IR 05000259/1992030
| ML18036A871 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 09/22/1992 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18036A869 | List: |
| References | |
| 50-259-92-30, 50-260-92-30, 50-296-92-30, NUDOCS 9210060270 | |
| Download: ML18036A871 (39) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos.:
50-259/92-30, 50-260/92-30, and 50-296/92-30 Licensee:
Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.:
50-259, 50-260, and 50-. 296 License Nos.:
DPR-33, DPR-52, and DPR-68 Facility Name; Browns Ferry Units 1, 2, and
Inspection at Browns Ferry Site near Decatur, Alabama Inspection Conducted:
August
September 16, 1992 Inspector:
>
e nspector aeSlge
I Accompanied by:
E. Christnot, Resident Inspector W. Bearden, Resident Inspector J.
Munday, Resident Inspector Approved by:
au Re ctor
'
son A
Division of Rea or Projects SUMMARY ate S>gne Scope:
This routine resident inspection included surveillance observation, maintenance observation, operational safety verification, Unit 2 modifications, Unit 1'activities, Unit 3 restart activiti'es, reportable occurrences, action on previous inspection findings, and site organization.
One hour of backshift coverage was routinely worked during the workweek.
Deep backshift inspections were conducted on August 22, August 29, and September 12, 1992.
Results:
Unit 2 completed 48 days of power operation at the-end of this period without any significant problems.
Preparations were being
'72100b0270 920'924 PDR ADOCK 05000259 PDR
made to begin power coastdown corresponding with the normal fuel depletion, paragraph two.
A major site reorganization was announced on September 2,
1992, paragraph ten.
The change placed all the units under one
.
organization, Nuclear Operations.
A noncited violation was identified concerning a hold order violation, paragraph four.
This was identified by the licensee during an incident investigation.
A valve operator linkage was disconnected without authorization.
Operations personnel received additional training on following procedures and management expectations.
A noncited violation was identified concerning a missed Appendix R
required firewatch, paragraph nine, This problem was identified by a plant operator who observed an Appendix R component tagged out of service without a fire watch.
The licensee's review of this found that the software used in the automatic clearance system was inadequate to flag all Appendix R components.
The licensee conducted an incident investigation and changed the software.
An unresolved item was identified concerning an unclear calibration surveillance instruction, paragraph two.
The inspector observed during the performance of the procedure the technicians did not follow the procedure as written.
The procedure requires a test pressure be applied to the installed gauge and then be compared to the. standard.
This is opposite the normal calibration method, Other calibration procedures will be reviewed to determine the magnitude of the problem.
An inspector followup item was identified concerning a diesel generator turbocharger failure, paragraph two.
The turbocharg'er assembly had been returned to the vendor to determine the cause of'he failure.
An inspector followup item was identified concerning three spurious circuit breaker trips, paragraph four.
The licensee is conducting a circuit breaker coordination review of each of the breakers involved in the trip REPORT DETAILS Persons Contacted Licensee Employees:
0. Zeringue, Vice President, Browns Ferry Operations
- J. Scalice, Plant Manager J. Rupert, Engineering and Modifications Manager H. Herrell, Operations Manager J.
Haddox, Project Engineer
- H. Bajestani, Technical Support Manager R. Jones, Operations Superintendent A. Sorrell, Special Programs Manager C. Crane, Maintenance Manager
- R. Baron, Site guality Manager
- G. Pierce, Regulatory Licensing Supervisor
- P. Salas, Compliance Supervisor
- J. Corey, Site Radiological Control Manager A. Brittain, Site Security Manager Other licensee employees or contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, and public safety officers; and quality assurance, design, and engineering personnel.
NRC Personnel:
P. Kellogg, Section Chief
- C. Patterson, Senior Resident Inspector
- E. Christnot, Resident Inspector
- W. Bearden, Resident Inspector
- J. Hunday, Resident Inspector
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Surveillance Observation (61726)
The inspectors observed and/or reviewed the performance of required SIs.
The inspections included reviews of the SIs, for technical adequacy and conformance to TS, verification of test instrument calibration, observations of the conduct of testing, confirmation of proper removal from service and return to service of systems, and reviews of test data.
The inspectors also verified that LCOs were met, testing was accomplished by qualified personnel, and the SIs were completed within the required frequency.
The following SIs were reviewed during this reporting period:
Standby Liquid Control Pump Test The inspector observed portions of 2-SI-4.4.A. 1, Standby Liquid Control Pump Functional Test, which tested the 2A SLC pump.
During the test demineralized water is pumped from a small test tank through a high pressure rubber hose to a floor drain.
The time it takes the level in the test tank to drop to a
predetermined point is used to calculate pump flow rate.
Difficultywas observed in performing this portion due to the high discharge pressure of the pump blowing the hose away from the floor drain and causing a large amount of leakage at the connection to the system.
This required stopping the pump, repairing the hose placement, and realigning the system prior to restarting the pump.
The operators successfully backed up in the procedure and re-performed steps to complete the surveillance.
The SI also includes flow measurement by a strap-on Controlotron flowmeter.
This data is being compared to the flow rate calculation for qualifying its use.
The flowrate from the calculation was determined to be 54.71 gpm and from the Controlotron 54.61 gpm.
System engineering will be exploring the possibility of using this instrument and pumping directly back to the test tank in lieu of the current method.
The inspector reviewed the SI and determined it contained adequate steps and information for its performance and return to service of the pump.
