IR 05000259/1996008
| ML18038B761 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 09/25/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B760 | List: |
| References | |
| 50-259-96-08, 50-259-96-8, 50-260-96-08, 50-260-96-8, 50-296-96-08, 50-296-96-8, NUDOCS 9610030201 | |
| Download: ML18038B761 (52) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License Nos:
50-259, 50-260, 50-296 DPR-33, DRP-52, DPR-68 Report Nos:,
50-259/96-08, 50-260/96-08, 50-296/96-08 Licensee:
Tennessee Valley Authority Facility:
Browns Ferry Nuclear Plant, Units 1,
Im 3 Location:
Corner of Shaw and Browns Ferry Roads Athens, AL 35611 Dates:
July 21
- August 31, 1996 Inspectors:
Approved by:
L. 'Wert, Senior Resident Inspector H. Morgan, Resident Inspector'.
Husser, Resident Inspector S. Sparks, Project Engineer, DRP H. Lesser, Chief Reactor Projects Branch
Division of Reactor Projects Enclosure 96i003020f.
'760925 PDR ADOCK 05000259
II
EXECUTIVE SUMMARY Browns Ferry Nuclear Plant, Units 1, 2 5 3 NRC Inspection Report 50-259/96-08, 50-260/96-08, 50-296/96-08 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.
The report covers a six-week period'of resident inspection and includes efforts of the Region II, Browns Ferry Project Engineer.
~Ocr actions
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Overall conduct of operations was very professional and focused on safety.
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A clearance tag deficiency involving non-safety related equipment was identified by one of the inspectors (Section 01.2).
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During a routine tour of the units, an inspector identified various Unit 1 mechanical equipment room housekeeping deficiencies.
The inspector also noted that the Control Room Emergency Ventilation System (CREVS) ductwork was.structurally intact (Section 02. 1).
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A Unit 3 Division I Emergency Core Cooling System (ECCS)
ATU Inverter failure occur red on August 6.
This resulted in a loss of ECCS Division I logic inputs.
Licensee corrective actions were prompt; however, a specific cause of the inverter failure was not identified (Section 02.2).
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An inspector noted that a Unit 3 High Pressure Coolant Injection (HPCI)
flow controller was in "manual" rather than an expected
"automatic" position.
A Technical Specification (TS) Limiting Condition for Operation (LCO) had not been properly entered and was considered a non-cited violation (NCV) (Section 04.1)
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On August 6, the 2B recirculation pump motor generator tripped on high stator temperatures due to inadequate stator.
cooling.
This resulted in a loss of flow in the "B" recirculation loop.
Proper immediate and long-term corrective actions were taken by plant personnel (Section 04.2)
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An inspector attended a regularly scheduled Nuclear Safety Review Board (NSRB) meeting and noted that the meeting provided constructive third-party oversight of plant activities (Section 07. 1).
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The inspectors reviewed corrective action plans for about 25 Problem Evaluation Reports (PERs)
and concluded that the actions addressed deficiencies/causes.
Also, one of the inspectors attended a Human Quality Improvement Council (HPQIC) meeting and concluded the meeting reflected a
revitalized effort to improve plant performance issues (Section 07.2).
Maintenance
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The inspectors observed maintenance related to installation of.MSIV Limit Switch Isolation Transformer s.
The transformer s were installed to correct circuitry grounding problems.
Short-term corrections were found to be adequate; however, future modification review is needed to fully resolve the issue (Section M2.1).
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One of the inspectors observed maintenance activities associated with repair of the RCIC control valve 2-FCV-71-10.
The inspector s noted that work performed was satisfactory (Section M2.2).
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After inspection/review of EDG painting activities, inspectors concluded that supervision of painting was not strong (Section M4.1).
En ineer in
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The inspectors examined engineering activities related to troubleshooting, repair and testing the CREVS B Fan Suction Damper and concluded that engineering efforts appeared adequate (Section E2.1).
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The inspector s noted that planning activities for the Unit 3 Refueling Zone Supply Damper solenoid was an improvement over previously observed weaknesses.
However, a modif'ication to replace the existing solenoids with better solenoids is required to fully resolve the issue (Section E2.1).
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A discrepancy was identified between a fire hazard analysis (FHA) and an abnormal operating procedure and this was considered an NCV (Section E8.1).
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An inconsistency was identified regarding Final Safety Analysis Report description of the traveling screen washdown pumps.
The inconsistency was added to a previously issued URI (Section E8.4).
Plant Su ort An inspector reviewed a plant radiological waste procedure, toured the low level radwaste storage facility and concluded that overall conditions were satisfactory (Section R2. 1).
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A routine walkdown of the protected area fence was performed by one of the inspector s.
The inspector noted that physical barriers were satisfactory.
(Section S2.1)
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During a routine tour of the site intake structure, one of the inspectors noted that some of the covers associated with some of the Residual Heat Removal Service Water (RHRSW) valves were not secure.
Covers were locked in place and elevated management attention was observed (Section S2.2).
0
Summar of Plant Status Re rt Details Unit 1 remained in a long-term layup condition with the reactor defueled.
Units 2 and 3 operated at power during this report period.
On August 6, 1996, the Unit 2 2B Recirculation Pump Hotor Generator tripped due to high generator stator temperature.
Power was immediately reduced upon loss of the "B" recirculation loop, proper cooling flow was restored to the stator and the "B" recirculation loop was recovered.
On August 6.
1996, the Unit 3 ECCS, Division I ATU Inverter failed and was declared inoperable.
Proper TS LCOs were entered and, on August 7, the licensee notified the NRC in accordance with 10 CFR 50.72.
The affected converter was repaired and declared operable.
On August 10, 1996, Unit 3 power was reduced to 50 percent for rod pattern adjustment and miscellaneous corrective maintenance repairs.
The unit was returned to full rated power on August 11, 1996 and operated at power for the remainder of the reporting period.
Ol Conduct of Operations 01.1 General Comments 71707 I. 0 rations Using Inspection Procedure (IP) 71707, the inspectors conducted frequent reviews of ongoing plant operations.
In general, the conduct of operations continued to be professional and safety-conscious and specific observations are detailed in the following sections.
01.2 Clear ance Ta Deficiencies 71707 a.
Ins ection Sco e
71707 During routine walkdowns of accessible plant areas, inspectors specifically tracked clearance,
¹0-96-0278.
Portions of other clearances were verified in accordance with guidance presented in IP 71707, Section 02.03.a.
b.
