IR 05000259/1993045
| ML18037A755 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 01/26/1994 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18037A754 | List: |
| References | |
| 50-259-93-45, 50-260-93-45, 50-296-93-45, NUDOCS 9402150084 | |
| Download: ML18037A755 (25) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 30323-0199 Report Nos.:
50-259/93-45, 50-260/93-45, and 50-296/93-45 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:
December 18, 1993 - Ja uary 14, 1994 Inspector:
n n
cor a
>ne Accompanied by:
J.
Munday, Resident Inspector R. Musser, Resident Inspector G. Schnebli, Resident Inspector Approved by:
au Reac or roje
, Sectio 4A Division of ea tor Projects SUMMARY a
gne Scope:
This routine resident inspection included surveillance observation, maintenance observation, operational safety verification, Unit 3 restart activities, reportable occurrences and action on previous inspection findings.
One hour of backshift coverage was routinely worked during the work week.
Deep backshift inspections were conducted on December 18, 1993, January 8,
1994, January 9,
1994, and January 13, 1994.
9402150084 j140202.
PDR ADOCK -05000259 Q
In the area of Operations, one noncited violation was identified concerning a clearance on Unit 3 main steam line radiation monitors, paragraph 4.
An automatic start of the control room emergency ventilation system, standby gas treatment system, and reactor and refueling zone ventilation occurred due to an inadequate clearance review.
The licensee conducted an incident investigation of this problem and initiated several correction actions.
In the area of Engineering, the licensee committed to fix a long standing design deficiency with the secondary containment air lock doors by March 25, 1994, paragraph 4.
The doors, if opened simultaneously,";can defeat the interlock which was installed to prohibit both doors being open at the same time.
In the area of Plant Support, the security computer locked up securing doors to vital areas and preventing plant operators from entering, paragraph 4.
A fire watch was denied access to one area.
The licensee made procedural changes to promptly restore system operation.
Resolution of this problem will be a new computer system scheduled for installation this year.
Fifteen indications were identified during Unit 3 beltline weld inspection, paragraph 5.
These were internal flaws in circumferential welds.
These are being evaluated for a period of plant operatio REPORT DETAILS Persons Contacted Licensee Employees:
- 0. Zeringue, Senior Vice President, Nuclear Operations
- R. Hachon, Plant Manager
- J. Rupert, Engineering and Hodifications Manager
- T. Shriver, Licensing and guality Assurance Manager D. Nye, Recovery Manager E. Preston, Operations Manager
- J. Haddox, Engineering Manager
- H. Bajestani, Technical Support Manager
- A. Sorrell, Chemistry and Radiological Controls Manager C. Crane, Maintenance Manager
- P. Salas, Licensing Manager
- R. Wells, Compliance Manager
- J. Corey, Radiological Control Manager J. Brazell, Site Security Manager Other licensee employees or, contractors contacted included licensed reactor operators, auxiliary operators, craftsmen, technicians, public safety officers, quality assurance, design, and engineering personnel.
NRC Personnel:
P. Kellogg, Section Chief
- C. Patterson, Senior Resident Inspector
- J. Munday, Resident Inspector R. Musser, Resident Inspector G. Schnebli, 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, observa-tions 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:
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2-SI-4.2.8-7(C),
Core and Containment Cooling Systems Reactor Low Pressure Instrument Channel C Calibration b.
C.
On January 9,
1994, the inspector observed portions of the performance of 2-SI-4.2.8-7(C),
Core and Containment Cooling Systems Reactor Low Pressure Instrument Channel C.Calibration.
This surveillance test checks the calibration of instrumentation associated with low pressure emergency core cooling system initiation logic.
No deficiencies were noted by the inspector and the test was completed satisfactorily.
2-SI-4.6.E. 1, Jet Pump Operability Surveillance The inspector reviewed the performance of 2-SI-4.6.E. 1, Jet Pump Operability (Two Pump Operation),
on December 17, and December 27, 1993.
This surveillance is performed to determine the integrity of the jet pumps in accordance with TS 4.6.E. 1 and to record the speed of the reactor recirculation pumps in accordance with TS 4.6.F. 1.
