IR 05000259/1994020
| ML18038A943 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 09/29/1994 |
| From: | Lesser M, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038A942 | List: |
| References | |
| 50-259-94-20, 50-260-94-20, 50-296-94-20, NUDOCS 9410120102 | |
| Download: ML18038A943 (43) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSlON
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 30323-0199 Report Nos.:
50-259/94-20, 50-260/94-20, and 50-296/94-20 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 1101 Harket 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
September 10, 1994 Insp ctor:
eo ert, r.,
d'or es>
en nspector ate sgn Accompanied by:
J.
Hunday, Resident Inspector R. Husser, Resident Inspector G. Schnebli, Resident Inspector Approved by:
ar
.
esser, cting rane ie Reactor Projects, Section 4A Division of Reactor Projects ate 1gne SUHHARY Scope:
This routine resident inspection involved inspection on-site in the areas of operations, surveillance testing, maintenance activities, Unit 3 recovery activities, problem resolution issues, employee concerns program, and review of open items.
Several hours of backshift coverage were routinely worked during most work weeks.
Deep backshift inspections were conducted on August 17, 18, 19, 21, 28, and September 4.
9410120102 940920 PDR ADQCK 05000259 Q
t t
Results:
One unresolved item was identified:
The unresolved item addressed the self contained breathing apparatus qualifications of licensed operators.
Several licensed operators are not currently qualified to wear the equipment.
The item is unresolved pending additional review of the applicable regulatory requirements and details of the licensee's medical certification processes.
(URI 260/94-20-01:
Self Contained Breathing Apparatus gualifications of Licensed Operators, paragraph 2d.)
The inspectors identified that proper testing may not have been performed during planned diesel generator inoperability periods. 'he problem was caused by an interpretation of technical specification requirements.
The licensee has planned a meeting with NRC on September 22, to discuss the issue.
Additionally, it was noted that the diesel generators had been removed from service with Unit 2 at power in order to perform biennial preventive maintenance.
Although some analysis of the impact of the inoperability was performed, the licensee had not analyzed the relative risks of diesel generator inoperability during power operation versus during a refueling outage.
(paragraph 2c)
~
In recent months, the inspectors identified several examples of weaknesses involving resolution of problems:
Inadequate testing of the diesel generator building flooding check valves was identified by the licensee on June 17, 1994.
In early September, the inspectors observed poor material conditions associated with the valves and noted that the valves had failed previously in 1988.
Subsequent testing on September 6 indicated that one of the valves was not fully functional.
(paragraph 6a).
A small amount of leakage from the Unit 1 spent fuel pool liner had been identified by the licensee several years ago.
During their reviews associated with Bulletin 94-01: Potential Fuel Pool Draindown Caused By Inadequate Maintenance Practices At Dresden Unit 1, in June 1994, the inspectors questioned the licensee about the leakage.
Subsequently, the leakage rate was measured, the leak was evaluated, and additional moni-toring actions were initiated.
(paragraph 6b).
Excessive moisture in a Unit 1 residual heat removal heat exchanger, which was intended to be in dry layup, was noted by one of the inspectors.
Investigation indicated that the service water isolation valves were leaking by.
The licensee had previously addr essed this concern on some other heat exchanger lines by the installation of blanks in the supply lines.
The blanks had not been installed on the appropriate Unit 1 lines and some Unit 3 lines.
(paragraph 6c).
Routine reviews of the Employee Concerns Program and the Drawing Deviation program were completed.
The inspectors concluded that the licensee was appropriately addressing the concerns.
The inspectors reviews indicated that drawing deviations were being managed properly.
Although there is still a
backlog of previously identified drawing deviations, the inspectors concluded that the licensee is meeting the applicable commitments.
(paragraph 7)
One of the inspectors observed immediate operator and recovery actions involving a failed emergency core cooling system inverter.
The problem was rapidly identified, appropriately reviewed, and expeditiously repaired.
(paragraph 2b)
REPORT DETAILS Persons Contacted Licensee Employees:
- T. Abney, Technical Support Manager J. Brazell, Site Security Manager D. Burrell, Acting Engineering and Materials Manager
- J. Corey, Radiological Control Manager T. Cornelius, Emergency Preparedness Manager C. Crane, Business and Work Performance Manager
- J. Johnson, guality Assurance Manager
- R. Jones, Operations Superintendent R. Hachon, Site Vice President, Browns Ferry
- J. Haddox, Maintenance and Modification Manager R. Moll, Plant Operations Manager
- E. Preston, Plant Manager S.
Rudge, Site Support Manager P. Salas, Licensing Manager T. Shriver, Licensing and guality Assurance Manager A. Sorrell, Chemistry and Radiological Controls Manager D. Stinson, Recovery Manager
- R. Wells, Compliance Manager Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, and public safety officers; and quality assurance, design, and engineering personnel.
NRC Personnel:
- L. Wert, Senior Resident Inspector J.
Hunday, Resident Inspector R. Husser, Resident Inspector G. Schnebli, Resident Inspector
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Plant Operations (71707)
(92901)
(92703)
(71700)
'a ~
Operations Status and Observations Unit 2 operated at power this period without any significant problems.
At the end of the period the unit had been continuously on-line for 142 days.
End of cycle coastdown began in July and at the end of the report period the unit was at 91 percent rated
thermal power.
Final feedwater temperature reduction was implemented in August.'ecovery activities continued on Unit 3.
Unit 1 remained in layup conditions.
Activities within the control rooms were monitored routinely.
Inspections were conducted on day and night shifts, during week-days and on weekends.
Observations included control room manning, access control, operator professionalism and attentiveness, and adherence to procedures.
The inspectors noted that operators were cognizant of plant conditions and were attentive in their duties.
Instrument readings, recorder traces, annunciator alarms, operability of nuclear instrumentation and reactor protection system channels, availability of power sources, and operability of the Safety Parameter Display System were monitored.
One of the inspectors performed a walkdown of the RCIC system.
