
and entered
a 72-hour
LCO in accordance
with TS 3.6.H.
On
the morning of June 4. attempts
were made to refill the snubber
reservoir to an acceptable
level.
While adding oil to the snubber,
the
leakage
increased significantly.
The licensee conservatively
made the
decision to replace the oil reservoi r.
The inspector observed portions of the snubber
reservoir replacement.
No problems were noted.
The licensee
then proceeded to perform
a
functional test
on the snubber
per
3-SI-4.6.H-2C.
Functional Testing of
Bergen-Paterson
Torus Dynamic Restraints.
The functional test strokes
the snubber
and ensures
that no air is in the main body of the snubber.
Additionally, the inspector
observed the surveillance
performance.
Actual testing
was performed using contractors
and contractor supplied
special test equipment.
The inspector observed
good control of the
contractors
throughout the test.
Conclusion
The licensee effectively performed'orrective
maintenance
on
a Unit 3
torus dynamic restraint that had
a leaking oil. reservoi r.
The licensee
maintained
good control of contractor personnel
performing the
functional test of the torus dynamic restraint.
Miscellaneous
Haintenance
Issues
(62707,
92902)
Closed
Violation 260 296/97-05-02,
Failures to Implement Maintenance
Procedures.
The inspector verified the corrective actions
described in
the licensee's
response letter.
dated July 1,
1997, to be reasonable
and
complete.
The Systematic
Assessment
of Licensee
Performance
(SALP)
letter,
dated
May 21 '998,
noted that overall
human performance
compared to the previous
assessment
period improved;
however,
operational
challenges
continued to be caused
by inattention-to-detail
by maintenance
workers.
This was primarily due to problems
encountered
during the earlier portion of the assessment
period (September
8,
1996
through April 18, 1998).
Additionally. the licensee
has taken steps to
systematically track and analyze
human errors in the maintenance
area
as
part of self assessment.
This violation is closed.
Closed
Violation 260 296/97-07-02,
Foreign Material Exclusion Controls
not Implemented in Accordance with Procedures.
The inspector
verified
the corrective actions described
in the licensee's
response
letters,
dated August 14.
1997.
and September
26,
1997, to be reasonable
and
complete.
Recently.
the Browns Ferry site procedure
for foreign
material exclusion
(FHE) controls
was replaced with TVA Nuclear Standard
Programs
and Processes
(SPP) 6.5
~ Foreign Material Control.
The new
procedure simplifies the administration of foreign material exclusion
controls.
For example.
the original site specific procedure established
5 levels of FHE controls whereas
SPP-6.5
has consolidated
and simplified
these
requirements
into 3 levels of controls.
The inspector verified
that the licensee's
corrective procedural
changes
for the violation were
contained in SPP-6.5.
This violation is closed.
Closed
Violation 260/97-09-01,
Functional Testing of Snubbers
While
not in Refueling Outage Conditions.
The licensee
performed
a review to
verify that all other refueling outage
TS surveillances
were
incorporated into the outage surveillance
schedule.
As
a result the
licensee identified an additional
TS refueling surveillance that was not
included in the outage surveillance
schedule.
The inspector verified
that the licensee's
corrective actions
were adequate
and complete.
This
violation is closed.
III. En ineerin
Conduct of Engineer ing
0 eratin
Limit Minimum Critical Power Ratio Correction Coefficient
h
Ins ection Sco
e
37551
The inspector
reviewed the licensee's
actions following the discovery of
an incorrect correction factor to the operating limit minimum critical
power ratio
(OLMCPR).
This correction factor
(TAU) is used to adjust
the
OLMCPR based
on slow control rod scram times.
Observations
and Findin s
On Nay 18,
1998, while performing
a review due to implementing
Improved
Standard
Technical Specifications,
General Electric informed the
licensee that the method
used to calculate the slow control rod
correction factor
(TAU) was incorrect in the Units 2 and
3 Core
Operating Limits Report
(COLR).
