IR 05000259/1998007
| ML18039A654 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 12/09/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18039A651 | List: |
| References | |
| 50-259-98-07, 50-259-98-7, 50-260-98-07, 50-260-98-7, 50-296-98-07, 50-296-98-7, NUDOCS 9812240100 | |
| Download: ML18039A654 (45) | |
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License Nos:
50-259, 50-260, 50-296 DPR-33, DPR-52, DPR-68 Report Nos:
50-259/98-07, 50-260/98-07, 50-296/98-07 Licensee:
Tennessee Valley Authority Facility:
Browns Ferry Nuclear Plant, Units 1, 2, & 3 Location:
Corner of Shaw and Browns Ferry Roads Athens, AL 35611 Dates:
October 4 - November 14, 1998 Inspectors:
W. Smith, Senior Resident Inspector J. Starefos, Resident Inspector E. DiPaolo, Resident Inspector R. Carrion, Project Engineer (Section M8.8)
J. Blake, Senior Reactor Engineer (Section M1.3)
W. Bearden, Reactor Engineer (Section M1.4)
C. Smith, Reactor Engineer (Section E.1.1)
Approved by:
H. O. Christensen, Chief Reactor Projects Branch 6 Division of Reactor Projects 98i2240i00 98i209 PDR ADOCK 05000259'
PDR Enclosure 2
EXECUTIVESUMMARY Browns Ferry Nuclear Plant, Units 1, 2, 8 3 NRC Inspection Report 50-259/98-07, 50-260/98-07, 50-296/98-07 This integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support.
The report covers a 6-week period of resident inspection with assistance from a Project Engineer.
In addition, an Inservice Inspection, a Procurement.Inspection, and a review of the Maintenance Rule required periodic assessment were performed.
~oeratione The operators performed in a professional and conservative manner.
A strength was noted in the high quality of the control room logs (Section 01.1).
Subsequent to the completion of the Cycle 8 refueling outage, drywell housekeeping was excellent with a few minor exceptions which were promptly corrected (Section 01.1).
Licensed operators demonstrated a knowledge deficiency when they failed to implement the requirements of Technical Specification (TS) Limiting Condition for Operation 3.0.4.
The operators continued startup activities when TS Applicabilitystatements were in effect with inoperable equipment (Section 01.2).
Fuel movement prerequisites and observed activities were properly implemented during the Unit 3 refueling outage.
Refueling bridge personnel demonstrated good communications by performing fuel movement verifications in a consistent manner (Section 01.3).
Maintenance Work practices observed during the inspection period were professional and properly controlled. Workers were found to be knowledgeable of their assigned tasks.
The lead performer demonstrated exceptional knowledge of the construction and operation of the new Siemens vacuum type breaker during replacement activities on the Unit 1 4-kilovolt Unit Board (Section M1 ~1).
Surveillance test activities observed during the inspection period were conducted in a professional manner.
Good coordination was demonstrated between operations, engineering, and chemistry personnel by completing troubleshooting activities on an effluent radiation monitor expeditiously during Residual Heat Removal Service Water pump testing (Section M1.2).
Based on the sample of activities reviewed, the licensee's inservice inspection activities, including repairs and replacements, were being conducted in accordance with regulatory requirements and licensee commitments (Section M1.3).
The licensee's periodic assessment report provided sufficient detail to demonstrate that the licensee had adequately evaluated performance, condition monitoring, associated goals, and preventive maintenance activities for systems, structures, and components
within the scope of the Maintenance Rule. The licensee's,assessment met the requirements of NUMARC 93-01 and paragraph (a)(3) of 10 CFR 50.65 (Section M1.4).
Improper use of a volt-ohm meter (VOM) during Common Accident Signal Logic testing resulted in the unexpected actuation of the B3 Emergency Equipment Cooling Water pump. Additional deficiencies associated with the recommended use of the VOM were noted after testing was restarted following the actuation (Section M4.1).
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The surveillance procedure for functional testing of the Standby Gas Treatment System relative humidity flowswitch channels was inadequate to test the flow switch contacts in the relative humidity heater circuit (Section, M8.5).
~En ineerin Implementation of the procurement program was demonstrated to be in accordance with plant procedures (Section E1.1).
P Reviewed procurement engineering packages demonstrated that technical and quality requirements were imposed on the procurement documents in order to satisfy licensing and design basis requirements (Section E1.1,).
Plant Su ort Radiation protection of personnel was effectively implemented through the proper administration of the control point, and integrity of locked high radiation areas (Section R1.1).
Performance of security officers in safeguarding the facilitywas satisfactory in that they were attentive to their duties and cognizant of their surroundings (Section S1.1).
Re ort Details Summa of Plant Status Unit 1 remained in a tong-term lay-up condition with the reactor defueled.
Unit 2 operated at or near full power with the exception of scheduled maintenance down powers.
Unit 3 began this period with the unit shutdown for the Unit 3, Cycle 8 refueling outage.
On October 15, 1998, a reactor.startup commenced.
Following testing due to plant modifications and thermal power up rate, the unit achieved full steady state power on October 25, 1998. On November 8, 1998, operators reduced power to approximately 86%, per abnormal operating instructions, in response to an inadvertent low pressure feedwater heater isolation. The heater isolation was caused by a malfunctioning heater level float switch. The unit remained at or near full power with the exception of scheduled planned down powers for the remainder of the inspection period.
I. 0 erations
Conduct of Operations 01.1 General Comments 71707 Using Inspection Procedure 71707, the inspectors conducted reviews of ongoing plant operations by monitoring control room activities, touring the plant spaces, attending the Plan-of-the-Day meetings, and reviewing the control room logs. The inspectors noted that operations were being conducted in a professional and conservative manner, operators were attentive and responsive to plant alarms, and communications were carried out in a three-way manner.
Particularly noteworthy was the high quality of the control room logs which were informative and comprehensive.
On October 13, 1998, the inspectois performed a closeout inspection of the drywell with a focus on cleanliness.
At the time of the walkdown, the licensee had not yet released all elevations for closure due to remaining work activities in progress.
The cleanliness of the upper elevations was excellent; however, some areas in the lower elevations needed additional work. The inspectors verified that the core spray system manual maintenance valves were in the open position. Several items which needed attention were discussed with the licensee.
These items included insulation issues, drywell coating questions, and drywell seal corrosion. The licensee responded to the inspectors and addressed the safety concerns prior to restart.
Between October 10 and 25, 1998, the inspectors observed the startup and ascension'o full power on Unit 3 on a sampling basis.
The startup was conducted in an orderly, controlled manner, and the applicable procedures were utilized as intended.
However, the inspectors identified a problem with Technical Specification (TS) compliance, which is discussed in Section 01.2. The operators responded well to the minor problems that typically occurred during a startup following a refueling outag Failure to Cpm I withLimitin ConditionforO eration LCO 3.0.4forHi hPressure Coolant ln'ection HPCI S stem 0 erabilit Ins ection Sco e 71707 Based on a control room log entry, the inspector questioned the operator's determination that the HPCI system was in a 14-day LCO when conditions were met that required the system to be operable during the startup from the Unit 3 refueling outag'e.