The inspector did not identify any deficiencies during the work activity.
24 Hour DG SI The inspector reviewed and observed the activities with a mechanical failure of the 3fA DG.
On August 25, 1992, surveillance instruction SI-4.9.A. I.a(A24), Diesel Generator 3A 24 Hour Run, was completed and the DG was unloaded.
During the coast down, the machine prematurely stopped and the attempts to restart were not successful.
Followup activities by the maintenance, operations and system engineering groups discovered major gear damage to the turbocharger.
The licensee initiated a category
incident investigation, 11-8-92-063.
Repairs were made to the DG and it was successfully tested on September 1,
1992.
The licensee returned the turbocharger to the vendor for disassembly and inspection.
Determination of the cause of the failure will be tracked as IFI 259, 260, 296/92-30-01, DG Turbocharger Failure.
Core Spray To Reactor Pressure Vessel Differential Pressure Calibration 2-PDIS-75-56 The inspector observed the performance of portions of Surveillance Instruction 2-SI-4.2.b-24(II),
Core Spray To Reactor Pressure Vessel Differential Pressure Calibration 2-PDIS-75-56.
The purpose of this instrument is to continuously confirm the integrity of the core spray piping inside the reactor vessel (between the nozzle and the shroud)
during operation at rated
power conditions and to provide an alarm in the main control room if the integrity of the piping is violated.
This instruction determines the operability of this instrument and its alarm; and if necessary, performs a calibration of the switch.
The test installs a calibrated gauge in parallel with the installed gauge that is being tested.
A pressure is then applied and the two gauges compared.
The procedure is written to,apply pressure until the installed instrument being tested indicates a certain value and to then verify that the calibrated gauge is within a certain range.
The technician performing the test applied pressure until the calibrated gauge indicated a certain pressure and then verified the installed gauge being tested was within a certain range.
This was discussed with engineering and the I&C foreman and though the test was not performed the way it was intended by procedure the results were determined to be satisfactory.
The licensee stated that the method the technician used is the typical method for verifying the calibration of an installed instrument of this type.
In addition the inspector stated the procedure step describing this process was unclear and confusing.
The licensee agreed and thought it prudent to clarify the procedure during its next revision.
Pending further review of other calibration procedures, this issue is being documented as unresolved item, URI 260/92-30-02, Unclear Calibration Surveillance.
No violations or deviations were identified in the Surveillance Observation area.
Maintenance Observation (62703)
Plant maintenance activities were observed and/or reviewed for selected safety-related systems and components to ascertain that they were conducted in accordance with requirements.
The following items were considered during these reviews:
LCOs maintained, use of approved procedures, functional testing and/or calibrations were performed prior to returning components or systems to service, gC records maintained, activities accomplished by qualified personnel, use of properly certified parts and materials, proper use of clearance procedures, and implementation of radiological controls as required.
Work documentation (HR, WR, and WO) were reviewed to determine the status of outstanding jobs and to assure that priority4'.<as assigned to safety-related equipment maintenance which might affect plant safety.
The inspectors observed the following maintenance activities during this reporting period:
a 0 RHR System A Maintenance The inspector observed activities associated with WO 92-47816-00, which inspected the spring pack for the RHR HX A discharge valve, 2-HVOP-23-0034.
This inspection required visually inspecting the Limitorque spring pack for excessive and/or dried or cracked grease in accordance Mechanical Maintenance Instruction HHI-87,
Preventive and Corrective Maintenance of Limitorque Operators.
The procedure states that if this condition is found the spring pack must be removed, degreased, and cleaned prior to returning it to service.
When the cover was removed an excessive amount of grease was found.
Engineering was contacted to determine operability of the valve and originally decided to replace the spring pack.
Upon further evaluation it was decided that the quality of the grease was acceptable and that simply cleaning the grease from the spring pack would be satisfactory.
The inspector discussed this decision with the licensee management and engineering.
It was decided that the statement in HHI-87 was too restricting and inappropriate.
The inspector reviewed the hold order that removed, the valve from service, 2-92-0484, and determined it to be adequate.
The inspector also reviewed the LCO, 2-92-,281-3.5.B associated with this and other work on the RHR system, and found it to be appropriate.
An inspector observed work on the RHR System I Fill and Drain Pump A Suction valve, 2-HVOP-74-104.
The controlling document for this maintenance was WO 92-53024 and contained inspection of the Limitorque spring pack.
Hold order 2-92-0616 removed the valve from service to facilitate inspection.
The inspection was satisfactory with very little grease being found.
The work plan and the procedure used, Mechanical Preventive Instruction HPI-0-OOO-ACT001, Preventive Maintenance for Limitorque Operators, were both adequate and of sufficient detail to support the work activity.
No deficiencies were noted during this activity.
RHR Pump B Maintenance An inspector observed portions of the 2B RHR pump motor breaker inspection conducted in accordance with Electrical Preventive Instruction, EPI-O-OOO-BKR002, Maintenance of GE (Hagne-Blast)
Switchgear and Circuit Breakers, under work order 92-56561.
The inspection tested the breaker electrically and mechanically as well as cleaned and lubricated the breaker and compartment.
The inspection was performed and the breaker tested satisfactorily.
No deficiencies were identified by the inspector during this work activity.
SLC Pump 2B Maintenance The inspector observed portions of maintenance that replaced the 2B SLC Pump Local Test switch, 2-HS-63-6E.
