IR 05000259/1991031
| ML18036A410 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 10/02/1991 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18036A409 | List: |
| References | |
| 50-259-91-31, 50-260-91-31, 50-296-91-31, NUDOCS 9110290166 | |
| Download: ML18036A410 (35) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-259/91-31, 50-260/91-31, and 50-296/91-31 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.:
50-259, 50-260, and 50-296 License Nos.:
DPR-33, DPR-52, and DPR-68 Facility Name:
Browns Ferry Units 1, 2, and
Inspection at Browns Ferry Site near Decatur, Alabama Inspection Conducted:
August 17 - September 15, 1991 Inspector:
C.
. Patter Inspector 0 z Dat S gned Accompanied by:
E.
Chr stnot, Resident Inspector M. Bearden, Resident Inspector K
vey, Res't Ins ector Approved by:
Pa J.
TV Prog cion
ef Dat S gned SUMMARY Scope:
This routine resident inspection included operational safety verification, maintenance observation, engineered safety feature system walkdown, and a
review of power ascension testing, modifications, Unit 3 activities, licensee commitments, nuclear safety review board, Part 21 reports, and reportable occurrences.
Results:
Thirty-nine days of continuous operation for Unit
ended on September 14, 1991 with an automatic trip (paragraph 2).
The trip occurred in response to low reactor water level caused by a
transient in the feed and condensate system.
The transient was initiated when a valve air supply line soldered connection failed.
Licensee management involvement in the post trip, review and plant recovery was good.
Limited work activities on Unit 3 resumed following a work stoppage to improve work control paragraph 7.
The licensee implemented
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several corrective actions to prevent Unit 3 work activities from affecting Unit 2 operation.
The limited work activities involved reactor vessel disassembly, walkdowns, and installation of contractor trailer facilities.
The licensee is continuing to integrate the Unit" 3 workforce, procedures, and organization.
Onsite meetings of the Nuclear Safety Review Board were attended, paragraph 9.
There was evidence that the offsite members held discussions with plant personnel, toured the facility, and were current on plant issues.
Members held excellent critical self-questioning discussions with the plant staff.
The technical specification requirements sampled were being met.
A negative trend was noted in the timely completion of commitments, paragraph 8; resolving of potential Part 21 issues, paragraph 9.b.;
and switchyard access concerns,.paragraph 9.a.
Examples of this were extending the resolution of control room emergency ventilation system design and training commitments in LER 260/91-10.
An unresolved item in inspection report 91-24 discussed the failure of main steam line flow Rosemount transmitters and resolution of the safety relief valves acoustic monitor card problems.
In these cases the issues were not tracked and components were delayed being returned to the vendors for testing.
In inspection report 91-21 conducted May 18-June 14, 1991, issues were raised concerning access control of the switchyard.
These concerns were not corrected.
An Independent Safety Engineering report in July had a finding that personnel and vehicular access controls to the transformer and switchyard areas ylere not adequate.
No violations or deviations were identified.
Four licensee event reports and a Part 21 issue were close REPORT DETAILS Persons Contacted.
Licensee Employees:
0. 2eringue, Vice President, Browns Ferry Operations H. McCluskey, Vice President, Browns Ferry Restart
- J. Scalice, Plant Manager
+J. Swindell, Restart Manager
"N. Herrell, Operations Manager J. Rupert, Project Engineer
- N. Bajestani, Technical Support Manager
'. Jones, Operations Superintendent A. Sorrel', Maintenance Manager G. Turner, Site (}uality Assurance Manager
- P. Carier, Site Licensing Manager
- J. McCarthy, Unit 3 Licensing
- P. Salas, Compliance Supervisor
- J. Corey, Site Radiological Control Manager Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operator s, craftsmen, technicians, and public safety officers; and quality assurance, design, and engineering personnel.
NRC Personnel:
- P. Kellogg, Section Chief
- CD Patterson, Senior Resident Inspector
- E. Christnot, Resident Inspector
- W. Bearden, Resident Inspector K. Ivey, Resident Inspector
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Operationa'i Safety Verification (71707)
The NRC inspectors followed the overall plant status and any significant
'safety matters related to plant operations.
Daily discussions were held with plant management and various members of the plant operating staff.
The inspectors made routine visits to the control rooms.
Inspection observations included instrument readings, setpoints and recordings, status of operating systems, status and alignments of emergency standby systems, verification of onsite and offsite power supplies, emergency power sources available for automatic operation, the purpose of,temporary tags on equipment controls and switches, annunciator alarm status, adherence to procedures, adherence to LCOs, nuclear instruments operability, temporary alterations in effect, daily journals and logs,
stack monitor recorder traces, and control room manning.
This inspection activity also included numerous informal discussions with operators and supervisors.
General plant tours were conducted.
