IR 05000259/1996003
| ML18038B675 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 04/15/1996 |
| From: | Lesser M, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B673 | List: |
| References | |
| 50-259-96-03, 50-259-96-3, 50-260-96-03, 50-260-96-3, 50-296-96-03, 50-296-96-3, NUDOCS 9604220244 | |
| Download: ML18038B675 (62) | |
Text
~ ~g REpp UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 303230199 O
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Report Nos.:
50-259/96-03, 50-260/96-03, and 50-296/96-03 Licensee:
Tennessee Valley Authority 6A 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-280)
Docket Nos.:
50-259, 50-260, and 5"-296 License Nos.:
DPR-33, DPR-52, and DPR-68 Facility Name:
Browns Ferry Units 1, 2, and 3 Inspection Conducted:
February 4,
1996 - March 16, 1996 Inspector:
onar
.
ert, r.,
endor ess ent nspector
+Iz,fc, te cygne J.
Munday, Resident Inspector R. Musser, Resident Inspector M. Morgan, Resident Inspector D. Jones, Plant Support Branch, DRS (paragraphs 5.1-5.4)
J. Milliams, Project Manager, NRR (paragraph 4.4)
Approved by:
ar
.
esser, e
Reactor Projects Branch
Division of Reactor Projects f ss /fC a e gne SUMMARY Scope:
Inspections were conducted by the resident and other inspectors in the areos of operations which included routine observations, Unit 3 reactor scram, and condensate and supply system coupling failures; maintenance which included routine maintenance and surveillance observations, Unit 2 core spray system maintenance, Unit 2 pre-outage work, instrument maintenance attention to detail issues, Unit 3 scram solenoid pilot valve work, Unit 3 forced outage work, and review of open items; engineering which included Appendix R issues, quality assurance and independent assessment of Unit 2 refueling outage schedule, review of spent fuel pool design basis and operating information; plant support which included water chemistry, radioactive effluent monitoring, training for chemistry and radiological controls workers, liquid radwaste processing, emergency preparedness drill, and review of open items.
Updated Enclosure
9604220244 9604i5 PDR ADQCK 05000259
Final Safety Analysis Report commitments were specifically reviewed during the inspection.
Two meetings with local officials were conducted.
Results:
Pl nt 0 s
The actions of control room operators in response to a Unit 3 reactor scram due to an electro hydraulic control equipment probl,em were good.
The cause of the scram was conclusively identified, appropriate maintenance was completed while the unit was shutdown, and the unit was returned to power operations with no major problems.
(paragraphs 2.2 and 3.6)
Several failures of threaded pipe couplings in the condensate supply and storage system have occurred within the last year.
Some of these couplings are located such that failure could affect safety significant equipment.
Initially, the licensee's actions in response to the failures wer e not aggressive.
Late in this inspection period, after an additional coupling failure, an action plan was developed and stronger actions were initiated.
(paragraph 2.3)
ce A violation was identified involving failure to document completion of procedural steps during maintenance on a Unit 2 core spray valve.
One step not signed off as complete involved verification of the correct component.
Problems with procedural adherence during maintenance activities have been identified during previous inspections.
The licensee initiated some actions specifically to improve performance in this area in 1994.
(VIO 260/96-03-01, Failure to Follow Procedures During Core Spray Valve Haintenance, paragraph 3.2)
An inspector followup item was identified addressing examples of inattention to detail during performance of important surveillance testing.
The issues had minimal operational effect, were promptly reported, and corrective action has been initiated by the licensee.
(IFI 260,296/96-03-03, Instrument Hechanics Inattention to Detail Issues, paragraph 3.4)
A second inspector followup item was identified involving adjustment of the packing on three Unit 3 scram valves.
The packing was adjusted after post maintenance testing identified that two-by-two array scram times were sl.ight,ly above Technical Specification limits.-
The inspector's review of information in technical manuals and vendor documents indicated that adjustment of scram valve packing (within the torque values used),
should not affect scram times.
(IFI 296/96-03-04, Adjustment of Scram Valve Packing on Control Rod Scram Times, paragraph 3.5),
Review of licensee maintenance activities in preparation for the Unit 2 refueling outage indicated that the activities: were adequately scheduled and planned.
Reduction of system inoperability periods was emphasized by management.
Safety system availability factors were above goals.
In addition to adequate planning and scheduling efforts, Operations personnel continued to
3.
be sensitive to potential effects of work activities on plant safety.
(paragraph 3.3)
ne An unresolved item was identified involving several Appendix R deficiencies identified by the licensee during a detailed review of the Unit 2 Safe Shutdown Program.
The problems primarily involved cable routing issues.
At the end of the inspection period, the licensee had not yet completed the review.
(URI 260/96-03-02, Appendix R Instrumentation Discrepancies, paragraph 4.1)
Significant effort was put into development of the Unit 2 refueling outage quality assurance plans and performance of the independent assessment of the outage schedule.
For the quality assurance plans, a thorough review for the identification of potential problem.areas was conducted.
The independent assessment of the outage schedule included detailed review of decay heat removal system issues.
(paragraph 4.3)
latS t
The licensee's water chemistry control program for monitoring reactor coolant quality was implemented in accordance with the Technical Specification.
requirements and the EPRI guidelines for BWR water chemistry (Paragraph 5.1).
The licensee had established procedures to demonstrate operability. of radioactive effluent monitors by performance of surveillances at the frequency specified in the Offsite Dose Calculation Manual.
Licensee records indicated that those surveillances had been performed in accordance with established procedures for the instruments used to monitor liqui'd radwaste and'ain plant stack noble gas effluents (Paragraph 5.2).
The licensee had provided training for radiation protection and chemistry technicians and shift supervisors which was consistent with requirements (Paragraph 5.3).
The licensee had implemented an effective effluent release control program for compliance with state and federal regulations applicable to liquid radioactive effluents.
The equipment and procedures used for sampling batches of liquid radwaste prior to their release were adequate for ensuring that representative samples were obtained and the analytical procedures used to analyze those samples wer e appropriate for their application (Paragraph 5.4).
During an emergency preparedness drill conducted by the licensee, the accountability objectives were not met.
Some workers did not respond properly to the drill.
The licensee satisfactorily conducted an additional accountability drill several days later.
(paragraph 5.5)
REPORT DETAILS Acronyms used in this report are defined in paragraph 8.
1.0 2.0 2.1 PERSONS CONTACTED Licensee Employees:
- Abney, T., Manager, Independent
'Review and Assessment Brazell, J., Site Security Manager Coleman; R., Radiological Controls Manager
- Corey, J.,
Chemistry and Radiological Controls Hanager Crane, C., Assi'stant Plant Hanager Grafton, J., Technical Support Supervisor, Chemistry Hilmas, S., Supervisor, Technical Support
- Johnson, J., Site equality. Hanager Jones, R., Operations Manager Little, G., Operations Superintendent
- Machon, R., Site Vice President, Browns Ferry
- Maddox, J.,
Maintenance.
and Modification Manager Pierce, G., Technical Support Manager Preston, E., Plant Manager Sabados, J.,
Chemistry Manager Salas, P., Licensing Manager
- Shriver-, T., Nuclear Assurance and Licensing Manager Thomison, W., Program Hanager, Technical Support
- Wetzel, S.,
Compliance Licensing Engineer White, D., Manager, Reactor Safety Engineering and Review White, J.,
Manager, Outages Williams, H., Engineering and Materials Manager
- Attended March 15, 1996, exit Interview Other licensee employees contacted included office, operations, engineering, maintenance, and chemistry/radiation personnel.
PLANT OPERATIONS (71707,,71715, 92901, 40500)
OPERATIONS STATUS AND OBSERVATIONS (UNITS 2 AND 3)
Units 2 and 3 operated at power during most of this inspection period.
Unit 3 scrammed on February 29 due to an EHC equipment failure (see paragraph 2.2).
Unit 3 was restarted on March 2 and operated at power for the remainder of the report period.
Unit 2 continued coastdown operations in preparation for a planned refueling outage scheduled to begin on March 22, 1996.
At the end of the report period, Unit 2 was operating at 82X of rated full power.
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Operations were routinely inspected throughout the report period in accordance with the guidance in Inspection Module 71707.
In addition to weekday monitoring, some inspections were conducted on night shifts and'eekends.
One of the inspectors observed Unit 2 control room operators as they pressurized and warmed the RCIC steam supply line following maintenance.
Observation of RCIC MOV testing was also conducted.
While steam was being admitted to the steam line, the inspector monitored the system locally and noted that an unused plastic radiological trash bag had been left draped over a steam line drain line pipe.
As the pipe heated,
"he bag melted and fell to the floor.
The inspector informed the control room of this and other material left in the area following the maintenance activities.
The SOS immediately had the material removed.
During observations in the main control room the inspector noted clear communications between the ASOS and the board operators.