The work was performed under WO 92-58481 using Electrical Corrective Instruction, ECI-0-OOO-SWZ002, Replacement of Switches, as the controlling procedure.
The old switch was removed and was determined to have failed due to age.
The new switch was installed and tested during the performance of 2-SI-4.4.A. 1, Standby Liquid Control Pump Functional Test.
The inspector reviewed the work order and determined it contained adequate guidance to support the intended
work.
The inspector did not identify any deficiencies during the work activity.
No'iolations or deviations were identified 'in the Maintenance Observation area.
Operational Safety Verification (71707)
The NRC inspectors followed the overall plant status and any significant
,safet'y matters related to plant operations.
Daily discussions were held with plant management and various members of the plant operating staff.
The inspectors made routine visits to the control rooms.
Inspection observations included instrument readings, setpoints and recordings, status of operating systems, status and al.ignments of emergency standby systems, verification of onsite and offsite power supplies, emergency power sources available for automatic operation, the purpose of temporary tags on equipment controls and switches, annunciator alarm status, adherence to procedures, adherence to LCOs, nuclear instruments operability,. temporary alterations in effect, daily journals and logs, stack monitor recorder traces, and control room manning.
This inspection activity also included numerous informal discussions with operators and supervisors.
General plant tours were conducted.
Portions of the turbine buildings, each reactor building, and general plant areas were visited.
Observations included valve position and system alignment, snubber and hanger conditions, containment isolation alignments, instrument readings, housekeeping, power supply and breaker alignments, radiation and contaminated area controls, tag controls on equipment, work activities in progress, and radiological protection controls.
Informal discussions were held with selected plant personnel in their functional areas during these tours.
a
~
b.
Unit Status The unit operated at power during this month without any significant problems.
The unit was on-line for 48 days at the end of the period.
Preparations were being made to begin coastdown in power as the fuel depleted.
Thermo-lag On August 31, 1992, a conference call between NRR, Region II, and the licensee was conducted to discussBulletin 92-01, Failure of Thermo-Lag.
Discussions were held on Supplement I to the bulletin issued on August 28, 1992.
The licensee stated 21 conduits were effected.
On September 3,
1992, the inspector and fire protection manager toured the control bay and reactor building for location of the thermo-lag areas and fire watches.
The inspector requested a cross-reference of the 21 conduits to the areas toured.
The licensee provided a copy of the bulletin response that cross-referenced the conduits to the fire watchs.
The inspector
reviewed a sampling of compensatory tracking documents in the control room on September 15, 1992.
No deficiencies were identified.
Spurious Circuit Breaker Trips During July 1992, three spurious circuit breakers tripped for no apparent reason.
The three breakers involved were breaker 1180 on Battery Board 82. on July 21, 1992, breaker 3C on 480V shutdown board 2B on July 5, 1992, and breaker 5B on 480V shutdown board 3B.
The inspector reviewed the licensee's II-B-92-050, Circuit Breaker Trips.
The licensee concluded these trips did not occur due to a
common failure.
The corrective action consisted of breaker replacement.
The II.
determined the root cause was unexpected failure.
Part of the corrective action for each failure was for nuclear engineering to verify that adequate breaker coordination exists for each breaker.
Also, breaker 5B has a solid state trip device, RM S-9.
These devices have recently been installed on some breakers in the plant.
The RMS-9 device was being returned to the vendor for analysis.
The dates for completion of the breaker coordination analysis were listed in the II as November 23, 1992.
The inspector questioned the timeliness of completing this analysis with plant management.
Various electrical boards are required to be operable in TS 3.9.
Any lingering questions that could potentially affect operability should be promptly resolved.
Resolution of coordination analysis will be tracked as IFI 259, 260, 296/92-30-03, Circuit Breaker Coordination.
Condensate Demineralizer Clearance Error On July 8, 1992, Unit 2 experienced a low condensate suction pressure and flow perturbations during system restoration following maintenance on a condensate demineralizer.
Reactor power was reduced to about 800 MWe.
The licensee initiated Incident Investigation B-92-049 to investigate the event.
.
Hold Order 2-92-0519 required closing the 2C demineralizer effluent valve, 2-FCV-2-208C.
The AUO hanging the clearance could not get the valve to completely close so he disconnected the valve actuator linkage and manually closed the valve, however he failed to effectively communicate this to the ASOS.
Following maintenance and ASOS authorization to pull the hold order, the same AUO attempted to reconnect the valve linkage.
When the linkage could not be aligned the AUO decided to admit air to the actuator in an attempt to slowly move the valve to align the actuator and the linkage.
The air pressure behind the valve caused it to go full open and the empty effluent piping to rapidly fill resulting in the reduction of condensate booster pump suction pressur The II identified an unauthorized change in system configuration when the AUO removed the actuator linkage.
Additionally, the AUO did not follow the sequence required by the hold order for system restoration.
The licensee is revising the AUO lesson plans to inform operators of valve capabilities with the linkage disconnected and is providing training on this event to Operations personnel.
Additionally, Operations personnel will be retrained to follow procedures.
Management's expectations when unexpected conditions are found will be emphasized in this training, TS Section 6.8. l.I.a requires that procedures shall be implemented covering procedures in-Appendix A of Regulatory Guide 1.33, Revision 2, February 1978.
Appendix A of Regulatory Guide 1.33
'ncludes procedures for tagging and controlling equipment.
