IR 05000271/1996009
| ML20135D378 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 12/02/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20135D350 | List: |
| References | |
| 50-271-96-09, 50-271-96-9, NUDOCS 9612090357 | |
| Download: ML20135D378 (87) | |
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ENCLOSURE 2 l
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
l Docket No.
50-271 Licensee No.
DPR-28 l
l Report No.
96-09 Licensee:
Vermont Yankee Nuclear Power Corporation Facility:
Vermont Yankee Nuclear Power Station
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Location:
Vernon, Vermont l
Dates:
September 1,1996 - October 19,1996 Inspectors:
William A. Cook, Senior Resident in eactor Edward C. Knutson, Resident inspector l
John H. Lusher, Health Physicist, DRS I
Harold Eichenholz, Project Engineer, DRP Joseph L. Nick, Radiation Specialist, DRS George W. Morris, Reactor Engineer, DRS Alfred Lohmeier, Sr. Reactor Engineer, DRS Patrick Peterson, NDE Technician, DRS
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Approved by:
Richard J. Conte, Chief, Reactor Projects Branch No. 5 Division of Reactor Projects i
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9612090357 961202 PDR ADOCK 05000271 G
PDR L
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EXECUTIVE SUMMARY Vermont Yankee Nuclear Power Station NRC Inspection Report 50-271/96-09 This integrated inspection included aspects of licensee operations, engineering, l
maintenance, and plant support. The report covers a 7-week period of resident inspection; in addition, it includes the results of announced inspections by regional specialist inspectors and a regional projects inspector.
Operations Integration of the various inspector findings and licensee root cause evaluation results for events discussed in this report (reference Sections M1.2 through M1.4, M3.1, M3.3-M3.5, M8.4 and P2) identified a recurring theme. This recurring theme was observed in all functional areas and involved various procedural adequacy and adherence discrepancies.
As acknowledged by the VY staff in recent Functional Area Assessments, the broad area of procedural usage warrants continued VY management and staff attention and improvement in discriminating, categorizing, and trending those aspects of procedure usage that provide the defense in depth to nuclear power generation processes.
The inspector concluded that the calculated spent fuel pool systems' decay heat removal capacitias in conjunction with operating procedures, provided adequate assurance that the largest projected decay heat loading of the spent fuel pool would not exceed the systems'
design limits.
Although of minor safety significance, the inspector considered the incorrect setting of the
"A" EDG Ioad limit to be an example of imprecise watchstanding performance.
Maintenance in general, the conduct of maintenance by the VY workers was good. Appropriate procedural adherence was noted and good attention to detail was observed.
VY exercised conservative decision-making in aborting from the September 6 turbine overspeed trip test. Use of a switch-type jumper for RHR system logic testing was not clearly recognized in the surveillance procedure indicating both a procedure adequacy and adherence weakness. Operators' failure to properly adhere to the EDG surveillance test governor load limit setting requirement was viewed as imprecise watch-standing performance and was dispositioned as a Non-Cited Violation. Prior to conducting the ECCS integrated automatic initiation test, the licensee considered the possibility of a spill due to the ongoing MSIV maintenance. Although a vessel overfill and subsequent spill did occur, it was the result of a cognitive error made by a single individual, rather than inadequacy of the licensee's contingency planning. The procedural violation which caused this event was not l
cited. The October 18 re-test following corrective maintenance on equipment was
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appropriately conducted, and the corrective actions to address the operator error were timely and proper.
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The reactor pressure vesselinservice inspection was performed in accordance with established procedures. The analysis of the ultrasonic testing (UT) data was performed by (
qualified technicians. The UT indications were appropriately identified for further
evaluation. The licensee had appropriate interaction and oversight of the ongoing non-l destructive examination and inservice inspection activities.
The inspector found the VY core shroud repair modification design review, materials conformance, manufacturing procedures, ultrasonic examination of the vertical welds l
inspected, and quality assurance of the repair procedure was performed in a manner meeting 10 CFR Part 50 regulatory guidelines and the relevant approved requirements of the l
ASME Boiler and Pressure Vessel Code for Nuclear Vessels.
l The licensee performed the UT examination of the core shroud in accordance with the qualified procedures and techniqu'. The licensees analysis methodology for the UT data was performed satisfactorily. No recordable indication were noted by the licensee for the UT examinations. The licensee maintained good oversight and interaction with the subcontractor.