Observations and Findin s On August 7, 1996, one of the inspectors identified two deficiencies involving clearance
¹0-96-0278:
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Clearance tag ¹0-96-0278-1 was located on the Hain Shop Supply Fan
"C" breaker; cubicle 3B on Service Building Vent Board ¹1.
The tag was hanging on a breaker fuse bag holder.
The tag should have been on switch ¹0-XS-30-119; a selector switch on cubicle 5B of the same vent boar ll
C.
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Switch ¹0-XS-30-119 was positioned in the "on" position instead of the clearance tag ¹0-96-0278 specified "off" position.
The cubicle 5B breaker (Power Stores Supply Fan
"B" breaker)
was tagged open so personnel hazards were limited.
The inspector reported the above to the Shift Support Supervisor and PER ¹961051 was initiated.
Operations management postulated that the tag may have fallen off the Service Building Vent Board and was incorrectly reinstalled; however, this explanation did not account for the selector switch being in the
"on" position.
Plant procedures require that any clear ance tags discovered misplaced from their installed position are to be reported to Operations for resolution.
Personnel involved in the clearance were interviewed and security tasked to further investigate the problem.
The inspector did not see any nearby equipment or ongoing work activities which would have resulted in the component being bumped.
The licensee concluded that the most likely cause was that the tag had been bumped, knocked off, or moved after it was hung.
Site inspectors reviewed the PER corrective action plan and noted that Operations has been.tasked with issuing a site briefing which should clarify actions required if a tag is found out of position or if equipment is bumped.
Conclusions The equipment involved was not safety-related.
Because other clearance tags controlled the fan's power supply breaker position, the fact that the switch was not "tagged" or positioned in "off" was inconsequential and did not result in a personnel safety hazard.
The inspectors have not identi.fied any similar clearance deficiencies in recent months.
During routine reviews of PERs the inspectors did not observe similar problems.
The actual cause of the condition could not be determined and safety-significance was minimal.
Operational Status of Facilities and Equipment 02.1 General Plant Cleanliness and E ui ment Conditions a.
Ins ection Sco e
71707 On several occasions during the report period, the inspectors toured accessible plant areas in accordance with guidance presented in IP 71707, Section 02.01(b).
Observations and Findin s:
On August 27, 1996, an. inspector toured the mechanical equipment room located in the Unit 1 end of the control bay.
Host of the equipment in the room contained safety-related air conditioning and this equipment supports operation of Unit 2.
The inspector noted several water leaks (around the condenser)
without work request tags, an electrical junction box without a cover, and an accumulation.of rags and towels under some air handling unit ductwork.
The inspector noted that a Unit 1 caution tag, ¹94-0192-1 had been installed in November 1994 to indicate that a
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02.2 damper, f31-.712, functions in reverse of posted
"open/close" position labels.
The inspector informed the Unit.2 Unit Supervisor of these observations and the problems were promptly addressed.
The rags and towels were removed and the area cleaned.
Work requests were issued to address other deficiencies.
Licensee management determined that the employee responsible for the area had identified most of the items on an employee walkdown conducted about one week earlier than the inspector 's walkdown; however, items previously identified had not been corrected prior to the inspector's observations.
Also, during the inspection period, one of the inspectors walked down the suction ductwork of the Control Room Emergency Ventilation System (CREVS) from open ends near the edge of the control building roof to the CREVS fans in the control bay.
Ductwork was intact and no other problems were noted.
Overall housekeeping in the ventilation tower structures on the control building roof was satisfactory.
Conclusions Corrective actions were performed promptly.
General condition of the CREVS system and other inspector observed areas was satisfactory.
Plant personnel followed through on assigned housekeeping corrective action items in an adequate manner
.
Unit 3 Emer enc Core Coolin S stem Inverter Failure 71707 93702 Ins ection Sco e
71707 93702 While providing a prompt, onsite assessment of the inverter failure, inspectors determined adherence to facility approved abnormal operating instructions and examined unit status during the event.
The inspector 's actions were performed in accordance with guidance presented in IP, 71707 Sections 02.01.a.2 and 02.0l.a.3 and IP 93702, Sections 02.01 to 02.06.
Observations and Findin s At 8:41 p.m.,
on August 6, 1996, the Unit 3 Division I Emergency Core Cooling System (ECCS) Analog Trip Unit (ATU) inverter failed.
This resulted in loss of Division I logic inputs for ECCS including Residual Heat Removal (RHR), Core Spray (CS),
High Pressure Coolant Injection (HPCI), Automatic Depressurization (ADS), Emergency Diesel Generators (EDGs), other reactor pressure sensors, containment parameters, and the RCIC flow controller
.
A blown inverter fuse was found and additional troubleshooting was initiated. Technical Support personnel and the Plant Hanager responded to the site and a 4-hour notification was made to the NRC at 12:37 a.m.
Except for actuating the RCIC and one CS loop, the remaining Division II inverter was sufficient to automatically actuate all other ECCS equipment.
Because there was not a specific TS associated with the inverter, the licensee reviewed multiple TS LCO entries associated with inverter failures.
The licensee concluded that the ADS TS contained the, most l-imiting and appropriate LCO.
An inverter control board and SCR were replaced and the circuit was re-energized at 1:54
II
0
a.m.
All ECCS systems were restored to pre-event conditions.
An AOI was subsequently approved which provides additional operator guidance to respond to future inverter failures.
The inspector verified that the Unit 3 operators understood the true condition of'he Unit 3 ECCS equipment.
Some of the inverter troubleshooting activities were also observed.
The inspector was aware that the licensee had been having difficulty with the chiller that cools the electric board room in which the inverter is located.
The inspector noted that room temperature was 96 degrees F shortly after the inverter failed.
Compensatory actions included opening doors and use of external/portable fans.
All actions were controlled by procedures.
The inspector discussed with plant management his concern that high temperature may have played a role in the failure.
The inspector noted that the Division II inverter is in another board room which, at the time of the event, also had elevated temperatures.
There was a recent ECCS inverter failure at Browns Ferry.
On July 17, the Division I inverter failed due to a control board and SCR failure.
The inspectors had observed some of the repairs and noted that the electric board room was not hot when that failure occurred.
The licensee does not know the true cause of the failure but acknowledged temperature could have been a factor.
Plant management directed additional steps be taken to decrease board room temperatures.
Subsequently air conditioning was returned to operation.
While there have been reliability problems with these air conditioning systems, the inspectors haven't noted any other operational impacts on safety-related equipment.
The licensee has developed detailed procedural controls to address. loss of air conditioning cooling capacity in the electrical equipment rooms.
The inspectors reviewed the inverter vendor manual and noted that the inverters must be mounted a minimum of six inches away from the wall to allow for proper ventilation.