Portions of the turbine buildings, each reactor building, and general plant areas were visited.
Observations included valve position and system alignment, snubber and hanger conditions, containment isolation alignments, instrument readings, housekeeping, power supply and breaker alignments, radiation and contaminated'rea controls, tag controls on equipment, work activities in progress, and radiological protection controls.
Informal discussions were held with selected plant personnel in their functional areas during these tours.'.
Unit 2 Status The unit operated continuously for 39 days until an automatic trip occurred on September 14, 1991.
At 6:33 p.m.,
a trip occurred due to low reactor water level.
A separated soldered connection on a
I/2 inch copper air supply to 2-FCV-02-190, Steam Packing Exhaust Bypass Flow Control Valve, caused the valve to fail close.
This closure reduced the flow to the condensate booster pumps causing two pumps to trip on low net positive suction head.
The trip of the booster pumps caused two of three reactor feed pumps to trip.
Reactor water level decreased to the low level scram setpoint.
Level was restored in one to two minutes with the remaining feed pump.
All other safety equipment operated as designed.
Following a review of the trip by licensee management the unit was restarted on September 16, 1991.
The reactor was critical at 3:30 p.m.,
and the main generator tied to the grid at 10:05 p.m.,
on September 16, 1991.
The inspectors observed the plant manager and other managers actively involved in a detailed post trip review of this event.
Management concluded the cause of the trip was known, equipment operated at designed, and the unit could safely be restarted.
A detailed investigation report was to follow.
The inspector will review this report as part of the normal inspection activities.
b.
Annunciator System Reliability The inspector reviewed the licensee's program for insuring that the control room has a reliable annunciator system to provide operators with indication of abnormal parameters or other equipment problems.
In particular the inspector was interested with any licensee activities associated with a potential loss of annunciation event similar to the one that occurred recently at Nine Mile Point 2.
Additionally the inspector performed a
review to determine any similar events at this facility that may have occurred within the last two year,
The inspector determined that Browns Ferry had not had any similar type events, i.e.
compl ete or significant partial loss of annunciation within the last two years.
The licensee did experience various problems during the recently completed power ascension program associated with the restart of Unit Z.
These problems were associated with frequent nuisance alarms that occurred on the 2-9-8 Panel in the main control room.
These alarms were for various remotely operated components such as station transformers, switchyard components, and cooling towers.
Some of these alarms simultaneously actuated in all.three control rooms at the same time due to-grounds which fed through a
common power supply.
The alarms were not valid conditions and in most cases were due to problems such as -failed sensors or damaged cables to those remote components.
The licensee has done a
good job of identifying and correcting these type problems.
Any known nuisance alarms are tracked on a list with a priority and due date assigned.,
Any late or significant outstanding nuisance alarms are discusse'd at the plan of the day meeting.
During another recent review the inspector noted that the licensee had removed the auto acknowledge feature from control room panels associated with the emergency diesel generators.
This modification was performed by the licensee in response to an identified problem at the Sequoyah facility where an alarm that automatically acknowledged could result in a diesel generator being inoperable without the operator being aware.
This work was performed under DCN H16734A and is discussed, in more detail in IR 91-16.
The control room annunciator system at Browns Ferry does not currently have reflash capability.
However the system is scheduled to be upgraded with that function during the DCRDR planned during 1992.
Additionally, the licensee was reviewing the'Nine Mile Point 2 event for applicability to this facility.
Site engineering personnel have made contact with personnel at the Nine Mile Point 2 facility and determined that the event is related to the unique configuration and design of their unit preferred system transfer logic. Although that review is still ongoing a preliminary determination has been made that the event does not appear to apply to Browns Ferry.
Unlike Nine Mile Point 2, this site does not have inverters but uses a series of regulating transformers, 48 volt batteries, and motor generators to provide uninteruptable power to the station preferred and non-preferred instrumentation'systems.
The resident staff will continue to follow the licensee's actions in this area.
Separation Signs and Boundary Problems On September 12, 1991, the inspector observed that some orange and black Unit 2/Unit 3 Separation Signs were missing.
The signs were missing from the reactor building ventilation pit access ladders and door 830 for mechanica')
equipment room 'A'n the Unit
0
building roof.
The same signs were a concern in IR 91-26 found on July 28, 1991.
This was discussed with licensee management on September 13, 1991.
The problem with the signs was immediately'orrected.
The audit program for these signs was reviewed.
The signs are audited once a quarter as required by SSP 12.50 using Form SSP 186.
The signs were last audited on July 16, 1991.
The licensee as an interim measure to audit the outside signs once a week until more permanent'1y attached signs are in place.
Additionally, the inspector questioned why two Unit
RHR heat exchanger outlet valves, 23-52 and 23-46, were identified as boundary isolation valves but orange tape was not on either side of the valves, to designate which side of the valves could be worked.