This surveillance is performed daily when in startup or run modes with both recirculation pumps running.
The inspector verified the accuracy of the data by comparing the values recorded with the existing values and found them to be accurate.
The inspector reviewed the results of the surveillances and verified they were satisfactory.
No discrepancies were identified.
2-SI-4.1.A-8(F),
Scram Discharge Volume Surveillance On December 28, 1993, the inspector witnessed portions of the performance of 2-SI-4. 1.A-8(F),
RPS High Water Level In Scram Discharge Tank Functional Test.
The inspector verified the proper revision of the procedure was used, authorization was granted to begin work, proper anti-contamination clothing was donned, and proper communication was used.
The inspector reviewed the RWP and verified all requirements were met.
The inspector questioned the individual performing the surveillance about the method of performing independent verification at the conclusion of the surveillance.
Step 7. 13 required that all valves manipulated during the surveillance be verified returned to service by a person not involved with its performance, however the step did not list the affected valves.
The test performer stated that a
drawing located in the surveillance indicated the valves that were manipulated and the position they were required to be left in.
He further stated that it would be clearer if the affected valves were listed as a separate sign off rather'han one sign off for all valves.
He stated that he intended to submit a procedure change request to this effect.
The inspector later verified that individual signoffs had been incorporated into Revision 8 of the procedure on January 5,
1994.
No other discrepancies were noted.
No violations or deviations were identified in the Surveillance Observation are '
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 documents were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which might affect plant safety.
The inspector observed maintenance being performed on the unit 2 RWCU sample return pump.
The WO controlling the work, 93-11845-00, indicated that the pump level controller continuously leaked control air.
This work consisted of troubleshooting the various components to determine the cause of the leak.
The inspector reviewed the WO and verified proper authorizations had been obtained and that the workers were performing work as written in the WO.
The radiological controls were established and controlled by RWP 93-2-10005-0100.
The inspector reviewed this RWP and verified the, craft were complying with the requirements.
No discrepancies were noted by the inspector with this activity.
No violations or deviations were identified in the Maintenance Observation area.
Operational Safety Verification (71707)
The NRC inspectors followed the overall plant status and any significant safety matters related to plant operations.
Daily discussions were held with plant management and various members of the plant operating staff.
The inspectors made routine visits to the control rooms.
Inspection observations included instrument readings, setpoints and recordings, status of operating systems, status and alignments of emergency standby systems, verification of onsite-and offsite power supplies, emergency power sources available for automatic operation, the purpose of temporary tags on equipment controls and switches, annunciator alarm status, adherence to procedures, adherence to LCOs, nuclear instruments operability, temporary alterations in effect, daily journals and logs, stack monitor recorder traces, and control room manning.
This inspection activity also included numerous informal discussions with operators and supervisors.
General plant tours were conducted.
Portions of the turbine buildings, each reactor building, and general plant areas were visited.
Observations included valve position and system alignment, snubber and hanger conditions, containment isolation alignments, instrument readings, housekeeping, power supply and breaker alignments, radiation and contaminated area controls, tag controls on equipment, work
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activities in progress, and radiological protection controls.
Informal discussions were held with selected plant personnel in their functional areas during these tours.
Unit Status b.
Unit 2 operated continuously without any significant problems during this period.
At the end of the period the unit was on line for 225 days.
Secondary Containment Door Interlocks On January 9,
1994, while in process of entering the Unit 1/2 Reactor Building to Turbine Building airlock, the inspector observed the simultaneous opening of the reactor and turbine building doors.
Having the two doors open at the same time constitutes a loss'f secondary containment as defined by TS 1.0/P. I.a.
The two doors were open only momentarily.
This matter was brought to the attention of the SOS and Unit 2 ASOS.
The inspectors and the licensee have previously observed this condition as documented in IRs 50-259, 260, 296/93-18 and 93-32.
IR 93-32 documents the licensee's commitment to repair the interlocks prior to the completion of the Unit 2 Cycle 7 operating period (scheduled for October 1994).