Disconnecting the actuator linkage and failure to follow the system restoration sequence required by hold order 2-92-0519, is a
violation of SSP-12.3, Equipment Clearance Procedure, section 3.2.8.
This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the Enforcement Policy.
NCV 260/92-30-04',
Valve Operator Clearance Error, will be issued to document this event.
LPRM Reassignments Multiple failures of Westinghouse LPRH's have resulted in two APRN's having only the minimum number of LPRH's operable.
Each APRN must have a total of fourteen detectors operable with at least two on each level.
Failure of one additional LPRN would result in the APRH being inoperable.
On September 9,
1992, LPRH's were reassigned using Technical'Instruction O-TI-281, LPRN Reassignment, as the controlling document.
The new locations for the LPRN's were posted on the main control panel.
Following reassignment the APRH was tested successfully with the performance of applicable sections of Surveillance Instruction 2-SI-4.2.C-IE, Instruments That Initiate Rod Blocks/Scrams, APRM Calibration.
The licensee has identified additional LPRH's that are suspect for failure and they are scheduled to be reassigned in the future.
General Electric provided the analysis that determined the reassignments would be acceptable.
The inspector reviewed the analysis which contained proprietary information and concluded that the analysis supported the reassignemets.
End of Cycle Reactor Recirculation HG Set High Speed Stop Adjustment r
On September 12, 1992, the mechanical and electrical high speed stops for the reactor recirculation HG sets were increased to 106.5X and 106% respectively.
The stops were raised to allow increased core flow and thus power during the end of cycle reactor coastdown.
These higher flow rates are permissible by the core reload document and TS.
Special Instrument Instruction SII-2-, SE-
g,96-004, Reactor Water Recirculation Bailey Drive Positioner Stop Adjustments For Coast Down was the controlling document and contained adequate detail for accomplishing this work.
'I ESF System Walkdown (71710)
The inspector walked down selected portions of System 74, Residual Heat Removal System.
During the walkdown the inspector verified the current configuration and handswitch lineup on the control panel was that required by OI-74, Residual Heat Removal for the existing plant conditions.
The inspector also examined portions of the Loop II system for leaks, valve or piping damage, hanger and support alignment and instrumentation indicating within expected ranges.
These items as well as housekeeping were found adequate.
The inspector noted that instrument lines leading to the pressure indicators on the suction of RHR pumps A and C and the pressure indicators and switches on the discharge of pumps A
and C had high point vent valves that were not on the flow diagrams and were not labeled.
Following discussion with the licensee it was determined that these valves were outside the scope of drawing improvements required to be made prior to unit startup.
The inspector will continue to review this issue.
One NCV was identified in the Operational Safety Verification area.
5.
Unit 2 Modifications (37700, 37828)
The inspectors maintained cognizance of modification activities of Unit 2.
This included reviews of scheduli,ng and work control, routine meetings, and observations of field activities.
Throughout the observation of modifications being performed in the field gC inspectors were observed monitoring and documented verification at work activities.
a.
RPS Circuit Protectors b.
The inspector observed and reviewed the activities involved with the implementation of DCN W5628, Unit 2 RPS 'circuit protectors channel A.
This modification was installed to assist plant personnel in determining the cause of a circuit protector trips and to prevent inadvertent trips due to light bulb replacements.
The installation was in accordance with approved WPs 2035-92 and 2042-92.
The PHT 2-SI-4. 1,B-16(A) was performed successfully and the equipment was returned to service.
This was the last of 18 total circuit protectors, six per unit, to be modified.
Control Bay Intake Duct The inspector reviewed t'e modifications in progress on the'ontrol bay roof.
These modifications are described in DCN W18060A.
They provide new intake duct and grilles in the control bay roof canyon between the reactor building and the turbine building for.intake plenums in the Unit 1 and Unit 3 tower e Also, this installs a new duct from the Unit 2 vent tower to the new Unit 1 and 3 intakes.
This will serve the new CREVs unit.
The new intakes will provide outside air to the vent tower plenums from locations with lower concentrations of radiation releases following an accident.
The work in progress, consisted of installing seismic Class I supports to the control bay roof.
The supports will house the new ducts.
Additionally, the inspector reviewed the use of a 4000W Hanitowoc tower crane used for lifting materials onto the control bay roof to support the installation of the new ductwork.
The crane had been moved just north of the Unit 3 DG building next to the control bay.
A buried potable water line was ruptured after the crane was moved into this area.
The licensee provided a copy of the safety evaluation and associated calculation concerning moving the crane into this area.
This item was reviewed by the PORC on September 9,
1992, and approved the use of the crane.
The inspector reviewed safety evaluation SEBFDCN920099 and associated calculation CD-N0999-910269.
The calculation looked at known subsurface safety and non safety-related commodities, in addition to safety-related structures.
The calculation looked at buried electrical cable tunnel, CCW tunnels, condensate pipe tunnel, and other structures.
The potable water lines were often field run and not identified on plant drawings.
No deficiencies were identified in the calculation or safety evaluation.
The inspector concluded use of the tower crane had been adequately evaluated for use.
6.
Unit 1 Activities The inspector reviewed and observed the licensee's activities involved with Unit 1.
The activities consisted of walkdowns for multi-unit, Unit 2 cycle 6 modifications, DCN implementations to the Unit 1 turbine building crane and electrical cable installation associated with DCN W17257A.