In addition, as alarms sounded, annunciator procedures were referenced and actions were taken appropriately.
Other control room activities observed during this report period included a power reduction for feedwater heater valve maintenance, which involved a great deal of feedwater system manipulation.
While observing this activity the inspector noted numerous alarms were received as system manipulations were made.
The inspector observed good coordination between control room personnel and operators in the field.
During the power reduction the inspector observed operators frequently scanning instruments to verify proper plant response.
In addition, the reactor engineer was observed to be monitoring many of the same parameters.
Discussions. with control room operators indicated that they had a clear understanding of plant conditions and system alignments.
Overall, control room operators were attentive and professional in their duties.
Following completion of maintenance activities associated with the HPCI, RCIC, and Core Spray systems, the inspector verified the control room alignments were correct and the systems returned to their proper configurations.
The pump discharge lines were verified to be properly pressurized and for the HPCI and RCIC. systems, the steam supply lines were also verified to be pressurized.
During this report period one of the inspectors reviewed and walked down clearance 2-96-0414.
This clearance removed the 2A RBCCW heat exchanger from service for cleaning and eddy current testing.
During the walkdown the inspector noted that one of the drain valves identified on the clearance did not have a valve identification tag affixed.
The inspector verified on plant drawings that it was in fact the correct valve and informed the unit ASOS who stated that he would ensure that a
valve tag request would be generated.
A review and plant walkdown of clearance 2-96-0443 was also performed.
This clearance was to allow inspection and repair of the actuator for valve 2-NVOP-85-27, CRD Exhaust Water Valve; The inspector's review concluded that the clearances, were acceptable for the work to be safely performed and would not negatively impact system or plant operatio.2 During backshift tours on February 12 and March 3, the inspectors observed additional examples of good communications and coordination.
The inspectors noted that the ongoing control board walkdowns were being conducted in a thorough manner.
During one of the tours, Unit 3 was conducting control rod scram timing.
The inspector noted that the controlling procedures were in continuous use and the reactor engineer as well as the ASOS were actively involved in the evolution.
During routine review of the electrical distribution system alignment, one of the inspectors noted: that the electrical system portions of the UFSAR had not been updated to reflect Unit 3 in operation.
The l,icensee confirmed that the UFSAR is not up to date in this regard and that with the exception of two modification packages, there were not any documented changes pending to update the description.
The licensee began a review for additional oversights due to Unit 3 being.returned to power operation.
UNIT 3 REACTOR SCRAM On February 29, a Unit 3 reactor scram occurred due to a fluctuation in the main turbine's EHC overspeed sensing control system.
The failure of an, electronic equipment card.in the speed sensing circuit caused the turbine control valves to close to approximately 25X open.
The rapid closure of the control valves caused the turbine bypass val.ves to open and main steam line pressure to decrease from approximately 945 psig to about 914 psig.
Subsequently, the bypass valves closed and main steam line pressure increased to about 995 psig.
The shifting valve -positions and the oscillations in main steam pressure induced a high reactor pressure condition and consequently a high neutron flux condition.
An APRH High-High Neutron Flux signal was generated and initiated the scram.
Following the scram, reactor vessel water level decreased to approximately minus five inches and was immediately restored by the reactor feedwater pumps.
All systems responded as expected and all control rods fully inserted.
PCIS groups 2, 3, 6, and 8, standby gas treatment, and control room emergency ventilation systems initiated.
No ECCS safety systems were actuated as there was no requirement for any injection.
The, peak reactor pressure was about 1040 psig and no SRVs were actuated.
The scram was reported to the NRC Operations Center.
The resident inspectors were notified and immediately reported to the site.
The inspectors reviewed available instrumentation and verified the unit was stable.
The inspectors verified the peak pressure and minimum water levels during the transient.
APRN indications were reviewed closely.
Di'scussions were held with some of the involved operators and Operations management.
The inspectors monitored the activities of the licensee's event evaluation team.
The evaluation team determined that the scram was caused by a malfunctioning circuit card in EHC.speed control.
The team noted that at the time of the event, there was no testing, maintenance,
2.3
or major plant evolutions in progress.
The team also determined that no personnel were in the area of the. EHC panels (located in the Auxiliary Instrument Room) at the time.
The malfunctioning EHC speed control circuitry card was replaced and the suspect card was sent to the vendor's testing facilities for further analysis.
Testing was performed by, the licensee which confirmed the cause of the scram.
On March 2, 1996, after the EHC system was repaired and other maintenance activities were completed, Unit 3 was restarted.
In addition to the reviews described above, the inspectors examined applicable portions of the UFSAR and confirmed that the observed equipment performance was bounded by analyses.
The UFSAR included a
"Generator Load Rejection Mithout Bypass" event in which rapid closure of the control valves was evaluated assuming that the bypass valves failed to open.
The EHC scram event resulted in a pressure increase of less than 20 psig in about 4 seconds.
In the UFSAR analyzed event, reactor vessel pressure increased by greater than 150 psig in about
seconds.
The inspectors concluded that the scram was bounded by UFSAR analysis.
CONDENSATE STORAGE AND SUPPLY SYSTEM COUPLING FAILURES (UNITS 2 AND 3)
On January 24, a two inch diameter condensate storage and supply pipe providing the Unit 2 refuel floor elevation with service water broke.
This spilled approximately 15,000 gallons of water onto the floor on two elevations in the Unit 2 reactor building.
Fire Operations personnel in the building at the time of the break informed the control room of the leak.
In addition, Radwaste operators informed the main control room of excessive pumping of the Unit 2 reactor building floor drain sump pumps.
Operators identified the break to be a pipe coupling which penetrated the ceiling between the 639'levation and the refuel floor.
Because of its obscurity and the physical location of the break, Operations was unable to quickly identify an isolation point.
However, after reviewing applicable plant drawings, an isolation valve was identified and the leak was subsequently isolated.
The coupling that broke was embedded in the concrete refuel floor and is made of a resin or nylon type substance which serves as a transition piece between stainless steel and aluminum pipe.
PER 960151 was initiated to identify additional couplings of this type and to determine if further actions need to be taken.
A similar failure had occurred involving a coupling in the Unit 3 reactor building last year.
The coupling was subsequently replaced and the system returned to its normal alignment.
The inspector reviewed the event and determined that no safety-related equipment had been affected by the leak and that the water had sprayed to the floor and was routed to the reactor building floor drain system.
The inspector concluded that although the leak had occurred for approximately fiftyminutes, the licensee's response to the event was acceptable considering the location of the break and the relative obscurity of the pipe.
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2.4 On Harch ll, another coupling failure occurred.
This coupling was located on the refueling floor on a condensate supply and storage line.
The failure was identified after a fuel pool cooling skimmer surge tank high level alarm actuated.
The leak was promptly isolated.
The licensee concluded that the couplings may have approached end of life and are susceptible to failure without warning.
Since some of these couplings are located such that a failure may affect important equipment, the inspectors questioned licensee management on the status of corrective actions.
For example, the inspectors noted that many of the couplings are located on water lines that do not need to be continuously pressurized and could be isolated so that coupling failure would not result in a significant leak.
Since the failures of the couplings may have been accelerated by pressure surges in the condensate transfer system, the cause of the pressure surges should be reviewed.
During the final days of the inspection period, management began
.to develop an action plan.
Engineering personnel started a list of the susceptible couplings, their location and availability of isolation valves.
Intentions were that Operations would then. set priorities so that the potentially significant couplings would be repaired first.
Actions were initiated to ensure the necessary spare parts would be available for the repairs.
The inspectors concluded that although the licensee's initial actions in response to the series of failures were not aggressive, the actions in progress at the end of the report period were sufficient to reduce the likelihood of a coupling failure resulting in a safety significant issue.
MEETINGS WITH LOCAL OFFICIALS On March 13, 1996 the senior resident inspector held two meetings with local officials.
The inspector first met with Julian Price, the mayor of Decatur.
Later that morning, a meeting was held with Stanley Menefree, a county commissioner for Limestone county, and Dan Williams, the mayor of Athens.
The inspector briefly discussed the responsibilities and organization of the NRC with emphasis on the BFN resident inspectors.
Copies of NUREG/BR-0164, Rev 1 (NRC-Regulator of Nuclear Safety)
were left with the officials as well as the phone numbers to contact the inspector.
No areas of concern were expressed by any of the officials.
No violations or deviations were identified.
3.0 3.1 MAINTENANCE (62703, 92902, 40500, 61726, 92901, 37551, 92903)
MAINTENANCE AND SURVEILLANCE ROUTINE OBSERVATIONS (UNITS 2 AND 3)
Maintenance activit'ies and surveillance tests were observed and/or reviewed during the reporting period in accordance with the guidance in Inspection Modules 62703 and 6172.2 The following maintenance and surveillance activities were reviewed and witnessed during routine inspections:
I-SI-3.2.4, EECW Check Valve Test On Harch 4 the. inspector witnessed, portions of the performance of I-SI-3.2.4, EECW Check Valve Test.