Procedure 2-0I-71, RCIC System Operating Instruction, 2-SI-4.5.F.-
1.f, RCIC System Monthly Valve Position Verification, HPI-0-071-TRB001, RCIC Turbine Preventive Maintenance, and the applicable TS were reviewed.
The inspector verified the system was in its appropriate lineup for current plant conditions and in conformance with applicable TS.
The inspector noted two discrepancies with 2-OI-71.
The first concerned a precaution which stated that the bearing oil sump should be sampled and have the moisture removed every four weeks.
The inspector determined that this inspection frequency was changed to every three months on March 10, 1991, and to every six months on February 6, 1994.
The inspector reviewed the system vendor. manual, BFN-VTH-G080-6740, and noted it recommended that the oil be checked for moisture monthly.
The second discrepancy concerned a check performed in 2-OI-71 Attachment 4, Instrumentation Checklist.
The checklist verifies 2-FR-071-0036, RCIC/HPCI Pump Discharge Injection Flow Recorder, is in service.
This check was not performed but was annotated to state that this instrument was uncalibrated and unplugged.
The inspector determined that this instrument has been removed from service and there are no intentions of placing it back into service.
Subsequently, the licensee initiated a
DCN to place the equipment in an
"abandoned in place" status.
While the equipment had previously been labeled as out of service, a
DCN had not been initiated, apparently due to an oversight.
The inspector identified a small amount of grease leaking from around the clutch handle on motor 2-HTR-071-0019, RCIC CST 2 Suction Valve and informed the licensee of this condition.
Inspection of this system and followup on the oil sump moisture issue will be completed during the next report period.
Unit 1/2 control room observations also included ECCS system lineups, primary and secondary containment integrity, reactor mode switch position, scram discharge volume valve positions, and rod movement controls.
Observations in the Unit 3 control room were more limited in scope and focused on major activities in progress and operable system Several clearances were verified as being correctly implemented.
While observing maintenance activities on the 8 DG, an inspector found a clearance tag, 94-600-22, lying on the floor. It was evident that the tag had been blown off of the component to which it was attached by air flow from a large area cooling fan.
The control room was contacted and responded by reattaching the tag to the appropriate component.
On August 29, one of the inspectors noted that the local control switch for the C shutdown board battery room ventilation fans was caution tagged.
The tag stated
"PHT required per WO 92-47074-04" and was dated June 24, 1994.
The issue was discussed with the operations onshift personnel.
It was determined that some testing had been completed in June but closeout of the associated paperwork could not be completed due to problems with the testing.
The licensee's clearance procedures permit this type of tagging.
The inspectors questioned the component being caution tagged for PHT for such a long period.
Additional components in the control room were noted to be caution tagged pending PHT.
At the close of the report period the licensee was reviewing active caution tags.
Daily discussions were held with plant management and various members of the plant operating staff.
One of the inspectors attended the daily Plan of the Day meetings.
During one meeting, the inspector noted that one of the two switchyard breakers connecting the Unit 2 generator to the 500 kV transmission system was removed from service to perform three weeks of preventive maintenance.
The inspector questioned management's review of this action since it placed the plant at an increased chance of a scram and was so close to a scheduled refueling outage.
The licensee's planning organization informed the inspector that both output breakers had to be worked on and that limited manpower restrictions required that one breaker be worked with the plant operating.
The other breaker will be worked on during the outage.
Plant tours were taken throughout the reporting period on a
routine basis.
Observations included valve position and system alignment, snubber and hanger conditions, containment isolation alignments, instrument readings, housekeeping, power supply and breaker alignments, radiation and contaminated area controls, tag controls on equipment, work activities in progress, and radiological protection controls.
Informal discussions were held with plant personnel during these tours.
The tours in the Unit I areas focused on maintenance activities and systems required to be operable.
Emphasis was placed on control of maintenance activities during the Unit 3 tours.
Failure of ECCS Division I Inverter On August 31, 1994 at 12:48 p.m., Unit 2 Emergency Core Cooling Systems (ECCS)/Anticipated Transient Without Scram (ATWS) Division I instrumentation and the Reactor Core Isolation Cooling (RCIC)
flow controller power was lost due to the failure of the
associated ECCS Division I inverter.
This condition was discovered when numerous alarms (ECCS Analog Trip Unit Trouble, Reactor Pressure Low/Core Spray RHR Permissive, and several suppression pool level and temperature alarms)
were received in the Unit 2 control room.
One of the resident inspectors was present in the control room when the failure occurred and recovery actions were observed.
Investigation by plant personnel revealed that the inverter had failed due to a faulty silicon controlled rectifier.
The SCR was replaced and the inverter was returned to service at I:50 p.m.
The ECCS Division I inverter supplies power'o two of four channels of drywell pressure and reactor water level sensors.
These sensors feed both divisions of initiation logic for all ECCS (RHR, CS, HPCI, RCIC, ADS, and the DGs).
Other sensors for reactor pressure and containment parameters are also supplied by this inverter, as is the RCIC flow controller.
The remaining channels of instrumentation powered from the ECCS Division 2 inverter are sufficient to initiate the logic of all ECCS divisions (with the exception of RCIC).
The inspectors reviewed portions of the ECCS logic and verified that all ECCS would have initiated if called upon (if no additional single failure occurred in the logic).
The inspectors concluded that the appropriate actions were completed, proper management involvement and review was performed, and the problem was expeditiously repaired.
Diesel Generator Inoperability Issues On August 30, 1994, during a review of TS limiting conditions for operation involving the C DG, one of the inspectors noted that the surveillance requirements of TS 4.9.B.3 were not being performed.
This TS describes DG testing and power availability checks to be performed when a
DG is found to be inoperable.
The C
DG had been removed from service for performance of required preventive maintenance and testing including biennial maintenance and battery testing.
Additionally, some modification activities were being performed.
The inspectors were informed that the licensee does not perform the TS 4.9.B.3 testing requirements when a
DG is removed from service for planned maintenance activities.
The licensee has interpreted the words "...found to be inoperable..."
as meaning that the actions were required only if an unplanned outage of the DG occurred.