Observations and Findin s On October 15, 1998, while reviewing the Unit 3 control room logs, the inspector noted a log entry that indicated that the requirement for the HPCI system to be operable during plant startup was applicable.
At that time, an associated LCO action statement was entered due to the HPCI system being inoperable for maintenance.
The system remained inoperable due to maintenance for approximately one additional hour. TS LCO 3.0.4 states, in part, that when an LCO is not met, entry into a MODE or other specified condition in the Applicabilityshall not be made except when the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicabilityfor an unlimited period of time. In this case, increasing pressure above the 150 pounds per square inch gage (psig) Applicabilitythreshold should not have been performed with the HPCI system inoperable.
The inspector discussed the concern with Operations management.
Further inspection, using the integrated computer system, was performed to determine whether the operators held pressure at the threshold for HPCI system operability until the maintenance was complete.
The inspectors found that the threshold for the HPCI system operability '(>150 psig Reactor Steam Dome Pressure) was reached at the approximate time of the log entry and pressure was increased over the next hour. At the time that the HPCI system was returned to an operable condition, the reactor steam dome pressure was above 300 psig.
'S 3.5.1, Emergency Core Cooling System (ECCS) Operating, is applicable in Mode 1 and Modes 2 and 3, except HPCI is not required to be operable with reactor steam dome pressure ~150 psig. When reactor steam dome pressure reached 150 psig, the operator made a log entry that stated that the reactor was at 150 psig pressure and the HPCI system was still inoperable due to power being secured to HPCI steam admission valve (3-FCV-73-16) for maintenance activities. A 14-day action statement to restore the HPCI system to operable status was entered at that time. The licensee failed to meet TS 3.0.4 when reactor pressure exceeded 150 psig without meeting LCO 3.5.1.
This is identified as Violation (VIO) 50-296/98-07-01, Failure to Comply with LCO 3.0.4 for HPCI System Operability.
The licensee initiated Problem Evaluation Report (PER) 98-011475-000.
The licensee also identified a second example that did not meet the requirements of TS 3.0 4 when the reactor was placed in Mode 1 (Run) while a surveillance procedure was in progress which procedurally required the HPCI system to be declared inoperable.
Immediate
corrective actions included documentation of the occurrence in the Operations Daily Instructions that also provided other specified conditions for the operators to be aware of. Planned corrective actions included:
(1) the Operations Training department to provide additional training for operations personnel on Section 3.0 and bases of the TS; (2) the Operations Support group to review and revise appropriate procedures to enhance references to requirements necessary prior to unit condition or mode changes during unit startup/shutdowns; (3) the scheduling department to review and coordinate necessary measures to ensure that system maintenance or testing is not scheduled during any startup or shutdown which would cause a conflict with TS requirements; and (4) the Operations Manager willdiscuss this PER with each crew.
The inspector concluded that information regarding the reason for the violation, and the corrective actions taken and planned to correct the violation and prevent recurrence was adequately addressed.
Conclusions Licensed operators demonstrated a knowledge deficiency when they failed to implement the requirements of TS Limiting Condition for Operation 3.0.4. The operators continued startup activities when TS Applicabilitystatements were in effect with inoperable equipment.
Unit 3 Refuelin Outa e Observations Ins ection Sco e 71707 The inspector observed portions of fuel movement during the Unit 3 refueling outage.
Observations and Findin s On October 6, 1998, the inspector reviewed fuel movement prerequisites and observed refueling floor operations.
Drywell access controls were in place in accordance with the procedure.
The inspector observed that a control room reactor operator and the refueling floor reactor engineer were properly monitoring source range nuclear instrumentation.
Refueling bridge personnel performing the fuel movement demonstrated good communications.
First and second party verifications of the fuel movements were performed in a consistent manner.
A minor issue was identified concerning the documentation of the verifications on the working copy of the fuel assembly transfer forms. This was promptly corrected by the refueling floor senior reactor operator.
Conclusions Fuel movement prerequisites and observed activities were properly implemented during the Unit 3 refueling outage.
Refueling bridge personnel demonstrated good communications by performing fuel movement verifications in a consistent manne Miscellaneous Operations Issues (92901)
08.1 Closed VIO 50-259 260 296/98-02-01, Failure to Meet Minimum Shift Crew Requirements.
The licensed operator activation and reactivation processes were not correctly implemented as required by 10 CFR 55.53(e) and (f), respectively.
Consequently, operators that were certified by the licensee as holding an active license were performing the duties of licensed operators when, in fact, the operators had not met the minimum number of hours per quarter actively performing the duties of licensed operators (or under instruction). There were several instances where these operators were fulfillingthe minimum shift crew requirements of TS 6.2.2.a.
08.2 The licensee promptly removed the operators identified as not having valid active licenses from the watch list. On April 13, 1998, the licensee issued Operations Section Instruction Letter (OSIL) 105, Requirement for Maintaining Active License Status, and OSIL-106, Requirements for Returning an Inactive License to Active Status.
The inspector reviewed both documents and found them to properly implement the requirements of 10 CFR 55.53(e) and (f), respectively.
Operations management reinforced operator awareness though discussions and inclusion in the Night Orders.
The inspector noted that the operators were logging their performance as operators as defined and required by OSIL-105. By review of the records, the inspector found that the licensee retained comprehensive documentation of operator reactivation, as required by OSIL-106. Through interviews, the inspector gained adequate confidence that each licensed operator Understood the requirements, felt accountable for maintaining his license in an active status unless otherwise directed by management, and that the operators had the necessary tools available to them to ensure that the regulatory activation/reactivation requirements would be met. The inspector concluded that the licensee's corrective actions were appropriately completed.
This violation is closed.
Closed Ins ection Followu Item IFI 50-259/97-03-05, UnitOne FuelPoolMakeup Valve Operator Removed.
On March 25, 1997, the inspector identified that the Unit 1 fuel pool makeup valve (1-FCV-78-61) operator from the Residual Heat Removal (RHR)
system was removed.
The licensee's procedures provide direction for realignment of RHR/Residual Heat Removal Service Water (RHRSW) for makeup to the" Spent Fuel Pool using this valve. At the time that the issue was identified, the licensee demonstrated that the valve'could be opened locally using manual means and thereby provide a path for makeup from RHRSW. The post-maintenance testing of the replacement valve operator for valve 1-FCV-78-61 was completed on November 6, 1997. The licensee's PER further identified that both stroke timing and position verification is performed for the comparable Unit 2 and 3 valves as part of the American Society of Mechanical Engineers (ASME)Section XI program. This testing was not performed on the Unit 1 valve. The licensee developed testing procedures and implemented the procedures on November 6, 1997. The valve was declared operable on November 12, 1997. This inspection followup item is close II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Ins ection Sco e 62707 The inspectors observed portions of the following work activities Unit 2 C RHR punip motor trim balancing Unit 3 electro-hydraulic control pump discharge filter0-ring replacement Unit 1 4-kilovolt (kV) unit board 1C normal feeder breaker replacement Unit 3 preparations for Integrated Leak Rate Testing b.