The inspectors observed that the actual installed clearances are about 3 inches.
The inspectors questioned if the modification installing the inverters had addressed the smaller clearances.
The licensee initiated PER f961123 to address this issue.
c.
Conclusions The inspectors reviewed LER 296/96-004, Loss of'CCS Inverter Renders ECCS Equipment Inoperable.
The inspectors noted that in the event analysis, the LER described
"manual" operation of ECCS equipment if required during the incident.
Automatic operation of most ECCS systems was still available.
This observation was discussed with the licensee and the licensee will submit a revision to the LER to more accurately describe the issues.
The specific cause of the inverter failure, impact of air conditioning, and questions on the inverter instal-lation clear ances were not fully under stood by the licensee.
The issues will be addressed as IFI 296/96-08-02, Emergency Core Cooling System lnverter Failur II
Operator Knowledge and Performance Failure to Enter Technical S ecification TS LCO for HPCI S stem Ino er abilit 71707 Ins ection Sco e
71707 During routine control room observations, inspectors determined whether or not the licensee complied with appropriate TS LCO action statements when abnormal conditions existed.
Determinations were performed in accordance with guidance presented in IP 71707, Section 02.01.a.3 Observations and Findin s On August 1, 1996, during observation of Unit 3 control room activities, an inspector observed'hat the HPCI flow controller, ¹3-F-73-33, was in
"manual" instead of "automatic".
The reactor operator (RO)
and senior reactor operator (SRO) indicated that for various reasons, an LCO action statement had not been entered and HPCI was not considered
"inoperable".
The inspector noted other components of the ECCS were normally aligned.
The Unit Operator (UO) stated to the inspector that other ECCS.equipment would not be removed from service under present conditions.
The inspector further questioned the SRO on whether the procedure being performed, ¹3-LCI-3-F-73-33, addressed desired, HPCI status.
It was subsequently confirmed that this procedure clearly stated that HPCI should be deemed inoperable during performance of the procedure.
The issue was further discussed with Operations management who stated that it was expected that HPCI be declared inoperable and that the LCO would be entered during such conditions.
The inspectors are not aware of similar issues at this facility in recent years.
Subsequent licensee review indicated that the switch had been placed in manual for a short period two days ear lier and the system was not declared inoperable.
The same operating staff were apparently involved in both instances.
The incident is a misunderstanding of TS operability and related administrative requirements. It was further noted that in both cases, the switch had been in manual for only short periods of time and other ECCS injection systems were oper able during these periods.
Site Specific Procedure (SSP)
12.51, Tracking of Limiting Conditions for Operation, states that when equipment identified in a TS is made or becomes inoperable, plant conditions may require LCOs to be entered.
Also, the UO is responsible for logging entry into and exit from TS LCOs.
Section 3.3.4 of SSP 12.51 specifically required the UO to enter, in the narrative log, the time impacted equipment is made inoperable and the time limit permitted to remain-inoperable based on current plant/unit conditions and redundant equipment status.
Conclusions The inspectors found that the licensee response to the issue was prompt/
appropriate.
This failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation (NCV) consistent with
Ci
0
Section IV of the NRC Enforcement Policy.
This issue is identified as NCV 296/96-08-01, Failure to Enter TS LCO for High Pressure Coolant Injection System Inoperability.
Unit 2 Recirculation Pum Tr i 71707 93702 Ins ection Sco e
71707 93702 While providing a prompt, onsite assessment of a Unit 2 Recirculation Pump trip, the inspectors determined adherence to approved emergency and abnormal operating procedures and noted unit status during the event.
The inspector's actions were performed in accordance with guidance presented in IP 71707 Section 02.01.a.2 and IP 93702, Sections 02.01 through 02.06.
Observations and Findin s At 7:18 p.m.,
on August 6.
1996 the 2B recirculation pump motor generator tripped which resulted in a loss of flow in the "B" recirculation loop. Plant response was as expected.
The region of
"incr eased awareness" for power instability was not entered and the reactor level decrease was not excessive.
Operators performed actions of 2-AOI-68-1, Recirc Pump Trip/ Core Flow Decrease.
Reactor power was further reduced by rod insertion prior to pump restart.
Along with others, a reactor engineer and the Operations Hanager responded to the site.
The cause of trip was traced to a failure of a temperature control circuit.
The failure resulted in reduced Raw Cooling Water (RCW) flow to the recirculation HG set stator.
A control room alarm was received on increasing temperature and the operators responded.
but the temperature increase was too fast to prevent stator high temperature from tripping the pump.
RCW cooling flow was subsequently reestablished by bypassing the automatic temperature control valve.
The "B" recirculation loop was recovered at 10:50 p.m.,
and the operators were thorough in performance of surveillance to meet all requirements to restart the pump.
The region of potential instability was -not entered on the pump restart.
An inspector observed pump recovery and verified response to the trip was performed as required by approved procedures.
The inspector specifically verified the following:
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Region of instability wasn't entered on pump restart or initial loss.
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Pump restart requirements were met.
The inspector independently reviewed temperature, power and flow conditions against TS requirements.
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Reactor engineer adjusted APRN gains thus
"R" factor was reduced as required by TS.
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Single recirculation loop LCOs were entere Cl
C.
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As running pump speed was reduced flow was kept above minimum required to ensure indicated flows were conservative.
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Operators and reactor engineer used required procedures.
Conclusions The inspector noted that proper immediate actions were taken by plant personnel.
Subsequent corrective actions were also in accordance with approved plant procedures and such actions taken were appropriate.
Quality Assurance in Operations 07.1 Nuclear Safet Review Board Heetin NSRB Heetin Ins ection Sco e
40500 b.
An inspector observed portions of a periodically scheduled NSRB meeting which was performed in accordance with TVA Policy 8 Organization Manual, HD-3.1 and SSP-4.8, Nuclear Safety Over sight.
In accordance with directions given in IP 40500, Sections 2.05 and 2.06, the inspector evaluated the licensee's performance of self-assessment in lieu of NRC inspections.
Observations and Findin s On August 21, 1996, an inspector attended portions of a scheduled NSRB meeting (No. 274).
The meeting was held at the plant site and provided an independent review of operations, engineering,,maintenance, plant support, and quality assurance activities.
The meeting met Technical Specification 6.5.2. 1 requirements for an off-site review committee and meeting agenda and discussions were extensive.
The meeting was orderly and also met Technical Specification 6.5.2.2. requisite for attendance.
A Technical Specification 6.5.2.6 quorum consisting of a board chairman, at least five NSRB board member s, appointed alternates, and advisor s were present.