This DCN was issued because existing ECN P0697 RO provided a
redundant, non-safety grade air conditioning system to serve the new process computer room added by DCN W14487A, existing unit computer rooms, communications room, and communications battery board room on elevation 593 of the control bay.
ECN P0697 also provided for the redistribution of safety grade air from the areas listed above to other safety related control bay rooms on elevation 593.
ECN P0697 was only partially implemented, using PHEN P0697-P1, to allow the control bay HVAC, system 31, to be placed into service for Unit 2 restart.
DCN W17257A also required that the non-installed portions of ECN P0697 be identified and provide all design requirements to complete the non-installed portions of the ECN.
The inspector observed the work activities associated with WP 0252-92, written to pull cable through conduit in the Unit 1 turbine building.
All observed activities were performed in accordance with the W.
Unit 3 Restart Activities (30702)
The inspector reviewed,and observed the licensee's activities involved with the Unit 3 restart.
This included reviews of procedures, post'-job activities, and completed field work; observation of pre-job field work, in-progress field work, and gA/gC activities; attendance at restart craft level, progress me'etings, restart program meetings, and management meetings; and periodic discussions with both TVA and contractor personnel, skilled craftsmen, supervisors, managers and executives.
'a 0 b.
Pilot/Prototypical Progr am
The licensee resumed repair activities involved with the return to service of cooling towers 1, 5, and 6 as part of the pilot/prototypical program.
The activities reviewed included the pump runs of lift pump motors 1A, 1B, and 5A, preparations for the conduct of pre-operational test procedures PHT BF 27.001 and 27.007, and removal of cooling tower fan motors for installation of water proofing kits.
Design Activities 1.)
FDCN Tracking The inspector observed and reviewed the activities associated with DCN W17666, CSST A Tap Changer Modification, DCN W17463, Reactor Vessel level Indication System, and various CRDR DCNs.
The purpose of the review was to determined the adequacy of tracking and statusing of FDCNs.
The CRDR program personnel hold daily field work meetings and twice weekly design meetings.
The status of FDCNs affecting the various DCNs were discussed at both meetings.
The inspector obtained a listing of the FDCNs affecting DCNs W17666 and W17463 and noted that the FDCNs were being statused and tracked in a timely manner.
2.)
Lifting Stop Work Order On August 21, 1992, the stop work order for electrical distribution calculations was lifted.
The basis for lifting the order was an approved corrective action plan for SCAR BFSCA920014 and in-line review by the licensee of all electrical distribution calculations performed by Bechtel.
In addition, the licensee identified several specialists to perform independent verification of the calculations in the area of their identified expertise.
A formal training program was being developed for the review and assessment of design documentation for development of the bases for the electrical distribution system calculation.
The inspector reviewed the corrective action plan for SCAR and other actions taken by the licensee.
These steps supported lifting the stop work orde Construction Activities CSST Load Tap Changer Hodification The inspector reviewed the modification work associated with the addition for a tap changer to the 'A'SST.
The tap changer provides voltage correction as load fluctuates.
This work is being performed in the transformer yard inside the protected area fence.
The inspector observed during several tours of the area that access to the transformer yard was being restricted by a locked fence.
Only personnel authorized by operations were allowed.
All personnel who work in nuclear plant switchyards must have completed nuclear experience review training.
The inspector reviewed the training lesson plan OPN 121.029.
This training is provided to the customer service group and other personnel who work in nuclear plant switchyards.
The inspector concluded that personnel access control is being conducted for switchyard work.
Personnel are being trained to recent industry switchyard events and preventive measures.
Haintenance Activities 1.)
Haintenance Organization The licensee recently merged the site maintenance groups into one site organization.
All maintenance acti'vities at the BFNP site were placed under the plant maintenance manager with the Unit 3 maintenance manager reporting directly to him.
The contractor maintenance manager in turn reports to the Unit 3 maintenance manager for day to day activities, direction as to priorities and schedule adherence.
The overall purpose of the organization is to insure that all work activities are controlled by one organization, that the system return to service/SPOC schedules are met and adequate coordination between work.
groups is accomplished.
2.)
Condenser Circulating Water Pumps The inspector observed and reviewed the activities associated with the installation of the Unit 3 CCW pumps.
This was performed under the recently established single maintenance organization.
The task manager remained aware of the field activities, work activities were discussed on a
daily 'basis and work documents were at the job site under direct control of the foreman.
The work activities for pumps A, B, and C were documented on WOs 92-48818-00, 48818-01, and 48818-02 respectively and the activities for the motors were documented on WOs 89-10080-30, 31, and
respectively.
The inspector observed the field activities involved with the A pump and motor.
All activities were in accordance with the WO Pre-Operational Testing/Return to Service Activities
,The inspector observed and reviewed activities involved with the vessel floodup, drywell chiller installation, the SPOC process and the auxiliary raw cooling water system.
Vessel F'loodup The inspector observed and reviewed the activities involved with the vessel floodup.
The floodup was scheduled to be performed in three phases.
Phases one and two were to put water into the recirculation piping and phase three was to complete the floodup to the refueling level.
Phase I was completed on September 13, 1992 and phase II was scheduled for October 14, 1992.
During the hookup of the portable demineralizer skid a contractor did not check the lineup and the resin beds were backflushed through the demineralizer vessel vents.
Resin was discovered in the temporary connection hoses.'he licensee initiated incident investigation II-B-92-065 to determine the causes of the event.
The inspector will continue to follow the vessel floodup activities.
2.)