The licensee reviewed this question and determined that tagging was conservative and for consistency some tags may be removed.
d.
Special Nuclear Material During this period the licensee reported SNM inventory problems.
A special inspection was conducted September 3-6, 1991, to address the issues.
As part of the corrective action for the SNM inventory problems the licensee started moving SNM material out of the spent fuel pools.
This consisted of loading the SNM into a shipping cask for removal from the site.
The first cask was transported on September 17, 1991.
Two or three additional cask shipments are planned.
No violations or deviations were identified in the Operational Safety Verification.
3.
Maintenance Observation (62703)
Plant maintenance activities were observed and/or reviewed for selected safety-related systems and components to ascertain that they were conducted in accordance with requirements.
The following items were considered during these reviews:
LCOs maintained, use of approved procedures, functional testing and/or calibrations were performed prior to returning components or systems to service, gC records maintained, activities accomplished by qualified personnel, use of properly certified parts and materials, proper use of clearance procedures, and implementation of radiological controls as required.
Work documentation (MR, WR, and WO) were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which might affect plant safety.
The inspectors observed and/or reviewed the fo'Ilowing maintenance activities during the reporting perio WO 91-33214-00 which was issued to accomplish a routine preventative maintenance requirement to change grease in the Unit 2 Division II LPCI NG set.
The inspector reviewed the licensee's controls for this ongoing job which included LCO 2-91-211-3.9.B. 13 and hold order 0-91-0595.
WO 91-37598-00 which repaired the Pl.fuel oil transfer pump associated with the Unit 1/2 B diesel generator.
The inspector verified that the licensee performed the required post maintenance testing in accordance with O-SI-4.9.A. l.a(B).
WO 91-37469-00 which replaced the electrical contacts associated
. with the 87 cooling fan for the B phase main generator transformer.
The inspector observed portions of the ongoing work activities.
WO 90-14264 which was issued to accomplish routine preventative maintenance requirements on a
GE Type AK-25 breaker located in 480 volt diesel auxiliary board, compartment 6D.
The inspector reviewed the compl.eted work package to verify compliance with documented requirements.
WO 90-14527 which was issued to accomplish routine preventative maintenance requirements on GE Type AK-15 breaker located in the lA 480 volt shutdown board, compartment 6D.
The 'nspector reviewed the completed work package to verify compliance with documented requirements.
WO 91-34887 which was issued to accomplish routine preventative maintenance requirements on the 250 volt DC breaker for the HPCI auxiliary oil pump.
The inspector reviewed the associated 7 day LCO, 2-91-234-3.5.E.2.
No violations or deviations were identified in the Naintenance Observation area.
4. 'SF System Walkdown (71710)
The inspector walked down. selected portions of System 73, High Pressure Coolant Injection.
During the walkdown the inspector verified that the current configuration and handswitch lineup on the control room panel was that required to support standby readiness as defined in OI-73, High Pressure Coolant Injection.
Additionally the inspector noted the position of various valves, instrumentation and general housekeeping locally at the HPCI turbine/pump.
'The inspector made the following observations:
Housekeeping was adequate although a small contamination zone existed that was contained within the turbine skid.
Two normally closed isolation valves, 2-FCY-73-17A and 2-FCY-73-17B, are controlled from a single common control room handswitch.
These valves provide a flowpath for turbine gland seal condensate to clean radwaste.
The inspector noted that although these valves were in the correct position the panel handswitch label was
incorrectly engraved to state that the valves were normally open.
The inspector discussed this concern with the onshift SOS.
The inspector was later informed that the licensee agreed that the label was incor rect and that a label request had been generated to correct the deficiency.
On a 'later trip to the control room the inspector noted that the panel included a small tag to inform the operator that the label was incorrect.
2-PI-73-218, which provides a remote indication for the HPCI turbine exhaust pressure, was reading 5 psig.
Since the turbine had not recently operated and no condition existed that would otherwise result in having a positive pressure in the turbine exhaust, the inspector discussed this condition with the SOS.
The inspector was informed that local instrumentation for this parameter showed 0 psig and there was a
psig +/- error associated with the remote indication.
Additionally the inspector was informed that the SOS had directed that personnel walkdown the local system piping to determine there was no valve leakage or any other problem which could have caused a positive pressure in the piping.
On a subsequent trip to the control room the inspector noted that the remote indication read 0 psig.
During a subsequent tour of the HPCI room the inspector noted that licensee personnel had placed a fan such that a continuous air flow was forced toward the HPCI Pump Panel, 2-25-50, and HPCI System Panel, 2-25-63.
The licensee stated that the fan had been placed in the location by painters and that the fan would be removed.
5.