Items observed included:
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Discussion of 10CFR50.59 Issues
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Safety Evaluation Preparations
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Radiation Control Work Practices
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.Review of Vendor Reports and Impact on BOP Equipment
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'FSAR Restructuring Issues
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Engineering Safety Assessments
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Check Valve Problem Discussions
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Actions To Improve Management Involvement In Training Prior to the meeting, member s were provided with a specific agenda of items to be discussed and a detailed information package for each item..
Board members appeared well'-informed and the meeting was conducted in a very professional/thorough manner.
During discussions NSRB member evaluations and conclusions did not find trends indicative of a decrease in plant safety.
The inspector noted members, when deemed necessary/
appropriate, did not hesitate to presented differing views and they were often quite candid in suggesting methods of resolutio c.
Conclusions The inspector noted applicable TSs were met and the meeting was informative and provided an adequate opportunity for constructive
"third-party" oversight of plant activities.
07.2 Licensee Corrective Action Pro ram a.
Ins ection Sco e
40500 In accordance with IP 40500, inspectors reviewed corrective action plans for approximately 25 Problem Evaluation Reports (PERs).
Review focused on verification of adequate corrective actions.
The inspectors selected PERs which were reviewed based on potential safety significance.
SSP-3.4, Corrective Action Program was reviewed prior to and during the inspection.
Additionally, one of the inspectors attended a
Human Performance Quality Improvement Council (HPQIC)'eeting.
b.
Observations and Findin s The following observations resulted from review of PER corrective actions:
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Corrective action plans that proceeded'hrough all reviews, including a final Nuclear Assur ance and Licensing (NASL) approval, were comprehensive and sufficiently addressed the issues.
NASL performed reviews which are not specifically required by procedures.
NA&L reviews of completed PERs
- which had not been reviewed by NASL as part of the normal PER process
- identified several examples in which corrective actions could have been stronger.
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The inspector noted several examples in which NA&L questioned corrective action plans and subsequently precipitated revisions in corrective actions.
In these cases proposed corrective actions did not address conclusions in the PER or were not sufficiently broad.
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The inspector noted several of the plant personnel-initiated PERs, addressed long standing equipment issues.
One example addressed radiation alarms which were set so low that they were expected to alarm during testing of the High Pressure Coolant Injection system.
This would not reliably inform operators of a problem.
These
.PERs indicated good insight in identifying areas for improvement.
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The inspector.
questioned scope of corrective actions on two PERs.
PER $960894 addressed an incident where a safety-related motor operated valve (HOV) was manually torqued shut without review of potential effects.
PER $960919 addressed delays in returning the HPCI system to service after maintenance with a unit at full power.
In both cases, corrective actions listed on the PER did not appear to be sufficiently broad to fully address PER conclusion ii
I!
On August 1, an inspector attended a
HPQIC meeting.
The council was established to address procedural noncompliances and human performance issues which were initially identified as an area for improvement at Browns Ferry two years ago.
The meeting included discussion of detailed trending information on procedural adherence issues.
Independent Review and Analysis performed a detailed review of 245 failure to follow procedure PERs.
The meeting also included discussion of other plant actions to reduce human performance issues.
Some attendees reported on actions initiated in their departments to improve performance.
It was evident that council members dedicated a large amount of attention to the effort.
Conclusions
08 08.1 08.2
'08.3 The inspector concluded that, in general, corrective actions were sufficient to address identified deficiencies and causes.
The inspector also concluded that NASL reviews of the.PER process have been effective and, in some cases, instrumental in strengthening corrective actions.
Browns Ferry management has been encouraging line management to improve corrective actions.
Reviewed PERs were completed in accordance with procedural requirements.
Furthermore, the inspector concluded that the HPQIC meeting reflected a revitalized effort to improve plant performance issues.
Miscellaneous Operations Issues (92700)
Closed LER 50-260/96-01 Rev.
0 and 1:
Noncompliance Results in the Plant being Outside its Design Basis and Being in a Condition Not Covered by Plant Operating Instructions.
This issue was addressed as a violation in IR 50-259,260,296/96-04.
No new issues were revealed by this LER.
Closed VIO 50-296/95-26-01:
Failure to Implement Actions of Abnormal Operating Procedure.
This violation was issued due to failure to implement O-AOI-100-7, Tornado, which requires that the reactor building crane be secured during a tornado watch.
The licensee's response to the violation, dated July 6, 1995, contained corrective actions which included SOS counselling, and a revision to 0-AOI-100-7.
The revision provides the SOS with latitude to evaluate weather conditions and determine whether the building crane should be secured.
The inspector reviewed revision 10 to 0-AOI-100-7 and verified the procedural changes had been made.
The inspectors concluded that the licensee's corrective actions were appropriate.
Closed VIO 50-296/95-56-01:
Failure to Follow Alarm Response Procedures Results in Loss of 480V Bus.
This violation was issued due to a failure by an SRO to implement 3-ARP-9-8B.
This resulted in an electrical board being transferred to a deenergized alternate supply, causing an unexpected engineered safeguards (ESF) actuation.
Licensee corrective actions as delineated in the response to the violation, dated December 4,
1995, included'roup meetings with on-shift operations
Cl 4I
personnel, and emphasis of self-verification techniques.
The inspectors concluded that the licensee's corrective actions w'ere appropriate.
Closed VIO 50-296/95-60-01:
Failure to Follow Configuration Control
.Procedures Resulting in Misconfiguration of SDV System Components.
VIO was issued due to identification of four scram discharge volume (SDV)
vent valves and drain valves, and a
SDV high level scram switch, found in a position other than that described in procedures.
The licensee's Incident Investigation (II) for the four scram discharge volume vent and drain valves could not determine a cause for the mispositioned valves.
The cause of SDV high level scram switch misposition was personnel error.
The inspector reviewed licensee corrective actions and considered them to be satisfactory.
In addition, the licensee has lowered their threshold and placed added emphasis toward issues related to personnel performance where management expectations are not being met.
An example of this increased attention was presented in PER f960726.
It reviewed/developed corrective actions for several recent issues of lower significance, involving attention to detail, self checking, and procedural adherence.
Conduct of Maintenance II. Haintenance Obser vation of Maintenance and Sur veillance Activities Ins ection Sco e
62703 61726 Selected surveillance and maintenance activities were observed to determine if the activities were performed in accordance with procedural and regulatory requirements.
Inspection scope included observation of surveillance tests 2-SI-4.5.F.1.d, RCIC System Flow Rate Test, O-SI-4.7.