SPOC Process The inspector continued to review the licensee's SPOC process and noted that Section 3.2, Determination o'f Systems Requiring a
SPOC, of procedure SSP 12.55 stated:
The Unit 3 Technical Support Hanager shall compile a listing of systems or portions of systems that are required to be evaluated under the SPOC process, and submit the listing to the Plant Technical Support Hanager and the Plant Operations Hanager, for approval.
The listing shall indicate those systems that are considered to be Hinor Systems, that is, those which have no safety-related requirements, do not significantly affect plant operation, are not required to have system status maintained in accordance with SSP-12.2 and have no RTP testing requirements.
The SPOC process for Hinor Systems is simplified by omitting the Phase I
SPOC and allowing the use of not applicable (NA), for specific parts of the Phase II SPOC Checklist, Form SSP-124, as indicated on the form.
The inspector asked the Unit 3 TS manager if the listing considered systems impacted by the EOIs.
The inspector was informed that the fOIs were not considered when the list was made.
The inspector discussed this item with the plant operations group.
The operations group agreed to review the issue and discuss the. resolution with the resident inspector.)
Auxiliary Raw Cooling Water The inspector reviewed the licensee's activities associated
'ith the SPOC and return to service of the auxiliary'raw cooling water system designated System 24 A.
This was one of'he first systems being completed by the Unit 3 organization for turn over to plant operations..
The inspector reviewed the MTS for SPOC items, observed field activities involved with the system flush and reviewed the OI upgrade.
Procedure 2-0I-24, Raw Cooling Water System, Section 8.3, Auxiliary RCW System Operation, was upgraded to allow operation of the two pumps, designated AUX RCW PUMP A and B.
The system flush was conducted in accordance with procedure O-POI-24-1, AUX RCW Pump Suction and Discharge HDR Flush, and the MTS items were reviewed on a daily basis by the Unit 3 management.
A deficiency was identified involving the A pump discharge pressure.
The B pump flush was considered successful.
4,)
Drywell Chiller The inspector observed and reviewed the performance of test PMT 236, Drywell Outage Cooling Pre-operational Test.
The specific field observations involved section 5.3, Pump/Chiller 'B'ombination test, data sheet 5.2, Pump Performance Data Sheet and data sheet 5,3, Chiller Performance Data Sheet.
The inspector noted that all M & TE used were within calibration, adequate personnel were available to support the test and pre-job briefings were given to participating personnel.
The test results were reviewed and a total of 5'TDs were initially identified.
TD1 3KVA Utility Transformer 0-XFA-070-1043 failed when initially powered up.
TD2 Fuse block FB1, in utility box O-JBOX-070-9399, did not have fuses installed.
Fuses supplied were too short.
Item affected flow switch power supply.
TD3 Chiller A/Pump A did not meet design requirements of 40 degrees fahrenheit outlet water temperature at 520 gpm flow.
TD4 Chill Water B pump failed to start.
TD5 Chiller B/Pump B did not meet design requirements of 40 degrees fahrenheit outlet water temperature at 520 gpm flow.
After completion of the test, two additional TDs were identified as a result of, post test review TD6 Chill water pump A was found to perform outside
+ 5X tolerance of manufacturers pump data specified in the test scoping document acceptance criteria.,
TD7 Same as TD6 except for chill water pump B.
The inspector noted that each TD was addressed by part replacement, termination tightening or forwarding the TD to site engineering for technical resolution.
The inspector concluded from these observations and reviews that the licensee was performing the pre-operational testing and the SPOC process in accordance with approved procedures.
Q-List The inspector reviewed the activities involved with the development of the Unit 3 Q-List.
The process was set up to utilize the lessons learned from the development of the Unit 2 Q-List.
The site control procedure SSP 3.3, Q-List/CSSC List Use and Control, stated:
This procedure established administrative controls and provides standard requirements and processes for: (1)
developing a Q-List, (2) reviewing, releasing, and using a
Q-List, a
CSSC List, or a non-CSSC list, and (3) maintaining a Q-List, a
CSSC list, or a non-CSSC list as required by TVA's Nuclear Quality Assurance Plan.
The engineering procedure, BFEP PI 87-52, Development and Control of Browns Ferry Nuclear Plant Q-List, stated:
The purpose of this Browns Ferry Engineering PI is to provide the methodology and requirements for development and control of the Browns Ferry Nuclear Plant "Q-List."
Both procedures contained criteria for determining components for inclusion on the Q-List.
Appendix E of BFEP PI 87-52, Safety Classification Criteria, contains the general criteria for safety classification.
The inspector discussed the Q-List development with the licensee and obtained a copy of Form SSP-103, Q-List Action Request/Response Form.
This form stated:
This evaluation provides the documentation of the safety classification for the components in the CCW system, 027, as identified by the CCW SRC.
The classification of the components are based on the system operating modes and safe shutdown boundaries as defined in the SRC (SRC MD-Q0027-920038).
The document contained 139.component by UNID and the inspector noted such components as:
.
UNID Descri tion CAT BFN-0-BKR-205-A/11 BFN-0-BKR-205-A/4 BFN-0-PX-027-125A-5 Normal Supply BKR 1922 CTSG A/11 4KV CTSG A/4 CT Pump 1A CCW CT 5 Outlet ADD/SR Trip 4K CTSG ADD/SR Trip Lift Pump 1A ADD/SR Trip Lift Pumps BFN-0-TI-027-125BAB-6 CCW CT 6 Outlet Temp ADD/SR Complete Lift Pump Trip CKT BFN-3-FCV-027-118A CCW Vacuum BKR Vent ADD/SR Prevent Warm WTR Channel Backf1 ow into Forebay The inspector concluded from this review that the Unit 3 g-List was being developed in accordance with approved procedures and criteria.