Power Ascension Testing a
~
b.
gA Coverage The inspector observed and reviewed BFNP gA organizations coverage of the PATP.
This included observation of gA personnel in the plant, attendance at meetings and review of gA monitoring activity 'reports.
The inspector also reviewed gA monitoring reports covering the period between Hay 24 - July 19, 1991.
These monitoring reports indicated that BFP gA reviewed such areas as:
TIs for. thermal expansion, process computer and core performance, feed water pumps, APRH calibration, and main turbine testing.
Also reviewed were water chemistry, compensatory air sampling, SIs, conduct of operations, TACFs, maintenance, modifications, and clearances.
No CAgRs were identified by the gA group.
The inspector concluded from this review and observations that the BFP gA group conducted adequate monitoring during the PATP.
Power Ascension Test Program JTG Review (70301')
The inspector reviewed the activities of the JTG.
The group functioned as a
subcommittee of the PORC and was tasked with reviewing and recommending for approval the RTP and PATP test
results.
This subcommittee's activities were governed by applicable plant procedures.
The inspector's review included a
summary report of the RTP and a Final PATP report.
The summary report of the RTP indicated:
a total of 43 RTP tests were generated and performed; test results were reviewed and approved; and test exceptions were reviewed and dispositioned.
The PATP report indicated:
a total of 21 tests were generated and performed; test results were reviewed and approved; and test deficiencies were reviewed and dispositioned.
The inspector concluded from this review that the JTG adequately performed the activities as designated by the PORC.
6.
Modifications (62703, 37701)
a
~
Analog Trip Unit Noise Spikes During a
recent walkdown of protective instrumentation panels performed by 'a member of the licensee's system engineering group it was noted that the LED on the "C" Main Steam Line High Flow ATUs, 2-PDIS-1-36A, 36B, 36C, and 36D, were intermittently flashing.
This equipment is intended to initiate a Group I PCIS isolation signal 'to close the MSIVs on the respective steamline whenever an abnormally high steamline flow condition exists.
This LED flashing indicated a
'otential high MSL flow condition even though the plant was operating at 100Ã rated reactor power and steam flow.
The associated instrumentation channel was indicating normally, i.e.
no meter deflection corresponding to possible spikes and no seal-in was occurring on the respective channel of the primary containment isolation logic.
Unit 2 control room personnel decided to reduce electrical output from approximately 1190 MWe to approximately 1150 MWe.
This power reduction was enough to stop the ATU LED blinking.
The licensee later determined that the condition was due to process noise spikes of sufficiently short duration, (less than 10 milli-seconds)
such that the relay contacts did not actuate resulting in a
seal-in on the respective PCIS logic channel.
lt ~
On August 26, 1991, the licensee declared a single ATU inoperable and temporary installed different capacitors on 2-PDIS-1-36D to accumulate data for evaluation by design engineering personnel.
This work activity was performed under WO 91-38631-00.
Based on this testing the licensee decided to permanently install a single 100 microfarad capacitor across the input resistor for each of the
associated MSL flow channels.
The licensee informed the inspectors that they had determined that this modification had already been performed at several other BWRs.
This work was later performed under DCN W17073A.
On August 31, 1991, an inspector observed. portions of the ongoing activities associated with the WP that was to implement DCN W17073A.
Work activities in this area were stopped when the system, engineer identified that continuing with the WP as written could have resulted in a potential
'loss of a TS required function.
That function is the turbine first stage pressure permissive (power greater than 30Ã) and
b.
includes circuity shared with the NSL flow channels that were to be modified.
Lifting of leads associated with the NSL flow ATUs would have potentially determinated other electrical leads.
The planned activity could have unnecessarily resulted in placing the plant in a less conservative condition during the performance of the work.
The work plan was revised to include temporary jumpers which ensured that the turbine first stage pressure permissive function was maintained during the work.
The revised work plan was then completed on September 5,
1991.
Although the licensee's identification of the potential problem with the original work plan occurred prior to performing any work that could have resulted in placing the plant in a less conservative condition, the inspectors are concerned that the safety assessment and impact review performed to support this planned work did not identify this discrepancy.
This concern was discussed with licensee management on September 13, 1991.
The inspectors will continue to review licensee activities in this area during upcoming reporting periods.
HPCI Low Suction Pressure Time Delay (37701)
The inspector observed portions of licensee activities associated
'ith DCN W17015A which installed Time Delay Relay, 2-91-3-73, in ECCS Division II ATU Cabinet, 9-82.
During power ascension testing HPCI did not inject into the RPV due to a spurious low suction pressure condition occur ring during system initiation.
At that time the licensee had temporarily installed a pair of time delay relays in series to prevent spurious actuation of the HPCI low suction pressure trip from 2-PIS-73-29-1 until a
permanent modification could be implemented.