Observations and Findin s The inspector found the work practices observed during the inspection period to be thorough and professional.
Workers were found to be knowledgeable of their assigned tasks.
Radiological work practices were in conformance with established requirements.
Good support from engineering personnel was observed.
On October 10, 1998, the inspector observed preparations for the Integrated Leak Rate Testing. The inspector observed as maintenance technicians removed relays from cabinets in the auxiliary instrument room. A Senior Reactor Operator (SRO) ensured that work was performed in a careful and controlled manner.
On October 10, 1998, the inspector observed the replacement of the Unit 1 4-kV Unit Board 1C normal feeder breaker.
The licensee had been in the process of replacing the existing General Electric type Magne-Blast breakers with new Siemens vacuum type breakers.
Maintenance personnel were aware of previous issues concerning physical clearances between the breakers and breaker. compartment components.
The lead performer of the maintenance crew demonstrated exceptional knowledge of the construction and operation of the replacement breaker through discussions with the inspector.
c.
Conclusions Work practices observed during the inspection period were professional and properly controlled. Workers were found to be knowledgeable of their assigned tasks.
The lead performer demonstrated exceptional knowledge of the construction and operation of the new Siemens vacuum type breaker during replacement activities on Unit 1 4-kV Unit Boar M1.2 Surveillance Observations a.
Ins ection Sco e 61726 71707
'E The inspector observed all or portions of the following surveillance tests:
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3-SR-3.8.1.1(3B) Diesel Generator 3B Monthly Operability Test
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2-SI-4.5.C.1(3) RHRSW Pump and Header Operability and Flow Test b.
Observations and Findin s The surveillance tests observed were performed in a controlled and professional manner.
Communications were clear and good self checking techniques were observed.
The inspector observed troubleshooting activities on 2-RM-90-134D (loop II RHRSW discharge radiation monitor) during 2-SI-4.5.C.1(3).
Good coordination was demonstrated between operations, engineering, and chemistry personnel which allowed troubleshooting activities to be completed expeditiously.
In addition, the inspectors reviewed the licensee's criteria for removing the C1 and D2 RHRSW pumps from increased inservice test frequency.
No problems were noted.
c.
Conclusions Surveillance test activities observed during the inspection period were conducted in a professional manner.
Good coordination was demonstrated between operations, engineering, and chemistry personnel by completing troubleshooting activities on an effluent radiation monitor expeditiously during RHRSW pump testing.
M1.3 Unit 3 Inservice Ins ection ISI a.
Ins ection Sco e 73753 The inspector observed Unit 3 ISI activities and reviewed completed inspection, analysis, and repair-and-replacement documentation.
b.
Observations and Findin s Browns Ferry Unit 3 was in the first period of the second ISI inspection interval for piping and components and the first period of the first ISI inspection interval for the containment.
The ASME Code of record for piping and component ISI activities was ASME Section XI, 1989 Edition with no addenda, and the ASME Code of record for the containment ISI activities was ASME Section XI, Subsection IWE, 1992 Edition with the 1992 Addenda.
The inspector reviewed portions of the following ISI activity:
Reactor Vessel Internals:
Core Shroud weld inspections and analyses.
The licensee conducted visual and ultrasonic examinations of the Core Shroud welds in accordance with the "BWR Vessel and Internals Project Guidelines for Reinspection of BWR Core
Shrouds (BWRVIP-07)." The inspectors reviewed selected portions of the inspection data and discussed the scope and results of the inspections with the licensee.
The inspector agreed with the licensee's interpretation of the inspection data, and the assessment of the condition of the core shroud.
Reactor Vessel Internals:
Replacement of Core Spray Piping. The inspector reviewed portions of the remote visual inspection documentation for the replacement section of core spray piping inside the Unit 3 Reactor Vessel.
The piping replacement was conducted in accordance with the licensee's Design Change Notice, DCN T40683A.
Based on a review of inspection documentation digital pictures and discussions with licensee representatives, the inspector concluded that the replacement piping assembly had been properly installed in accordance with DCN T40683A.
ISI of containment.
The licensee's program for ISI inspection of the steel containment vessel (SCV) identified several potential areas for augmented inspection.
One area of interest was the Drywell SCV at the Sand Bed Region, which is subject to moisture intrusion from leaking penetrations or from the refueling cavity through bellows leakage during refueling. This area is inaccessible for visual inspection from the outside surface.
Selected areas of the Drywell SCV were ultrasonically examined for thickness in 1987 in response to NRC Generic Letter (GL) 87-05, "Request for Additional Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells." While earlier inspections showed no evidence of wall thinning, there had been documented incidents of water leaking from the sand bed drains since those 1987 inspections.
The inspector reviewed the documentation for the ultrasonic testing (UT) thickness measurements that were conducted on the accessible areas of the Drywell SCV at the Sand Bed Region. 'Based on a review of the data, and a partial visual examination of the accessibility of the areas to be inspected, the inspector agreed that the UT inspection showed no indications of significant corrosion in the Sand Bed Region of the Drywell SCV.
During the NUREG 0313 (GL 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping" ) UT inspection of Recirculation Loop system piping, an intergranular stress corrosion cracking (IGSCC) indication was found in the heat-affected zone (HAZ) of weld GR-3-63. Weld GR-3-63 is located in the 28-inch diameter piping of the "B" Recirculation Loop system piping. The indication exceeded the flaw size acceptable by ASME Section XI, therefore, in accordance with GL 88-01, the licensee's evaluation of the flaw had to be approved by NRC prior to resumption of operations.
The inspector reviewed the data for weld GR-3-63, as well as other welds in the Recirculation Loop system piping. Based on this review, the inspector agreed that the flaw in weld GR-3-63 was properly characterized in the licensee's October 5, 1998, request for NRC review of the flaw evaluation.
(On October 9, 1998, the NRC provided a response that approved the licensee's flaw evaluation, with the condition that TVA review the 1984 Induction Heating Stress Improvement (IHSI) data, and reinspect the weld during the next refueling outage.)
Conclusions Based on the sample of activities reviewed, the licensee's inservice inspection activities, including repairs and replacements, were being conducted in accordance with regulatory requirements and licensee commitments.
Maintenance Rule Periodic Evaluation 62706 Ins ection Sco e
Paragraph (a)(3) of the Maintenance Rule, 10 CFR 50.65, requires that performance and condition monitoring activities and associated goals and preventive maintenance activities be evaluated taking into account, where practical, industry-wide operating experience.
This evaluation was required to be performed at least one time during each refueling cycle, not to exceed 24 months between evaluations.
The inspector reviewed the licensee's completed periodic assessment to verify that it met the requirements of 10 CFR 50.65, paragraph (a)(3).
Observations and Findin s At the time of the Maintenance Rule inspection, during April 1997, the licensee had not completed its first periodic evaluation.