With the latest occurrence, the inspectors questioned the adequacy of the timeliness of the licensee's corrective action.
Licensee management committed to performing a modification to the Unit 1/2 and Unit 3 interlocks by Harch 25, 1994.
The inspectors will continue to follow this issue.
C.
Loss of Security Computer As followup to a loss of the plant security computer reported in IR 259, 260, 296/93-44, the inspector reviewed the completed II-B-93-050.
The II determined the root cause of the event was an unregulated and unprotected power supply.
The licensee stated that a new computer system with a regulated and protected power supply is scheduled to be installed in 1994.
Until that time, the possibility of the computer locking up again exists.
Security management generated a memorandum, to be followed by a procedure change, to restore the system to operation should this recur.
The inspector reviewed this memorandum and questioned security personnel to ensure they were familiar with carrying out the tasks required to restore the system.
This event resulted in a fire watch being denied access to an area in which one was required.
The II stated that a 10 CFR 50.59 safety review would be performed to address the effect of the missed fire watch.
Discussions with the licensee indicated that the FPR-Volume 2, Section I-L, had previously been revised to address this concern, and therefore the safety review required by
0,
d.
the II would not be performed.
The inspector reviewed the procedure and verified it was adequate for this condition.
Clearance Error On December 8, 1993 while placing clearance 3-93-0503 on the Unit 3 main steam line radiation monitors, an auto start of the CREVs and SBGT systems and initiation of the reactor and refuel zone ventilation occurred.
II-8-93-051 was initiated to determine the cause of the event and to develop corrective actions.
The II was issued on January 3,
1994 and determined that the isolation occurred when breaker 905 on battery board 3 was opened.
In preparing the ciearance the licensee failed to recognize that this breaker, supplying power to the main steam line radiation monitors, also supplied power to the Unit 3 reactor and refuel zone radiation monitors.
When the breaker was opened and the monitors deenergized, the actuations occurred as designed.
Following a review of the appropriate plant drawings, Operations reclosed breaker 905 and returned the systems to their normal lineup.
Corrective actions for this event included training for all licensed operators, including upgrade and initial license classes, Modifications and Unit 2 Work Control personnel.
In addition the II will be placed in required reading for all operators.
Drawings will be upgraded to improve their useability.
The Plant Operations Manager will conduct a detailed review of the requirements of SSP-12.3, Equipment Clearance Procedure, to ensure that management's expectations regarding clearances are procedurally clear.
TS Section 6.8. l.l.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 includes procedures for tagging and controlling equipment.
SSP-12.3, Equipment Clearance Procedure, Section 3.2. 1.D, 3.2. 1.G, and 3.2.2.A define the requirements for the review and determination of plant impact when placing equipment under clearance.
Failure to perform an adequate review to determine the effects of placing clearance 3-93-0503, 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.
This item will be identified as NCV 50-259, 260, 296/93-45-01, Inadequate Review of Clearance.
One noncited violation was identified in the Operational Safety Verification are Unit 3 Restart Activities (30702, 37828, 61726, 62703, 71707)
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.
Observations of pre-job field work, in-progress field work, and QA/QC activities.
Inspectors attended restart craft level progress meetings, restart program meetings, and management meetings; and held periodic discussions with both TVA and contractor personnel, skilled craftsmen, supervisors, managers and executives.
Hajor work activities were control room design review, seismic support modifications, and drywell steel modifications.
a.
Design Changes and Plant Hodifications The inspectors reviewed selected DCN packages associated with plant modifications to support the Unit 3 recovery effort.
The DCN work packages were reviewed and work in progress was observed to:
ensure that the DCN packages were properly reviewed and approved by the appropriate organizations in accordance with the licensees administrative controls; verify the adequacy of the
CFR 50.59 evaluations performed and that the appropriate FSAR revisions were planned or completed, if applicable; ensure that the applicable plant operating procedures and design documents were identified and revised to reflect the modification; verify that the modifications were reviewed and incorporated into the operations training program, as applicable; verify that the modifications were installed in accordance with the work package (for those that could be physically inspected);
ensure that the modification was consistent with applicable codes and standards, regulatory requirements, and licensee commitments; and ensure that post modification testing requirements were specified and that adequate testing was accomplished.