The inspector verified that plant conditions necessary for the performance of the surveillance had been established prior to the test commencing, that the measuring and test equipment being used was within its required calibration date, and that the procedure was the proper revision and being performed correctly.
The inspector observed the manipulation of several valves involving both second party and independent verification and noted that the steps had been completed properly in accordance with site procedures.
Because the procedure involves the surveillance of a large number of.valves, a step at the beginning of the procedure allowed the performers to perform the surveillance in any sequence desired.
The inspector discussed this aspect with the test performers and after reviewing the procedure noted that they had started and stopped at appropriate steps and had completed those portions of the surveillance observed satisfactorily.
2-SI-4.5.F.I.C,.
RCIC System HOV Operabil.ity Test On February 6, the inspector witnessed the performance of 2-SI-4.5.F. I.C, RCIC System HOV'perability Test.
The inspector verified that the test performers were timing the various system valves correctly, according to the procedure and performing the procedure as it was written.
During the surveillance, when, both the inboard and outboard steam supply isolation valves were cl'osed the steam line depressurized.
The operators performing the test determined that a
packing leak on the 2-FCV-71.-6B, RCIC steam line drain isolation valve, was leaking to the point of depressurizing the steam line.
The system engineer was consulted and concurred and appropriately followed up on the problem.
Operations isolated the leaking valve and the steam line was repressurized.
The inboard and outboard steam supply isolation valves were then successfully tested.
UNIT 2 CORE SPRAY SYSTEM HAINTENANCE On February 29, two inspectors witnessed maintenance being performed on the Core Spray Loop I Test valve, 2-FCV-75-22.
The maintenance consisted of torque switch and limit switch disassembly in preparation for valve diagnostic testing.
While observing the work in progress the inspectors noted that maintenance craft were not refer ing to their procedure.
A copy of the procedure, ECI-O-OOO-HOVOOI, Maintenance For Limitorque Hotor Operated Valves, was enclosed in the work package and was identified as a "Continuous Use" procedure.
A review of the procedure indicated that while several of the steps had been signed as having been completed, others were not signed.
The inspectors asked the maintenance workers why the steps were not being signed as they were completed and they stated that when the work was f'.nished they would fill out the remaining portions of the procedure.
Additionally, the
inspectors noted that the first step in the work order, which was to verify the correct component prior to star ting work, had not been signed.
These items wet e discussed with the licensee and PER 960176 was initiated.
The licensee pointed out that although the procedure was identified as a "Continuous Use" procedure, a precaution at the beginning of the procedure allowed maintenance workers to perform steps out of sequence as desired; however, this did not preclude signing off steps as they were completed.
The inspectors discussed with the licensee their observations that maintenance workers are not completely following their procedures.
Examples of similar deficiencies were identified in IR 95-64 and included workers applying an incorrect torque to bolts on a RCIC system snubber although a precaution in the procedure clearly identified how to determine the proper torque value.
A second example resulted in a spill in the Unit 3 reactor building when a freeze seal used during CRD HCU maintenance was released prior to isolating the system drain valve.
The procedure being used clearly listed the proper sequence of steps to preclude this from happening.
In July 1994, the licensee had initiated a large effort (incident investigation team) to review maintenance procedure related issues at BFN.
The effort included interviews with workers and supervisors and a
list of corrective action initiatives was developed.
The response to a Notice of Violation contained in IR 94-09 discussed the licensee's activities.
Implementation progress appears to have been slowed during the final stages of the Unit 3 recovery.
While it is clear to the inspectors that licensee management considers the performance in the above examples to be unacceptable and has'taken some corrective actions, the work identified in this report associated with the Core Spray valve indicates that additional attention is warranted.
The inspectors discussed with plant management that the corrective actions should not be limited to the specific incident described.
SSP-2. 1, Site Procedures Program, step 3.2.B, identifies that each step of a "Continuous Use" procedure is to be signed off as complete before proceeding to the next step.
Failure to perform ECI-0-000-NOVOOI in this manner was a violation of this requirement and will be identified as VIO 260/96-03-01, Failure To Follow Procedures During Core Spray Valve Maintenance.
3.3 UNIT 2 CYCLE 8 REFUELING PRE-OUTAGE MAINTENANCE During this inspection period the amount of pre-outage maintenance activity on Unit 2 increased.
The activities included valve diagnostic tests and ISI examinations on various HPCI, RHR, CS, CRD, and EECW system components.
Other activities included miscellaneous primary containment valve LLRT's, preventive maintenance activities on condensate and feedwater system valves and pumps, and digital feedwater control system hardware installation and cable pulls.
The inspector discussed with the licensee the significance of performing these
activities with the unit on line.
The licensee stated that no safety systems were made inoperable for the specific purpose of performing outage activities.
However, outage activ~ities were completed while the various systems were removed from service for other maintenance and surveillance activities already scheduled by the twelve week rolling schedule process.
Before outage activities were scheduled to be worked in conjunction with normal system outage work, several factors were first considered.
Senior reactor operators assigned to the outage management group reviewed both the routine work and the outage work to determine if they could be performed simultaneously.
In addition, the pre-outage work was reviewed to ensure that the original system outage
.time was not increased.
Mhen it was determined that it would be acceptable to perform both type activities simultaneously, the list of pre-outage activities was factored into the system outage plan by maintenance planners using the normal work planning processes..
This would ensure that maintenance in progress on other systems would not be affected by the system outage, the surveillances scheduled would not affect other trains or safety systems, and that the appropriate level of review was obtained prior to the work commencing.
The inspector reviewed activities associated with HPCI, RHR, and EECM and determined that the reviews were comprehensive and the level of management attention was appropriate.
In all cases it was determined that priority was given to limiting the system unavailability time.
The inspector reviewed the HPCI, RCIC, RHR, and EDG system availability percentages and noted that they were all well within the licensee's goals.
The inspector noted that in one case Operations identified that a routine surveillance of Core Spray system instrumentation was scheduled to occur coincident with a HPCI system outage.
The ASOS delayed. the performance of the surveillance until the HPCI system was returned to operable.
PER 960149 was initiated to document the occurrence and determine corrective action.
3.4 INSTRUHENT NINTENANCE INATTENTION-TO DETAIL ISSUES (UNITS 2 AND 3)
During the inspection period, the inspectors reviewed a number of recently initiated PERs which appeared to involv, inattention to detail by inst} ument mechanics during surveillance testing.
The issues ha'd" minimal operational effects and seemed to have been promptly reported.
Because of the potential problems that could arise if the issues were not resolved, the inspector questioned the licensee on the magnitude of the problem and the status of corrective actions.
Discussions were held with IH, gA and Haintenance management.
A total of nine PERs were examined which were attributed to attention to detail problems by instrument mechanics over a seven month period.
The inspector examined the specifics of each PER and concluded that there
,had been no adverse affects or significant challenges to plant equipment caused by the specific incidents.
However, the inspector expressed the point, to the licensee that the occurrence of errors should be reduced to prevent a safety significant inciden.5 Corrective actions for each of the issues had been initiated by management personnel and many actions were still in progress.
Until the resident staff obtains further information on other proposed corrective actions, and a status on the actual effectiveness of these actions, this issue will be tracked as Inspector Follow-up Item 50-260,296/96-03-03, Instrument Mechanics Inattention To Detail Issues.
UNIT 3 SSPV MODIFICATION AND ON-LINE MAINTENANCE ASSESSMENT One of the inspectors reviewed documentation for an assessment of a proposed on-line maintenance/modification of the Unit 3 scram solenoid pilot valves.
The licensee planned to replace the SSPV exhaust diaphragms with the unit on-line during a scheduled down power on March 1-4.
The inspector concluded that the licensee had adequately planned, prepared, and evaluated the performance of this work with the unit on-line.
However, following an unplanned shutdown of Unit 3 on February 29 (see paragraph 2.2), the maintenance was performed with the unit in hot shutdown.
Details of the SSPV issue are discussed below.
The originally installed SSPVs were pilot-operated 3-way solenoid valves manufactured by ASCO.
These GE (vendor)-supplied SSPVs used nitrile rubber (Buna-N) for all seals and gaskets as well as the pressure and exhaust diaphragms.
In the early 1990's, the original Buna-N diaphragms presented various cracking and brittleness problems, (See NRC IN 94-71),
and, in response, SSPV design changes were performed.
ASCO also began supplying fluoro-elastomeric (Viton) diaphragms.
Prior to the restart of Unit 3 in November, 1995, all SSPV's were replaced with valves containing Viton diaphragms.
In December, 1995 and January, 1996, (See NRC IN 96-07),
a number of BWR licensees experienced problems with slow 5X scram insertion times due to "adherence phenomena" between the Viton exhaust diaphragms and the brass seat of the SSPV body.
