IR 05000259/1993036
| ML18037A556 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 11/09/1993 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18037A555 | List: |
| References | |
| 50-259-93-36, 50-260-93-36, 50-296-93-36, NUDOCS 9311160267 | |
| Download: ML18037A556 (24) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 30323.0199 Report Nos.:
50-259/93-36, 50-260/93-36, and 50-296/93-36 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:
September
October 15, 1993 Inspector:
esi e
nspector a
gne Accompanied by:
J.
Munday, Resident Inspector R. Musser, Resident Inspector G. Schnebli, Resident Inspector Approved by:
Reactor rope s, Sectio 4A Division of Reac or Projects at Si ne SUMMARY Scope:
C This routine resident inspection included surveillance observation, mainte-nance observation, operational safety verification, Unit 3 restart activities, and action on previous inspection findings.
One hour of backshift coverage was routinely worked during the work week.
Deep backshift inspections were conducted on October 3 and 10, 1993.
9311160267 931109 PDR ADOCK 05000259 Q
Unit 2 operated continuously during this month and was on-line for 134 days at the end of the period, paragraph 4.
A difference in reactor vessel water instruments was observed on October ll, 1993, and the instruments off one reference leg were declared inoperable.
The reference leg was backfilled and the condition corrected.
This problem was observed several times during last operating cycle.
The licensee is conducting an incident investigation review of the problem but final resolution is expected with installation of a continuous fill modification for bulletin 93-03.
Unit 3 activities consisted of finalization of the recovery schedule and preparation for the condenser hydrostatic test milestone, paragraph 5.
Condenser circulating water system restoration activities were monitored and found to be thorough.
An unresolved item was identified concerning the installation of a reactor building to torus vacuum breaker, paragraph 4.
A system engineer identified that one of the two valves was installed with a different stem orientation.
The valve was determined to be operable but questions remain concerning drawings and FSAR statements.
The inspectors are continuing to review this problem in parallel with the licensee's incident investigation.
The licensee's leak sealant practices (Furmanite)
were reviewed, paragraph 3.
Procedures are in place for control of these activities.
The licensee's goal is to limit the length of use of a leak sealant to the next system outage or refueling outag REPORT DETAILS Persons Contacted Licensee Employees:
- 0. Zeringue, Vice President J. Scalice, Plant Manager
- J. Rupert, Engineering and Modifications Manager
- T. Shriver, Licensing and guality Assurance Manager D. Nye, Recovery Manager
- R. Moll, Acting Operations Manager
- J. Haddox, Engineering Manager
- H. Bajestani, Technical Support Manager A. Sorrell, Chemistry and Radiological Controls Hanager 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, and public safety officers; and quality assurance, design, and engineering personnel.
NRC Personnel:
P. Kellogg, Section Chief
- C. Patterson, Senior Resident Inspector
- J. Hunday, Resident Inspector R. Husser, Resident Inspector
- G. Schnebli, Resident Inspector
+Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
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:
a.
2-SI-4.3.B. I.a - Control Rod Coupling Integrity Check and 2-SI-4.3.A.2 - Control Rod Exercise Test On October 10, 1993, the inspector observed performance of por-tions of these surveillances.
The rod exercise test was performed after a five percent load reduction.
First, a fully withdrawn rod was inserted to position 46 and then withdrawn to 48.
This was repeated for each row of rods.
This SI verifies operability of all partially or fully withdrawn control rods as required by TS 4.3.A.2.a.
Also, performed was the coupling integrity check.
This SI verifies the integrity of the coupling between the control rod and the drive mechanism as required by TS 4.3.B. l.a.
Opera-tors verify that the control rod is following its drive through observance of neutron instrumentation response each time a rod is moved,.
No deficiencies were noted during observance of the SIs.
b.
2-SI-4-1.A-8(F)
RPS High Water Level In Scram Discharge Tank Functional Test On October 5, 1993, the inspector witnessed the performance of portions of 2-SI-4. 1.A-8(F),
RPS High Water Level In Scram Dis-charge Tank Functional Test.
This test verifies the operability of RPS channels 2-LS-85-45E and 2-LS-85-45F.
The inspector verified the latest revision of the procedure was used and was being followed.
This surveillance requires the coordination of four people.
The inspector noted the communication between them was clear and concise.
First and second party and independent verifications were performed properly.