The following were reviewed:
1.)
Jet Pump Beam This issue was reviewed with discussion of RICSIL 065.
The RICSIL was an update of SIL 330 and contained the latest recommendations for jet pump beam failures.
The RICSIL 065 recommended replacement of all jet pump beams with beams that had received high temperature anneal heat treatment and were less susceptible to IGSCC.
Previously, Browns Ferry had replaced the beams in all three units with the recommended material.
Unit 3's were replaced one year ago; Unit 2's were replaced prior to restart in 1991; and Unit 1's were replaced around the same time as Unit 2.
The actions recommended by RICSIL 065 were considered complete.
2.)
Shroud Inspection The licensee plans to conduct a shroud inspection of the Unit 3 vessel around the middle of Harch 1994.
This will be
performed using a
UT device being developed and scheduled for testing January 17, 1994, in San Jose, California.
This device rests on top of the shroud and tr averses circumferentially around the shroud providing uniform coverage with UT probes.
This machine will allow BWRs to conduct refueling operations while the inspection is performed.
Unit 2 shroud inspection is scheduled for October-to November 1994.
The licensee had previously performed a visual inspection with no indications found.
However, this inspection was not in accordance with the latest SIL that required brushing of the weld areas to provide better inspection results.
Unit 3 Vessel Beltline Weld Inspection The licensee has completed this inspection using the GERIS 2000 equipment.
Fifteen indications were identified.
These were internal flaws in circumferential welds.
The licensee stated these meet the criteria for evaluation per IWA 3500 and IWA 3600.
Preliminary evaluation of the flaws based on crack size and fracture mechanics indicated these would be acceptable for some period of operation with more frequent inspections to follow.
The overall weld coverage was estimated at 83 percent.
Lessons learned from the inspection were more equipment problems were experienced than expected especially with electrical connectors and numerous small indications that had to be filtered or evaluated away that required lots of computer memory.
The inspector questioned when and how the results of this inspection would be transmitted to the NRC.
The licensee stated that the code requirement for the report to be submitted was generally 60 days after the end of the refueling outage.
The inspector questioned the timeliness of this since this was the first inspection performed, indications were identified, and one and one half years remain in the outsge.
The inspector will continue to follow this issue for reporting and followup inspections.
Location. of Large Crane Adjacent to Unit 3 Diesel Generator Building The inspector reviewed the placement of the Hanitowoc 4100W Sl crane on cribbing next to the Unit 3 Diesel Generator Building.
The licensee had previously performed a
calculation titled, "gualification of Crane Location for Reactor Building Roof Replacement",
CD-(0111-931122, to address this issue.
The inspector reviewed the calculation for consideration of underground piping.
In IR 89-10, an issue concerning vitrified clay pipe on the EECW discharge piping was raise The licensee provided drawings 0-17W405-3 and 0-17E405-1 that identified the vitrified clay piping as three feet underground and nine feet away from the diesel generator building.
The edge of the crane cribbing was 21 to 22 feet away from the building and therefore was not affected.
Also, being buried only three feet, the cone of impact was below the piping.
The location of the piping was discussed in the calculation.
The inspector concluded that the location of the crane had been adequately addressed.
System SPOCs The purpose of the SPOC process is to provide a systematic method for evaluating items and issues which potentially affect the ability of Unit 3 systems and the Unit 3 portion of common systems to perform as designed.
This process determines the status of each item/issue and assures completion of'hose which affect system return to operation for Unit 3 restart.
For each system evaluated, the SPOC process may be accomplished in two phases.
Phase I SPOC addresses the Restart Test Program testing milestone if that milestone exists for the system, and establishes system status control by the Operations department.
Phase II SPOC addresses System Return to Operation in preparation for the declaration of system operability.
Each phase ensures that open items/issues which potentially affect the phase are either completed, or reviewed and satisfactorily dispositioned.
The SPOC process does not declare the system operable.