These exhaust diaphragms must open to vent the scram valves and initiate insertion of the control rods.
As presented by the vendor, this SSPV diaphragm adherence resulted in a delay in diaphragm separation from the seat and, therefore, accounted for observed overall increases in scram times.
Since BFN has a number of Buna-N diaphragm replacement kits, (manufactured before 1989)
and, since the industry (and vendor)
has yet to determine a long-term solution for this phenomena, BFN elected to install available Buna-N diaphragms (and brass end caps),
on the exhaust side of all of the U3 SSPVs.
Licensee DCN, OT39372A, was issued for Unit 3 to replace all scram SSPV Viton exhaust diaphragms with Buna-N based on qualification by the vendor and ASCO.
As stated by the vendor,
"the Buna-N diaphragms will function normally in the valve bodies designed for use with the viton diaphragms, regardless of which end cap design is installed".
However, during recent bench testing of various "hybrid" SSPVs, it was determined that the valves with the Buna-N diaphragms and the newer, "revision G",
end caps would not always reset - i.e., close the exhaust port - when expected/designed air pressures were applied.
Valves with "non-revision G" end caps and Buna-N diaphragms would consistently reset.
Therefore, the DCN to replace the presently installed U3 Viton diaphragms was
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revised to also replace the nickel-plated "revision G" end caps with
"non-revision G" end caps from the previously installed SSPVs.
The SSPV end caps were cleaned in accordance with the vendor'manual and further inspected to ensure that sealing surfaces were free of visible damage.
.End cap ports were also inspected to ensure that they were not obstructed.
Each end cap was further inspected and certified for use by vendor engineering personnel.
The inspector reviewed the licensee's inspection and certification process for the end caps and concluded that the process was satisfactorily performed.
Three of the resident inspectors observed portions of the SSPV diaphr gm replacement activities on Harch 1.
The licensee dedicated a significant amount of personnel to this effort.
The operations, maintenance, radiological controls, and gC departments performed the task in a highly organized manner.
It was obvious to the inspectors that the effort had been well planned as coordination oF the numerous tasks were carried out very efficiently.
The inspectors observed the licensee performing inspections of the valve internals to ensure internal seating surfaces were free of damage.
gC inspectors were observed ensuring end caps were being tightened to the specified torque.
Overall, the task was performed satisfactory and in accordance with the requirements specified by the work controlling document.
After the SSPV material was changed out, the control rod scram times were measured by testing.
An inspector observed some of this testing.
during a routine backshift tour. Three rods were identified as not meeting the initial five percent time requirements of TS 3.3.C.2.
This TS involves the average scram times of those control rods in a two-by-two array.
The licensee initiated corrective action through an existing maintenance work order to adjust the torque on the packing of the scram inlet/outlet valves.
The torquing was completed and the rods were tested again later that day.
The subsequent scram times were within the TS limits.
The inspectors reviewed these actions closely since it was not clear what actions had resulted in the slower scram times being corrected.
The times being measured are very small (milliseconds)
and the previous cycling (scram timing) may have been the actual reason that the rods subsequently scrammed within the time limits.
Additionally, the inspectors noted that the packing on the scram inlet/outlet valves has been adjusted numerous times in the past and scram timing of the rod is not performed as post maintenance testing.
If adjustment of the packing did affect the scram times, then it appears that time testing must be performed after any such adjustment.
The inspector reviewed a copy of the completed work order, related'rocedures, and technical references.
On Harch 11, 1996, the inspector met with licensee management on the issue.
As a result of the reviews and the meeting, the following issues were noted:
In response to the inspector's questions regarding the "as found" torque on the packing, it was stated that information was
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difficult to obtain since the nuts were simply "backed off" and then re-torqued to 10 in. lbs.
The inspector noted that procedure MCI-0-085-HCUOOl, Maintenance of CRD HCUs, states that 5 in. lbs.
of torque should be initially applied and that the 5 in. lbs.
should be sufficient to prevent leakage.
MCI-0-085-HCUOOl states that if additional torque is required, then a maximum of 15 in.
lbs. is allowed.
The licensee stated that GE has indicated that the packing can be torqued up to fifty in. lbs. without affecting the scram times.
The inspector reviewed the GE technical manual on the HCU and noted the statement that if packing. is torqued above 15 in. lbs.
then retesting of the scram valve operation is recommended.
The licensee also stated that a
GE representative was involved in the decision to adjust the packing.
The inspector noted that GE Service Information Letter 575, CRD Slow Start of Motion, (issued October 27, 1993), states that after SSPV refurbishment, during rod scram timing pay close attention to "slow start of motion" times or first detectable position from position 48.
The letter states that if delay times occur, consider replacing SSPV kit or valves.
Licensee management stated that the issue regarding scram time testing after packing adjustment was a "management concern" since these packing adjustments were made.
The current position is that if packing is adjusted on the scram valves, the rods will be time tested.
The licensee intends to include the three rods which were slow in the sampling of rods which will be timed on the next quarterly testing.
The inspector concluded that it is not clear that the cause of the slow
"array" scram times (after the SSPV material was replaced)
was corrected by the adjustment of the-packing.
Additionally, it was concluded that more review is needed on the overall issue of how adjustment of the scram inlet/outlet valve packing can affect scram times.
These concerns will be addressed as IFI 296/96-03-04, Affects of Adjustment of Scram Valve Packing on Control Rod Scram Times-.
3.6 UNIT 3 FORCED OUTAGE WORK ACTIVITIES In addition to the SSPV diaphragm replacement, the licensee performed a
number of maintenance activities on non-safety related components during the Unit 3 forced outage.
Noteworthy items included the replacement of the A 5 B exciter coolers, repairing the actuator for valve 3-2-FCV-190 (condensate bypass around the steam packing exhauster),
cleaning the condenser water boxes, various repairs to the three reactor feed pump turbines and a number of other miscellaneous secondary maintenance activities.
The inspectors monitored the licensee's activities and noted a vigorous management approach to completing the work in a safe and efficient manne.7 OPEN ITEHS REVIEW (UNITS 2 AND 3)
3.7.1 (CLOSED)
LER 260/94-12, RESIDUAL HEAT REHOVAL SHUTDOWN COOLING VALVE WAS INADVERTENTLY CLOSED AS A RESULT OF PERSONNEL FAILURE TO FOLLOW PROCEDURE DURING PERFORHANCE OF A SURVEILLANCE INSTRUCTION Inspection review of this event was discussed in IR 94-24.
The review determined the incident was of minimal safety si'gnificance.
This LER was a minor issue and is closed.
3.7.2,(CLOSED)
LER 260/94-10, LOSS OF ECCS DIVISION II INSTRUHENTATION RESULTING FROH A BLOWN FUSE IN THE ANALOG TRIP UNIT INVERTER CAUSED BY A FAILED CAPACITOR Details of this event and the licensee's corrective actions were documented in IR 94-27.
Subsequent information provided by the vendor identified that the failed capacitors contained manufacturing defects.
The vendor stated that the internals of the capacitor had been contaminated during manufacture and would ultimately result in the capacitor failing.
This new information led the licensee to decide not to replace the capacitors with "heavy duty" capacitors as discussed in IR 94-27; however, the remaining capacitors in the ECCS analog trip units that were subject to the manufacturing defect were replaced.
This LER is closed.
3.7.3 (CLOSED)
LER 259/96-01, A UNIT 1/2 DIESEL GENERATOR AUTO STARTED DURING LOCAL PANEL TESTING AS A RESULT OF A COHPONENT FAILURE.
Inspection review of this event was discussed in IR 96-01.
This LER was a minor issue and is closed.
3.7.4 (CLOSED)
LER 296/95-01, LOSS OF A 161 I(V LINE CAUSED ACTUATION OF THE ESF SYSTEH.
The event was discussed in IR 95-38. This LER was a minor issue and is closed.
3.7.5 (CLOSED)
LER 296/95-06, SDV INSTRUHENT VENT AND DRAIN VALVES FAIL TO CLOSE AFTER THE REACTOR NODE SWITCH WAS PLACED IN SHUTDOWN POSITION.
Inspection review of this event was discussed in IR'5-60 and a notice of violation was issued.
A licensee response to the notice of violation was received January 16, 1996, and was, adequate.
Based on the reviews described in the inspection report, this LER is closed.
3.7.6 (OPEN)
EA 95-220, NOTICE OF VIOLATION (SEVERITY LEVEL II) AND IHPOSITION OF CIVIL PENALTY ($80,000)
FOR ALLEGED'DISCRIHINATIONAT BROWNS FERRY.
The subject NOV was issued February 14, 1996.
This issue is open and will be reviewed during future inspections for corrective actions Two violations and two inspec+:r followup items were identifie.0 4.1 ENGINEERING (37551, 92903, 40500)
APPENDIX R ISSUES (UNIT 2)
On February 16, the licensee determined that instrumentation required for the performance of Units 2 and 3 Safe Shutdown Instructions would not be available for fires occurring in certain fire areas.