E.5.B, Control Room Emergency Ventilation System (CREVS) Flow Rate Test, and examination of portions of the following maintenance activities:
W096003531000 Unit 3 MSIV Limit Switch Isolation Transformer Installation W096000129000 Unit 3 Emergency Diesel Generator (EDG) Painting W096052815000 Unit 3 EDG Painting W095022364000 Replacement of the Unit 2 RCIC Turbine Control Valve, 2-FCV-71-10, Stem, Packing and Packing Spacers Observations and Findin s Observed surveillance tests; performed as a post-maintenance test for RCIC and a modification test for Train "B" CREVS; were satisfactory.
Approved procedures were used and were properly followed.
Tests
II
H2 H2. 1 performed were in accordance with surveillance instructions and SSP 8.1, Conduct of Testing.
Surveillances were appropriately controlled.
With the exception of work involving EDG painting, (Section H4.1),
observed maintenance activities were satisfactorily performed and work was accomplished in accordance with work documents and work package instructions.
Haintenance and Hater ial Condition of Facilities and Equipment Installation of Unit 3 HSIV Limit Switch Isolation Transformers b.
Ins ection Sco e
62703 The inspectors verified that maintenance activities associated with HSIV
.Limit Switch Isolation Transformer installation were conducted in a manner that ensured reliable post-installation operation of transformers and HSIVs.
Inspection activities wer e performed, in part, in accordance with guidance contained in IP 62703, Sections 02.01.a.l to 02.0l.a.10.
Observations and Findin s Grounding of circuitry associated with the Unit 3 HSIV position limit switches has been occurring since January 1996 (See Inspection Report 96-05, Paragraph 3.2).
The problem is believed to have been caused by minor grounding of the limit switch wiring housed within flexible cables that run from the switches to Reactor Protection System (RPS) circuitry.
Grounding resulted in fuses clearing in the RPS circuitry, which caused de-energizing. of the relays and "fail-safe" inputs, into the RPS.
Because a number of switches failed, RPS logic was at times partially actuated.
During the inspection period isolation transformers were installed within the HSIV portion of the RPS circuitry in accordance with guidance contained in Temporary Alteration Control Form (TACF) 3-96-01-99 and Work Orders 96-003531-000 through 96-003531-005.
During a planned Unit 3 shutdown in September 1996, limit switch wiring is to be further checked by the licensee to gain additional details on the issue of spurious circuit y grounds.
The inspectors reviewed circuitry TACF documentation, drawings, work orders, transformer placement and post maintenance testing (PHT) associated with the transformers and existing circuits.
Conclusions The inspectors noted that installation of these transformers should resolve the immediate problem of minor system grounding.
However, further examination of temporary alteration and a future inspection of proposed permanent repairs is warranted.
Therefore, an item is opened as IFI 296/96-08-03, Unit 3 HSIV Limit Switch Circuitry Failure Unit 2 RCIC Turbine Tri Due to Unres onsive Control Valve 2-FCV-71-10 Ins ection Sco e
62703 The inspectors verified that maintenance activities associated with repair of RCIC control valve FCV-71-10 were performed in a manner which ensured reliable oper ation of the valve.
Inspection activities were performed, in part, in accordance with guidance contained in IP 62703, Sections 02.01.a.1 through 02.01.a.10.
Observations and Findin s On August 21, during performance of RCIC flow testing, system flow, as expected, rose to maximum upon start of the RCIC pump.
However, it then failed to settle out to rated flow conditions.
System flow would not decrease and the operators attempted to adjust discharge pressure in accordance with the surveillance instruction SI-4.5.F. l.d..
After the pressure adjustment operators took manual control of the flow controller and, again, attempted to lower flow.
The manual flow controller was adjusted to its lowest setting; however, flow remained at maximum and the control room operators decided to manually trip the pump turbine.
An inspector contacted the system engineer and noted that the apparent cause of the unresponsive control valve was corrosion between the control valve's carbon packing ring steel spacers and the liquid-nitrided, 410 stainless steel valve stem.
This condition was verified by inspector observation of the removed parts.
Because of this corrosion the valve's seal package (the carbon packing rings and steel spacers)
was essenti'ally frozen to the shaft and the desired designed movement, a slight flexure of the seals, did not occur
.
Without this desired designed flexure, when the valve initially opened, pieces of the carbon packing ring broke off and wedged the valve stem into an open position.
Similar industry problems with RCIC control valves have been referenced/
noted in NRC Information Notices 86-10 and 94-66.
Industry experience has shown that originally installed "gas" nitrided 410 stainless steel valve stems are less susceptible to this form of corrosion and related control valve failures.
Also, the industry has recently found that inconel-type valve stems are the least susceptible.
Replacement of these stems with inconel is an alternative.
The licensee's operating experience review was good; however, the licensee has had problems with the procurement of inconel stems.
Resolution of these problems are on-going.
The licensee's maintenance and engineering personnel were unable to find inconel-type stems in stock so they elected to install one of the original gas-nitrided stems until desired inconel stem replacements can be obtained.
The inspector noted that the Unit 3 RCIC control valve stem is of the gas-nitrided type.
The licensee currently plans to replace both of the Unit 2 and Unit 3 RCIC control valve stems with the inconel-type stems during upcoming planned, long-term outage Conclusions The valve was repaired in accordance with guidance contained in an approved work package, the turbine control valve technical manual and instructions of work order 485-022364-000.
The inspectors noted that the work performed was satisfactory.
Maintenance Staff Knowledge and Performance EDG Paintin Ins ection Sco e
62703 The inspectors verified maintenance activities associated with painting of Unit 1, 2, and
EDGs were conducted in a manner which would ensure reliable post-maintenance operation of the EDGs.
Inspection activities were performed, in part, in accordance with guidance contained in IP 62703, Sections 02.01.a.l through 02.01.a.l0.
Observations and Findin s During a routine tour on August 26, 1996, inspectors noted painting was in progress for several of the Unit 1, 2 and 3 EDGs.
On previous tours, inspectors had noted preparations for painting of both walls and floors in the EDG rooms.
The inspector s had verified that appropriate measures were in place to protect relays/cabinet interiors from dust generated during the work.
During a closer examination of the painting effort, the inspectors noted that on some of the diesels, application of gray aint had not been well-controlled.
Paint was observed on some moveable inkages between the governor mechanism and the EDG fuel'acks and on a position indicating switch.
The inspectors also noted that duct tape had been placed directly over'DG governor setting switches and questioned whether the associated switches had been moved or might be moved as tape was removed.