The inspectors noted that the TS appeared to require the power availability checks to be performed within one hour and at least once per eight hours thereafter.
It was not clear to the inspectors why the requirements for such checks would be different depending on the manner in which a
DG was rendered inoperabl The inspectors also noted that other facilities perform the power availability checks whenever a
DG is inoperable.
The issue was discussed with licensee management, regional management, and the NRR project manager.
Additional review was conducted by the inspectors.
On August 19, 1988, TS Amendment 149 (Unit 2) was approved by the NRC.
This amendment contained several changes recommended by GL 84-15 which were intended to reduce the number of DG fast starts and improve DG reliability, The requirements to test DGs whenever an ECCS train fails were deleted.
The requirements to test the remaining DGs whenever another DG or electrical equipment is inoperable was revised from
"immediately and daily thereafter" to "within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />'.
Other DG testing requirements were revised.
The inspectors noted that the safety evaluation for the TS amendment did not specifically discuss
"planned" or "unplanned" DG outages.
The inspectors noted that the "if found to be inoperable" wording was included in the licensee's amendment submittal and had been in the original TS.
The inspector s reviewed GL 84-15 and did not note any clear differentiation between planned or unplanned DG outages.
Early on August 31, a phonecall was held involving the inspectors, regional management, the NRR project manager, and a
NRR electrical reviewer.
The NRR representatives initially indicated that the licensee may not interpreting the TS requirements correctly and that the actions of TS 4.9.B.3 should be performed regardless of the reason for the DG inoperability.
The inspectors immediately communicated this information to licensee management.
The station manager directed operations management to perform the testing for each DG outage.
During this discussion, the licensee stated that this interpretation would require that all the DGs be tested each time monthly testing is performed on each DG.
(During the monthly testing, the DG initiation logic is not operable for short periods of time.)
The inspectors noted that the surveillance testing inoperability periods would not normally approach 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and thus testing of the other DGs did not seem to be required by the TS.
NRR representatives verified that the testing of the other DGs would not be required (by BFN TS) if the inoperability for surveillance testing did not approach 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Testing of the A, B, and D DGs in accordance with Procedure 0-SI-4.9.B (A) was completed satisfactorily at 9:03 pm on August 31.
The power availability checks were also completed at 9:03 pm and at eight hour intervals thereafter.
The C
DG was returned to service on September 2.
Prior to the removal of the A DG from service on September 12, the testing of the other DGs was performed satisfactorily.
The licensee indicated that additional discussions will be held with NRR on this issue.
The inspectors concluded that in the interim the licensee's actions addressed the concerns regarding the testing and power availability requirements.
The situation
\\ ~
had developed as a result of an interpretation of TS requirements.
This interpretation had not previously been questioned by NRC inspectors.
The licensee intends to meet with the NRC on September 22, to further discuss their interpretation and plans to resolve the issue.
As part of their review of this issue, the inspectors examined the licensee's preparations and analyses regarding performance of planned DG maintenance activities during power operations instead of shutdown conditions.
The inspector referenced the guidance in GL 91-18 pertinent to this issue.
Because some of the planned modification work was related to Unit 3, the requirements of Section 3.2.3, of SSP 7. 1, Work Control, were applicable.
The inspectors reviewed the documentation and noted that impact of the DG inoperability had been evaluated.
The evaluation included the increase in core damage frequency as a result of the planned activities.
The evaluation stated that the required surveillance testing was expected to be completed well within the TS allowed outage time period.
Additionally, it was stated that the planned modification activities would not exceed 75 percent of the time expected for the surveillance testing.
The planned activities had been reviewed and approved by the PORC and the plant manager.
The inspectors review of the fragnet (a detailed timeline schedule promulgated to plan and track the DG maintenance activities)
and the activities in progress indicated that the inoperability period was being appropriately limited to the minimum required to complete the work.
The inspectors noted that the evaluation did not specifically compare the effects of performing the activities at power instead of during the upcoming planned refueling outage.
Considering that the interval of the required testing is every two years, the inspectors concluded that such an analysis would be a
valuable tool in planning the DG work to minimize any adverse effects on plant safety.
SCBA gualifications of Operations Personnel During a recent inspection, a regional inspector noted that approximately 19 onshift operations personnel were apparently not currently qualified to wear a SCBA.
The inspectors conducted followup review of this issue.
Regulatory requirements and the licensee's procedures were reviewed.
The inspectors also met with the individual assigned to monitor operator qualifications and discussed the issue with operations management.
The inspectors were informed that the goal is that all onshift operations personnel receive SCBA training during the first few weeks of each year.
The inspectors noted that Appendix R of lOCFR50 states that SCBAs will be provided for fire brigade, damage control, and control room personnel.
This requirement does not specifically state that all CR personnel should be qualified to wear SCBA.
At BFN, the fire brigade functions are performed by personnel other than the
'
onshift operators.
The inspectors determined that the operations watchstanders had received SCBA training at some time but their annual qualification status had not been maintained.
Portions of the licensee's Appendix R commitments and procedures were reviewed.
No specific commitments regarding operations personnel SCBA qualifications were noted.
The inspectors verified that the appropriate number of SCBAs were present in the CR and the
"C" 4kV Shutdown Board Room (location of the backup control panel).
With the assistance of regional inspectors knowledgeable in the requirements regarding licensed operators, the inspectors reviewed ANSI/ANS Standard-3.8 (1983).
Section 5 addresses the health requirements.
Section 5.4.6 specifically addresses the ability to utilize respiratory protective filters and air supply masks.
The inspectors requested that the licensee's compliance organization verify that the licensee was commmitted to this Standard.
Additional review of the regulatory requirements and the licensee's medical review processes is necessary to determine if any noncompliance occurred.
This issue is addressed as URI 260/94-20-01:
Self Contained Breathing Apparatus gualifications of Licensed Operators.
The inspectors also examined the issue from a performance perspective, considering when might SCBAs be necessary and who would be required to wear them.
As a result of those reviews, one concern was identified.