Rather, it is used to support a declaration of system operability which is made after other requirements for operability are satisfied (e.g.,
support systems available, performance of Surveillance Instructions, etc.).
The inspectors reviewed a copy of the projected SPOC closeout schedule dated December 14, 1993.
During the period of January 18, 1994, through February 6,
1995, approximately
months, the schedule indicated completing
SPOCs (14 Phase I and 16 Phase II) for an average of 2.3 per month.
For the period of April 6, 1995, through June 14, 1995, the schedule shows the completion of 62 SPOCs (27 Phase I and 35 Phase II) which is an average of about 30 closeouts per month.
The average SPOC closure during the Unit 2 recovery was 5-6 per month which is significantly less then the current schedule for Unit 3 recovery.
The inspectors discussed the schedule with licensee management and expressed a concern that it did not appear that necessary resources would be available to complete the SPOCs as scheduled.
The following system SPOC packages were reviewed to ensure they complied with SSP 12.55, Unit 3 System Pre-Operability Checklist, Revision 5.
Hinor deficiencies were resolved with the system enginee System 005, Extraction Steam System Minor System SPOC, Phase I completed on April 22, 1993.
The SPAE package was completed on February 17, 1993.
The Extraction Steam System is responsible for delivering steam from five stages of the main steam turbine to the low and high pressure feedwater heaters, where heat from the steam is transferred to the feedwater prior to returning to the reactor.
The boundary for this evaluation consisted of the piping, flow control valves for isolation, check valves, and instrumentation between the Unit 3 turbine and associated feedwater heaters.
Also included in the boundary were the bypass lines and valves from the extraction lines No. 2, 3, 4, and 5 to Unit 3 condenser hotwells, and the low point drains and connections from extraction lines No.
2 and 3 for minimum extraction steam to Unit 3 condenser A hotwell.
System 007, Turbine Extraction Traps and Drains, and System 008, Turbine Drains and Miscellaneous Piping Minor System SPOC, Phase I completed on Hay 5, 1993.
The SPAE package was completed on April 16, 1993.
The turbine extraction traps and drains and the turbine drains and miscellaneous piping systems provide manual steam isolation to the Unit 3 reactor feedwater turbine seals and stop valves, steam seal regulator, and main low pressure turbine exhaust hood sprays.
Also, the systems provide the means for draining the Unit 3 reactor feedwater turbine and associated stop valves, steam packing unloading header, and the main low pressure turbine exhaust hoods.
The boundary for this evaluation included the entire system.
System 025, Raw Service Water System Major System SPOC, Phase I completed on April 29, 1993.
The SPAE package was completed on April 19, 1993.
The purposes of the RSW system are as follows:
provide charging water to the HPFP system; provide service water to equipment in remote areas where raw water is not readily available; provide service water for yard watering, outside wash down, etc.; provide water for fighting small fires (up to two fire hoses).
The portion of the RSW system evaluated consisted of the Unit 3 RSW pumps and associated piping from the suction point on the RCW suction header to the RSW common header in the Unit 3 turbine building and that portion of the system in the intake pumping station which supplies bearing lube water and motor bearing cooling water for the Unit 3 CCW pumps.
The portion of the RSW system which was previously evaluated for Unit 2 was also reviewed and determined to be capable of supporting multi-unit operatio.)
System 37, Gland Seal Water System Minor System SPOC, Phase I completed on March 4, 1993.
The SPAE package was completed on February 17, 1993.
The Gland Seal Water System supplies low pressure water from the Condensate System to certain valves and pumps to prevent the entrance of air into the Feedwater System.
This system also furnishes water for the expansion joint on the main condensers, seal water for the condenser vacuum breaker valve, water for the off-gas condensate loop seal, and water for the lantern glands on the condenser vacuum pumps as well as to the'makeup valve on the separator.
This system only has one safe shutdown mode which is to support secondary containment.
The secondary containment functions were returned to operation during the Unit 2 restart effort.
The boundary encompassed for this review included the entire Unit 3 Gland Seal Water System up to and including valves 3-VLV-037-504 and 3-VLV-037-506, the condensate header supply isolation valves.
6.