These TD relays had been installed and tracked as temporary alterations under TACF 2-91-3-73.
DCN W17015A was implemented by WP 2120-9 which closed-out the TACF and replaced the pair of TD relays with a single adjustable TD relay.
The new relay has a
time delay setting for approximately
seconds.
This modification was performed after TVA contacted GE and determined that the problem had been observed at other BWRs and corrected in a
s imi 1 ar.manner.
The inspector observed portions of the ongoing work activities and reviewed the work package in use during the activities.
The inspector verified that the licensee had properly entered the required
day LCO in accordance with T.S. 3.5.E.2 requirements.
Additionally the inspector reviewed the proposed PNT requirements specified in the work package and determined that were adequate to support returning the system to standby readiness.
7.
Unit 3 Activities (60705, 30702)
The inspector reviewed the activities involved with the Unit 3 restart.
This included attending restart meetings, review of procedures, observation of field activities, and discussions with licensee representatives, TVA contractor personnel, supervisors, and coordinator \\"
a
~
Unit 3. Work Stoppage As a result of the fire wrap removal in the intake structure discussed in IR 91-26, the licensee stopped Unit 3 work activities.
TVA's field services were performing support of walkdowns and other work activities in the plant until a contractor could be selected.
TVA selected a contractor for field services. work and chose to resume work using the contractors.
Walkdown support will be provided by TVA Unit 3 maintenance until the construction contractor arrives.
The contractor will be trained, procedures in place, and implementation verified b'y management prior to performing work activities.
Some limited work activities have been resumed by GE for the vessel disassembly and Bechtel
'walkdowns requiring no physical work.'rior to resuming these activities the licensee conducted an incident investigation report and implemented several work restart requirements'.
These requirements were verified by gA.
The items verified are summarized below:
b.
c
~
Operational Sensitivity Personnel gualification and Training Work Control Process, Field Work Oversight Recurrence Control Bechtel Walkdown Requirements TVA Walkdown Requirements guality Assurance Actions The inspector discussed completion of these items with site management and gA.
A training session on operational sensitivity was attended by the inspector.
The Unit 2 / Unit 3 separation drawings were verified to be in place in Bechtel offices and procedurally controlled.
Work planning meetings were attended in Unit 2 and Unit 3.
The inspectors concluded that the actions taken supported resumption of limited work activities.
Un>t 3 Schedule The licensee developed an initial Level II schedule for Unit 3 restart.
A goal of rod pull in October 1993 and closing the generator breaker the first quarter of 1994 was established.
Once the walkdowns are complete in November 1991, the schedule will be updated.
Construction work is scheduled to start in January
)992.
Work Control Process Because of the problems associated with the Unit 3 work stoppage, the licensee added controls and interfaces for control of work.
A revision was made to SSP-12.50, Unit Separation for Recovery
ly
0
Activities, for the changes.
All work activities will be processed through a
common work control group.
Unit 2 activities will continue to be processed through the Unit 2 shift support supervisor and" tracked
.on the plant daily.work list.
Unit 3 activities will be processed initially by the work control group for an impact evaluation on Unit 2.
If the work is determined not to impact Unit 2, then the work will be allowed after approval of the Unit 3 ASOS.
If the work impacts Unit 2, then the work will be processed as any other Unit 2 work activity.
The inspector reviewed SSP-12.50, attended Unit 2 and Unit 3 work planning meetings, reviewed daily work lists, and discussed the changes with the work control supervisors.
The inspectors stressed to the work control supervisor a need for common lists between Unit 2 and Unit
and a
tracking mechanism to insure no items are
.
overlooked.
d.
Refuel Floor Work 1.)
The inspector observed and reviewed the licensee's activities involved in pumping the water out of the suppression chamber through portable demineralizers and the reactor vessel through the CRD system.
These activities were controlled by procedure 3-SOI-31, Pump Down of Unit
Torus Through Temporary Demineralizer to CST or Reactor Yessel Cavity.
The inspector noted that numerous changes to the procedure had to'e made prior to the performance of the activity.
The inspector concluded that the personnel involved with performing the activity did not coordinate this effort adequately.
The inspector discussed this item with the licensee.
2.)
The inspector observed and reviewed the licensee's activities involved in the disassembly of the Unit 3 reactor vessel.
This included lifting of the vessel shield plugs, the drywell head, and the vessel head, and the removal of the steam dryer.
A licensee's contractor, GE, performed these activities using applicable TYA procedures.
The inspector concluded from this observation and review that the vessel disassembly was carried out in a controlled manner and in accordance with approved procedures.
e.
The inspector attended the Unit 3 project meeting and discussed these and other observations and reviews with the licensee's Unit 3 representatives.
Teflon Tape The inspector observed portions of ongoing activities associated with removal of the Unit 3 RPV head, dryer removal, and steamline plug installation.