Based
on the results of scram insertion
time testing,
TAU is calculated
and adjusts the
The
OLMCPR was
determined to be slightly nonconservative
for Unit 3 based
on control
rod scram time testing.
The licensee
placed additional controls
on Unit
3 thermal limits to ensure that the
OLMCPR was not
exceeded.'rior
to Unit 2 cycle 7, the licensee
performed their
own core reload
analysis.
In the 1986 time frame,
General Electric changed the method
used for performing the core reload analysis to an updated version,
Gemini.
The assumptions
used for performing the reload analysis
and in
calculating
TAU were changed to reflect
a newer control rod scram time
statistical
database.
At that time, all three
Browns Ferry units were
in long term shutdown.
The licensee did not update the methodology for
performing the reload analysis
and determining
TAU to reflect changes
in
the database.
The methods
used
by the licensee for calculating
TAU and
the reload analysis
were based
on an older control rod scram time
statistical
databas Beginning with the Unit 2 cycle
7 in 1992,
General Electric has
been
performing core reload analysis for the licensee.
Since the Gemini
method for performing the reload analysis utilizes assumptions
made in
the newer control
rod scram time statistical
database.
the results of
the reload analyses
were not consistent with the licensee's
method for
calculating
TAU.
Consequently.
the
OLMCPR used since then have
been
potentially nonconservative
due to not utilizing the updated control rod
scram time statistical
database
for calculating
TAU.
The licensee
reviewed operating data for the affected cores
(Unit 2
cycles 7.8.9,
and
10 and Unit 3 cycles
7 and 8).
The data also showed
that the
OLMCPR was not exceeded
at any time while the incorrect method
of calculating
TAU was employed.
Therefore,
no potential for exceeding
the Safety Limit MCPR (if an abnormal
operating transient occurred)
existed during the affected operating cycles.
The inspector
reviewed
the licensee's
methods for determining whether the
OLMCPR was exceeded.
The inspector
found that conservative
methods
were used (e.g.,
using the
worst
TAU for any fuel bundle type with the wor'st case
MCPR value).
The
licensee also reviewed the methods for calculating the other thermal
limits and found that they were not dependent
on the different database
methods (i.e.,
Genesis
or Gemini).
The inspector
reviewed the licensee's
corrective actions (i.e., placing
additional restrictions
on OLMCPR, revising the
COLRs, making necessary
software changes to the Integrated
Computer System
and 3D-Monicore) and
determined that they were performed promptly.
The licensee attributed
the root cause of using the incorrect values of TAU to the process that
changed the responsibility for performance of the reload analysis to a
different organization.
As a result of review of the Institute of Nuclear Power Operations
(INPO) Significant Operating Experience
Report 96-2.
Design
and
Operating Considerations
for Reactor
Cores,
the licensee
has instituted
upgrades to the review process for core reload analyses
(SPP 10.8,
"Nuclear
Fuel
Management,
Rev. 1").
These include increased
coordination
and communication
between
design organizations,
additional
reviews at designated
stages
throughout the core reload design
process'nd
increased
licensee oversite to the vendor's control of design input
and calculational
methods.
The inadequate
method for control of the design interfaces
and for
coordination
among participating design organizations
constitutes
a
violation of 10 CFR 50, Appendix 8, Criteria III, Design Control.
This
non-repetitive,
licensee-identified
and corrected violation is being
treated
as
a Non-Cited Violation, consistent with Section VII.B.1 of the
This
NCV is identif'ied as 260.296/98-04-04.
Incorrect
TAU Constant
Used to Adjust Operating Limit MCP Conclusion
E8
E8.1
The correction coefficient
(TAU) 'used to adjust the operating limit HCPR
for slow control rod scram insertion times was incorrect for several
Unit 2 and
3 operating cycles,
however,
the corrected
OLHCPR was never
exceeded.
Weak design controls were in place
between the licensee
and
the contractor performing core reload analysis.