During some postulated emergency conditions, certain workers (auxiliary unit operators)
may have to access plant spaces with SCBAs to perform operations functions.
These workers would most likely be some of those designated on the "Shift Manning Sheet" by their assigned watchstanding position as
"emergency workers".
There was no mechanism to ensure that personnel assigned to those positions were SCBA qualified.
In response to this observation, Operations management subsequently directed that only workers with current SCBA qualifications would be designated as
"emergency workers".
The inspectors verified by discussion with onshift operators that this direction had been received.
The SCBA qualification status of operators had not been readily available to the SOS.
Other information such as medical status or requalification training status were available.
Operations management has initiated a change to the "Weekly Operations Schedule".
Individuals who are not SCBA qualified will be designated as such on this schedule.
One unresolved item was identified.
Surveillance Testing (61726)
(92901)
a.
Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy.
The completed tests reviewed
ly were examined for necessary test prerequisites, instructions, acceptance criteria, technical content, authorization to begin work, data collection, independent verification where required, handling of deficiencies noted, and review of completed work.
The tests witnessed, in whole or in par t, were inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and systems restoration was completed.
The following surveillances were specifically reviewed and witnessed in whole or in part:
O-SI-4.8.B.l.a.l Airborne Effluent Release Rate 0-S I-4.9. B DG A Operability Check 2-SI-4.7.A.2.g-3/43f LLRT of Valve 2-FSV-043-0070 The inspector noted that the main stack flow indication 0-FI-90-271 had been rendered inoperable and reviewed the requirements for the inoperable instrumentation.
The Offsite Dose Calculation Manual and O-SI-4.8.B.l.a.l were reviewed.
The SI is utilized to estimate flowrate every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required by the Offsite Dose Calculation Manual.
Portions of the SI were performed independently by the inspector.
The inspector verified the calculations were performed properly and the checks were performed at the required interval.
No deficiencies were noted.
The inspectors reviewed the procedures and practices associated with testing of the RHR System.
At another BWR facility, it had been identified that the torus spray valve was being opened to obtain minimum required flow through the test line during testing.
2-SI-4.5.B.ld (I), 2-SI-4.5.B.l.d. (II), FSAR Section 4.8.8 and 4.8.6.2, TS 4.5.B, and OI-74 were reviewed.
OI-74 stated that the torus spray valve is interlocked closed if the test return valve is not fully shut.
The issue was discussed with several shift operators and SRO's.
The inspector concluded that the licensee did not open the torus spray valves during flow test of the RHR pumps.
Additionally, the inspector noted that opening of the test return line valves was limited by an indicating light on the control room panel.
The corresponding procedure on the Unit I (System II) RHR system was reviewed and the same conditions were noted.
No violations or deviations were identifie ~
~
4.
Maintenance Activities (62703, 92902, 62700)
a ~
Maintenance Observations Maintenance activities were observed and/or reviewed during the reporting period to verify that work was performed by qualified personnel and that approved pro'cedures in use adequately described work that was not within the skill of the trade.
Activities, procedures, and work requests were examined to verify proper authorization to begin work, provisions for fire hazards, cleanliness, exposure control, proper return of equipment to service, and that limiting conditions for operation were met.
The following maintenance activities were reviewed and witnessed in whole or in part:
WO 94-13185-00 Flushing and Testing of Valve 2-FSV-043-0070 WO 94-05271-00 DG B Cooler Maintenance WP 19785-56,-57 DG C Control Circuitry Modifications On August 16, 1994, while reviewing WPs 19785-056 and 19785-057, the inspector noted several steps not performed in the package.
guestion 3 of form SSP-7. 1, entitled Work Control, and known as the Red Sheet, was blank.
This series of questions is answered by Operations to identify potential problems with the associated activity.
The inspector discussed this omission with the ASOS on shift who stated that the questions had been addressed and the signature was simply missed.
Additionally steps 2 and 7 of the WP were blank.
Step 2 ensures that the SOS, the affected UO, and Radcon are aware of the work to be performed and requires a
signature by the craft foreman upon completion of the notifications.
Step 7 ensures the protection of sensitive plant equipment located in the vicinity of the work area.
In addition a
step requiring the latest revision of drawings to be used by the craft was left blank.
The foreman for the job was questioned about these discrepancies and stated that although question 2 was not signed the appropriate disciplines had been informed.
Additionally, although the drawing revision verification page had not been signed the proper revisions had been verified as evidenced by the appropriate revisions having been documented in the WP.
The inspector agreed with the, foreman on these issues.
The foreman stated that he would ensure the WPs were updated to include these two signatures.
However, the foreman stated that step 7 was generally completed during closure of the WP.
The inspector stated that by that time sensitive equipment located in the area of the work activity would already have been negatively affected.
The foreman agreed but stated that to the best of his knowledge that question was not addressed until closure.
The inspector was later informed that the foreman was mistaken and that step 7 is addressed prior to beginning work.
However, a
l>>
recent revision had added a signature not previously required.
To ensure that the responsible personnel were familiar with this change, training was conducted to provide clarification. The inspectors concluded that the deficiencies were not of large safety significance and were additional examples of VIO 260/94-09-01:
Inadequate Drawings and Failure to Follow Mork Instructions.
In addition to the immediate corrective actions, these deficiencies are of the type that are being addressed by the licensee's actions described below.
The inspectors were briefed on the results of the incident investigation for PER 94-0298.
This PER addressed a recently identified adverse trend involving failure to follow procedures.
Several violations have been issued.
The investigation was conducted by a multidisclipinary team led by a senior manager from the corporate office.
The investigation focused on first line personnel and individual interviews and survey questions.
The investigation identified four primary areas of concern; perception of schedule or priority pressure, unclean and/or complex procedures and programs, work order/procedure interface issues, and training deficiencies.
A corrective action plan will be developed to address the issues.
The inspectors concluded that the investigation represented a detailed examination of the issues.
A number of the problems areas identified as a result of the investigation have been noted by the inspectors as contributing factors in procedural adherence issues.