The inspector noted no discrepancies with the performance of this surveillance.
n No violations or deviations were identified in the-Surveillance Observa-tion 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 maint'ained, activities accomplished by qualified personnel, use of properly certi-fied 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
u
maintenance which might affect plant safety.
The inspectors observed the following maintenance activities during this reporting period:
'a ~
Leak Sealant Practices The inspector reviewed the licensee's program for use of temporary leak sealant practices.
This is commonly referred to as Furmanite.
2)
3)
4)
Use The licensee has contracts with Furmanite, Inc.
and Leak Repair, Inc. for services and materials used in leak sealing process.
The processes used by both companies are the same and are available throughout the industry.
They follow Nuclear Naintenance Applications Center guide booklet,
"On-Line Leak Sealant,"
prepared by EPRI.
Some processes used are injection clamps for flange leaks, enclosure boxes for leaks in elbows, wire wrap of joints, packing gland injection and "killing" of a thru-leak in a valve.
Scope Sealants have been used primarily on nonsafety-related equipment.
The inspector reviewed the database with the cognizant maintenance engineer of. the items repaired for Unit 2 cycle 6 and cycle 7.
There were 30 repairs during cycle 6 on nonsafety-related equipment such as high-pressure feedwater heaters and moisture separators.
There are nine repairs for cycle 7 operation.
There are no uses on safety-related equipment.
It can be used on safety-related equip-ment with Nuclear Engineering approval in accordance with procedures.
Procedures Repairs are performed under work orders prepared by SSP 6.2, Maintenance Management System, and General Engineering Specification G-85,
"On-Line Leak Sealing."
For safety-rel-ated equipment the approval is processed using the DCN/DCR process.
Work orders are developed from vendor supplied procedures that cover the particular process to be used.
Control The control of the type and amount of injected material is accomplished by specification G-85.
This specifies require-ments for chemical composition and a requirement that the volume of sealant to be injected be estimated with a check-point to limit this volume.
The leak sealing companies supply the estimated volume for application and recommend the compound and enclosure best suited for fixing the lea ~l
This information is then used by the licensee for evaluating the amount of sealant material needed to fill the enclosure area.
5)
Safety Review Safety-reviews are required on DCN/DCR for safety related equipment.
An independent qualified reviewer is required for WOs on BOP equipment.
6)
Limitations The licensee's policy on length of use is to make the temporary repair permanent at the next refueling outage or system outage.
Any extensions must be approved by NE.
A review of the database for cycle 6 and cycle 7 indicated only one exception that was documented by PRD 910184P.
Design engineering reviewed the applicable under DCN S
17136 A.
The licensee concluded that the change was acceptable.
Issues addressed were appendix R, seismic, and piping vibration.
The inspector reviewed the S-DCN and concluded this application had been appropriately addressed.
7)
Oversight gA has been involved with the issuance of a PER.
gA review is required for DCN/DCR on safety equipment.
8)
Management Plant Management is made aware of temporary repair methods being proposed on operational equipment by either outage scheduling meetings or verbal communication with the Maintenance Manager.
Bypass Valves Opening On October 9, 1993, during a weekly main turbine stop valve test several bypass valves opened when the number 4 stop valve was closed.
This test is performed using 2-0I-47, Turbine Generator System, section 6. 11.
The inspector reviewed the OI and test data.
The bypass valves opened as follows:
¹1 109.8X
¹2 41.9X
¹3 24.1X
¹4-8 stayed closed
¹9 109.9X The test was suspended pending resolution of this problem.
The inspector will continue to follow this item.
The licensee plans
to instrument various signals during the next weekly test to aid in determining the cause of this problem.
No violations or deviations were identified in the Maintenance Observa-tion 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 tempo-rary tags on equipment controls and switches, annunciator alarm status, adherence to procedures, adherence to LCOs, nuclear instruments opera-bility, 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.
Observa-tions 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 ~
Unit Status b.
Unit 2 operated continuously during this month and was on-line for 134 days at the end of the inspection period.
Water Level Anomaly On October II, 1993, plant operators observed that channel
'A'ormal reactor water level instruments were reading higher than the channel
'B'nstruments.
Instruments 3-53 and 3-206 off the
'A'eference leg were reading 38 inches compared to 33 inches for 3-60 off the 'B'eference leg.