The inspectors also noted that a temporary light cord was hanging from some of the moveable linkage.
The inspectors immediately discussed their observations with two maintenance foremen present at the EDGs and the EDG system engineer
.
After these discussions, paint was removed from the EDG linkage, and, after removal of duct tape, governor settings were verified correct.
A plant PER f961153, was initiated to address the problems.
The licensee was responsive to inspector observations.
At the close of this report, review and additional corrective actions were being developed.
The inspectors reviewed the controls in place over the painting.
The painting was being per formed under work orders $96-000129 and 52-52815.
The 1992 work order stated that valve stems and fittings should not be painted.
The other work order directed that the work be performed in accordance with Hodification and Addition Instruction 5.7, Painting and Coating.
The inspectors reviewed Revision 9 of that procedure and noted that areas/components that are moveable or have operating parts are not to be painted.
Modification and Addition Instruction 5.3, Protective Coatings, also stated that moveable/operating parts are not to be
M8 H8.1 M8.2 M8.3
painted.
Pre-job briefings for the painters were to include designation of any areas that should not be painted.
Conclusions After additional review and discussion with maintenance management, the inspectors concluded that the painting had not caused inoperability of any of the EDGs
- the misapplied paint was spray applied and appeared to have thinner layers.
However, supervision of the painting activities was not strong.
Pending determination of the significance of this issue, Unresolved Item URI 260,296/96-08-05, Diesel Generator Painting Controls, is identified.
Hiscellaneous Haintenance Issues (92902)
Closed LER 50-260/94-13 Rev.
1: Unit 2 Scram From 541 Power Caused by Balance Of Plant Equipment Failure.
Revision 0 of this LER was reviewed and closed in IR 50-259,260,296/95-51.
The licensee issued Revision
to reflect additional enhancements being taken to evaluate other balance of plant devices capable of causing a turbine generator trip.
Revision 1 did not provide additional information not already reviewed/discussed in Inspection Report IR 50-259,260,296/95-51.
This LER is closed.
Closed IFI 50-296/95-16-04:
Work Plan Implementation Deficiencies.
This IFI was initiated due to several examples of deficiencies involving implementation of work acti.vities on Unit 3.
In response, the licensee initiated Level B PER ¹950151 and an Incident Investigation.
In addition, the licensee is addressing similar issues on an overall plant wide basis as part of the Muman Performance Quality Improvement Council actions.
The inspector attended a Council meeting on August 1, 1996, as discussed in section 07.2.
Recent inspection reports have documented licensee improvement in this area, however, additional progress is needed.
Based on licensee and NRC ongoing activities in this area, as discussed above, this issue is closed.
Closed LER 50-260/95-03 Rev..0 and 1:
Hain Steam Safety/Relief Valves Exceeded the Technical Specifications Required Setpoint Limit as a Result of Disc/Seat Bonding.
The licensee reported a condition following testing that revealed that 11 of 13 Safety Relief Valves (SRVs) were outside the TS limit of +/- one percent setpoint tolerance.
The licensee's analysis of "as-found" condition revealed that primary reactor system pressure would not have exceeded TS safety limit.
Cause was attributed to corrosion bonding of the SRV pilot disc/seat interface resulting in an upward setpoint drift.
During the Unit 2 cycle 7 outage, 'the licensee implemented Boiling Water Reactor Owners Group (BWOG) recommendations and replaced main steam SRV pilot cartridges with cartridges that have a 0.3 percent platinum alloyed stellite pilot disc.
Based on continuing licensee activities of this generic industry issue, this LER is close l II
E2 E2.1 a.
III. En ineerin Engineering Support of'acilities and Equipment Re air of CREVS B Fan Suction Dam er 0-31-7215 Ins ection Sco e (37551)
The inspectors examined engineering activities related to troubleshooting, repair and testing of CREVS B Fan Suction Damper 0-31-7215.
Inspection activities.were performed in accordance with guidance contained in IP 37551, Section 02.01.
Observations and Findin s At the request of the CREVS system engineer, on August 2, 1996, the B
train CREV was started in accordance with operating instruction, 0-OI-31, in order to perform a test of the damper
.
During testing the damper failed to open and CREVS was immediately shutdown.
Subsequent licensee maintenance and engineering troubleshooting activities determined that the damper required extensive repairs and the damper was shipped out to the vendor.
The vendor determined that a plastic pivot pin grommet had worn away and this caused binding of the damper assembly.
While at the factory, the damper assembly was cycled approximately 50 times without problem.
After return to the licensee and after reinstallation and resetting of the damper limit switches, on August 8, 1996, it was again cycled over 25 times and presented no problems.
On August 8, after PHT was performed in accordance with SI-4.7.E.5.B, CREVS Flow Rate Test, the B train was returned to service.
Conclusions E2.2 Current monitoring of CREVS performance by on-site engineering appears adequate and provides an early indication of any degradation in system performance.
Secondar Containment Dam er Solenoid Valve Failures b.
Ins ection Sco e (37551)
The inspectors examined'ngineering actions related to troubleshooting, repair and testing of the Unit 3 Refueling Zone Supply Isolation Dampers 3-FCO-64-6.
Inspection activities were performed in accordance with guidance contained in IP 37551, Section 02.01.
Observations and Findin s On August 13, 1996, one of the Unit 3 refueling zone supply isolation dampers (3-FCO-64-6) failed to close when the refuel zone fans were secured.
The other damper in the line shut as expected.
The solenoid valve which ports air to the damper operating cylinder apparently stuck shut.
Light tapping on solenoid valve resulted in valve repositionin Cl
Later on August 14, one of the Unit 3 Reactor Zone exhaust dampers also stuck.
These situations are similar to ASCO solenoid valve failures which occurred previously at Browns Ferry.
IR 95-64 contains a detailed description of the issues.
IFI 260, 295/95-64-10, Secondary Containment Ventilation Damper Failures was opened to track licensee corrective actions regarding the solenoid issues.
The inspector verified that the operators deactivated the other refueling zone supply damper (there are two dampers in series in the line) in the closed position.
A TS LCO was entered until the damper was secured.
The solenoid was subsequently replaced.
Subsequent review indicated that the failed solenoid was a type NP206 which had been replaced seven months ago as corrective action to the ear lier solenoid issues.
At that time, data indicated that the 'NP206 solenoids would operate without sticking for at least 12 months.
Information indicates that the same type of core-plug interface problems involved in the previous failures occurred in this most recent example.
The licensee is continuing to shift ventilation fans weekly.
This is intended to detect malfunctioning dampers.