The licensee corrective
actions were prompt and complete.
Hiscellaneous
Engineering
Issues
(92903)
Closed
Unresolved
Item 260 296/97-03-01
~ Review of Switchyard Control
Power.
Following a loss of offsite power to Unit 3 during
a refueling
outage.
the inspectors
had noted that switchyard control
power was
supplied by one battery board
and questioned
whether this met the intent
of General
Design Criteria
(GDC) 17.
A request for Technical Assistance
was submitted for Nuclear Reactor Regulation
(NRR) review.
On June
12,
1998.
NRR completed review of the issue
and concluded that
the
BFN offsite power system design
meets the requirements of GDC 17.
The Unresolved
Item is closed.
E8.2
Closed
Ins ection Follow-u
Item 260 296/97-007-03,
Spent
Fuel
Pool
Cooling System Heat
Removal Capacity.
During Follow up of inspector
observations
that predicted spent fuel pool temperatures
during
refueling outage activities did not match actual
pool temperatures,
the
inspectors
noted that the licensee's
practice of calculating time after
shutdown at which the fuel pool gates could be installed was not
reflected in the description of Spent
Fuel
Pool Cooling System
(SFPCS)
capacity in the Updated Final Safety Analysis Report
(UFSAR).
Immediately following a core off-load of 1/3 of the core to the pool,
the gates
separating
the pool from the reactor cavity are not installed
since the
SFPCS
does not have capability to remove the decay heat.
The
licensee
performs calculations of the decay heat
and determines
the time
at which the gates
could be installed.
Section 10.5.5 of the
states that the
SFPCS
can keep pool temperatures
below 125 degrees
F
when removing maximum normal heat load from the pool with maximum
reactor building closed cooling water
(RBCCW) temperatures.
It should
be noted that supplemental
spent fuel pool cooling
(RHR system assist)
is normally available to cool the spent fuel pool if necessary.
In response to the inspector's
questions,
the licensee initiated Problem
Evaluation Report
(PER) 971322.
The SFPCS
system engineer
performed
a
detailed review of the issues.
In addition to confirming that the
did not adequately
describe the
BFN practice regarding fuel pool gate
installation and
SFPCS capacity,
the engineer
identified several
other
deficiencies:
Cl
The value listed in UFSAR Table 10.5-1
as
"maximum possible heat
load" was
not correct.
The value of 29E+06 BTU/hr was based
on
16 day minimum core off-load time which is no longer valid.
The
actual
value for maximum heat load is dependent
on calculated
heat
removal
system capability
and administrative controls
on fuel pool
gates.
The licensee
performed
a detailed calculation of current
actual
SFPCS
and
RHR assist
fuel pool cooling capacities.
The
results indicated
a total capacity of 35E+06 BTU/hr at
150 'F
which bounded the 29E+06 BTU/hr value listed in the
The
inspector
noted that the calculation included allowances for heat
exchanger
tube plugging and used conservative
values of RHR
.service water temperature.
Outage Risk Assessment
and Hanagement
(ORAN) calculations for heat
removal capability of the
SFPCS did not consider that heat
exchanger
tube plugging had reduced the capacity below design
value.
Detailed review indicated that the actual
SFPCS capacity
was less
than the value (27.6E+06
BTU/hr at
125 'F) included in a
1977
submittal to the
NRC for
a high density fuel storage
system
(HDFSS).. The actual
value was about
19E+06 BTU/hr at 125 'F which
corresponds,to
about
35E+06 BTU/hr at 150 'F.
As stated in
section 10.5.5 of the
125 'F is
a normal operational
limitation on SFP water temperature,
150 'F is
a maximum limit for
larger than normal core off loads,.
If temperature
appears
to be
likely to exceed
125 'F
RHR assisted
fuel pool cooling is
available to maintain temperature
less than
150 'F for the benefit
of personnel
working near the SFP.