The inspectors will continue to monitor the licensee corrective actions in this area.
Paragraph 7 of this report contains additional observations in the maintenance area.
Diesel Generator IB Maintenance Outage On August 15, 1994, the licensee removed the 1B DG from service to perform scheduled maintenance and modifications.
The inspector witnessed maintenance activities associated with the engine coolers.
MOs 93-05271-00 and 93-05270-00 contained the appropriate instructions for disassembly and eddy current testing of the two coolers.
The inspector verified the hold order was appropriate for the work being performed.
Observation of the craft working on the coolers indicated they were extremely knowledgeable about the equipment and the wor k to be performed.
The inspector verified the procedure was adequate for the work to be performed and that the craft complied with its instruction.
The inspector examined the cooler after it was opened and noted it was relatively clean and free of debris and mud.
The licensee's inspection indicated no major concerns with biofouling.
The eddy current test results indicated that none of the tubes in the cooler had detectable damage and therefore none were plugge c ~
The inspector noted no deficiencies with these maintenance activities.
Motor Driven Fire Pump Maintenance Previous IR 259, 260, 296/94-17 documented continuing problems with maintenance on the motor driven fire pump A.
Since that time the licensee has successfully repaired the pump and returned it to service.
In addition a report describing the component failures, procedural weaknesses, and corrective actions surrounding this activity was prepared.
The inspectors reviewed this report closely to ensure that the significant maintenance problems had been examined sufficiently.
Component failures identified in this report included a motor oil reservoir leak, high motor vibration, broken motor upper drive shaft, a worn pump stub shaft, and a
faulty fuse holder.
Procedural weaknesses included a procedure which lacked adequate detail and failure to obtain the proper authorization signatures prior to commencing work.
Three PERs were written due to the problems encountered during the work.
BFPER940254 was initiated to document the damage to the motor upper drive shaft as a result of running the motor uncoupled from the pump.
Procedure revisions are in progress to prevent recurrence of this problem.
In the interim, the procedure has been placed on administrative hold.
BFPER940256 was initiated to document the fuse holder malfunction and the tendency it has to allow fuses to dislodge.
No further corrective action was warranted by the licensee following replacement of the defective clip.,
BFPER940292 was initiated to document maintenance activities started without Operations signature granting authorization.
Immediate corrective actions included obtaining the appropriate signatures.
In addition the Site Vice President and Plant Manager met with all the managers in the maintenance department to discuss this problem and possible solutions.
All work was stopped and the section supervisors in turn discussed the problem with their craftsmen.
The craftsmen were instructed to conduct more in depth pre-job briefings and to be completely confident that they are fully aware of the work scope and its requirements.
The inspectors review indicated that the licensee had thoroughly examined the problems associated with these maintenance activities.
No violations or deviations were identified.
Unit 3 Restart Activities (37828, 61726, 62703, 37550, 92903)
(Unit 3)
a 0 Unit 3 Status and Observations The inspector reviewed and observed the licensee's activities involved with the Unit 3 restart.
This included reviews of procedures, post-job activities, and completed field work; observation of pre-job field work, in-progress field work, and
-. e gA/gC activities; attendance at restart progress meetings, and management meetings; and periodic discussions with both TVA and contractor personnel, skilled craftsmen, supervisors, and managers.
The inspectors reviewed selected DCN packages associated with plant modifications to support the Unit 3 recovery effort.
The DCN work packages were reviewed and work in pr ogress was observed to:
ensure that the DCN packages were properly reviewed and approved -by the appropriate organizations in accordance with the licensees administrative controls; verify the adequacy of the
CFR 50.59 evaluations performed and that the appropriate FSAR revisions were planned or completed, if applicable; ensure that the applicable plant operating procedures and design documents were identified and revised to reflect the modification; verify that the modifications were reviewed and incorporated into the operations training program, as applicable; verify that the modifications were installed in accordance with the work package (for those that could be physically inspected);
ensure that the modification was consistent with applicable codes and standards, regulatory requirements, and licensee commitments; and ensure that post modification testing requirements were specified and that adequate testing was accomplished.
No deficiencies were identified.
During one of the weekly tours with the Recovery Manager, the inspector noted large droplets of water on the temporary plexiglass end covers for the Unit 1A and C
RHR heat exchangers.
The two heat exchangers were in dry layup with RHRSW side (tube side) drained, the top end caps removed, desicant installed, and temporary end caps with plexiglass viewing windows installed to allow for inspection.
The problem was traced to leaking RHRSW supply line isolation valves.
Additional discussion of this issue is provided in paragraph 6 of this report.
Diesel Generator Auxiliary Board Supply Breaker Trip On August 13, 1994, breaker SA on 480V Shutdown Board 3B tripped for no apparent reason.
This breaker is the normal supply to Diesel Auxiliary Board 3EB and the alternate supply for Diesel Auxiliary Board 3EA.
The licensee transferred supply power to the 3EB auxiliary board from its alternate power supply and commenced troubleshooting the 5A breaker in the maintenance shop.
The licensee performed current injection testing, megger testing, and load testing which did not identify any problems with the breaker.
Breaker 5A was returned to its cubicle and returned to service on August 14, 1994.
The breaker operated satisfactorily and no spurious trips occurred until August 29, 1994.
A spare breaker was then installed in the 5A cubicle and the faulty breaker was taken to the shop for additional troubleshooting which is ongoing.
The residents will continue to follow this issue until resolve No violations or deviations were identified.
Problem Resolution Issues (40500)
(92901)
(92903)
In recent months, the inspectors have identified several examples of weaknesses associated with problem resolution.
Three significant examples are discussed below.
a ~
Diesel Generator Building Flood Check Valves During a routine backshift tour, one of the inspectors noted that the general conditions of the Unit 3 DG building flooding check valves were poor.
These valves are large swing check valves which are installed outside the DG buildings in small pits just below ground level.
There are two valves associated with the Unit 3 DG building and one with the Unit
DG building.
The valves are designated as O-CKV-40-3, -519, and -520.