This is because this instrumentation shares a power supply with other instrumentation which is not protected for Appendix R events.
Should an Appendix R event occur in one of the identified fire areas a fault in one of the unprotected cables could propagate back to the power su-"ly and render the required instrumentation unavailable.
The instruments affected by this condition are torus water level indication, 2-LI-064-0159A, 2-XR-064-0159 and 3-LI-064-0159A, and drywel1 pressure indication, 2-PI-064-0160A, 3-PI-064-0160A, and 3-XR-064-0159..
The licensee corrected this condition by ensuring other instrumentation providing this same function would be available for Appendix R fires occurring in the identified fire areas.
The affected Safe Shutdown Instructions were then revised to reflect the new instrumentation to be used during that event.
On Harch 8, the licensee identified three additional instruments that would become unavailable during certain Unit 2 Appendix R events.
Those instruments were reactor water level indicator, 2-LI-003-0058A, reactor pressure indicator, 2-PI-003-0074A, and torus temperature indicator, 2-TI-064-0161.
In.this case, other instruments which perform the same function were not available to be used during an Appendix R event in the identified fire area.
Therefore, the licensee established fire watches in the affected areas as compensatory measures pending a permanent resolution.
On Har ch 13, the review identified that the cable to the Unit 2 HPCI steam supply valve (2-FCV-73-16)
was incorrectly routed through fire zone 11.
Apparently, this deficiency was caused by inadequate review of a modification field change.
A supplemental report was made to the NRC and compensatory fire watches were initiated.
The inspectors have walked down some of the involved cables and verified that the compensatory actions are being performed as required.
These discrepancies were identified by the licensee during an ongoing analysis of the Unit 2 Safe Shutdown Program to establish a consistent multi-unit baseline.
The Unit 2 safe shutdown program was analyzed differently than Unit 3 and did not take credit for some available plant equipment which was used in the Unit 3 analysis.
One part of the ongoing review compares the Unit 2 conduit routes, as determined by plant drawings, with the Unit 3 conduit routing which utilized a
computer program.
If differences are identified, field walkdowns are performed to verify drawing accuracy.
With this information the licensee determines if a discrepancy exists or dispositions the difference as an identified unit difference.
This analysis is expected to be complete by Harch 18, 1996.
The above mentioned discrepancies were reported to the NRC in accordance with 10 CFR 50.72 (b)(1)(ii)(B)
and (C) in several phone calls.
This issue is identified as URI 260/96-03-02, Appendix R Instrumentation Discrepancies.
Additional NRC review
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4.2 4.3 of the issues will be necessary after completion o'f the licensee's
- analysis.
EECW SYSTEM UFSAR REVIEW (UNITS 2 AND 3)
During the inspection period, while reviewing a section of the UFSAR, the inspectors examined specific information involving the EECW system.
As stated in Paragraph 10.10 of the UFSAR, the safety objective of EECW is to provide cooling water to the EDG coolers, the RHR pump seals/room coolers, the CS pump room coolers, the Unit 2 shutdown board room chillers, and she hydrogen-oxygen analyzers.
It was a1so noted that the system will act as additional makeup for the fuel pool, when required.
The inspectors also noted that the system also acts as a backup system to the raw cooling water system, the RBCCW system heat exchangers and provides cooling to the control air compressor coolers and can also provide water to the Unit I
2 emergency condensing unit.
Following a detailed review of the above information, the inspector concluded that the UFSAR description of the EECW system was accurate.
EQUALITY ASSURANCE PLANNING AND INDEPENDENT ASSESSMENT OF SCHEDULE FOR UNIT TWO REFUELING OUTAGE One of the inspectors was briefed on and reviewed a Unit 2 refueling outage
"exposure list" which was developed by NA&L as part of the overall quality. assurance plans for the outage.
The exposure list will be used to further focus the quality assurance efforts during the outage.
The inspector noted that the development of the exposure list included reviews of previous refueling outages at BFN as well as at other TVA facilities.
NAEL also included measures to ensure that Unit 3 operation is not improperly affected by the outage.
The inspector noted that performance areas that the NRC currently regards as potential problems were included in the exposure list and the overall quality assurance plans for the outage.
One of the inspectors reviewed the Unit 2 cycle 8 refueling outage risk assessment.
Appendix C, Independent Shutdown Risk Assessment of SSP-7.2, Outage Management, contains guidance for the performance of the assessment.
The independent assessment was performed by a team in accordance with tne SSP and utilized a barrier analysis to evaluate the risk of the planned outage activities according to the developed schedule.
The inspector noted that the team had dedicated considerable effort toward the assessment, specifically reviews of decay heat removal capabilities.
The inspector met with several members of the assessment team and discussed the assessment.
The assumptions used in the assessment were conservative.
For example, since adequate thermal mixing has not been proven, credit was not taken for the fuel pool cooling system being capable of removing the decay heat from the pool and the reactor vessel (when they were connected).
Similarly, it was not assumed that shutdown cooling was capable of cooling the pool when the cavity and pool were connected.
An analysis was performed by GE which showed that an alternate shutdown cooling system (RHR assisting
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fuel.pool cooling) can remove decay heat from the pool and reactor vessel.
The inspector noted that the assessment team had reviewed the. impact of a submersible pump to be temporarily used to assist in circulation between the Unit 1 and 2 fuel pool volumes.
The inspector met wi,th a refueling floor SRO and discussed the use of the pump in detail.
The inspector concluded that provided the discharge hose of the pump is properly secured, the use of the pump would not be in conflict with NRC requirements or design considerations.
Subsequent to this review, the licensee decided that the pump would not be used this outage.
The inspector concluded that the determinations of risk for the highlighted periods on the outage schedule were appropriate.
Periods of the outage were color coded, according to risk.
With the exception of one short period of orange (considered as high risk.with less than desired complement of equipment)
on reactivity control, the only key safety function with orange or red periods was shutdown cooling.
The inspector noted that section 6.1 of SSP 7.2 states that the assessment will confirm that contingency and mitigating plans have been developed and are adequate.
These plans were not documented at the time of the assessment.
Discussions with the assessment leader indicated that he was br'iefed by responsible management on the intentions for the plans.
Further discussion indicated that he was being informed on all the contingency plans as they were developed and ensuring that they were appropriate.
The inspector concluded-that since the use and assessment of the ORAH process is still an emerging process at BFN, these actions were acceptable but it would be more desirable to have the plans documented for assessment team review.
After the discussion, the team leader informed the inspector that the assessment team would review the contingency plans.
The inspector noted that the assessment considered the use of the RHR pumps when RHR assist of fuel pool cooling was to be utilized '(alternate SDC) while the procedural controls specifically indicate that the use of the RHR drain pumps is preferred.
The team reasoned that the higher quality standard pumps should be used since the alternate SDC was a
backup method of decay heat removal.
The inspector reviewed the procedures and walked down portions of the flowpaths.
The inspector did not identify any problems that would be caused by use of the drain pumps.
At the inspector's request, the licensee verified that the RHR assist mode of fuel pool cooling had been used at BFN utilizing the RHR pumps.
The inspector reviewed several sections of the UFSAR including section 10.5 (spent fuel pool)
as part of the assessment review.
The inspector concluded that the statements and conclusions of the assessment regarding decay heat removal issues were consistent with the UFSAR.
The inspector noted one discrepancy between the plant equipment
4.4 configuration and statements in the UFSAR.
Section 10.5.5 of the UFSAR states that fuel pool high or low levels will actuate alarms in the control ro'om.
The inspector determined that only low fuel pool level will actuate an alarm in the control room.
The inspector noted that in most configurations, the fuel pool skiamer surge tanks level alarm systems would warn the operators of a high pool level.
At the close of the report period, the licensee was reviewing the issue for corrective actions.
The inspector noted that the UFSAR stated that the fuel pool cooling system return lines to the reactor well would be used when the cavity was flooded to prevent thermal stratification.
The GE analysis for the alternate SDC did not utilize this flowpath and relied on natural circulation.
The inspector verified that the procedures require that the reactor well return path be used whenever RWCU is removed from service and the cavity is flooded.
The inspector noted that the UFSAR did not specifically address the licensee's practice of connecting the Unit 1 and Unit 2 pools together during outage activities, but did not identify any safety concerns associated with connecting the pools.
A review by quality assurance personnel had identified and questioned the same issue.
The inspector concluded that the independent assessment met the intent of the SSP guidance and that considerable effort had been dedicated to the process.
The inspector noted that the scheduled corporate level review of the outage schedule had not yet been completed.
The inspector noted that the assessment recommended that NRC IN 96-05, Partial Bypass of SDC From the Reactor Vessel and IN 95-54, Decay Heat Management Practices During Refueling Outages, be reviewed by appropriate groups prior to and during the outage.