The inspector reviewed the licensee's completed Maintenance Rule Periodic Assessment, dated July 7, 1998. This first periodic assessment covered the period from July 10, 1996, until March 31, 1998. The licensee's periodic assessment report consisted of a higher level summary report which summarized individual system engineer quarterly system assessment reports rather than a single comprehehsive evaluation report. This method was an option allowed by NUMARC 93-01, Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2. The periodic assessment also documented balancing between unavailability and reliabilityfor risk-significant systems, structures, and components (SSCs), as required by paragraph (a)(3) of the Maintenance Rule.
The periodic assessment was conducted in accordance with Section 3.11, "Performance Reporting," of TVA's Standard Programs and Processes, SPP-6.6, "Maintenance Rule Performance Indicator Monitoring, Trending and reporting." The inspector determined that the licensee's assessment satisfied the requirements of 10 CFR 50.65 and NUMARC 93-01, Revision'2. The use of industry operating experience was verified as being well integrated with system engineering, scoping, reviews of functional failures, and cause determinations.
The inspector was informed that the next periodic assessment is scheduled for March 1999. The licensee intended to perform a new periodic assessment on an annual basis not to exceed 24 months between assessments to meet Maintenance Rule requirements.
Conclusions The licensee's periodic assessment report provided sufficient detail to demonstrate that the licensee had adequately evaluated performance, condition monitoring, associated
goals, and preventive maintenance activities for SSCs within the scope of the Maintenance Rule. The licensee's assessment met the requirements of NUMARC 93-01 and paragraph (a)(3) of 10 CFR 50.65.
Maintenance Staff Knowledge and Performance Com onent Actuation Caused b
Im ro er im lementation of Procedure Ins ection Sco e 62707 The inspector observed portions of the Common Accident Signal Logic testing for Unit 2 following problems experienced earlier during testing. The licensee experienced a start of the B3 Emergency Equipment Cooling Water (EECW) pump early during the testing due to a personnel error.
Observations and Findin s On October 28, 1998, the licensee experienced an unexpected start of the B3 EECW pump while performing Surveillance Test O-SR-3.8.1.6, Common A'ccident Signal Logic.
The licensee determined that steps which checked for a lack of continuity were implemented incorrectly. A short circuit was presented across open contacts which actuated the B3 pump. To verify relay contact position (by continuity check), Step 3.16 of the precautions and limitations of the surveillance procedure recommended that a voltage check should be performed first. If voltage was not present, the procedure then directed the technician to check resistance across the contacts.
The electrical technician apparently did not reset the volt-ohm meter (VOM) to voltage before.
beginning the next set of contacts after measuring resistance on the previous set of contacts.
The relay that was being tested was energized to one side of the open contacts.
When the relay contacts were bridged with the VOM set on ohms, the energized circuit was completed and the B3 EECW pump started.
The test was halted to investigate the cause and correct the condition.
Following an investigation, a briefing was performed and the surveillance procedure was restarted.
The inspector observed the first step following the restart of the procedure which tested for lack of continuity across a set of contacts.
The inspector observed the step being performed and noted that the steps performed did not appear to match the description in Precautions and Limitations Section 3.16 of the procedure.
The inspector questioned the electrical technician as to how the meter was zeroed.
The technician, indicated that it was not zeroed between the voltage and continuity check.
The inspector was concerned that Precautions and Limitations 3.16 recommendation was not followed as written in view of the earlier event. The inspector discussed the observation with the Operations Superintendent.
The surveillance test was again stopped.
PER 98-012725-000 was written to document both problems.
Recent issues with the training of maintenance personnel on the use of testing equipment was previously identified in NRC IFI 260,296/98-04-02, Use of Maintenance and Test Equipment.
This VOM issue was of concern to the inspectors because the
procedural guidance for performing continuity checks did not appear to be consistent with "skillof the craft" training, based upon discussions with the licensee.
The licensee identified the root cause to be failure of the technician to meet expectations.
The inspectors reviewed corrective actions taken and planned to prevent recurrence.
Licensee actions included:
(1) conducting briefings with maintenance personnel on lessons learned from this problem; (2) developing and implementing annual training on the proper use of measuring and test equipment, including VOMs; and (3) counseling of the individuals involved with this problem. The inspector considered these actions to be adequate to prevent a recurrence.
Failure to properly implement O-SR-3.8.1.6 and thus prevent unexpected events such as the above start of the B3 EECW pump is a violation of TS 5.4.1.a, which requires written procedures to be implemented covering TS surveillance activities. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy and is identified as NCV 50-296/98-07-03, Failure to Properly Im'plement Common Accident Signal Logic Test.
C.
Conclusions Improper use of a VOM during Common Accident Signal Logic testing resulted in the-unexpected actuation of the B3 EECW pump. Additional deficiencies associated with the recommended use of the VOM were noted after testing was restarted following the actuation.
M8 Miscellaneous Maintenance Issues (62707, 92902)
M8.1 Closed VIO 50-259 260 296/98-02-02, Failure to Follow High Efficiency Particulate Air Filter Testing Procedures.
The model of the Dioctylphthalate (DOP) generator used fortesting the Standby Gas Treatment (SBGT) and Control Room Emergency Ventilation (CREV) systems was not equivalent to the model required by system testing procedures.
System retesting was completed satisfactorily. The cause and corrective actions were submitted in the licensee's response letter to the violation, dated June 4, 1998. The inspector verified that the licensee's corrective actions were completed.
This violation is closed.
M8.2 Closed VIO 50-259 260 296/98-02-03, Inadequate Testing of Downstream Standby Gas Treatment HEPA Filter. The surveillance procedure did not incorporate the results of an air-aerosol mixing uniformity test in accordance with American National Standards Institute, Inc (ANSI) N510-1975.
As stated in the licensee's response letter, dated June 4, 1998, the licensee performed a DOP distribution test and in-place filter leakage conforming to ANSI N510-1975 on the high efficiency particulate air (HEPA) filters for the three trains of SBGT.
In addition, the licensee performed training for appropriate engineering personnel in filtertesting. The inspector verified that the revised test instructions for the SBGT system incorporated the requirements of ANSI N510-1975.
This violation is close Closed Licensee Event Re ort LER 50-259/1998-001-00and50-259/1998-001-01, Standby Gas Treatment System HEPA Filter Testing Not In Compliance With ANSI Standard Requirements.
The description of this event was originally discussed in NRC Inspection Report 50-259, 260/98-02 and resulted in VIO 50-259, 260, 296/98-02-03.
See closeout of the violation in Section M8.2. In addition, the licensee found that the Containment Purge System HEPA filters had not been tested in accordance with the DOP mixing and uniformity criteria of ANSI N510-1975, as required by TS. Revision (Rev.) 01 of the LER reported the results of Containment Purge System HEPA filter DOP air-aerosol mixing tests that the licensee performed.
The causes and corrective actions for the inadequate testing of the Containment Purge System were similar to those of the Standby Gas Treatment System.
This violation constitutes an additional example of VIO 50-259, 260, 296/98-02-03 and is not being cited individually. No additional response to VIO 50-259, 260, 296/98-02-03 is required.
The inspector verified that the actions and commitments made by the licensee were adequate to ensure that the SBGT and Containment Purge systems willbe tested in accordance with ANSI N510-1975. This Licensee Event Report is closed.