The purpose of the valves is to allow a path for water to drain from the DG building in the event of an internal flooding problem.
= The valves also are intended to prevent floodwaters of the maximum probable flood (outside the building) from entering the building.
The Unit 3 valve pits sumps contained numerous items such as soft drink cans, sticks and trash.
One of the sumps was nearly full of water.
The piping on the exterior of one of the valves contained an accumulation of silt and seve} al small items of trash.
The valve hinge pins appeared to be corroded.
The inspector was concerned that the valves may not open to drain water or that they may become stuck in the open position if opened.
The inspector immediately informed the SOS and the Unit 3 ASOS of his concerns.
On July 15, 1994 Technical Operability Evaluation 0-94-040-0337 had been completed which addressed a postulated failure of the check valves and implemented compensatory actions.
IR 259,260,296/94-18 discusses the inspectors'eview of the evaluation.
After the degraded conditions described above were noted, the inspectors reviewed maintenance work orders to determine if any actions were planned regarding the functioning of the valves.
The inspectors determined that three work orders had been initiated on July 17, 1994 as a result of PER 94-0337.
The work orders requested that the valve pits be cleaned and the valves cycled. This work had not yet been performed and was scheduled for September 2.
The inspectors also noted that work orders 89-0879-63 and 64 had been performed in May 1988 on the 519 and 520 valves.
The work orders addressed water backing up into the DG building through the valves.
The description of work performed stated that the valves were frozen in the shut position and had to be freed.
The inspectors informed plant management of this information.
On September 6, the inspectors observed as-found testing of the valves.
One of the Unit 3 valves did not function properly.
It
had frozen in the shut position and water had leaked back into the line through the valve'which was not fully seated.
The other two valves functioned properly.
The problem was not of large safety significance because of the functioning valves and the compensatory factors described in the TOE.
The inspectors had two concerns in this issue.
The licensee had not properly addressed the earlier failure.
Additionally, prompt actions were not completed to ensure operability despite clear indications of potential valve failure.
During their review of the diesel generator building flood protection, the inspectors noted that Section 12.2.8.4.
1 of the FSAR describes a portable flood prevention bulkhead.
The bulkhead is intended to seal the doorway between an individual diesel room and the adjoining corridor.
The FSAR states that whenever an exterior door to a diesel generator room is to remain open for an extended period, the rear door to the room is removed and the bulkhead is bolted over the doorway.
The inspectors noted that the exterior doors have been opened continuously for periods of at least several hours during recent weeks and the bulkheads have not been installed.
A security guard has been posted at the opening and the doors have remained operable.
The inspectors verified that the bulkheads are available.
One is located in the Unit 3 DG building and one in the Unit I/2 DG building.
The inspectors questioned the licensee regarding the statements in the FSAR.
At the close of the inspection period, the licensee was reviewing the issue.
The inspectors will monitor the licensee's action involving the portable bulkheads.
Fuel Pool Liner Leakage During this report period, the licensee identified the corrective action needed to resolve the unit 1 fuel pool liner leakage concern discussed in detail in IRs 94-12 and 94-17.
In those reports the inspector noted that the licensee had known about the liner leak for quite some time but had taken no action to positively identify and quantify the leakage.
Following repeated questioning by the inspectors, the licensee issued BFPER940174 with the following corrective aciton:
Revise the appropriate procedures and drawings to leave the liner drain valve throttled to fifty percent.
This would include performing a safety evaluation to verify this condition is acceptable.
Establish precautions to isolate the liner drain if the refill rate unexpectedly exceeds 4 gpm.
Perform a monthly leak rate determination which would include isolating the liner drain if the leakage rate exceeds
.25 gp Trend the liner leak rate.
Investigate the difference between the liner leak rate and the makeup rate.
Incorporate a monthly system engineer walkdown and inspection of all wall and overhead surfaces in the spaces around and below the fuel pool.
Provide an assessment to determine if the liner leakage is acceptable as-is.
Site engineering provided the analysis for the last item which stated that the liner leakage would not weaken the structural integrity of either the SFP or the drywell.
The analysis stated that the corrosion rate of the carbon steel angle iron which makes up the drain paths would be approximately
.004 inches per year.
This would have no safety impact in that the angle iron provides no structural support but exists solely as a means to route the leakoff.
The analysis stated that these conclusions could be verified by routine visual examination to ensure the liner leakage is not increasing.
It further recommended that the drywell shell in the area of the sand bed be periodically monitored for shell thickness degradation.
The inspector verified this inspection which was last performed in 1992, is captured in the PH program and performed every 36 months.
Residual Heat Removal Service Water Isolation Valves Leakage During a routine tour with the Recovery Manager, the inspector noticed large droplets of water on the temporary plexiglass end covers for the Unit 1A and C
RHR heat exchangers.
The two heat exchangers were in dry layup with RHRSW side (tube side) drained, the top end caps removed, desicant installed, and temporary end caps with plexiglass viewing windows installed to allow for inspection.
Subsequently, the licensee determined the RHRSW inlet valves to the heat exchangers were leaking by their seats.
The licensee subsequently drained the IA and IC HXs and changed out the desicant.
This problem was not applicable to the 1B and ID HXs as they are not in dry layup but rather are in standby service to support Unit 2 operation.
When questioned about the status of Unit 3 RHR HXs the licensee initially indicated that blank flanges were installed on the Unit 3 RHRSW supply lines in the service water tunnels.
The inspectors obtained access to the tunnels and noted that blank flanges were installed only on Unit 3 A and D
RHRSW supply lines.
The Unit 3B and C and Unit IA and C
RHRSW supply lines had recently installed flanges in the lines (May 1994) to facilitate placing blanks in the lines, however the blanks were not yet installed.
The blanks installed in the 3A and 3D supply lines had been installed in May 1994, due to leakage past the HX inlet isolation valves.
In further discussions with the licensee concerning this issue they stated that blanks would
be installed in the Unit lA and C and the Unit 3B and C
RHRSW supply lines in the ne'ar future.
The residents will continue to monitor the licensees actions.