The effect of the different
heat values
was not significant since
35E+06 BTU/hr at
150
F
bounded the heat load of Z9E+06 BTU/hr at
150 'F.
While the total
.margin assumed
in the Safety Evaluation Report
(SER) was not
available,
the conclusions
continued to be valid.
As discussed
above.
an error had caused
inaccurate
fuel pool
cooling capacities to be documented.
That information was used in
a 1996 safety assessment
to increase
the maximum possible fuel
pool cooling heat load values in the
UFSAR from 27.6E+06 BTU/hr to
29E+06 BTU/hr.
Additionally, the licensee
noted that
a safety
evaluation
was not completed since the
UFSAR change
was considered
insignificant because it reflected values in the 1977
HDFSS
submittal
and
SER.
The change
was based
on
a 1978
NRC (SER) in
which the
NRC interpreted the TVA full decay heat load curve as
Z9E+06 BTU/hr after
16 days.
As discussed
above.
the actual
heat
removal capacity
(35E+06BTU/hr at
150 'F) was well above the decay
heat load In March 1998,
UFSAR Change
Package
17-001
was completed.
The change
revised. the values listed in Table 10.5-1 to reflect design capacity
heat
removal capabilities.
The change also clarified how BFN assures
that heat loading is withi'n capabilities of the SFPCS.
RHR assist,
and
Additional Decay heat
Removal
(ADHR) systems.
ADHR is
a recently
installed large capacity cooling system designed to cool the fuel pool
and connected
volumes during refueling outages.
The revision is
expected to be incorporated into UFSAR revision 17.
The licensee
attributed the cause of the
UFSAR not reflecting the actual
operation to
inadequate
documentation of changes.
The licensee is still in the process of a detailed
programmatic
examination of the
Revision
2 of Technical Instruction (TI)-353
contains
guidance
on the current review process.
The licensee is
utilizing a team review approach with different site groups
represented
on the team.
The review has
been identifying on differences
between
UFSAR descriptions
and actual
operations
such
as this issue.
ORAM methodology
has
been revised to ensure that updated
SFPCS
heat
exchanger
data is used for calculations of decay heat
removal
capacities.
Recent predicted fuel pool temperatures
have been very
close to actual
values.
The actual capacity of the
RHR assist
mode of
fuel pool cooling was calculated
as described
above.
Licensing reviewed
the results
and determined that no issues
existed which required
reporting to the
NRC.
TVA has significantly strengthened
50.59 procedures
since the 1996
safety assessment
was completed.
A safety evaluation is required for
any
UFSAR changes.
The inspectors
concluded that the licensee's
engineer
performed
a
thorough review of the issues.
While NRC inspectors
had identified that
the
UFSAR description of fuel pool heat loading did not reflect actual
operating practices,
the licensee's
review identified several
other
deficiencies.
The inspectors
have observed that refueling outage
activities are well scheduled
and. DRAM is emphasized
during the outages.
Corrective actions were completed,
including detailed calculations of
fuel pool cooling capabilities
and revision of the
UFSAR, within an
acceptable
time period.
Although the
UFSAR did not accurately reflect
the actual
operating practices
regarding the spent fuel pool gates,
the
potential safety role of the
SFPCS is limited.
In safety analyses.
emergency
fuel pool
makeup is relied upon to maintain the pool inventory
sufficiently high to prevent spent fuel damage.
There have
been
no
problems associated
with fuel pool cooling capacity
BFN, pool
temperatures
have
been maintained within operating limits.
This
inspection follow-up item is close E8.3
Closed
Ins ection Follow-u
Item 296/98-01-03,
Slow Control
Rod Arrays
Five Percent
Insertion Scram Times.
This item addressed
slow five
percent insertion times for four groups of control rods attributed
to
sticking exhaust
valve scram solenoid pilot valves
(SSPVs).
The
inspection follow-up item was opened
because
the cause of the problem
had not yet been determined.
The licensee
had requested
evaluation
of=
the slow SSPVs
by General Electric and Automatic Switch Company
(ASCO).