Closed LER 50-259/1998-002-00, Inadequate Surveillance Instruction for Calibration of the SGT Train B Relative Humidity Control Heater Flow Switches.
The licensee determined that the flowswitch calibration test did not ensure calibration of both instrument channels, as required by TS. The inspector reviewed the licensee's findings and corrective actions in closeout of Unresolved Item (URI) 260, 296/98-03-02 (See Section M8.5). Apparent violation (EEI) 50-259, 260, 296/98-07-02 was identified concerning the adequacy of functional testing of relative humidity flowswitch contacts.
This Licensee Event Report is closed.
Closed Unresolved Item URI 260 296/98-03-02, Standby Gas Treatment System Flow Switch Testing Issues.
The flowswitch instrument channels operate the relative humidity heaters.
The heaters are required to ensure proper functioning of the charcoal absorbers during a design basis event. The calibration test method consisted of adjusting the SBGT filtertrain suction damper and measuring the air flow rate at which the relative humidity heaters operate.
During a previous observation of a SBGT System relative humidity heater flow switch calibration, several issues were identified. The test required calibration of the flow switches only if the "as found" flow rate was not within the acceptance criteria when the heaters operated.
During testing, the licensee identified that because the associated relay contacts for the two flow switch channels were in parallel, the testing methodology used was not adequate to ensure that both instrument channels were within the acceptance criteria. The inspector noted other problems with flow rate adjustments and flow measurements that required additional review. For example, flow rate measurements appeared to vary and may have been due to test equipment accuracies and/or the methods used to adjust system flow. Additional review was also required regarding the licensee's actions in response to NRC Generic Letter (GL) 96-01, Testing of Safety-Related Circuits. The licensee's handling of the SBGT flow switch circuitry during the GL 96-01 review was unclear.
In the licensee's response letter to GL 96-01, dated April 18, 1996, the licensee committed to perform the requested actions in conjunction with the conversion to the
II
'
Improved Technical Specifications (ITS). This required the review of actuation logic for engineered safety features systems against plant surveillance test procedures to ensure that all portions of the logic circuitry were adequately tested to fulfillthe TS requirements.
The 'conversion to the ITS moved the requirements to calibrate and functionally test the heater flow switch channels out of the ITS and into a licensee controlled document (i.e., the Technical Requirements Manual). Therefore, the licensee did not perform the actions requested by GL 96-01 on the heater flowswitch channels.
The inspector reviewed the ITS testing requirements and concluded that review of the heater flow switch circuitry was not within the scope of the licensee's review commitment for GL 96-01.
The licensee found that the inconsistent flow rate measurements during SBGT testing was the result of manipulating the inlet damper in a manner that would not produce optimal test results.
Due to the low system flows and the sensitivity of the flow measurement equipment used during testing, small increments of damper movement followed by a waiting period (approximately 40 seconds) for flows to stabilize was necessary.
The procedure used for testing only stated that the damper should be closed slowly. This resulted in overshooting the setpoint of the flow switches and inconsistent flow measurement results.
Flow rate testing was subsequently reperformed using small damper movements.
Testing in this manner produced consistent results.
The licensee revised the procedure to clearly communicate the necessity of small damper movements followed by a waiting period for system flow and flow detector stabilization.
In addition, the licensee has ongoing corrective actions to improve the test methodology for the flowswitch calibration. The licensee was in the process of performing extensive system testing with the goal of revising the flow switch calibration procedure to not require throttling system flowwith the inlet damper.
This has the potential to reduce performance time of the surveillance and maintain the system operable during the calibration.
During the testing, the licensee identified that the flow switch calibration test did not ensure calibration of both instrument channels, as required by TS. Test methodology monitored the flow switch operation by determining flowwhen the relative humidity heaters turned off. However, because the contacts in the relative humidity heater circuit for the two flow switch channels were in parallel, only the data from the flowswitch with the lowest "as found" setpoint was compared to acceptance criteria. Following review of previous test data, the licensee determined that the flow switch channels for the B train of SBGT had not been calibrated within their required frequency.
The licensee
~ submitted LER 50-259/1998-002-00, Inadequate Surveillance Instruction for Calibration of Standby Gas Treatment Relative Humidity Control Heater Flow Switches.
The inspector reviewed the revised test methodology and found that the test procedure adequately performs calibrations of both flow switch channels.
The inspector found that the other licensee corrective actions were appropriate.
No further issues were revealed by the LER.
In reviewing the licensee's corrective actions for the SBGT flow switch calibration, the inspector reviewed O-SI-4.2.A-12, Standby Gas Treatment Blower and Heater Logic Functional Test, Rev. 21. This surveillance contains procedural steps for performing functional testing on the relative humidity flow switch channels.
The inspector identified that the functional check did not adequately test the flowswitch contacts in the relative
Cl
humidity heater circuit. Because the heater flow switch contacts are in parallel in the heater circuit, the test procedure checked functioning of the flow switch by checking that the flow switch relay energized when the SBGT train was operating.
The surveillance instruction verified actuation of the relative humidity flow switch relay by verifying continuity across a pair of unused contacts and verifying that the heater operates when the SBGT system is in operation.
However, because the flowswitch contacts for the two channels were in parallel in the heater circuit, this method was insufficient to ensure that each of the parallel contacts functioned properly. The licensee was informed of the inspector's findings.
The licensee entered Technical Requirements Manual (TRM) LCO 3.0.3. This allows a 24-hour delay, to allow performance of the required test, prior to entering the actions required by the TRM. The licensee subsequently performed the required test on the relative humidity flow switch contacts by the use of a work order. Contact testing was performed satisfactorily and TRM LCO 3.0.3 was exited. The inspector verified that the testing performed was adequate to ensure that the functional testing requirements were met.
The procedures used to perform functional testing of SBGT flow switch channels did not adequately test the contacts used to actuate the SBGT relative humidity'heaters.
This is an apparent violation of TS 5.4.1.a, which requires written procedures to be established, implemented, and maintained for SBGT test procedures.
This issue is identified as apparent violation EEI 50-259, 260, 296/98-07-02, Inadequate Standby Gas Treatment Heater Flow Switch Logic Functional Test, pending review of the licensee's corrective actions.
The inspector found that the scope of the licensee's corrective actions for LER 50-259/1998-002-00 could not have reasonably prevented this apparent violation. This unresolved item is closed.
Closed IFI 50-260/95-41-01, EDG Turbocharger Inspection.
This item was opened pending further review of licensee actions associated with the failure of the 1C Emergency Diesel Generator (EDG) turbocharger in January 1995. The licensee had originally reported the event under LER 50-260/95-01, as required by 10 CFR 50.73 (a)(2)(i);
The inspector reviewed LER 50-260/95-01, along with various licensee laboratory failure evaluation reports, vendor documentation, and the licensee's technical operability report, dated December 23, 1996. A previous failure of the 3A EDG turbocharger had occurred under similar circumstances during August 1992.
In each case, the failure had resulted due to fatigue failure of the turbocharger planetary gears.