Additionally, the licensee has initiated design changes to replace the solenoids with a type that is not susceptible to the core-plug interface problems.
Plans are being made to replace several of the solenoids on Unit 3 with the more reliable type of solenoids during a planned maintenance shutdown since those solenoids are difficult to replace with the unit operating.
Conclusions E8 E8.1 The inspectors noted that this activity had been scheduled for the next refueling outage but was pulled back into the September 1996 maintenance shutdown.
This indicates improvement over previous NRC observations of weaknesses in maintenance planning (IR 96-05).
IFI 95-64-10 remains open on the overall solenoid issue.
Hiscellaneous Engineering Issues (92902)
Closed URI 50-260 296/95-64-08:
Fire Damper Procedur al Controls.
This issue was identified by the NRC dur ing an ORAT (IR 50-296/95-201)
due to.an apparent discrepancy between the Fire Hazards Analysis (FHA)
and Emergency Plan Implementing Procedure (EPIP) 21.
The FHA states that procedures are in place to require the control room to initiate HVAC zone isolation when a fire is verified in an area.
However, Abnormal Operating Instr uction AOI-26-01 stated that actions to secure ventilation are to be taken based on recommendation of the fire brigade leader.
As such, plant procedures do not require zone isolation as stated in the FHA, but allow for judgement of the incident commander (ASOS).
The inspector held discussions with licensee personnel, who stated that this issue is being addressed as part of DCN T39363A.
This DCN provides for revision of the FHA such that zone isolation can be initiated on an as-required basis, based on the judgement of the emergency response
0
team.
The inspector reviewed the design change package and associated safety assessment/safety evaluation, and considered the licensee's actions to be satisfactory.
The inspector concluded that the discrepancy between the FHA and AOI-26-01 represents a violation of minor safety significance and is being treated as a Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy.
This issue is identified as NCV 260,296/96-08-04, Fire Damper Procedural Controls.
E8.2 Closed LER 50-260/94-11:
Failure of a Motor With a Magnesium Alloy Rotor on a Reactor Water Recirculation System Pump Discharge Isolation Valve Placed Unit 2 in a Limiting Condition for Oper ation.
This voluntary LER was submitted due to the generic safety significance of this event.
The issue was associated with a recirculation pump discharge valve which failed to shut during a planned shutdown of Unit 2 in October 1994.
Unresolved item 260/94-24-07 was opened to address this issue, and was subsequently closed.
Inspection report 259,260,296/94-27 also addressed the licensee's root cause and response to this issue, as well as resident inspector review of this issue.
The inspector reviewed the above information, and concluded that the previous NRC review is sufficient to close this LER.
E8.3 Closed IFI 259 260 296/94-12-02:
Correction of BFN Design Change Process Problems.
This item was inspected and closed in Inspection Report 259,260,296/96-04, however was err onously identified in that report as IFI 94-12-01.
E8.4 FSAR Reviews 71707 40500 During the inspection period, the inspectors examined and noted the following FSAR issues:
~
Section 11.6.3, Condenser Circulating Water system description, describes how the gate structures are to be positioned depending on the Circulating Water System mode of operation.
During a plant tour when the circulating system was in the open mode, the inspector noted that gate 1 was not being maintained closed as the -FSAR described.
In response to this observation, the licensee provided a copy of a Change Request to Licensing Document dated July 3, 1996, which revised the FSAR to reflect the actual oper ation of the gate structures.
This revision had been initiated to update the number of cooling towers (after a fire destroyed one)
and the gate functioning had been updated as a result.
During subsequent review of this issue, the licensee identified that although the FSAR had been revised, the Operating Instructions for the circulating water system had not yet been revised to specifically permit gate 1 to be left open in the open mode.
The procedure was subsequently revised.
~
Section 11.6.3 also describes the functioning of'he traveling screens and screen wash system.
The inspector identified that the screenwash system was not being operated as described in the FSAR.
The FSAR describes automatic start/stop of the screenwash pumps and screens based on screen differential pressure.
The screenwash pumps
ll
are run essentially continuously and the screens are manually initiated.
The licensee plans to revise the FSAR to reflect the actual oper ation of the system.
~
Section 10. 12.5.2 contains a description of the Turbine Building heating, ventilation, and cooling systems.
It states that the systems are designed to provide a
summer maximum inside temperature of 105 degrees F with outside conditions at 97 degrees
.F.
One of'he inspectors noted that some temperatures in the turbine building were in excess of 105 degrees F and questioned this apparent discrepancy.
The licensee responded that this FSAR statement is referring to overall "bulk" temperatures in the turbine building. It was concluded that this condition is not a nonconforming condition.
The above described inconsistencies associated with the screenwash system operation will be addressed as part of URI 259,260,296/96-04-08, FSAR Discrepancies, which remains open.
No other inconsistencies were identified by the inspectors and the licensee as well as the on-site inspection staff is continuing extensive FSAR reviews.
IV. Plant Su ort R2 Status of Radiological Protection and Chemistry Facilities and Equipment R2.1 Low Level Radwaste Stora e Facilit Ins ection a.
Ins ection Sco e
71750 One of the inspectors reviewed Procedure RWI-111, Storage of Radioactive Waste/Haterials and related safety assessments.
This licensee procedure specifically addresses storage of low level waste stored exterior to permanent plant buildings.
Other related inspection activities were performed in accordance with guidance contained in IP 71750, Sections 02.01.a through 02.01.d.
b.
Observations and Findin s On August 16, 1996, one of the inspectors toured the low level r adwaste storage facility area located, outside the protected area but within the owner controlled area.
Several dozen truck trailers and other containers, most containing contaminated equipment, are stored in the
,area.
Such storage area of low level radwaste is mentioned briefly in Section 9.3.4.2 of the FSAR. Several years ago, a separ ate license had been maintained under Part 30 of 10CFR for a low level storage facility.
In 1989, the license was terminated at the licensee's request and storage of the r adwaste was continued under an evaluation in accordance with 10CFR 50.59 as allowed in Generic Letter 81-38.
The following was noted by the inspector during walk down of the facility:
~
The boundaries of the storage area were clearly posted, within a lockable enclosure, and the containers were well labeled.
While some
of the containers and the overall physical appearance of the area appear poorly maintained, most of the containers. were very well sealed.
~
No significantly deteriorated containers or containers resting in water were identified.
~
One box was noted in the area that was labeled to indicate radiation levels as high as 800 mRem/hr on contact.
Rope barriers and signs were present to direct personnel to stand clear of the box.
~
The inspector reviewed the most recent survey conducted in the storage area and noted no problems.