The licensee's corrective actions were poor in addressing a configuration problem (introduction of water into the upward pointing vent port) with a MSIV air actuator. Neither the discovery of water intrusion into the V2-86A actuator, requiring actuator replacement, nor the inspector's initial prompting caused the maintenance staff to closely examine the cause for the water intrusion and define an appropriate resolution. Proper corrective action was taken by the end of the inspection period, but only after further inquiries by the inspector.
Technical Specification (TS) 6.5.A.6, requires detailed written procedures covering surveillance and test requirements. UFSAR, Section 1.9, states that the VY Ouality
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I Assurance program is in compliance with 10 CFR Part 50, Appendix B and ANSI N18.7-1976.10 CFR 50, Appendix B, Criterion XI, " Test Control," and ANSI N18.7, Section 5.2.19, " Test Control," require test procedures to incorporate acceptance limits contained in applicable design documents. Contrary to the above, OP 4215, Rev. 6, Main Station Battery Performance / Service Test, did not contain any formal acceptance criteria for the
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battery service tests. In addition, the informal acceptance criteria in the f mn of the test
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shutdown setpoint, had no basis in any design document. This is a violation l
(VIO 96-09-06)
i The licensee considered the battery service test as a go, no-go test and had no intention to either interpret the results for margin or use the results to trend battery performance. This l
limited use of available battery test data was a performance weakness. The battery service l
test procedure was weak in the area of non-continuous testing guidance. However, the test interruption documented for the 1B battery test was sufficiently controlled by the maintenance erigineer, so as not to void the test results. The battery service test procedure did not provide sufficient guidance to justify operation of the main station batteries with l
only 59 cells. However, it appears that VY may not have ever operated with less than 60 j
l cells and the recent service test results indicated sufficient voltage margins, at the tested
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electrolyte temperature, to enable VY to justify 59 cell operation.
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Aspects of the personal safety program were found to have been applied inconsistently between VY personnel and their contractors. This suggested that the program was based on a criteria rather than protection from a specific occupational health hazard.
I The interface between the design engineering group and the maintenance engineering department located at the site, responsible for station battery design and testing, was weak. Current revisions to engineering documents that impact operating and maintenance procedures had evidently not been forwarded to the appropriate site personnel. In addition, the maintenance engineering review of the service test results was not thorough.
I Knowledgeable personnel were observed to perform maintenance related activities in a professional manner, utilizing safe work practices and quality features in accordance with approved procedures. The work activities, associated with the portion of EDCR 95-407 that involved the RCIC system, demonstrated a strong level of VY maintenance supervision
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involvement in field.
The three Event Reports that were evaluated contained instances of deficient Maintenance i
Department performance in the area of procedural adequacy and adherence. This
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performance was contrary to Technical Specification 6.5, Plant Operating Procedures.
However, this licensee ideritified and corrected violatico is being treated as a Non-Cited Violation, consistent with Section Vil.B.1 of the NRC Enforcement Policy. The corrective i
actions for these Event Reports were appropriate, but the depth and precision of root cause i
analysis for these events were identified as an area for improvement. Recent Maintenance Department self-assessments and Quality Assurance Department assessments were determined by the inspector to provide valuable insights into VY's self recognition that
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procedural quality (or adequacy) and adherence warrants continued attention.
Enaineerina The VY staff took appropriate action to identify and resolve longstanding 10 CFR 50, Appendix J containment isolation valve testing deficiencies. The spec;fic resolution of the CS and RHR systems' containment isolation valves by redesignation of the isolation functions is pending further NRC staff review. (URI 96-09-07)
Based upon review of the HPCI and RCIC systems environmental qualification categorizations and supporting technical bases, the inspector verified that neither system was credited for accident mitigation for LOCA or HEl.B scenarios resulting in harsh environmental conditions in their respective rooms. Accordingly, the HPCI and RCIC motor heater de-energizations do not degrade the systems' safety function or Technical Specification defined operability.
VY's identification and short term resolution of EDG air receiver inservice testing and inspection results were appropriate. Design engineering's initial dispositioning A the bottom elliptical head wall thickness issue lacked quality and precision, but was adequately revised.