Although the licensee and the vendor were unable to reach agreement concerning the actual root cause of these'failures,= the licensee had taken adequate actions to prevent recurrence of this type failure. As corrective actions, the licensee conducted extensive research of other industry turbocharger failures, performed failure analysis of the failed turbocharger components, conducted metallurgical evaluation of a new set of replacement gears, implemented improvements for vibration monitoring of the turbocharger shafts for all eight EDGs, and performed a disassembly inspection of the turbocharger on an operating EDG. In addition, the inspector was informed that the licensee planned to implement a vendor-recommended design change to improve lubrication to the turbocharger during engine startin The inspector reviewed the results of the licensee's inspection of the 1B EDG turbocharger.
The licensee had decided to perform a disassembly inspection of the 1B EDG turbocharger due to higher operating hours and relatively higher turbocharger vibration readings on this engine.
The planetary gear system and turbocharger rotating assembly for that engine was removed and examined by the TVACentral Laboratory.
No anomalies were discovered during this inspection.
The inspector discussed the licensee's vibration monitoring program for the EDGs with the assigned system engineer.
As the result of the failure of the 1C EDG turbocharger, the licensee had implemented a program which specifically required monitoring of turbocharger shaft vibration during engine operation.
Conservative criteria for allowable vibration had been established based on industry and vendor information. The inspector concluded that the licensee's decision to establish specific criteria for turbocharger shaft vibration was appropriate and should allow the licensee to correct problems with turbocharger performance during operation of the engine prior to an actual failure.
Based on this inspection, the inspector determined that the licensee's corrective actions were adequate.
This inspection followup item is closed.
Closed IFI 260 296/97-08-05, Materials Upgrade Project. This item was opened pending further review of licensee actions associated with the use of an incorrect oil in the 1A and 1D EDGs between February and July 1997. The original oil specified for these engines had been ARGO/Lyondell Gascon Supreme Plus oil, which the licensee had procured under TVA Item Identification Code (TIIC) BXH934T. An incorrect note had been placed in the Integrated TVA Materials System (ITMS) database by Corporate Procurement Engineering Group (PEG) personnel in February 1996 which specified the use of Mobil DELVAC 1240 oil procured under TIIC CAQ060B for future use in the EDGs. Corporate PEG personnel subsequently attempted to correct this error with another note in ITMS during March 1996 which specified use of Mobilgard 450 (zinc-free) oil procured under TIIC CAT128N which met the same requirements as the oil originally used in the engines.
However, site PEG personnel had added subsequent notes in ITMS during August 1996 and January 1997 which again specified the incorrect oil. Mobil DEVAC 1240 oil was not appropriate in that oil containing zinc additives could, over a period of time, result in damage to the EDG bearings which contain silver. The initial incorrect note in the ITMS database had been added by the Corporate PEG during an ongoing effort to reduce the number of vendors and TIICs for materials, including lubrication products.
This error resulted in the addition of the incorrect oil in the 1A EDG during February 1997 and in the 1D EDG during July 1997. The high zinc content in the 1A EDG was subsequently detected in lube oil samples sent for routine analysis at the TVACentral Laboratory.
However, delays in processing and reporting of the sample results to the site had resulted in failure to identify the problem prior to July 1997.
The licensee subsequently determined that the problem had'been caused by the failure by maintenance planning personnel to follow requirements of TVAStandard (STD) 10.5, Technical Evaluation of Materials and Services, for ensuring that correct material was used during maintenance activities. Although the presence of incorrect TIIC information in the ITMS database had been a contributing factor, the planners should have verified the correct material by use of other approved sources, such as vendor manuals.
The licensee had originally documented the use of incorrect oil under PER BFPER971 078.
The licensee subsequently decided to add the equipment component performance and
testing deficiency to existing PER BF970563 and Corporate PER CHPER970050 was issued to address the improper control of TIIC information.
The inspector held discussions with the assigned system engineer and site PEG personnel.
In addition, the inspector reviewed PERs BFPER971078, BFPER0563, and CHPER970050 and determined that corrective actions should preclude recurrence of this problem.
Licensee immediate corrective actions included flushing the crankcases and adding correct oil to the affected engines.
In addition, the periodicy of oil samples was temporarily increased to weekly until the licensee was able to show that the zinc content of the oil in the affected engines remained within acceptable levels.
EDG 1A, 1B, 1C, and 1D oil samples taken July 14, 1997, indicated <1 part per million (ppm)
silver, which indicated that no significant degradation had occurred.
Subsequent engine oil samples did not show any abnormal silver levels.
Improvements in communications between the TVA's Central Laboratory and site engineering personnel have occurred which should prevent similar delays in processing and reporting of future sample results.
Maintenance Instruction, MPI -0-082-INS003, Emergency Diesel Generator Maintenance, was revised to specify the use of Mobilgard 450 lube oil in the engines of all EDGs. The site provided additional training to planners on use of additional information other than ITMS to specify replacement materials.
Corporate PEG personnel removed the erroneous notes for TIIC BXH934T in ITMS database.
A review of lubrication TIICs performed by Corporate PEG personnel and no additional TIIC errors were identified.
The inspector also reviewed the Procurement Data Sheets and Technical Evaluation Reports for TIICs BXH934T, CAQ060B, and CAT128N and compared each TIIC to the specific application.
No deficiencies were identified during that review.
In addition, the inspector noted that recent changes to TVA's procurement program should provide better controls for the future use of TIIC information. Based on this inspection, the inspector determined that the licensee's corrective actions were adequate.
This.
inspection followup item is closed.
0 en IFI 296/96-08-03, Unit 3 Main Steam Isolation Valve (MSIV) Circuitry Failures.
The grounding of circuitry associated with the Unit 3 MSIV position limitswitches was originally identified in January 1996.
(Refer to Section 3.2 of Report Inspection 50-259, 290, 290/96-05.)
Subsequently, this issue became an IFI in Report Inspection 50-259, 290, 290/96-08 and was last reviewed in Section M8.4 of Inspection Report 50-259, 290, 290/97-09.
By that time, the licensee had traced'the problem to damaged insulation on conductors in Conax conduit assemblies.
The damage resulted from a failure to install heat-shrink polyolefin tubing on the inboard conductors.
The licensee determined that 69 such seals exist in Unit 3 and had selected a ten percent sample (seven seals) to inspect during the Unit 3 outage of Fall 1998 to determine if heat-shrink polyolefin tubing was applied to the inboard conductors and determine the condition of the level switch leads.
However, due to scheduling/ communications oversights, only one of the seven of the identified sample population was inspected during the outage.
The licensee realized the error and had scheduled the remaining six to be inspected by the end of January 1999. At the conclusion of the sample inspection, the licensee planned to evaluate the need to install the insulation to the conductors.
(The inspectors noted that a similar problem did not exist on Unit 2. A licensee inspection of that unit determined that the similar circuitry was insulated and showed no signs of shorting.) Therefore, this
'6 IFI remains open, pending licensee completion of its Unit 3 inspection, evaluation of its findings, and corrective action implementation (if required).