A maximum of a five inch differ-ence is allowed.
Voltage readings were taken and water level instruments off the 'A'eference were declared inoperable and LCO's entered.
The reference leg was backfilled and a leaking valve on 2-LT-3-206 manifold was corrected.
This resolved the discrepancy between the water level instruments.
The LCO's were exite The inspector reviewed the licensee's action and TS compliance.
The most limiting LCO was two hours based on TS 3.2.A.
Normally one hour is allowed and then a trip channel must be made operable or placed in a tripped condition.
In this case 2-LT-3-203A and 2-LT-3-203B for a low reactor water level scram signal both came off the 'A'eference leg.
One LT inputs to RPS Channel A and the other to RPS Channel B.
Tripping these two would make up the one out of two taken twice logic for an actual trip function.
In these cases the TS allow two hours to restore instruments to an operable status.
The inspector concluded that the licensee action's were appropriate.
This same water level discrepancy problem was experienced last operating cycle and was discussed in IR 92-33.
The problems were resolved by backfilling the reference legs.
Elimination of this problem should occur with installation of a continuous fill system for Bulletin 93-03.
Containment Isolation Valve Improperly Installed On October I, 1993, during a plant/system walkdown, a system engineer noted that valve 2-FCV-64-20 was installed such that its shaft seals were on the inboard side of the valve seat.
Valve 2-FCV-64-20 is a high performance butterfly valve and is the inboard containment isolation valve for one of the two reactor building to torus vacuum relief lines.
High performance butterfly valves of this type (Flow Seal
¹20-1WA-121LGB-BXG) are constructed such that the valve stem is offset from the valve disc edge seating surface thereby allowing contact with the seat throughout the 360 degree circumference.
A problem evaluation report (93-132)
was initiated on this matter.
The initial concern with the valve being in-stalled in this orientation was that the shaft seals were outside of the test boundary of the periodic type C LLRT therefore creat-ing an untested leak path.
An engineering evaluation performed by the licensee demonstrated that if a total failure of the seals were to occur, containment leakage would increase by approximately 52.6 scfh.
During the previous refueling outage (January - June, 1993),
the licensee demonstrated an overall containment allowable leakage margin of 492 scfh.
Since this leakage path remains untested, the licensee will deduct the calculated leakage through the valve seals from the containment allowable leakage margin.
The inspectors were informed of this matter on October 4, 1993.
An independent review was performed by the inspectors.
During this review, several issues were brought forth.
Through review of the valve's technical manual, the valve's manufacturer states that for HPBVs 16 inches and larger, installation should always be made with the shaft horizontal.
Valve 2-FCV-64-20 is a 20 inch HPBV and is installed with its shaft oriented vertically.
The inspec-tor expressed a concern to the licensee about the valve's opera-bility.
The licensee and the inspector contacted the valve's manufacturer who stated that installation instructions were only a recommendation to increase the useful life of the valve internals.
The inspector also reviewed the valve's technical manual for
proper orientation of the valves disc as it relates to accident pressure.
Although the manufacturer states that all seat designs are completely bi-directional, they further state that every effort should be made to install the valve with pressure and flow from the seat side (seat upstream).
Again, in this case the valve is not installed in accordance with the manufacturers recommenda-tion (which are again made to increase the life span of valve internals).
Further review into the matter revealed two drawing discrepancies and a questionable statement in section 5.2.3.6 of the FSAR.
The FSAR states that the air-operated vacuum breaker valves (which includes valve 2-FCV-64-20) are actuated by a DP signal which is independent of electrical power.
The inspectors questioned the validity of this statement as electrical power is supplied to the air system that operates the valves and have asked the licensee to resolve this matter.
Valve 2-FCV-64-20 was installed during the previous refueling outage in accordance with DCN W16880A.
It appears that the craft personnel assigned to install valve 2-FCV-64-20 questioned the importance of flow direction during installa-tion in accordance with DCN g23608A and were informed that flow direction was not critical for proper performance of the valve.
The licensee is currently conducting an incident investigation into this matter.
Pending the results of the incident investiga-tion and the inspectors review, this issue will be tracked as Unresolved Item 260/93-36-01, Containment Isolation Valve Improp-erly Installed.
One unresolved item was identified in the Operational Safety Verifica-tion area.