During the observation of the lifting of the RPV head an inspector noted that four steamline plugs were located on the refueling floor within the roped off contamination control zone apparently staged to be placed into the vessel for plugging
the steamlines prior to vessel floodup.
During the lifting activities the inspector determined that the approximately 2 inch diameter stainless steel threaded pipe elbows connected to each plug were made up with teflon tape.
The tape had been used as a
thread sealant for the elbows and excess tape had been used for the work.
The excess tape had become frayed and feathers of tape as long as four inches were hanging down from the threaded fittings.
Due to the concern about use of teflon tape in any application involving systems that connect to the RPV the inspector discussed this concern with licensee management.
Teflon tape is a potential problem in applications with stainless steel due to breakdown of the teflon into florine with excessive temperatures and radiation exposure.
During a later meeting held with the licensee for the purpose of discussing this issue the inspector determined that use of the tape in this application was in accordance with GE's design for these particular steamline plugs.
Use of teflon tape at Browns Ferry is authorized when not used in a permanent application in contact with water systems connecting to the RPV and when approved on.a case by case basis by the chemistry department.
The licensee determined that it would not be. necessary to change the thread sealant.
Based on this additional information the inspector concurs with the licensee's determination with respect to changing the thread sealant.
Additionally licensee management stated that they were in agreement with the inspector that the excess tape was not appropriate for something to be placed into the RPV even for a temporary application.
During a subsequent trip to the refueling floor to observe placement of the plugs into the steamlines the inspector noted that the licensee had removed the excess tape from each of the elbow fittings.
The inspectors will continue to review the licensee's program for control of usage of teflon tape during upcoming reporting periods.
8.
Licensee Commitments The inspector noted during the review of licensee correspondence two instances where a
commitment date was extended.
In both cases, the letters did not specify who in the NRC agreed to the commitment change and when.
The first example involved the corrective action plan for the CREV.
BFNP was granted an approval to operate during cycle 6 with the CREV technically inoperable because it does not meet its design basis.
As part of this approval, the long-term corrective action plan was to be submitted to the NRC within
days after Unit 2 restart.
Unit
restarted on May 24, 1991.
The letter stated the issue was still being evaluated and the commitment was being rescheduled until November 22, 1991.
Discussions with the BFNP licensing and NRC Project Manager revealed a discussion did occur about the commitment being late but did not specifically discuss rescheduling the commitment until November 22, 199 The second example was LER 260/91-10, revision one, dated August 23, 1991.
This LER discussed that a August 1, 1991 commitment to review an event investigation with affected Plant Personnel.
This was completed for all except Operations which would be completed by September 9, 1991.
Discussions with the plant licensing staff indicated the change in dates was not discussed with the NRC.
The inspector discussed with plant management on August 30, 1991, the timely completion of commitments was necessary to ensure corrective actions are completed.
In an event that unusual circumstances prevent fulfillment of a commitment the change in commitment should be discussed with the NRC and stated in the appropriate letter.
These two recent examples are indication of a negative trend and weakness in the licensee fulfillment of NRC commitments.
9.
NSRB The inspector attended selected activities of the site NSRB meeting conducted September ll - 12, 1991.
Numerous issues at the plant were addressed in the NSRB meeting.
Items of particular interest were discussed by the inspector with licensee management on September 13, 1991 and are discussed below:
Switchyard Review The ISE group presented a copy of this audit to the NSRB, The NRC inspector conducted a review of switchyard control and documented this in IR 91-21 performed between May 18 - June 14, 1991.
Problems with access and work control in the plant switchyard were identified.
The ISE group reviewed this area during July 1 - July 22, 1991, and noted similar problems which still have not been corrected.
The findings were issued to the Vice President, Browns Ferry Operations on July 31, 1991, in report ISE-BFN-91-R02.
One finding and two observations were identified.
Findings are defined as issues which presently, or in the future, could have an adverse impact on nuclear safety, personnel safety, plant reliability, or significant financial consequence.
The finding was that personnel and vehicular access control to the transformer yard and switchyard areas was not adequate.
Several elements of this finding were as follows:
A section of fence for the transformer yard was missing leaving the yard open at all times.
Signs describing access requirements were not consistently poste It was reported by Nuclear Security that more than 70 entries per day into the transformer yard were being made by Nuclear Security vehicles.
Signs were not posted
- nor were procedural requirements established for vehicle speed limit or for a flagman/observer to accompany vehicles in the transformer or switchyard areas.
Key control was inadequate.
Five personnel had.been terminated but still had an assigned key.
The first observation was that labeling of equipment in the transformer yard and switchyard areas needed improvement.
The second observation was that some work practices and storage methods in the
'switchyard area deviated from acceptable industrial safety practices.