The inspector
reviewed the evaluation which concluded that
a root cause
could not be determined.
Testing
was performed
by mounting the valve
internals inside new SSPVs.
aging the assemblies
and testing for delays.
Although the testing confirmed that
some sticking occurs with the Buna-N
material.
ASCO was not able to duplicate the increased
response
times
seen
by the licensee.
No evidence
was found of contamination in the
control air system or lubricant effecting the elastomer material.
The inspector
reviewed the corrective actions listed in Problem
Evaluation Report 98-0089
and concluded that the licensee's
actions to
date
have been
adequate to address
the problem.
Insertion times since
the January
1998 incident have
been within requirements
and no other
pattern of degradation
has
been identified.
In response to questioning.
the licensee
indicated that plans are to replace the Buna-N material
with an upgraded
Viton material in about
50 percent of the hydraulic
control units during the next refueling outage
(September
1998).
Engineering indicated that the material would be within service life
limits through the next operating cycle.
The inspector
requested
verification that the Buna-N material
was not restricted
by the total
accumulated
"shelf life" and service life.
A licensee
engineer
subsequently
identified that Environmental Qualification binder
BFNEQ-
SOL-004 contains
a statement that the material
was to be replaced after
ten years
from date of manufacture or five years of service life,
whichever occurs first.
Other information in the
BFN harsh
environmental
data
base simply stated that the Buna-N material is to
replaced after five years of service life.
The Buna-N material in the
Unit 3 exhaust
diaphragms is at or greater
than ten years
from date of
manufacture.
PER 98-007412-000
was initiated to address this issue.
General Electric Service Information Letter (SIL) 585, dated January
4,
1995,
addressed
SSPV and air system maintenance.
The inspectors
reviewed the SIL and noted that the SIL specifically states
that service
time guidelines
assume that service time occurs after
maximum
recommended
storage
time.
The SIL lists eight years
as
recommended
maximum storage
time and 4 years
maximum energized application service
life.
The SIL stated the storage conditions that are assumed for
storage time limitations.
The inspectors verified that the actual
storage conditions for the spare
matched those described
in
the SI The licensee
indicated that although the cure date for the Buna-N
diaphragms installed in Unit 3 was not available. it was reasonable
to
conclude that the diaphragms installed in Unit 3 in February
1996 are
generally in compliance with the SIL recommendations.
The inspector
reviewed purchase
documentation
which described
a large quantity of
solenoid valve parts kits that were received in October
1988.
Shelf
life documentation
indicated
a ten year life span.
The
SSPVs were
placed in service
on Unit 3 in February
1996, which is within eight
years of the receipt date.
The licensee
does not expect
any material
degradation
problems throughout the remaining planned service period.
This item is closed.
IV. Plant
Su
art
Radiological Protection
and Chemistry
(RP8C) Controls
Ins ection Sco
e
83750
84750
The inspectors
reviewed implementation of selected
elements of the
licensee's
radiation protection program.
The review included
observation of radiological protection activities including personnel
monitoring, radiological postings,
high radiation area controls,
and
verification of posted radiation dose rates,
contamination controls
within the radiologically controlled area
(RCA), and container labeling.
In addition, observations
were made of ALARA work planning, pre-job
worker briefings,
and job execution.
The inspectors
also reviewed
licensee
records of personnel
radiation exposure
and discussed
program details,
implementation
and goals.
Requirements
for these
areas
were specified in 10 CFR 20 and TSs.
Observations
and Findin s
The inspectors
toured the health physics facilities, the Reactor
and
Turbine building and outside radioactive material storage
areas
(RNSAs).
From review of records,
the inspectors
determined
the licensee
was
tracking and trending personnel
contamination
events
(PCEs).
The
licensee
had tracked approximately
PCEs for the 1998 fiscal year to
date which included skin and clothing contaminations.
This equates
to
approximately 3.3
per
1000
RWP hours.