Reportable Occurrences (92700)
The LERs listed below were reviewed to determine if the information provided met NRC requirements.
The determinations included the
'erification of compliance with TS and regulatory requirements, and addressed the adequacy of the event description, the corrective actions taken, the existence of potential generic problems, compliance with reporting requirements, and the relative safety significance of each event.
Additional in-plant reviews and discussions with plant personnel, as appropriate, were conducted.
(CLOSED)
LER 296/91-04, Inability to Identify and Establish Compensatory Measure for Loss of HPFP System Hose Stations.
This LER was initiated on November 4, 1991 when the Unit 3 Control= Room was notified of a leak in a three inch high pressure fire protection system pipe.
An ASOS was dispatched to the scene and because of the probable equipment damage he isolated the leak.
Parallel actions were taken to initiate the required compensatory actions.
The required compensatory measures were not established within one hour as required by TS.
The inspector reviewed the corrective action that included the development of a method that would enable the fire protection group to begin compensatory measures immediately based on a pre-defined lis This pre-defined list of primary and secondary hose stations was issued in revision 6 of procedure FPP-I, Fire Protection Plan.
Action on Previous Inspection Findings (92701, 92702)
a ~
b.
c ~
(CLOSED) VIO 259, 260, 296/92-12-01, Failure to Control Contractor Design Activities This item was identified during a special inspection involving design activities performed by contractors on site and the violation documented two examples.
The first example, stated a
contractor signed as the design engineer on a
DCN, 12 Forms for AA FDCN, a TACF and drawing approVal for 2 MOs.
The second example state'd that a primary control room drawing, was not updated after modifications were completed and the system returned to service.
The inspector reviewed the licensee's response dated Hay 18, 1992.,
The licensee stated the reason for the first example was inappropriate personnel action.
The Unit 3 restart management assumed that the contractor had authority to issue design documents, consequently site engineering approval was not obtained.
The second example was due to the SPAE not being followed during the Unit 2 recovery.
The inspector reviewed the licensee's corrective action.
This consisted of designating a
single contractor for'esign and defining by position individuals who were authorized to sign design documents.
The action also consists of updating drawing.0-35E713-2.
The actions taken adequately address the violation.
(CLOSED) IFI 259, 260, 296/92-11-04, Proper Tracking of Circuit Breakers During Refurbishment.
The item was initially identified during observations and reviews of the licensee's activities involved with shipping circuit breakers offsite for refurbishment by the vender.
Subsequent to this item, an EDSFI was performed and a finding was identified, Finding 8, Improper Breaker Replacement.
The licensee issued a
PER number,920039 to address the finding.
To address this IFI the licensee designated a single point of contact to track the breakers, performed a walkdown of the electrical switchboards using switchgear drawings with breaker serial numbers as references, and issued a
PDD number 92-184 to correct discrepancies.
This area will be reviewed during the followup of EDSFI Finding 8.
(CLOSED) IFI 260/92-21-02, Adequacy of Scaffolding Review.
This IFI concerned a horizont'al scaffold identified on Hay 19, 1992 which contacted the torus wall on one end and a concrete wall on the other.
On July 31, 1992, the inspector noted that scaffold 2477 was installed with a diagonal member in contact with a RHR unit cross tie pipe.
Initial discussions between plant,
engineering, and modifications organizations concluded that a
clearance of six inches was required between the scaffold and the piping so the licensee decided to modify.the scaffold.
Incident Investigation B-92-053 was initiated to resol've the issue.
Walkdowns were performed on 168 scaffolds in unit 2 operating spaces to ensure they were erected in accordance with Technical Instruction O-TI-264, Scaffolds and Temporary Platforms.
Twenty seven discrepancies were originally noted.
Twenty scaffolds were determined to be acceptable as installed by Site Engineering while the remaining seven were modified.
Upon further review, the II team determined that scaffold'477 was acceptable as originally
.
installed.
They further concluded that the controlling procedure was not user-friendly and needed clarification.
Corrective action was assigned to unit 2 modifications to rewrite 0-TI-264 to provide a more straight-forward working document.
(CLOSED)
URI 260/92-24-01, Hissed Appendix R Required Firewatch, On July 4, 1992, the ASOS was notified that 3C Diesel Generator Battery Charger A had been removed from service for 22 days and that the Appendix R compensatory measures had not been implemented as required by 2-SSP-1, BFNP Unit 2 Appendix R Safe Shutdown Program.
This procedure requires that the charger be returned to service within seven days or a continuous fire watch be established.
A firewatch was immediately posted and Incident Investigation B-92-47 generated.
On June 12, 1992, clearance 3-92-0223 was hung to remove the battery charger from service for repair.
On June 24, 1992, the clearance was lifted to allow troubleshooting and then re-hung to allow replacement of a failed capacitor.
While on a plant tour July 4, 1992, the Unit 3 ASOS noticed the charger was tagged and did not remember an Appendix R
LCO from shift turnover.
He reported the discrepancy to the Unit 2 ASOS and a firewatch was established.