~
Radwaste management was well informed regarding current conditions and status of the storage area.
~
The doors providing access into the area were not locked closed but clear postings were present.
~
A self contained carbon dioxide decontamination facility is currently parked inside the storage area.
The inspector reviewed the procedures associated with this facility and concluded that it is being controlled appropriately.
Radiological controls personnel are involved when this equipment is operated.
~
The inspector verified that monthly inspections of the storage area and inventories required by RWI-111 were being completed.
c.
Conclusions The inspector concluded that the overall storage conditions were satisfactory.
From discussions with Radwaste management, the inspector concluded that adequate management oversight is being maintained on the storage.
ar ea.
Hanagement indicated that it was not desirable to store the higher radiation level boxes in the area and that they would be
,removed promptly. The licensee has constructed two warehouse buildings adjacent to the area and intends, to store most of the contaminated equipment within these structure II
Status of Security Facilities and Equipment Routine Securit Observations
- Walkdown of Protected Area Fence Ins ection Sco e
71750 An inspector, in accordance with guidance provided in Section 2.04 of IP 71750 inspected base integrity of protected area barriers, maintenance of isolation zones and various on-going security access control items.
Observations and Findin s On August 9, an inspector performed a routine walkdown of the facility's protected area fence and noted that the fence was in very good condition with no broken areas in the fencing or loose fence posts/parts.
Security arresting cable boundaries were also noted to be in very good condition and other security monitoring equipment
- cameras, sensors, etc..
- also appeared to be in good shape.
However, the inspector noted that along the northern portion of the protected area fence line, broken ground strapping clamps and excess strapping material was left in the area, after recently performed ground strapping repairs.
The inspector also noted that temporary security tapes used to isolate a muddy area of the east end of the Circulating Water Intake Structure were broken.
These minor items were reported to security and engineering personnel.
The inspectors also observed vehicles, personnel and packages entering the protected area and verified they were physically searched by special purpose detectors or for personnel physical patdown.
Conclusions The inspector noted that the physical barriers were adequate and that access control, particularly vehicle access, met baseline security requirements.
Residual Heat Removal Service Water RHRSW Su
Valves Hechanism Covers Not Secured Ins ection Sco e
71750 An inspector, in accordance with guidance provided in Section 2.04 of IP 71750, inspected the security of EECW/RHRSW valve covers.
Observations and Findin s During an intake area tour on July 29, 1996, one of the inspectors noted that some of the covers associated with several important Residual Heat Removal Service Water (RHRSW) valves were not locked in place.
Licensee management expectations are that the covers are reinstalled and locked unless access to the valve operating rods is necessary.
The covers had not been locked promptly after work was completed.
The inspectors reviewed the Site Security Plan and verified that the valves are not required to be more tightly controlled by regulatory requirement l
Conclusions In this case, management expectations for locking access covers were not effectively communicated. or implemented.
The covers were subsequently locked in place and Security management has increased the attention level associated with the valves.
The inspectors noted that these covers/physical barriers were adequate and that they met baseline security requirements.
Xl Exit Meeting Summary V. Hang ement Heetin s
The inspectors presented inspection results to members of licensee management on September 3,
1996.
The licensee acknowledged the findings presented.
The inspectors asked the licensee whether materials examined during the inspection should be considered proprietary.
No proprietary information was identified.
PARTIAL LIST OF PERSONS CONTACTED Licensee C. Crane, Assistant Plant Manager R. Jones, Operations Manager R.
Machon, Site Vice President, Browns Ferry E. Preston, Plant Manager P. Salas, Licensing Manager T. Shriver, Nuclear Assur ance and Licensing Manager H. Williams, Engineering and Materials Manager INSPECTION PROCEDURES USED IP 61726:
IP 62703:
IP 71707:
IP 71750:
IP 92901:
IP 92902:
'IP 92903:
IP 92904 IP 93702:
IP 92700 Surveillance Maintenance Observation Plant Operations Plant Support Activities Followup
- Operations Followup
- Engineering Followup
- Haintenance Followup
- Plant Support Prompt Onsite Response to Events at Operating Power Reactors Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 40500.
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems
~Oened ITEMS OPENED, CLOSED.
AND DISCUSSED
~T Item Number Status Descr i tion and Reference NCV 296/96-08-01 Opened and Failure to-Enter TS LCO for High Pressure Closed Coolant Injection System Inoperability (04.1)
IFI 296/96-08-02 IFI 296/96-08-03 Open Open, Emergency Core Cooling System lnver ter Failure (02.2)
U3.HSIV Limit Switch Circuitry Failures (H2.1)
NCV'60,296'/
'96-08-04 Opened and Fire Damper Procedural Controls. (E8.1)
Closed URI 260,296/
96-08-05 Open Diesel Generator Painting Controls (H4.1)
t Closed T~,
Item Number VIO 296/95-26-01 VIO 296/95-56-01 VIO 296/95-60-01 LER 260/94-11-00 LER 260/96-01.
Rev. 0,1 Status Closed Closed Closed Closed Closed Descri tion and Reference Failure to Implement Actions of Abnormal Operating-.Procedure.
(08.2)
Failure to Follow Alarm Response Procedures Results in Loss of 480V Bus.
(08.3)
Failure to Follow Configuration Control Procedures Resulting in Hisconfiguration of SDY System Components.
(08.4)
Failure of a Motor With a Magnesium Alloy Rotor on a Reactor Water Recirculation, System Pump Discharge Isolation Val.ve Placed Unit 2 in a Limiting Condition for Oper ation.
(E8.2)
10 CFR Part 50 Appendix R Noncompliance Results in the Plant Being Outside its Design Basis and Being in a Condition Not Covered by. Plant Operating Instructions.
(08.1)
t0
LER 260/94-13 Rev.
LER 260/95-03 Rev. 0,1 Closed.
Closed
Unit 2 Scram From 54'ower Caused by Balance Of Plant Equipment Failure.
(M8. 1)
Main Steam Safety/Relief Valves Exceeded the Technical Specifications Required Setpoint Limit as a Result of Disc/Seat Bonding.
(M8.3)
IFI 296/95-16-04 Closed IFI 259,260,296/
94-12-02 Closed URI 260,296/95-64-08 Closed Work Plan Implementation. Deficiencies.
(M8.2)
Correction of BFN Design Change Process Problems '(E8.3)
Fire Damper Procedural Controls.
(E8. 1)
Discussed.
URI 259,260,296/
96-04-08 IFI 260,296/
95-64-10 Open Open FSAR Discrepancies (E8.4)
Secondary Containment Damper Failures (E2.2)
4!