REVIEW OF SPENT FUEL POOL DESIGN BASIS AND OPERATING INFORMATION (UNITS 1, 2, AND3)
A memo dated February 8, 1996 from John Stolz of NRR directed all NRR project managers to gather and evaluate design basis and oper ating information for spent fuel cooling systems at operating reactors.
The Browns Ferry project manager visited the site Feb: uary 13 16 to gather background information necessary to complete this task.
The Browns Ferry fuel pool cooling systems consist of two trains per unit, with each train consisting of a fuel pool cooling pump and heat exchanger, with associated instrumentation, piping, and water purification equipment.
The design allows for cross-connection of the RHR system to provide additional heat removal capability.
The design limit temperature for the fuel pool is 150'F, which is reflected in TS 3.10.C.2.
The licensee has set an administrative temperature limit of 125 F for use of the RHR assist mode.
An engineering evaluation of issues raised in IN 95-54,
"Decay Heat Management Practices During Refueling Outages,"
dated January 12, 1996 documents the licensee's conclusion that a full-core offload from the reactor vessel to the spent fuel pool was acceptable and consistent with the plant design basis.
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The project manager reviewed design documents, including the UFSAR.
A minor discrepancy was identified in,UFSAR section 13.9, which erroneously states that refueling takes place on an approximate annual basis, when in fact refueling takes place about every 18 months.
The project manager also confirmed that Technical Specification surveillances for fuel pool level and temperature were performed as required for each unit.
Additional guidance was provided to project managers on Harch 1, 1996.
This guidance directs review of design documents by the NRR technical staff to identify current licensing basis requirements.
Project managers are required to review facility operating practices and procedures to confirm these requirements are satisfied.
This review is ongoing, and is scheduled to be completed by early April 1996.
4.5 REVIEW OF OPEN ITEMS (UNITS 2 AND 3)'.5.1 (CLOSED) THI 296/I.D.2.3, SAFETY PARAMETER DISPLAY SYSTEM FULLY IMPLEMENTED This THI item remained open following the restart of Unit 3 awaiting the licensee's certification of the operability of the SPDS system.
This certification was performed in accordance with the guidelines specified in GL 89-06.
Specifically, the checklist delineated in GL 89-06 was completed as was the required photography of various SPDS related components and displays.
These matters were reviewed and, with the exception of a minor labeling problem with the GL 89-06 required photographs (subsequently corrected by the licensee),
were found to be acceptable by the inspector.
The operation of the system was also reviewed by the inspector throughout the power ascension program.
The system was observed to perform satisfactorily during this period.
Based on this review, this matter is considered closed.
4.5.2 (OPEN) IFI 260/94-27-04, OUTAGE SCHEDULE SAFETY ASSESSMENT ISSUES A review of outage preparations and risk management issues was conducted as described in paragraph 4.3 above.
The IFI remains open pending verification of improvements in decay heat removal management during the outage.
One unresolved item was identified.
5.0 PLANT SUPPORT (71750, 84750, 71707, 92701, 40500)
5.1 WATER CHEMISTRY TS 3/4.6.B for Units 2 and 3 described the operational and surveillance requirements for chloride concentration, conductivity, pH and activity concentration in reactor coolant.
Operational limits for those attributes and sampling frequencies were specified for various operational conditions.
Action statements applicable to specific
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5.2
operational modes were also provided for conditions in which the operational limits were exceeded.
The inspector reviewed Site Standard Practice (SSP)
13. 1, "Chemistry Program" and determined that it included orovisions for collecting and analyzing reactor coolant samples at least as frequently as required by TS.
That procedure also identified acceptance criteria for those analytical results and the actions to be initiated in the event that the acceptance criteria were exceeded.
In addition, the licensee's water quality control program included provisions for implementing, with a few minor exceptions, the EPRI BWR Water Chemistry Guidelines.
The inspector noted that the licensee's program included administrative limits which were more conservative than the TS and EPRI guidelines.
The inspector also reviewed plots of analytical results for reactor coolant samples collected from Units 2 and 3 during November 1995 through January 1996.
During that period Unit 2 operated almost entirely at full power.
Unit 3 was restarted during late November 1995.
The following reactor coolant chemistry parameters were selected for review and were either required by TS to be monitored or recommended by the EPRI guide to be monitored as control parameters during reactor start up or power operation: conductivity, chloride concentration, sulfate concentration, dissolved oxygen concentration, pH, and dose equivalent iodine-131 (DEI).
The coolant conductivity for both units was typically <0. 1 mho/cm and within the TS limits of 1 mho/cm during startup and power operations.
The coolant chloride concentrations for both units were typically <0.5 ppb which were well below the TS limits of 200 ppb during startup and power operations.
The coolant sulfate concentrations for both units were typically <1 ppb which were below the EPRI guideline values of 20 ppb and 5 ppb for startup and power operation, respectively.
The coolant dissolved oxygen concentrations were typically 80 ppb for Unit 2 and 200 ppb for Unit 3 which were below the EPRI guideline value of 300 ppb startup.
The coolant pH for both units was typically 6.8 during power operations which was within the TS limits of >5.6 and <8.6.
During steady state operations the coolant DEI was typically <5 E-5 pCi/gm for Unit 2 and
<3 E-4 pCi/gm for Unit 3, which was within the TS limit of '3.2 pCi/gm.
Based on the above reviews, it was concluded that the licensee's water chemistry control program for monitoring reactor coolant quality had been implemented in accordance with the TS requirements and the EPRI guidelines for BWR water chemistry.
RADIOACTIVE EFFLUENT MONITORING INSTRUMENTATION TS 6.8.4. I.a for Units 2 and 3 required the licensee to establish, implement, and maintain a program for the control of radioactive effluents.
The program was required to be described in the ODCH, to be implemented by operating procedures, and to include limitations on the operability of radioactive liquid and gaseous monitoring instrumentation including surveillance tests.
Sections 1/2.1. 1 and 1/2. 1.2 of the ODCH required the instrumentation to be operable during specified operational
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conditions and demonstrated to be operable by the performance of instrument checks, source checks, channel calibrations, and channel functional tests at specified frequencies.
Compensatory measures for inoperable monitors were specified in action statements.
The inspector toured the main control room, the radwaste processing area, the main stack, and other relevant areas of the facility to locate and determine the current operational condition of the following effluent radiation monitors.
RH-90-130 RM-90-1478 RH-90-148 B Liquid Radwaste Effluent Monitor Hain Stack Noble Gas Activity Monitor Hain Stack Noble Gas Activity Monitor The above selected monitors were found to be operable at the time of the tour.
The inspector reviewed the procedures listed below which related to the performance and documentation of instrument checks, source checks, channel calibrations, and channel functional tests for the above listed monitors.
O-SI-4.8.A.l-l O-SI-4.2.D-1B O-SI-4.2.0.1 0-S I-4.2. D'. 1FT 0-SI-4'.8.B.l.a.l O-SI-4.2.K.1 0-S I-4.2.K. 1FT
"Liquid Effluent Permit"
"Liquid Radwaste Effluent Radiation Monitor (RH-90-130) - Source Check"
"Liquid Radwaste Monitor Calibration/Functional Test"
"Liquid Radwaste Honitor Functional Test"
"Airborne Effluent Release Rate"
"Airborne Effluents Hain Stack Honitoring System Calibration"
"Airborne Effluents - Hain Stack Honitoring System Functional Test" The inspector determined that the above procedures included provisions for performing the required surveillances in accordance with the relevant sections of the ODCH and at the specified frequencies.
The inspector also reviewed selected licensee records of performance of those surveillances for the selected monitors.
The records selected'for review were generally two consecutive recently completed data packages for the above surveillances.
Those records indicated that the surveillances had been performed in accordance with their applicable procedure and at the required frequency.
Based on the above reviews and observations, it was concluded that the licensee had established procedures to demonstrate operability of radioactive effluent monitors by performance of surveillances at the frequency specified in the ODCH.
Licensee records indicated that those surveillances had been performed in accordance with established procedures for the instruments used to monitor liquid radwaste and main plant stack noble gas effluent iP
5.3 5.4 RADIOLOGICAL CONTROLS AND CHEHISTRY PERSONNEL TRAINING TS 6.4.for Units 2 and 3 required the licensee to maintain a retraining and,replacement training, program for station personnel.
The licensee's training programs for Radiological Control and Chemistry personnel were administered by the Site Nuclear Training organization.
Those programs were described in procedures TRN-20 "Radcon Specialist Training" and TRN-21 "Radiochemical Laboratory Analyst Training".
The programs included provisions for initial basic skills training, in-plant qualification,, and continuing training.
The inspector reviewed the training records for four randomly selected individuals, one from each of the following positions:
Radiological Control shift supervisor, Radiological Control technician, Chemistry shift supervisor, and Chemistry technician.