Reportable Occurrences (92700)
The LERs listed below were reviewed to determine if the information provided met NRC requirements.
The determinations included the verification of compliance with TS and regulatory requirements, and addressed the adequacy of the event description, the 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 260/93-07, Reactor Shutdown Due to Recirculation Pump Seal Leakage This LER was submitted to document a TS required reactor shutdown initiated due to the failure of a reactor recirculation pump seal.
On May 27, 1993, with Unit 2 at eight percent thermal power, the number two mechanical seal on the 2A recirculation pump failed and therefore the pump was secured.
TS 3.6.F. 1 requires the plant to be placed in hot shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after entering single loop operation.
Because the condition warranted returning the unit to cold shutdown for repairs, an orderly shutdown was initiated with the unit reaching hot shutdown approximately five and one-half hours after entering the LCO.
The licensee's investigation revealed that the seal failure was due to small particles from the recirculation system collecting in the spring packing assembly thereby causing the seal not to seat properly.
The root cause of the seal failure was determined to be inadequate procedures.
The recirculation system operating instruction did not contain instructions to initiate seal purge flow prior to starting the pumps and opening the pump's isolation valve The licensees corrective actions included the revising of Operating Instruction 2-0I-68, "Reactor Recirculation System" to require seal purge flow to be established prior to starting the pumps and opening the pump's isolation valves.
Additionally, Maintenance Instruction HCI-068-PHP001,
"Maintenance of Reactor Recirculation Pumps,"
was revised to require that seal flow be established following seal maintenance activities prior to the suction or discharge valves being opened.
Prior to restarting the unit, both the 2A and 2B recirculation pump seals were rebuilt and returned to service.
The inspector reviewed these corrective actions and determined that adequate measures have been established to prevent recurrence of this matter.
Action on Previous Inspection Findings (92701, 92702)
(CLOSED) IFI 259, 260, 296/92-03-02, Alternate Breach Plan of Secondary Containment.
This item was an inspector concern that the licensee's original plan to exclude Unit 3 reactor building from secondary containment to facilitate recovery work was changed.
The licensee's new approach was to allow up to a
170 square inch hole in secondary containment based on calculations that secondary containment could be maintained due to free air leakage between zones and the ability of SBGT to maintain the required pressures.
A meeting between TVA and the NRC was held on September 29, 1992, to discuss combined zone secondary containment.
In addition, a
special inspection was conducted October 19-23, 1992, to review this issue.
IR 259, 260,296/92-36 was issued on October 29, 1992, and concluded the configuration changes.
and breach margin methodology were acceptable.
TVA agreed to use only half the calculated breach margin until the secondary containment surveillance instruction was performed in the combined zone configuration.
This test was successfully performed on January 30, 1993.
TVA in a letter dated February 12, 1993 concluded that the full calculated break margin was acceptable.
b.
(CLOSED) IFI 259, 260, 296/93-14-01, EDSFI Finding 5, Control Bay Water Chiller Circuit Breaker Modification This issue concerns the modification of the breaker trip unit to a
GE RHS-9 device.
Subsequent to the modification of numerous breakers to this new solid state trip device, the licensee has experienced spurious circuit breaker trips, which resulted in several LER's and the generation of 10 CFR 21 notification in November 1992.
This issue was previously discussed in IRs 259, 260, 296/92-30, 93-23, and 93-44, and is currently being followed by the inspectors as IFI 92-30-03.
Therefore, IFI 93-14-01 may be closed and tracking until corrective actions are complete will be by IFI 92-30-03.
The licensee's current plans, as discussed in meetings on December 17, 1993, and January 7,
1994, are to discontinue use of the RHS-9 devices and convert the previously
modified breakers back to the older type EC trip device.
The licensee is currently discussing this conversion with the vendor, GE, and the inspectors will continue to follow this issue.
(CLOSED) I'FI 260/92-41-01, Failure Of Environmentally gualified Limit Switch During the per formance of 2-SI-4.1.A-11(II), Hain Steam Isolation Valve Closure Functional Test, on November 28, 1993, the
"D" line outboard HSIV,, 2-FCV-001-0052, failed to generate a
RPS channel B
half scram when tested.