Radiologically controlled
areas
including RNSAs, High Rad Areas,
and Locked High Rad Areas were
appropriately posted
and radioactive material
was appropriately stored
and labeled.
Selected
boundaries
were independently
measured
by the
inspectors
and the dose rates
measured
were comparable to the posted
rates.
The inspectors
reviewed operational
and administrative controls for
entering the
RCA and performing work.
These controls included the use
of radiation work permits
(RWPs) that were to be reviewed
and understood
by workers prior to entering the
RCA.
The inspectors
reviewed selected
'WPs
and observed
RWP briefings for adequacy of the radiation protection
requirements
based
on work scope.
locations
and conditions.
For the
RWPs reviewed.
the inspectors
noted that appropriate protective
clothing.
and dosimetry were required.
During tours of the plant, the
inspectors
observed the adherence
of plant workers to the
requirements.
The inspectors
observed
workers properly entering the
controlled area
by signing on to the Radiation
Exposure
System
(REXS).
The inspectors
observed that personal
dosimetry was being worn in the
appropriate location.
The inspectors
observed
workers properly using friskers at the exit
locations
from controlled areas.
The inspectors
also observed
workers
properly exiting the protected
area through the exit portal monitors
located at the East
and West security portals;
The Fiscal
Year 1998 site exposure
goal
was set at 450 person-rem.
At
the time of the inspections
the site person-rem
was about 390.67 person-
rem TLD corrected through March 31,
1998.
The inspectors
reviewed the Contaminated
Square
Footage
Data for FY 98.
At the time of the inspection there were approximately
1070 contaminated
square feet(ft').
This includes approximately 130ft'rom
UO (common),
355ft'rom Ul, 370ft'rom U2,
and 215ft'rom U3.
This was slightly
more than the goal of 1000ft'.
The licensee tracks the contaminated
.
area
as
a running 30-day average
and at the time of the inspection the
previous 30-day average
was 1140ft'.
Decontamination,
scheduled for
approximately 120ft'n the reactor building of Unit 2 on June
29.
1998.
would reduce the contaminated
area to approximately 950ft'hich would
be below the 1000ft'oal.
The inspectors
attended
a meeting
and reviewed minutes of three previous
meetings of the High Impact Team (HIT) assigned
the Unit 3 Drywell
Decontamination.
The team is Chaired
by the Radwaste/Environmental
Supervisor
and consists of members
from Site Engineering,
Radcon,
Maintenance,
In-Service Inspections
Operations
Outage.
and Outage
Scheduling.
The multi-discipline team was constituted to determine the
best course of action on how to decontaminate
the
U3 Drywell which had
become contaminated
in the vicinity of an instrument sensor line leak.
Several of the smear
results
showed transferrable
contamination in
excess of 2E+6 dpm/100cm'.
Equipment lists by elevation,
location and
equipment protection requirements
had already
been factored in the plan.
The licensee
was evaluating the dress out and heat stress
factors,
had
polled the industry for like experiences
and was aggressively
planning
for the
U3 drywell decontamination
campaign.
The inspectors selectively reviewed the whole body counting program
procedures.
RCI-8 titled Bioassay
Program Revision 13, dated 02/03/98,
RCI 8.1 Internal Dosimetry Program
Implementation Revision 22A. dated
01/05/98,
the January
12,
1998 Whole Body Counting Measurement
Quality
Assurance
Report and the daily calibration checks.
The inspectors
determined that the licensee
was following the requirements of the
reviewed procedures.
The Quality Assurance
checks
were performed
as
requi red and the daily 'calibration checks
were also performed
as
required.
The tracking and trending of count data were performed
as
required
and the system
met Minimum Detectable Activity values.
Conclusion
Radiological facility conditions in radioactive waste storage
areas,
health physics facilities and Turbine and Reactor Buildings were found
appropriate
and the areas
we'e properly posted
and material
appropriately labeled.