The inspector concluded that the ISE report was an excellent report but noted that site management has neglected to fully correct problems that were discussed in IR 91-21.
b.
Rosemount Transmitters A URI in IR 91-24 concerns the failures of Rosemount Transmitters measuring steam line flow to detect a pipe break.
The licensee is trying to resolve a
CFR Part 21 question concerning the failure.
One of the action items was to return some of the failed detectors to'he vendor for analysis.
A NSRB member following this issue learned that the detectors had not shipped to the vendor for two months.
The inspector discussed with licensee management that a similar problem with failed acoustic monitor cards discussed in IR 91-24 had occurred.
The licensee is tracking this issue by CARR BFP910160.
The cards had not been shipped to the vendor for several weeks and no action was taken until after repeated questioning by the inspector.
The inspector observed the onsite activities of the NSRB on September 11-12, 1991.
The first day was spent observing a practice drill in the plant and subcommittee activities.
The second day the members assembled with members of plant management.
A full agenda of presentations were made covering a broad spectrum of problems at the plant.
The inspector requested and received from the plant licensing staff an audit of the gA program required by TS.
In addition, the inspector questioned if any activities were being reviewed related to Unit 3 gC.
The contractors for Unit 3 (Bechtel, GE, and SWEC) are running their own gA programs with TVA oversight.
One of the subcommittee was reviewing this area and made a presentation concerning the various gA programs.
The inspector at the site.
plant. staff.
were current laboratories.
I concluded that the NSRB was active on the current issues The members of the NSRB asked probing questions of the From the discussions held it was evident that NSRB members on industry issues at other utilities and national The TS requirements sampled were being me.
Part 21 Reports (CLOSED)
259, 260, 296/P21-91-09, PT
from Norrison-Kundsen Dimensional Problems Nay Exists in Certain Cutler-Hammer Contactors Used in Immersion Heating System.
Norrison-Kundsen notified all nuclear customers of a possible defect with DG immersion heater contactors.
The defect pertained'o contactors manufactured between January 1,
1987, and Nay 15, 1989.
They provided a
list of known customers shipped the suspect contactors.
The list was only accurate to mid-1987 and therefore all nuclear customers were notified.
BFNP operations performed a walkdown of the DG immersion heater contactors and none were the part mentioned.
One contactor located in the warehouse had the same part number but was purchased in October 1972, which is outside the time frame for the defective parts.
Three TVA contracts mentioned in the vendor letter pertained to the Sequoyah Nuclear Plant.
BFNP confirmed that none of the Sequoyah parts had been shipped to BFNP.
These actions resolve the issue.
11.
Reportable Occurrences (92700)
The LERs listed below were reviewed to determine if the information provided met NRC requirements.
The determinations included the verification 'of compliance with TS and regulatory requirements, and addressed the adequacy of the event description, the'orrective actions taken, the existence of potential generic problems, compliance with reporting requirements, and the relative safety significance of each event.
Additional in-plant reviews and discussions with plant personnel, as appropriate, were conducted.
a
~
(CLOSED)
LER 259/85-05, Inoperability of High Pressure Coolant Injection System.
This item was that HPCI failed a SI because a ball valve was found inadvertently closed in the hydraulic system.
The ball valve was opened and the SI was later passed.
In addition, HPCI system wi 11 be aligned and tested as part of the system return to service for the unit.
b.
(CLOSED)
LER 259/86-02, Revisions
and 1,,
RPS Circuit Protector 1A1 Trip on an Unidentified Cause.
On January 8, 1986, and again on January 24, 1986, Unit
RPS circuit protector lA1 tripped for unknown reasons.
This resulted in the loss of RPS bus A, causing secondary containment and partial primary containment isolations.
The circuit protector was reset and the affected systems were returned to their normal alignments after each occurrence.
Investigation and troubleshooting efforts did not reveal a
cause for the trips.
The licensee monitored the circuit protector using a disturbance analyzer which monitored voltage parameters to identify the cause of the previous trips.
No trips occurred during seventeen weeks of monitoring and these events were considered rando ~
~
The inspector reviewed the LERs and concluded that they met the reporting requirements of
CFR 50.73.
-All three BFH units experienced numerous RPS circuit protector trips during the Unit 2 shutdown and the licensee implemented actions for all RPS circuit protectors prior to the restart of Unit 2.
The resolution of RPS circuit protector concerns'as addressed in IR 90-33 and IR 90-40.
No deficiencies or additional concerns were identified during the review of this LER.
(CLOSED)
LER 260/91-02, Unplanned ESF Actuation Due to Radiation Monitors Downscale Caused by Degraded Radioactive Bug Source in the Radiation Monitor Detectors.
This event occurred. in Unit
on February 23, 1991."