No violations or deviations were identified.
Concerns Resolution Program (40500)
(92901)
(92903)
The inspectors reviewed the status of current open employee concerns.
A NRC review of the Browns Ferry Concerns Resolution Program was completed in late 1993 and was documented in IR 259,260, 296/93-43.
No significant deficiencies were noted.
This review focused on the status of the open issues and verification that Procedure SSP-1.2:
Concerns Resolution, was being implemented.
The Concerns Resolution staff informed the inspectors that seven concerns were currently open.
Portions of the records were reviewed by the inspectors and the issues were discussed with the CR staff.
The oldest issue had been initiated in February of 1992 and has been resolved.
Final closure of the issue was linked to completion of the security upgrade project.
Of the seven issues, all but three had been resolved.
Closure of one concern was pending completion of confirmatory audits.
The inspectors noted that one recently initiated concern included numerous technical issues.
While an operability impact review had been performed on many of the items, it was not clear to the inspectors that each of the items included in the concern had been reviewed to assess potential safety significant items.
The CR staff was in the process of organizing the file and ensuring that each of the items in the concern had been addressed.
The inspectors will review the CR staff files on this concern again in the next several weeks to ensure that all of the items in the concern are being addressed and to verify that no safety significant issues which would require immediate corrective action were involved.
A change involving the concerns resolution program has recently been implemented.
TVA and Contract employees will receive a face-to-face exit interview conducted by a member of the CR staff to ensure that the employee has an opportunity to voice any concerns.
This interview has been incorporated into the site checkout routine.
The inspectors discussed this with the CR representative for one of the primary contractors who confirmed that such interviews are being conducted for the contract employees as well. In the event that an employee leaves the site without an interview, the CR staff will attempt to contact the individual by mail-out forms. These changes are described in detail in a September 6,
1994 letter to the NRC from the licensee.
In addition to the concerns opened under the current Concerns Resolution Program, there are 113 Corrective Action Tracking Documents (CATDs) open at Browns Ferry.
These issues were identified prior to 1986 under the Employee Concerns Special Program and Corrective Action Plans (CAPs) for their closure have been initiated.
At one time there were over 350 open CATDs applicable to BFN.
The licensee is currently determining which
I e
of the open CATDs will be designated for closure prior to Unit 3 restart.
Additionally, the open CATDs are being converted (cross referenced)
to specific Nuclear Central Office (NCO) items so that they will be treated like any other open commitment item.
This process is being performed by the responsible line organizations under CR staff overview.
The inspectors reviewed the list of open CAPs and several NCOs which included CATDs.
It was noted that one NCO could address several open CATDs.
The NCO listing in TROI included the appropriate details of each of the open CATDs.
Because many of the items identified in one of the concerns discussed above involved Drawing Deviations (DDs), the inspectors briefly reviewed the status of open DDs.
SSP-2.11:
Drawing Deviations, describes the current (since 1990)
DD system.
The inspectors reviewed recent quarterly DD status reports.
These reports are issued by Technical Support and include trending and tracking reviews.
The reports indicated that approximately
DDs (Unit 2, commom, and Unit 3) were awaiting issue by engineering.
Site Engineering reports listed approximately 150 D-DCNs open.
D-DCNs are utilized to resolve the DDs.
The backlog of open DDs appeared to be effectively managed.
The inspector noted that the procedures contained specific timelines for completed reviews and actions for any DD.
Each DD was required to be reviewed for operability as appropriate to the potential impact of the issue.
Primary and critical drawings (or other drawings which affect primary or critical drawings)
are required to be corrected within 15 days.
Additionally, each DD is reviewed to ensure that a
PER is initiated if a condition adverse to quality exists.
Corrective actions for most of these DDs are implemented through the DCN processes.
DDs that were opened prior to 1990 are being closed out in a different manner.
These DDs were initiated under earlier programs including walkdowns.
All Unit 2 and common DDs which involved primary or critical drawings were closed prior to Unit 2 restart.
The remaining DDs are associated with Secondary drawings.
A schedule for closure of these DDs has been established.
As of the end of August 1994, only 24 Unit 2/Common DDs remained to be updated (revised and reissued)
by engineering.
1222 DDs on Unit 2/Common secondary drawings have been updated by engineering but remain open pending review and acceptance by the plant staff.
The inspectors reviewed reports that indicated that this number has been decreasing steadily.
Unit 3 DDs have been resolved more effectively as they were identified.
There are currently 132 open DDs which are awaiting engineering updates and 252 pending plant review and acceptance.
The inspectors also reviewed the licensee's commitments regarding the DD system.
The response to a
violation issued in IR 259,260,296/88-28 and the response to the 1990 SALP report both contained corrective actions involving the DD program.
The inspectors concluded that the licensee is meeting those commitments.
The inspectors reviewed 5 selected DDs which had been initiated in 1987.
DDs 0-87-0331,2-87-0897, 2-87-0668, 2-87-1010, and 2-87-0769 were examined.
The DDs involved drawings classified as secondary drawing r
18 In each case, an engineering assessment had been completed which concluded that the condition'as within the design basis and the drawing required correction.
Specific calculations or other design documents were referenced.
At least one of the issues was attributed to a
typographic error.
In several of the examples, the'nspectors noted that the assessment addressed specific related potential concerns such as 10CFR50 Appendix R and FSAR separation requirements.
The inspectors concluded that the potential safety significance of the issues involved in the DDs had been adequately addressed.
The inspectors concluded that the open employee concerns were being addressed in accordance with SSP-1.2.
Open issues were being tracked.
The CR staff was providing overview regarding resolution of the issues.
The programs to address CATDs and earlier DDs seem to be effectively managing those open issues.
With the exception of the one recently opened concern discussed above, all the identified deficiencies have been evaluated by the licensee for their safety significance.
No violations or deviations were identified.
8.
Review of Open Items (92700)
(92901)
(92902)
(92903)
(92904)
The items 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 corrective 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 296/92-02, Engineered Safety Feature Actuation Resulting from Relay Failure.