Those records included a listing of the training courses provided and the dates completed.
The inspector noted inconsistencies between the course numbers and titles listed in the
,training records and the initial training curricula listed in the current training procedures.
The licensee indicated that the individuals selected had completed initial training approximately ten years ago and that the initial training subject matter had been rearranged in the current curricula.
The licensee also provided the inspector with the correlation between the previous and current courses.
The listings of provided training also included the courses for refresher training and current industry experiences which had been provided through the continuing training aspect of the programs.
Based on the above reviews and discussions, it was concluded the l,icensee had provided training for radiation protection and chemistry technicians and shift supervisors which was consistent with TS and site training program requirements.
LI(UID RADWASTE PROCESSING Section 9.2 of the UFSAR described the system for collection, treatment, and disposal of liquid radioactive waste.
The system consists of piping and equipment drains for collecting liquid radioactive waste from various areas and equipment in the plant, collection tanks for high purity, low purity, chemical, and detergent wastes, filter demineralizers for cleaning the liquid waste, and storage tanks for the processed water.
If the processed water is of adequate quality it is transferred to the condensate storage tank for reuse as makeup water, otherwise it is discharged from the plant.
Prior to discharge, compliance with release limits is confirmed.
During the inspection conducted on October 30 - November 3, 1995, (reference NRC Inspection Report Nos. 50-259, 260, 296/95-59)
the l,icensee's actions taken in response to Problem Evaluation Report (PER)
No.
BFPER951561 were reviewed.
That PER was initiated to document a
concern that the licensee's procedures for releasing liquid effluents were not adequate for detecting radioactive resins in water discharged from the plant.
Given the implication that the facility was not in compliance with state and federal regulations for liquid effluent
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releases, the licensee initiated an Incident Investigation (II) to evaluate the concern.
The II team determined that the process for obtaining samples from the radwaste batch release tanks ensured that the samples were representative, that the liquid effluent releases were in compliance with applicable state and federal regulations, and that the releases have a negligible impact on the radiation dose to the public.
The inspector determined from the review of the II Report that the licensee had aggressively pursued the issues raised in the PER in order to resolve the concern and to ensure that liquid effluent releases from the plant have not adversely affected the health and safety of the general public.
The II Report also included recommendations which:;ere identified as enhancements to existing procedures.
During this inspection, implementation of those recommendations was reviewed.
The inspector verified that the following revisions to procedures were made and determined that the recommended procedure enhancements were adequate to detect and preclude release of radiactive resin in excess of state and federal limits:
TI-254 "Radwaste Pump Performance Check" was revised to include a
caution step to emphasize that obtaining representative samples is dependent on tank recirculation times.
That caution step was inserted at the points in the procedure where existing actions were specified to be taken if pump performance failed to meet acceptance criteria.
O-SI-4.8.A. 1-1 "Liquid Effluent Permit" was revised to lower the turbidity action level from 20 Nephelometric Turbidity Units (NTU)
to
NTU.
CI-405 "Environmental Sampling Procedures" was revised to specify that a turbidity greater than
NTU will require total suspended solids determination.
That statement was also expanded to specify that a visual inspection of the filter for particulates is required if the turbidity is greater than 1 NTU.
CI-620 "Suspended Solids (Color Comparison;.Resin Detection)"
was revised to include a log for documenting results of microscopic examination tests.
CI-702 "Data Acquisition and Data Reduction" was revised to include a step to specify that samples of liquid radwaste shall be agitated prior to aliquoting the sample in a Harinelli beaker for radionuclide analysis.
Attachment 6, BFN Liquid Effluent Batch Release Flow Chart to 0-SI-4.8.A. 1-1 "Liquid Effluent Permit" was revised to provide action guidelines for TSS/turbidity if found in excess of normal values.
The inspector performed further review of several concerns raised in the PER.
Previous revisions (No. 42 and 43) of procedure O-SI-4.8.A.l-l, which had been in effect prior to initiation of the PER, were reviewed
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and found not to explicitly state that analysis of radwaste batch releases for the presence of radioactive resin was required.
However, Section 4.5 of those revisions did require tha't the sampling and analysis requirements of the NPDES permit must be satisfied.
Reference to CI-405 was given for the sampling requirements.
Also, Section 4.6 of those revisions specified that a turbidity check was to be performed in accordance with CI-405.
The previous revision (No 9) of CI-405 specified that all liquid radwaste releases required a turbidity check per CI-683 prior to being processed for release by O-SI-4.8.A. 1-1 and that a turbidity greater than
NTU would require a total suspended solids (TSS) de'.armination prior to initiating the liquid release.
From those reviews the inspector determined that previous revisions of 0-SI-4.8.A. 1-1 required, through performance of CI-405 and CI-683, sampling and analysis for turbidity of each batch of liquid radwaste prior to release and for TSS if the turbidity exceeded 20 NTU.
Those revisions also required TSS analysis of biweekly batch composite samples to satisfy the sampling and analysis requirements of the NPDES permit.
In order to determine whether turbidity was an appropriate analysis for detecting the presence of resin in liquid effluent samples, the inspector reviewed the technical reference given in CI-683.
Section 2130 of "Standard Methods for the Examination of Water and Wastewater" stated that "Turbidity in water is caused by suspended matter, such as clay, silt, finely divided organic and inorganic matter, soluble colored organic compounds, and plankton and other microscopic organisms."
From that review the inspector determined that the application of turbidity analysis as an indicator for further analysis was appropriate, in that both CI-405 and CI-683 stipulated that analysis for TSS was required if the turbidity exceeded a specified value.
This process would provide assurance that the NPDES limit on biweekly composite samples would not be exceeded.
The inspector noted that CI-622 was used for the TSS analysis of the liquid effluent composite samples and CI-622 was used to detect the presence of resin in the batches of high purity (low conductivity) liquid radwaste which was returned to the plant for use as makeup water.
Another related issue reviewed during this inspection concerned the omission of a filter element from the floor drain filter following routine maintenance during December 1992.
This resulted in a path for unfiltered water
-.o enter the floor drain sample tank.
The inspector reviewed the licensee's logsheet (CI-564.1) of TSS results for floor drain sample tank batch release composite samples collected during November 1992 through January 1993.
During November 1992 the TSS values were
<1 ppm.
The highest TSS value recorded during December 1992 was
ppm.
After the problem was found and corrected the TSS values returned to <1 ppm.
These values were well below the NPDES limit of 100 ppm.
The liquid effluent release permits for late December 1992 and early January 1993 were also reviewed by the inspector.
Those records indicated that the radionuclide concentrations in the liquid effluent batch releases were 3 to 4 orders of magnitude below the limits specified in 10 CFR 20.
The inspector noted that, as indicated in
CFR 20.1302, those radionuclide concentration limits apply to radioactive material in liquid effluents and no distinction is made
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5.5 therein as to whether the radioactive material is or is not in particulate form.
During the II initiated in response to the PER, the licensee performed a
special sampling test to confirm that the recirculation time established by Special Test 88-1 was adequate for providing representative samples from the floor drain sample tank.
The data from that test confirmed that the recirculation time was sufficient.
The inspector noted that the TSS.was (1 ppm in the samples co11ected during the special test, which would indicate that if resin were present in the samples it was only present in trace amounts during the special test.
However, the results from the samples collected during December 1993, when unfiltered water entered the floor drain sample tank, indicate that the presence of particulates in low concentrations were detected by the sampling procedure.
Based on the above reviews and observations, it was concluded that the l.icensee had implemented an effective effluent release control program for compliance with state and federal regulations applicable to liquid radioactive effluents.
The equipment and procedures used for sampling batches of liquid radwaste prior to their release were adequate for assuring that representative samples were obtained and the analytical procedures used to analyze those samples were appropriate for their application.
EMERGENCY PREPAREDNESS PRACTICE DRILL 5.6 On March 6, 1996, one of the inspectors participated in and observed a
periodic emergency preparedness practice drill.
The inspector's observations were conducted primarily in the technical support center.
The inspector noted that the licensee was using the recently revised Emergency Plan Implementing Procedures.
The new procedures were observed to be an improvement over the previous versions in that they were symptom based and user friendly.
As expected, the drill scenario drove the licensee's players to simulate declaration of the various emergency action levels (alert, site area emergency, and general emergency).
Declarations were observed to be made in an appropriate and timely manner.
During the exercise, the licensee conducted an accountability drill to ensure all personnel within the protected area could be accounted for within a thirty minute time frame.
A number of personnel (total of 14) did not respond as required and remained unaccounted for.
A search of the protected area by plant security personnel eventually accounted for all personnel.
This portion of the drill was determined to be unsatisfactory and was subsequently performed satisfactorily a few days later.
Persons failing to respond to the accountability drill were given remedial training.
The remainder of the drill was observed to have been satisfactorily conducted.