The ESF actuation resulted when the two reactor building ventilation radiation monitors (2-RM-90-142 'nd 2-RM-90-143)
simultaneously had radiation count rates below their respective downscale trip setpoints.
The licensee conducted an incident investigation (II-B-91-041).which determined that the root-cause of this event was the lack of a program to control degraded (low radiation count rate)
vendor installed sources.
The vendor installed
"bug" sources ensure an on-scale radiation reading from the detectors.
The source for the 2-RN-90-'142 detector was readjusted to obtain acceptable count rates and the 2-RM-90-143 detector assembly was replaced to ensure a higher count rate could be detected.
In addition, the licensee revised radiation monitor SIs to include quarterly evaluation and adjustment of the bug sources.
The inspector reviewed the LER, dated March 21, 1991, and 'determined that it met the reporting requirements of
CFR 50.73; The inspector also reviewed the revised SIs and concluded that they should ensure that radiation detector sources are readjusted or replaced to maintain minimum count rates.
No deficiencies were identified.
(CLOSED)
LER 260/91-04, RPS Actuation as a Result of Exceeding the HI-HI SRM Channel Setpoint During Testing, Revisions 0 and,l.
On March 26, 1991, a Unit 2 reactor scram occurred when the count rate on SRM channel C spiked high.
Unit 2 was in cold shutdown and the neutron monitoring system was in the non-coincident mode.
The root cause of the event could not be determined and the high signal could not be repeated.
Licensee personnel were performing a time domain reflecto'meter trace on IRN channel C to determine the location of a ground fault in the detector cable shield.
The IRN cable is physically located in the proximity of the SRM cable.
The inspector reviewed the LERs, dated April 25, 1991, and June 24, 1991, respectively, and determined that they met the reporting requirements. of
CFR 50.73.
Revision 0 of the LER stated that a
detailed evaluation of the neutron monitoring system was to be conducted and that the licensee would report the results in.
a supplement to the LE Revision 1 to the LER reported the find'ings of the evaluation and the corrective actions taken by the licensee.
The evaluation involved diagnostic testing and maintenance on the SRM, IRM, and LPRM channels; preoperational testing of the RBM; and checkout of the TIP system.
In addition, GE reviewed all neutron monitoring maintenance procedures and SIs.
No procedural deficiencies were identified; however, the licensee committed to revise BFN's maintenance procedures to -incorporate new vendor information prior to startup following the Unit 2, cycle 6, refueling outage.
The inspector reviewed the licensee's closure package and corporate commitment tracking printout for the maintenance procedure upgrades.
In addition, the resident inspectors have followed the actions taken to resolve neutron monitoring problems as the have been implemented.
The inspector concluded that this event had been adequately addressed by the licensee.
No deficiencies were identified.
12.
Exit Interview (30703)
The inspection scope and findings were summarized on September 20, 1991 with those persons indicated in paragraph
above.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee; Licensee management was informed that
LERs, and one Part 21 Reports were closed.
13.
Acronyms and Initialisms
APRM ASOS ATU BFNP BWR CAQR CFR CRD CREV CST
'CRDR DCN DG ECCS ESF FCY GE HPCI IRM IR ISE Average Power Range Monitor-Assistant Shift Operations Supervisor Analog Trip Units Browns Ferry Nuclear Plant Boiling Water Reactor Condition Adverse to Quality Report Code of Federal Regulations Control Rod Drive Control Room Emergency Ventilation System Condensate Storage Tank Detailed Control Room Design Review Design Change Notice Diesel Generator Emergency Core Cooling System Engineered Safety Feature Flow Control Yalve General Electric High Pressure Coolant Injection Intermediate Range Monitor
Inspection Report
Independent
Safety Engineering
JTG
LCO
LED
LER
HSIV
MWe
NRC
PATP
RP.V
SOI
SOS
TACF
TD
TS
Joint Test Group
Limiting Condition for Operation
Light Emitting Diode
Licensee
Event Report
Low Pressure
Coolant Injection
Local
Power
Range Monitor
Motor Generator
Megawatts Electric
Nuclear Regulatory
Commission
Nuclear Safety Review Board
Operating Instruction
Power Ascension Test Program
Primary Containment Isolation System
Post Modification Test
Plant Operations
Review Committee
Pounds
Per Square
Inch Guage
Quality Assurance
Quality Control
.
Rod Block Monitor
Reactor Protection
System
Reactor
Pressure
Vessel
Restart
Test Program
Surveillance
Instruction
Special
Nuclear Material
Special
Operating Instructions
Shift Operations
Supervisor
Source
Range Monitor
Site Standard
Practice
Stone
and Webster Engineering
Company
Temporary Alteration Change
Form
Time Delay
Transversing
Incore Probe
Technical Specifications
Valley Authority