In August 1990, an automated clearance system had been installed and was to include a feature that checked a flag "Yes" on the Abnormal Configuration Log Sheet when an Appendix R component was being tagged.
This investigation determined the software was inadequate and the. data base did not include all the components that could render an Appendix R component inoperable.
This was determined to be a contributing cause for the event.
One of the root causes was determined to be inappropriate personnel actions due to lack of attention by the Operations personnel associated with the clearance, They relied solely on the Appendix R block on the Abnormal Configuration Log Sheet to determine if compensatory measures were required without ever referencing 2-SSP-1:
Additionally, inadequate communication of Standards, Policies, and Administrative Controls by Operations Hanagement was also considered a contributing caus As part of the investigation, the te'am reviewed all Abnormal Configuration Log Sheets for Units 0, 2, and 3 dated after October 1,
1991 for similar discrepancies.
Several forms were found that had the Appendix R block incorrectly checked but due to the short duration of the equipment being out of service, none resulted in compensatory measures being missed.
Two forms were found that exceeded the allowed out of service time of seven days, but the Appendix R blocks had been manually revised and the appropriate compensatory measures taken in time.
The licensee is reviewing the actions of the personnel involved and will initiate corrective measures as appropriately The automated clearance system is b'eing modified to properly flag Appendix R equipment.
This event is being reviewed by all Operations personnel.
Additionally, the Appendix R lesson plans are being revised to include more detail.
TS Section 6.8. 1. l.f requires that written procedures'e implemented covering Fire Protection and Appendix R Safe Shutdown programs.
Failure to establish compensatory measures required by 2-SSP-1 when the 3C Diesel Generator Battery Charger A was removed from service is a violation of this requirement.
This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcting the violation meet the criteria specified in Section VII.B of the Enforcement Policy.
NCV 259, 260, 296/92-30-05, Missed Appendix R Required Firewatch, will be issued to document this event.
Site Organization On September 1,
1992, Raul R. Baron became the Site guality Manager replacing Gerald G. Turner.
Mr. Baron was the Site Licensing Manager.
Other licensing supervisors will function as the Site Licensing Manager until a permanent replacement is. selected.
On September 2,
1992, it was announced that Browns Ferry Units
and
moved to Nuclear Operations.
This change placed all of the TYA operating and licensed shutdown Units under one organization, Nuclear Operations, The Site Vice President, Ike Zeringue, now has
.
responsibility for Unit 2 operations and return to service of Units
and 3.
The site priorities were established as safe operation of. Unit 2, Unit 2 Cycle 6 refueling outage, and recovery of Unit 3.
D'uring the next few weeks a transition will occur to consolidate activities in a
single organization.
Fred. McCluskey, Vice President of. Browns Ferry Restart, will transfer to Bellefonte as Site Vice President.
All construction projects will be under a single organization, Nuclear Project Exit'nterview (30703)
The inspection scope and findings were summarized on September 18, 1992 with those persons. indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed in detail. the inspection findings listed below.
Although proprietary material was reviewed during the inspection, proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
Item Number Descri tion and Reference 259, 260, 296/92-30-01 IFI, DG Turbocharger Failure, paragraph two.
260/92-30-02 259, 260, 296/92-30-03 UNR, Unclear Calibration Surveillance, paragraph two.
IFI, Circuit Breaker Coordination, paragraph four.
NCV, Valve Operator Clearance Error, paragraph four.
259, 260, 296/92-30-05 NCV, Hissed Appendix R Firewatch, paragraph nine, Licensee management was informed that
LER, 2 IFI, 1 URI, and 1 VIO were closed.
Acronyms and Initialisms APRH ASOS AUO CCM CFR CRDR CREV CSSC CSST DCN DG EDSFI EOI EPI ESF FDCN FPP GE GPH HVAC Average Power Range Honitor Assistant Shift Operations Supervisor Auxiliary Unit Operator Condenser Cooling Mater Code of Federal Regulations Control Room Design Review Control Room Emergency Ventilation Critical Structures, Systems, and Components Common Station Service Transformer Design Change Notice Diesel Generator Electrical Distribution System Functional Inspection Emergency Operating Instruction Electrical Preventive Instruction Engineered Safety Feature Field Design Change Notice Fire Protection Plan General Electric Gallons Per Hinute Heating Ventilation and Air-Conditioning
HX IFI II LCO LER LPRH HHI HPI HR HRTE HTS NCV NRC NRR OI PER PI PHT PORC
.
QA QC RCW RHR RPS RTP SI SII SLC SPAE SPOC SRC SSP TACF
Heat Exchanger Inspector Followup Item Incident Investigation Limiting Condition 'for Operation Licensee Event Report Local Power Range Monitor, Hechanical Maintenance Instruction Mechanical Preventive Instruction Maintenance Request Measuring and Test Equipment Master Tracking System Non Cited Violation Nuclear Regulatory Commission Nuclear Reactor Regulation Operating Instruction Problem Evaluation Report Project Instruction Post Modification Test Plant Operations Review Committee Quali,ty Assurance Quality Control Raw Cooling Water Residual Heat Removal Reactor Protection System Restart Test Program Surveillance Instruction Special Instrument Instruction Standby Liquid Control System Plant Acceptacne Evaluation System Pre-Operability Checklist Systems Requirements Calculation Site Standard Practice Temporary Alteration Change Form Test Deficiency Technical Specifications Tennessee Valley Authority Unresolved Item Violation Work Order Work Request
'