PLANT SECURITY COMPUTER BOARD FAILURE On February 25, 1996, following the receipt of intermittent communication alarms associated with the primary security computer,
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plant security personnel transferred control of the plant security system to the backup computer.
Although the transfer was successful, security personnel were unable to confirm th'is due to central alarm station panel lights not indicating that the computer had actually taken control.
Compensatory measures were initiated by security.
Approximately one hour later, security personnel transferred back to the
,primary computer.
For a period of 16 minutes following this transfer, neither computer was actually controlling although the numerous local intelligence units and compensatory measures were maintaining plant security integrity.
The primary computer was returned to service with the exception of 2 networks.
One hour later, the secondary computer was placed in service with all systems functioning as designed.
During the event, licensee personnel conservatively determined that the event met the I hour reporting criteria for a total loss of the security system specified in 10 CFR 73.
A report was made to the NRC Operations Center and the resident inspector who responded to the site to monitor the licensee's actions.
The problems associated with the primary computer were found to be associated with two network board failures.
A review of the event revealed that at no time had the entire security system failed and therefore the licensee retracted the one hour report on February 29.
No violations or deviations were identified.
5.7 OPEN ITEMS REVIEW (92903, 92904)
5.7.1 (OPEN) IFI 259,260,296/95-33-02:
REVIEW LICENSEE EVALUATION OR RADIATION MONITORING SYSTEM INSTRUMENT DESIGN SPECIFICATIONS.
During an inspection conducted on June 5-9, 1995, the inspector noted that both non-safety and safety-related radiation monitor design environmental specifications should be reviewed against UFSAR commitments and expected environmental conditions to ensure equipment reliability for normal and accident conditions, as applicable.
During this inspection the licensee's progress in their reviews was discussed with the Engineering personnel involved in the rev-)ew.
The licensee indicated that the target completion date for their review was the end
'f February 1996 and that the results of that review would be documented in the closure package for Site Licensing Tracking No. 950500001.
This item will remain open pending NRC review of the licensee's completed evaluatio i
5.7.2 (OPEN)
URI 96-01-02:
DRYWELL CONTINUOUS AIR HONITOR SETPOINT
- DETERHINATION METHOD In. December 1995, the resident inspectors noted that the Unit 2 Primary Containment Leak Detection Continuous Air Honitor was in constant alarm due to a slight increase in drywell leakage rate.
In accordance with 2-TI-24 the alarm setpoint was increased to correspond with the increased background activity concentration in the drywell.
The indicated drywell activity concentration was approximately 2E-9 Ci/cc and the alarm setpoint was approximately 1. 18E-8 Ci/cc, which was much higher that three times the average background as required by TS Table 3.2.E.
The licensee's method for determination of the alarm setpoint was deemed an
.unresolved item pending further review by the NRC.
During this inspection the licensee provided the inspector with the technical justification for their method of setpoint determination.
The technical basis for that method, is being evaluated by the NRC and this item will remain open pending completion of that evaluation.
6.0 REVIEW OF UFSAR COMMITMENTS A recent discovery, of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR description.
While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected.
The following inconsistencies were noted between the wording of the UFSAR and the plant practices, procedures and/or parameters observed by the inspectors.
Section 10.5.5 of the UFSAR states that a high level in the SFP will actuate an alarm in the control room.
The control room alarm is not actuated by high level.
(paragraph 4.3)
Section 13.9 of the UFSAR states that refueling takes place on an approximate annual basis instead of about every eighteen months.
(paragraph 4.4)
Several sections of the UFSAR associated with electrical systems have not been updated to reflect the return of Unit 3 to power operations.
(paragraph 2.1)
Paragraphs 2.2 and 4.2 describe other specific UFSAR reviews that were performed by the inspectors with no discrepancies noted in those sections of the UFSAR.
The licensee's gA management has directed that a detailed review of applicabl'e portions of the UFSAR be included in assessment activities.
This has resulted in one UFSAR inaccuracy being identified as well as several areas that should be clarified or enhanced.
Recently, the licensee identified that several doors between the RB and the control
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building were not being used "for emergency use" as stated in the UFSAR.
Corrective actions were initiated.
7.0 EXIT (30703)
The inspection scope and findings were summarized on March 15, 1996, by L. Mert with those persons indicated in paragraph 1.
An interim exit was conducted on February 9, 1996.
The inspectors~ldescribed the areas inspected and discussed in detail the inspection results.
A listing of inspection findings is provided.
Proprietary info'rmation is not contained in this report.
Dissenting comments were not received from the licensee.
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VIO 260/96-03-01 Failure To Follow Procedures During Core Spray Valve Maintenance, paragraph 3.2 URI 260,296/96-03-02 IFI 260,296/96-03-03 IFI 296/96-03-04 EA 95-220 (01012)
URI 259,260,296/96-01-02 TMI 296/I.D.2.3 IFI 260/94-27-04 IFI 259,260,296/95-33-02 Open Open Open Open Open Closed Open Open Appendix R Instrumentation Discrepancies, paragraph 4. 1 IM Inattention,To Detail Issues, paragraph 3.4 Affects of Adjustment of Scram Valve Packing on Control Rod Scram Times, paragraph 3.5 Failure to ensure that provisions of
CFR 50.7 were adequately implemented, paragraph 3.7.6 URI Drywell Continuous Air Honitor Setpoint Determination Method, paragraph 5.7.2 THI SPDS Fully Implemented, paragraph 4.5. 1 IFI - Outage Schedule Safety Assessment Issues, paragraph 4.5.2 IFI - Review Licensee Evaluation of Radiation Monitoring System Instrument Design Specifications, paragraph 5. LER 260/94-12 LER 260/94-10 LER 259/96-01 LER 296/95-01 LER 296/95-06 8.0 ACRONYMS Closed Closed Closed Closed Closed
Residual Heat Removal Shutdown Cooling Valve Was Inadvertently Closed As A Result Of Personnel Failure To Follow Procedure During Performance Of A Surveillance Instruction, paragraph 3.7.1 Loss Of The 'Emergency Core Cooling Systems (ECCS) Division II Instrumentation Resulting From A Blown Fuse In The Analog Trip Unit (ATU) Invertor Caused By A Failed Capacitor, paragraph 3.7.2 A Unit 1/2 Diesel Generator Auto Started During Local anel Testing As A Result Of A Component Failure, paragraph 3.7.3 Loss of a 16lkV Line Caused Actuation of the ESF System, paragraph 3.7.4 SDV Instrument Vent
& Drain Valves Fail To Close After The Reactor Mode Switch Was Placed In Shutdown Position, paragraph 3.7.5 APRM ASOS BFN BWR CAM CFR CI Ci/gm CR CRD CS DCN DEI EA ECCS EDG EECW EHC EPRI FCV GE GL Average Power Range Monitor Assistant Shift Operations Supervisor Browns Ferry Nuclear Plant Boiling Water Reactor Continuous Air Monitor Code of Federal Regulations Chemistry Instruction Curies/gram Control Room Control Rod Drive Core Spray Design Change Notice Dose Equivalent Iodine-131 Escalated Action Emergency Core Cooling System Emergency Diesel Generator Emergency Equipment Cooling Water Electro Hydraulic Control Electric Power Research Institute Flow Control Valve General Electric Generic Letter
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HCU HEPA HPCI IFI II IM INin. lbs.
IR ISI kv LER LLRT HOV NASL NPDES NRC NRR NTU ODCM ORAM PASS PCIS PDR PER PHT QA QC RBCCW RCIC RHR RHRSW RWCU SDC SDV SFP SI SPDS SRV SOS SSP SSPV TMI TI TS TSS TVA UFSAR URI VIO WO
Hydraulic Control Unit High Efficiency Particulate Air High Pressure Coolant Injection Inspector Followup Item Incident Investigation Instrument Mechanic Information Notice inch-pounds Inspection Report Inservice Inspection Kilovolts Licensee Event Report Local Leakrate Test Motor Operated Valve Nuclear Assurance and Licensing National Pollutant Discharge Elimination System Nuclear Regulatory Commission Nuclear Reactor Regulation Nephelometric Turbidity Units Offsite Dose Calculation Hanual Outage Risk Assessment and Hanagement Post Accident Sampling System Primary Containment Isolation System Public Document Room Problem Evaluation Report Post Modification Testing Quality Assurance Quality Control Reactor Building Closed Cooling Water Core Isolation Cooling Residual Heat Removal Residual Heat Removal Service Water Reactor Water Cleanup Shutdown Cooling Scram Discharge Volume Spent Fuel Pool Surveillance Instruction Safety Parameter Display System Safety Relief Valve Shift Operation Supervisor Site Standard Practices Scram Solenoid Pilot Valve Three Mile Island Technical Instruction Technical Specifications Total Suspended Solids Tennessee Valley Authority Updated Final Safety Analysis Report Unresolved Item Violation Work Order
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