The failure was determined to be a faulty position limit switch that was thought to have failed due to moisture intrusion from a nearby leak.
On March 31, 1993 the inspector accompanied maintenance personnel to inspect the internals of the limit switch.
The inspection revealed no signs of moisture related damage.
The tripper arm was found to be sticking.
Maintenance replaced the limit switch in accordance with WO 93-02603-00 and following calibration and adjustment, the switch tested satisfactorily.
The cause of the failure was not determined.
However, it was determined that it was not related to moisture intrusion.
(CLOSED)
VIO 259, 260, 296/93-12-01, Clearance Tags Not in Place This violation had two examples of problems with equipment clearances.
The first example was that five instances of hold order tags not in place were identified.
Five tags attached to fuse blanks were found laying inside a control room back panel cabinet while craft were working in the panels.
The licensee immediately stopped work in the cabinets and walked down all cabinets to identify any other problems.
Additionally, wooden dowels were purchased to be used in close quarter areas.
The dowels contain no protruding extensions like the plastic pieces that can be easily dislodge in confined spaces.
Personnel working in the panels were counselled to report any fuse blanks dislodged to the SOS.
The second example of the violation was that two hold order tags did not correctly specify the component position.
The clearance sheet specified P-K blank covers as
"PLACED" but the covers were removed and laying on the floor with the clearance tag attached.
The licensee corrected the specific problem and revised SSP 12.3, Equipment Clearance Procedure, to specify that hold order tags be attached to the stationary component of the P-K block.
The inspector reviewed the licensee's closure package for this then procedure revision.
(CLOSED)
VIO 259, 260, 296/93-23-02, CREV Components Not In Required Position
The inspector identified several valves and dampers associated with the CREV system, out of the required positions.
In addition, a valve had been omitted from the valve alignment checklist.
As a
result of this violation, the licensee properly realigned the system to agree with the alignment checklist and added the valve which was originally omitted.
Additionally, the licensee painted a red line on the duct to identify the proper positioning of the damper found out of position.
Based on these actions, the inspector considers this item closed.
8.
Site Organization On December 21, 1993, 0. J. Zeringue was named Senior Vice President, Nuclear Operations.
Hr. Zeringue will report to Hr. Kingsley and will be responsible for the operating nuclear plants and the nuclear readiness organization.
R.
D. Hachon, Browns Ferry Nuclear Plant Manager, will assume additional responsibilities as Senior Site Manager until a site vice president is named.
~ '.
H. Eytchison will continue to report to Hr. Kingsley in a special role focusing on operational improvements.
Exit Interview (30703)
The inspection scope and findings were summarized on January 18, 1994 with those persons indicated in paragraph
=1 above.
The inspectors described the areas inspected and discussed in detail the inspection findings listed below.
The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
Item Number Descri tion and Reference 259, 260, 296/93-45-01 NCV, Inadequate Review of Clearance, paragraph 4.
Licensee management was informed that one LER, three IFIs, and two VIOs, were close Acronyms and Initial i sms
BWR CFR CREV DCN EECW FSAR HPFP IFI IGSCC II IR LCO LER NCV NRC QA QC RCW RICSIL RPS RSW RWCU RWP SBGT SI SIL SPOC SSP TS UT VIO WO Boiling Water Reactor Code of Federal Regulations Control Room Emergency Ventilation Design Change Notice Emergency Equipment Cooling Water Final Safety Analysis Report High Pressure Fire Protection Inspector Followup Item Intergranular Stress Corrosion Cracking Incident Investigation Inspection Report Limiting Condition for Operation Licensee Event Report Non-Cited Violation Nuclear Regulatory Commission Quality Assurance Quality Control Raw Cooling Water Rapid Information Communications Service Information Letter Reactor Protection System Raw Service Water Reactor Water Cleanup Radiological Work Permit Standby Gas Treatment Surveillance Instruction Service Information Letter System Pre-Operability Checklist Site Standard Practice Technical Specification Ultrasonic Test Violation Work Order