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; observation of pre-job field work, in-progress field work, and gA/gC activities; attendance at restart craft level, progress meetings, restart program meetings, and management meetings; and periodic discussions with both TVA and contractor person-nel, skilled craftsmen, supervisors, managers and executives.
The licensee is still working on the Unit 3 Recovery Schedule which should be finalized in the near future.
The inspectors will continue to follow the progress of the schedule.
Construction activities continue to increase.
Hajor activities in progress include:
CRDR work in the control room panels; fire protection systems; seismic upgrades; and pipe supports.
a.
JTG Heeting The inspectors attended JTG meeting 93-004 on October 7, 1993.
The following items were reviewed and approved by the group at
'J
this meeting:
JTG Heeting Hinutes from the previous meeting (93-003)
conducted on January 25, 1993; JTG Hembership changes; Condenser Circulating Water System Restart Test Requirements; Raw Cooling Water System Restart Test Requirements; and closure of five JTG Open Items.
Closure of the open items was based on the following:
Item 1 dealt with the development of the remaining subsec-tions of the STH.
The content of the STH was evaluated with respect to the current methodology for implementation of the RTP, as outlined in SSP-8.50, revision 2.
The licensee's evaluation determined the STH should only contain the cur-rent sections 1.0, 2.0, 5.0, 6.0, and 7.0.
The other sec-tions, 3.0, 4.0, and 8.0 through 12.0, are no longer needed due to program changes, processes being covered by other procedures, and integration of testing responsibilities within the Technical Support Organization.
Item 2 concerned the identification of unique identifiers for RTP test instructions.
SSP-8.50 was revised to use the BTRD identifier as the RTP test requirement identifier.
This change will ensure consistency between the documents and eliminate the previous concern regarding test identifier numbers.
Item 3 dealt with evaluating the need for a Field Services Representative on the JTG.
Since the system readiness for testing evaluation is now done by the SPOC process instead of by JTG, and plant reorganization has resulted in a shift of responsibility for all testing activities to the Techni-cal Support Organization, the need for Field Services repre-sentation on the JTG is no longer necessary.
Based on this conclusion, SSP-8.50 was revised to delete this from the RTP review documentation, and SSP-12. 10 was revised to delete Field Services from the JTG membership.
Item 4 was a request by the JTG Chairman for the Operations Representative to review O-OI-27C, Cooling Tower System Operating Instruction, to determine if a precaution or limitation should be added to the procedure when pulling vacuum.
Problems have been encountered in the past when pulling vacuum due to a low level (below 551 feet) in the warm water channel.
The procedure was revised by revi-sion 18 to include this request.
Item 5 dealt with research and verification that the paper-work to allow operation of a sixth lift pump was issued.
This additional lift pump was noted to be required as a
result of previous cooling tower system testing.
DCN S1843-3B provided the necessary drawing and document changes to allow operation of a sixth lift pum The JTG approved all agenda items discussed above and no new items were added.
The inspectors will continue to monitor future JTG meetings.
SPOC Walkdown On October 14, 1993, the inspector accompanied the licensee on a
system walkdown of the Condenser Circulating Water System as part of Phase I
SPOC process.
The walkdown was conducted in accordance with OSIL-64, Operations Section Instruction Letter, System Pre-Operability Checklist Walkdowns.
The purpose of the walkdown was to identify and disposition items that affect system operability and unacceptable plant material conditions.
A pre-evolution briefing was conducted by the System Engineer for personnel performing the walkdown, which included members from the gA, Technical Support, Maintenance, and Operations departments.
The walkdown encompassed the entire CCW system for Unit 3 and all deficiencies were documented in Attachment 2 of OSIL-64.
The deficiencies will be dispositioned using existing licensee work documents and programs.
The deficiencies identified by the team members were minor and agreed with those noted by the inspector.
The residents will continue to monitor the SPOC process for Unit 3 restart.
Unit 3 Procedures During this inspection period a review of the licensee's progress in preparing procedures for the operation of Unit 3 was performed.
The reviewed focused on operations procedures, surveillance instructions, and the various categories of maintenance proce-dures.
Operations procedures are being developed/revised by the licensee's operations procedure group.
The starting point for Unit 3 operations procedures are the current Unit 2 operations procedures.
As design changes are implemented in Unit 3, the operations procedures will be revised to reflect the new plant conditions.