Personnel
dosimetry devices
were appropriately
worn.
Radiation work activities were appropriately planned.
Radiation
worker doses
were being maintained well below regulatory limits and.the
licensee
was maintaining exposures
A special
team was
aggressively
planning the
U3 drywell cleanup.
The Whole Body counting
program was performed
as procedurally required.
V. Mana ement Meetin s
X1
Exit Meeting Summary
The resident inspectors
presented
inspection findings and results to
licensee
management
on July 15,
1998.
An additional
formal meeting to
discuss
inspection findings was conducted
on June
26,
1998.
X3
Hanagement
Meeting Summary
The Browns Ferry Systematic
Assessment
of Licensee
Performance
was
presented to the licensee at the Browns Ferry site in a public meeting
on July 11,
1998.
PARTIAL LIST OF
PERSONS
CONTACTED
Licensee
T. Abney, Licensing
Manager
J. Brazell, Site Security Manager
R. Coleman,
Acting Radiological
Control
Manager
J.
Corey, Radiological Controls
and Chemistry Manager
C. Crane, Site Vice President.
Browns Ferry
R. Greenman,
Training Manager
J. Johnson'ite
Quality Assurance
Manager
R. Jones,- Assistant Plant
Manager
R. Moll, System Engineering
Manager
G. Little. Operations
Manager
D. Nye, Site Engineering
Manager
D. Olive. Operations
Superintendent.
J.
Shaw,
Design Engineering
Manager
K. Singer,
Plant Hanager
J. Schlessel.
Maintenance
Manager
IP 37551:
IP 62707:
IP 71707:
IP 71750:
IP 93750:
IP 84750:
IP 92901:
IP 92902:
IP 92903:
INSPECTION
PROCEDURES
USED
Onsite Engineering
Maintenance
Observations
Surveillance
Observations
Plant Operations
Plant Support Activities
Occupational
Radiation
Exposure
Radioactive
Waste Treatment,
and Effluent and Environmental
Monitoring
Follow-up-Plant Operations
Follow-up-Maintenance
Follow-up-Engineering
ITEMS OPENED AND CLOSED
OPENED
T~e
Item Number
Status
Descri tion and Reference
296/98-04-01
IFI
260.296/98-04-02
260/98-04-03
260,296/98-04-04
Closed
Open
Closed
Closed
Failure to Follow Procedure
for
Fill and Vent (Section 01.2).
Use of Maintenance
and Test
Equipment (Section Hl.1).
Unauthorized
Work Performed
on
Leaking
HPCI Valve Packing (Section
M1.3).
Incorrect
TAU Constant
Used to
Adjust Operating Limit HCPR (Section
E1.1).
CLOSED
T~e
Item Number
Status
Descri tion and Reference
296/97-05-01
260/97-010-02
Closed
Closed
Failure to Reset
Locked Scoop Tube
(Section 08.1).
Technical
Speci ficati on Requirements
During Control
Rod Drive (CRD)
296/97-10-03
260,296/97-05-02
260.296/97-07-02
260/97-09-01
260.296/97-03-01
IFI
260.296/97-007-03
IFI
296/98-01-03
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Closed
Accumulator Maintenance
(Section
08.2).
Unplanned
Hanual Start of an
Emergency
Diesel Generator
During
a
Scheduled
Redundant Start Test
(Section 08.3).
Failure to Complete
TS Action for
Containment
Isolation
Valve (Section 08.4).
Failures to Implement Maintenance
Procedures
(Section
H8. 1).
Foreign Material Exclusion Controls
not Implemented in Accordance with
Procedures
(Section H8.2).
Functional Testing of Snubbers
While
Not in Refueling Outage Conditions
(Section H8.3).
Review of Switchyard Control
Power
(section E8.1).
Spent
Fuel
Pool Cooling System Heat
Removal
Capacity (Section E8.2).
Slow Control
Rod Arrays Five Percent
Insertion
Scram Times (Section
E8.3).
Ip