III. En ineerin E1 Conduct of Engineering E1.1 Procurement Pro ram 38701 37551 a.
Ins ection Sco e
The inspector performed a review of the nuclear procurement program, TVANuclear Quality Assurance Plan, TVA-NQA-PLN89A,Rev. 8, Section 8.0, and its implementation in.order to verify that procurement activities for safety-related items were in conformance with regulatory requirements, licensee's commitments, and industry codes and standards.
b.
Observations and Findin s The following plant procedures were reviewed in order to verify compliance with regulatory requirements and licensee's commitments:
~
Procedure NEDP-8, Technical Evaluations for Procurement of Materials and Services, Rev. 1.
~
Standard Program and Processes SPP-4.1, Procurement of Material, Labor and Services, Rev. 0.
~
Procedure QAP-4.0, Reporting of 10 CFR 21, Rev. 9
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Procedure QAP-5.0, Identifying, Reporting and Correcting Deviations, Rev. 10 Based on the above reviews, the inspector determined that the licensee had developed a nuclear procurement program that satisfied regulatory requirements and licensee commitments.
The PEG used an automated procurement engineering data system (APEDS)
application software in the development of procurement engineering outputs.
The APEDS 3.3 system application software receives procurement process inputs and provides capability for the PEG engineers to accomplish the following:
~
Perform technical evaluations and process those inputs with the defined data base structure.
Provide for electronic interfaces to address customer needs and support the procurement engineering evaluation proces Provides outputs necessary to support the design engineering, procurement, administration, receipt inspection, and configuration management requirements of the TVAprocurement process.
The licensee has implemented a software verification and validation plan for the APEDS application software.
In addition, a software quality assurance plan was developed and implemented to define the steps and control the quality of the new development and ongoing maintenance of the APEDS application software.
In response to the Year 2000 (Y2K) problems described in NRC Generic Letter No. 98-01, Year 2000 Readiness of Computer Systems at Nuclear Power Plants, the licensee completed testing on September 25, 1998, for the APEDS application software, including the Bill of Material (BOM) Enhancement.
Based on these initial tests, the software was determined to be Y2Kcompliant. The inspector concluded that the licensee was adequately addressing the Y2K problems committed to in their letter to the NRC dated July 22, 1998.
The licensee's implementation of the procurement program was evaluated by review of objective evidence which demonstrated that selected material/equipment conformed to technical and quality requirements specified in procurement documents.
The following procurement engineering packages were selected at random for this review:
TVAItem Identification Code (TIIC) No. BYW515G, QA Level 1, Cables TIIC No. AWR272K-SVS, QA Level 1S, Circuit Breaker TIIC No. CAC330F, QA Level 1, Replacement parts for Model 504-A Converter TIIC No. CDQ312M, QA Level 1, Siemens 4160-Volt Vacuum Breakers TIIC No. CDX533B, QA Level 1, Reactor Vessel Access Hole Covers TIIC No. CDK682D, QA Level 1, Target Rock Solenoid Valve (MSRV Parts)
TIIC No. CBL335A, QA Level 1, AirConditioner Filter element, Charcoal Flatbed Absorber TIIC No. CBW908C, QA Level 1, Flapper for Series 4160 Wizard II Pressure controller TIIC No. CBG186M, QA Level 1, Standby'DG Safety Related Replacement Parts TIIC No. AXK220V,QA Level 1, Cable Transfer from Hartsville TIIC No. BVG950R, QA Level 1, NAMCO Controls Part No. EA740-50100 (Limit Switch)
TIIC No. BHR387Y, QA Level 1, Conax ECSA and Replacement Parts
TIIC No. CDT536L, QA Level 1, Replacement Parts for various safety related plant electrical distribution and control systems originally supplied by General Electric The inspector concluded that the procurement program was implemented in a manner which ensured that procured materials satisfied technical and quality requirements.
During this review the inspector identified discrepancies on the General Electric (GE)-supplied Product Quality Certificate for TIIC No. CDX533B. The licensee wrote PER BFPER 98-11697-000 documenting the error in the parts list revision level and contacted GE who revised the Product Quality Certificate to show the correct revision level. There was no change in the procured item material condition as a result of this corrective action. The inspector also observed for Procurement Item TIIC No. AKX220V involving cable transfer from Hartsville that neither procedure NEDP-8 nor SPP-4.2 provided clear direction for transferring quality and safety-related material from the TVA Hartsville Investment Recovery center to BFN. The license wrote PER BFPER98-1276-0000 to document this inspection finding. The inspector reviewed
'several procurements involving cable transfers from Hartsville and verified that all of the transferred materials met specified technical and quality requirements.
No nonconforming material was identified during this review.
During the course of the review of TIIC No. CBW908C, the inspector identified a deficiency in which a vendor-supplied material nonconformance report was'not reviewed and evaluated by the PEG. The vendor recommended a disposition of "Accept as-is."
The item procured was a Fisher Pressure Controller Model 4160 flapper, part number 1H2669-41132.
The procurement data sheet identified this as a QA Level 1 procurement and imposed the requirements of the licensee's QA program on the purchase order. The'inspector determined that the vendor prov'ided Nonconformance Reports (NCRs) No. 544579-1, -2, and -3, describing a deviation in which the flapper diameter dimension was 1.95 inches in lieu of 2.00-1.99 inches.
The material was received on site November 14, 1997, and inspected in accordance with the requirements of the procurement data sheet (PDS) after which it was placed in the warehouse for storage.
Mechanical Design Standard DS-M18.2.18, Standardized Procurement Notes, Rev. 10, Note T2054, requires nonconformances to the requirements of the contract to be handled in accordance with the vendor's QA program, with a recommended disposition of "Accept As-Is" or "Repair" to be submitted to TVAfor approval.
A copy of all nonconformances relative to the contract are required to accompany the shipment of the order.
Procedure SPP-4.2, Material Receipt and Inspection, Rev. 0, Section 3.6, delineated requirements for resolving unacceptable conditions by Acquisition and Material personnel or the PEG. The recommended
"Accept As-Is" disposition for this procurement action was not resolved in accordance with the requirements of SPP-4.2, which required the item to be held in abeyance pending resolution of the unacceptable condition. Section 3.6 of this procedure requires the responsible engineering personnel to disposition the non-conforming condition and document the disposition on a Receiving Unsatisfactory Report (RUR). The disposition may be either "Rework;" "Repair;" or "Accept As-ls," with an engineering basis and justification for the disposition.
Contrary to the requirements of the procedure, the three replacement flappers were placed in storage pending use in the plant without this disposition having been performed.
The inspector informed the licensee of this
inspection finding and PER No. BFPER98-11691 was initiated to document this deficiency.
The licensee implemented immediate corrective action by removing of the flappers from the warehouse and segregating them in a holding cage.
In addition, the flappers were evaluated by the PEG as "Accept As-ls," based on PEG package 9600011757XORO.
The developed corrective action for recurrence control of this item involves revising procedure NEDP-8 to more clearly describe when vendor nonconformance documentation is to be submitted to TVAand approved by TVAengineering.