Unit 3 procedures to support the operation of Unit 2, such as the Unit 3 Diesel Generator OI, have been in place since the startup of Unit 2.
Current estimates are that approximately 25,000 man-hours will be required to complete the Unit 3 opera-tions procedures.
This number includes the development of the Emergency Operating Instructions and the Safe Shutdown Instruc-tions.
Unit 3 surveillance instructions are currently being developed by the licensee's Technical Support organization.
Like the opera-tions procedures, Unit 2 SIs are being used as a starting point for the Unit 3 SIs.
Procedure 3-SI-I, Surveillance Program, the procedure which defines the total scope of the Unit 3 surveillance requirements is also currently under development.
This procedure will reference each TS surveillance requirement and the specific procedure which satisfies these requirements.
Once this procedure has been developed, the scope of the remaining work to develop the
l
SI will be more clearly known.
Like the Unit 3 operations proce-dures, the program to develop the Unit 3 surveillance instructions is in its infancy.
Maintenance procedures for the support of Unit 3 operations are beyond the initial stages of development of the operations and surveillance procedures.
This is simply explained by the fact that a large portion of maintenance procedures are written to work on equipment that is not unit specific.
Therefore, procedures developed for the support of Unit 2 will also be used for the support of Unit 3.
The major effort remaining in the maintenance area is the development of the ILC procedures.
The majority of these procedures will be unit specific and developed as plant modifications are implemented.
Because the licensee has not yet issued a firm schedule for the restart of Unit 3, a schedule for Unit 3 procedures has not been developed.
As modifications are implemented in Unit 3, the inspectors will review the licensees supporting procedures as part of the restart inspection effort.
6.
Action on Previous Inspection Findings (92701, 92702)
a 0 (CLOSED) IFI 259, 260, 296/92-30-01, DG Turbocharger Failure.
On August 25, 1992, a mechanical failure of the 3A Diesel Genera-tor Turbocharger occurred during the final portion of SI-4.9.A. l.-
a(A24), "Diesel generator 3A 24 Hour Run."
The licensee initiated an incident investigation (II-B-92-063) to review the event and to determine the cause of the turbocharger failure.
The damaged turbocharger was removed and sent to END for disassembly and inspection.
END determined the cause of failure to be planetary bearing failure which caused a loss of concentricity in the gear train.
The loss of concentricity within the gear train caused an improper meshing of the associated turbocharger gears and a
failure of gear teeth.
The root cause of the bearings failure was not possible to deter-mine but similar failures have occurred due to improper lubrica-tion.
However, during disassembly of the turbocharger, lubricat-ing oil was evident on all bearing surfaces and all drilled oil passages appeared clear.
The licensee replaced the turbocharger and successfully tested the DG on September I, 1992.
Because no root cause for the turbo-charger failure could be determined, no additional corrective actions other than replacement of the turbocharger and the engines lubricating oil (due to foreign material from the gear failures)
were performed.
A design change to enhance the engines pre-lubricating system is under consideration for implementation as budgetary restraints permit.
Based on this review, this item is close Exit Interview (30703)
The inspection scope and findings were summarized on October 15, 1993, 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 260/93-36-01 URI, Containment Isolation Valve Improperly Installed, paragraph 4b.
Licensee management was informed that one IFI was closed.
Acronyms and Initialisms BTRD CCW CFR CRDR DCN OCR DG DP END EPRI FSAR I&C IFI JTG LCO LER LLRT NRC OI OSIL PRD QA QC SI SCFH RPS RTP SPOC SSP STH TS TVA WO Baseline Test Requirements Document Condenser Circulating Water Code of Federal of Regulations Control Room Design Review Design Change Notice Design Change Request Diesel Generator Differential Pressure Electro-Motive Division of General Hotors Electric Power Research Institute Final Safety Analysis Report Instrumentation and Controls Inspector Followup Item Joint Test Group Limiting Condition for Operation Licensee Event Report Local Leak Rate Test Nuclear Regulatory Commission Operating Instruction Operations Section Instruction Letter Problem Reporting Document Quality Assurance Quality Control Surveillance Instruction Standard Cubic Feet Per Hour Reactor Protection System Restart Test Program System Preoperability Checklist Site Standard Practice Star tup Test Manual Technical Specifications Tennessee Valley Authority Work Order