The root cause of this event was determined to be an unexpected, random failure of a GE-CR-120 relay.
During the event, the relay began chattering which resulted in the PCIS actuations discussed in the LER.
Investigations by the licensee failed to determine the specific failure mechanism which cause the event.
The failed relay was replaced and plant systems were returned to their normal configuration.
Based on this review of the licensee's actions, This LER is closed.
b.
(CLOSED)
LER 260/94-03, Standby Gas Treatment Trains Declared Inoperable as a Result of Inoperable Emergency Diesel Generators This event was discussed in detail in IR 94-01 which resulted in the issuance of Violation 94-01-07.
The followup required for this issue will be documented in the closeout of the violation.
This LER is closed.
.
C.
(CLOSED) VIO 259, 260, 296/94-06-01, Inadequate PMT of DG Fire Pump.
This violation concerned the deletion of a PMT following maintenance on the Diesel Driven Fire Pump.
On October 22, 1993,
the controller for the pump was replaced with what was thought to be an identical controller.
Following installation, O-SI-4.11.B.
1.f, Simulated Automatic and Manual Actuation of the High Pressure Fire Pump System, was performed as the PMT, however, the portion which verifies the auto start capability was omitted by the system engineer.
It was decided that this portion was unnecessary in that the controllers were considered a like-for-like replacement.
On January 25, 1994, this surveillance was being routinely performed when it was recognized that the pump did not auto start.
Corrective actions for this violation included correction of the problem which prevented the pump from auto starting.
This was done with WO 94-01256-00 and DCN T28513A.
In addition, training was conducted with the system engineers on the potential consequences for not performing all post-modification tests.
Personnel corrective action was also taken with the involved individuals.
Based on the inspector's review of these corrective actions, this violation is being closed.
(Closed)
URI 259, 260, 296/93-43-01, Failure to Perform Craft Verification for Adequacy of Containment Coatings.
This item had remained open pending NRC review of licensee corrective actions associated with an issue identified by the licensee under SWEC Concern File 93-72.
Craft and craft supervisory personnel had failed to enter the Unit 3 Drywell to check the actual condition of containment protective coatings associated with Workplans WP3815-92, WP3816.-92, WP3561-92, and WP3986-92.
Portions of the protective coatings had also been rejected during gC inspection due to inadequate curing and unacceptable dry film thickness.
One of the NRC concerns raised during the original review was that although TVA management had determined that the failure had not been an attempt to falsify a gA record, the licensee's concern file did not reflect any effort by an employee concerns representative to contact TVA IG concerning this potential falsification issue.
The inspector determined that as corrective actions, the craft supervisor was counseled for not meeting management expectations.
The inspector reviewed the closed contractor concern file and noted that a copy of SWEC Interoffice Memorandum, BFN Nuclear Plant, dated August 25, 1994, was included in the file.
This memo, which had been made available to all SWEC personnel at Browns Ferry, provided craft and craft supervision specific guidance concerning management expectations with regard to craft verification of completion of work.
Additionally, the inspector noted that a note to file dated July 13, 1994, had been added to document a previous telephone call concerning this issue that had occurred on October 27, 1993, between the SWEC Employee Concerns Representative (ECR)
and TVA IG.
That note documented the TVA IG's agreement with the SWEC ECR's interpretation of the TVA definition of falsification and that an example of falsification
j had not actually occurred.
According to TVA, falsification is an attempt to defraud/mislead by providing information with a reckless disregard for the truth and the specific intent to falsify.
Based on the above review of the licensee's closed concern file, the inspector agreed that there was no intent to falsify any document.
Additionally, the associated datasheet was properly annotated to reflect additional work and reverification by craft and craft supervision prior to gC reinspection.
The inspector determined that a violation of NRC requirements had not occurred and licensee corrective actions were adequate to address the inspector's concerns as identified in the original review of the contractor concern file.
This item is closed.
9.
Exit Interview (30703)
The inspection scope and findings were summarized on September 12, 1994, with those persons indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Item Number Status Descri tion and Refe ence 260/94-20-01 Opened URI-SCBA gualifications for Licensed Operators, paragraph 2d.
Licensee management was informed that 1 violation, 2 LERs, and 1 URI were closed.
10.
Acronyms and Initialisms ADS ANS ANSI ASOS AUO ATWS BFN CATD CFR CR CS CST DCN DD DG ECCS ECR Automatic Depressurization System American Nuclear Society American National Standards Institute Assistant Shift Operations Supervisor Assistant Unit Operator Anticipated Transient Without Scram Browns Ferry Nuclear Corrective Action Tracking Document Code of Federal Regulation Concerns Resolution Core Spray Condensate Storage Tank Design Change Notice Drawing Deviation Diesel Generator Emergency Core Cooling System Employee Concern Representative
c,
FSAR gpm HPCI HX IG IR ISI KV LER LLRT NCO NRR PCIS PER PM PMT PORC QA QC RBCCW RCIC RHR RHRSW SCBA SCR SALP SE SI SFP SOS SRO SSP SWEC TROI TS UO URI WO WP WR
Final Safety Analysis Report Gallon Per Minute High Pressure Coolant Injection Heat Exchanger Inspector General Inspection Report Inservice Inspection Kilovolt Licensee Event Report Local Leak Rate Testing Nuclear Central Office Nuclear Reactor Regulation Primary Containment Isolation System Problem Evaluation Report Preventative Maintenance Post Maintenance/Modification Test Plant Operations Review Committee Quality Assurance Quality Control Reactor Building Closed Cooling Water Reactor Core Isolation Cooling Residual Heat Removal Residual Heat Removal Service Water Self Contained Breathing Apparatus Silicon Conrolled Rectifier Systematic Ass'essment of Licensee Performance Site Engineering Surveillance Instruction Spent Fuel Pool Shift Operating Supervisor Senior Reactor Operator Site Standard Practice Stone and Webster Engineering Corporation Tracking and Reporting of Open Items Technical Specification Unit Operator Unresolved Item Work Order Work Permit Work Request