This corrective action has a due date of February 2, 1999. The licensee was informed that this item would be identified as a violation of 10 CFR 50, Appendix B, Criterion V, Failure to Follow Procedure for Disposition of Non-Conforming Material Condition, and willbe tracked as'VIO 50-260, 296/98-07-04.
The NRC has concluded that information regarding the reason for the violation, the corrective actions taken and planned to correct the violation and prevent recurrence is already adequately addressed on the docket as described in this report.
Conclusions The inspector concluded that the licensee had developed and was implementing a nuclear procurement program that satisfied regulatory requirements incorporated in TVA Nuclear Quality Assurance Plan, TVA-NQA-PLN89A,Rev. 8, and licensee commitnients, as delineated in ANSI N45.2.13-1976, Quality Assurance Requirements for Control of Procurement of Items and Services for Nuclear Power Plants.
IV. Plant Su ort Radiological Prot'ection and Chemistry Control General Comments 71750 The inspectors observed radiological postings, radiological work practices, employee processing at the control point, and checked the locks. for locked high radiation areas while conducting plant tours. The inspectors found no significant problems in these areas.
Conduct of Security and Safeguards Activities General Comments 71750 The inspectors visited the Secondary Alarm Station during plant tours and found the security officers to be alert and attentive to activities at and around the site. Security officers at the Primary Access Point were observed screening employees by the inspectors daily as the inspectors processed in and out of the protected area.
The inspectors noted that the employee screening process was being effectively implemente V. Mana ement Meetin s X1 Exit Meeting Summary The resident inspectors presented inspection findings and results to licensee management on November 18, 1998. Additional formal meetings to discuss inspection findings were conducted on October 9 and 23, 1998.
X3 Management Meeting Summary On October 26, 1998, the NRC received comments from petitioners, the licensee, and members of the public in an informal hearing held at the site. The subject of the hearing was a request by the petitioners to revoke the operating license foi Browns Ferry Unit 1 which is currently shutdown and defueled.
PARTIALLIST OF PERSONS CONTACTED Licensee T. Abney, Licensing Manager B. Baker, Procurement Engineering Manager J. Brazell, Site Security Manager G. Bugg, Acting Radiation Protection and Chemistry Manager R. Coleman, Radiological Control Manager R. Greenman, Site Support Manager J. Johnson, Site Quality Assurance Manager R. Jones, Interim Plant Manager G. Little, Operations Mana'ger R. Moll, System Engineering Manager G. Moody, Interim Training Manager D. Olive, Operations Superintendent R. Rogers, Maintenance Superintendent R. Ryan, Engineering Manager J. Schlessel, Maintenance Manager J. Shaw, Design Engineering Manager K. Singer, Site Vice President INSPECTION PROCEDURES USED IP 37551:
IP 38701:
IP 62706:
IP 62707:
IP 61726:
IP 71707:
IP 71750:
IP 73753 IP 92901:.
Onsite Engineering Procurement Program Maintenance Rule Maintenance Observations Surveillance Observations Plant Operations Plant Support Activities Inservice Inspection Follow-up-Plant Operations
IP 92902:
Follow-up-Maintenance
~ IP 92903:
Follow-up-Engineering ITEMS OPENED, CLOSED AND DISCUSSED Opened 50-296/98-07-01 VIO Failure to Comply with LCO 3.0.4 for HPCI System Operability (Section 01.2).
50-259, 260, 296/98-07-02 EEI Inadequate Standby Gas Treatment Heater Flow Switch Logic Functional Test (Section M8.5).
50-296/98-07-03 50-260,296/98-07-04 Closed 50-260,296/98-07-04 NCV VIO NCV NCV Failure to Properly Implement Common Accident Signal Logic Test (Section M4.1).
Failure to Follow Procedure for Disposition of Non-Conforming Material Condition (Section E1.1).
Failure to Properly Implement Common Accident Signal Logic Test (Section M4.1).
Failure to Follow Procedure for Disposition of Non-Conforming Material Condition (Section E1.1).
50-259, 260, 296/98-02-01 VIO Failure to meet minimum shift crew requirements (Section 08.1).
50-259/97-03-05 IFI Unit One Fuel Pool Makeup Valve Operator Removed (Section 08.2).
50-259, 260, 296/98-02-02 VIO 50-259, 260, 296/98-02-03 VIO Failure to Follow High Efficiency Particulate Air Filter Testing Procedures (Section M8.1).
Inadequate Testing of Downstream Standby Gas Treatment HEPA Filter (Section M8.2).
50-259/1998-001-00 50-259/1998-001-01 50-259/1 998-002-00 LER LER Standby Gas Treatment System HEPA Filter Testing Not In Compliance with ANSI Standard Requirements (Section M8.3).
Inadequate Surveillance Instruction for Calibration of the SGT Train B Relative Humidity Control Heater Flow Switches (Section M8.4).
50-260, 296/98-03-02 50-260/95-41-01 50-260,296/97-08-05 Discussed URI IFI IFI
Standby Gas Treatment System Flow Switch Testing Issues (Section M8.5).
EDG 1A Turbocharger Inspection (Section M8.6).
Materials Upgrade Project (Section M8.7).
50-260,296/98-04-02 50-296/96-08-03 IFI'FI Use of Maintenance and Test Equipment (Section M4.1).
Unit 3 Main Steam Isolation Valve Circuitry Failures (Section M8.8).
LIST OF ACRONYMS USED ANSI-APEDS-ASME-BOM-CFR-CREV-DCN-DOP-ECCS-EDG-EECW-EEI-GE-GL-HAZ-'EPA-HPCI-IFI-IGSCC-IHSI-ISI-ITMS-ITS-kv-LER-LCO-MSIV-NCR-NCV-OSIL-PEG-American National Standards Institute, Inc.
Automated Procurement Engineering Data System American Society of Mechanical Engineers Billof Material Code of Federal Regulations Control Room Emergency Ventilation Design Change Notice Dioctylphthalate Emergency Core Cooling System Emergency Dies'el Generator Emergency Equipment Cooling Water Apparent Violation General Electric Generic Letter Heat-Affected Zone High Efficiency Particulate Air High Pressure Coolant Injection Inspection Followup Item Intergranular Stress Corrosion Cracking Induction Heating Stress Improvement Inservice Inspection Integrated TVAMaterials System Improved Technical Specifications Kilovolt Licensee Event Report Limiting Condition of Operation Main Steam Isolation Valve Nonconformance Report Non-cited Violation Operations Section Instruction Letter Procurement Engineering Group
PER-pslg-RHR-RHRSW-RUR-SBGT-SCV-SRO-TIIC-TRM-TS-TVA-URI-UT-VIO-VOM-Problem Evaluation Report pounds per square inch gage Residual Heat Removal Residual Hear Removal Service Water Receiving Unsatisfactory Report Standby Gas Treatment Steel Containment Vessel Senior Reactor Operator TVA Item Identification Code Technical Requirements Manual Technical Specification Tennessee Valley Authority Unresolved Item Ultrasonic Testing Violation Volt-ohm meter