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VY's long-term intentions to replace the air receivers and associated pressure relief valves appeared prudent.
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Plant Suocort i
VY continued to maintain an overall effective program for occupationsi radiation protection including external exposure controls, internal exposure controls, control of radioactive materials and contamination, surveys and monitoring, and the program to maintain personnel radiation exposures as low as is reasonably achievable (ALARA).
Audits and appraisals by the licensee's staff continued to improve the quality of the program. Minor program changes were noted, including the temporary staffing for the refueling and maintenance outage. Facility tours indicated that good controls were established for radioactive materials and contamination, high radiation areas, and very high radiation areas. External and internal exposure controls effectively limited the total dose assignment to personnel. Minor program weakness was identified in the use of inaccurate l
dose data for personnel exposure tracking.
The licensee continues to maintain a good emergency preparedness program. The emergency response plan and implementing procedures were current and effectively implemented. The emergency facilities, equipment, instruments and supplies were found to be maintained in a state of readiness. All required inventories through August 1996, were completed. A sempling of emergency response organization personnel training records pertaining to on-shift dose assessment indicated that training and qualifications were current. Reports indicated that quality assurance audits were thorough and satisfied NRC requirements.
The licensee's internal analysis of TSC habitability was reasonably founded, with the exception of the use of probabilistic assessments to demonstrate the time to recover from a loss of offsite power. The addition of definitive guidance for transferring critical TSC functions to other emergency response centers in the event the TSC becomes uninhabitable was found appropriate.
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TABLE OF CONTENTS EXECUTIVE SUMMARY..............
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TA B LE O F C O NT E NT S..............................................
vi Summ a ry of Pla nt Status............................................
1.
Operations
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O1 Conduct of Operations...
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01.1 (Open) irl 96-09-01: Core Spray System Minimum Flow Valves Containment Isolation Function............................
01.2 (Open) IFl 96-09-02: Diesel Generator Output Breaker Closure M ec ha nism Failure.....................................
01.3 (Open) IFl 96-09-03: Residual Heat Removal System Pump Start Interlock
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07 Quality Assurance in Operations.................................
07.1 Spent Fuel Pool Cooling and Decay Heat Removal Capacity........
08 Miscellaneous Operations issues.................................
08.1 Operation of the Augmented Off-Gas (AOG) System in a Bypass Mode
11.
Maintenance..................................................
M1 Conduct of Maintenance
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M1.1 Maintenance Observations
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M1.2 Surveillance Observations................................ 12 M1.4 (Open) IFl 96-09-04: Alternate Rod Insertion Actuation due to Maintenance involving a Reactor Vessel Water Level Instrument
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M1.5 (Open) IFl 96-09-05: Primary Containment Ftrogen Purge System Isolation Valve Leakage
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M1.6 ISI of the Reactor Pressure Vessel.......................... 17 M 1.7 Core Shroud
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M2 Maintenance and Material Condition of Facilities and Equipment
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M2.1 Main Steam Isolation Valves Corrective Maintenance............. 21 M3 Maintenance Procedures and Documentation........................ 22 M3.1 (Open) VIO 96-09-06: Inadequate Battery Service Test Acceptance Criteria
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M3.2 Battery Service Test Automatic Data Recording
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M3.3 Battery Discharge Test interruption Time Limitation.............. 24 M3.4 Battery Operation with 59 Cells............................ 24 M3.5 DC System Low Voltage Alarm............................ 25 M4.2 Battery Service Test Data Anomalies........................ 26 M4.3 Craft / Supervisory Performance - Personnel Error History
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M8 Miscellaneous Maintenance issues
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M8.1 (Closed) VIO 96-05-02: Testing and Inspection of the Suppression Chamber Cooling and Spray Modes of the Residual Heat Removal System.............................................
M8.2 (Closed) VIO 95-11-01: Inadequate Inspection of Interior Drywell Head 28 vi
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l M8.3 Maintenance - Engineering Interf ace......................... 29 M8.4 (Closed) IFl 96-03-01: Recirculation Pump Trip Due to Maintenance
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Pe rs o nn el Error........................................ 29 Ill. Eng ine e ring................................................... 31 E1 Conduct of Engineering
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E1.1 (Open) URI 96-09-07: Core Spray and Residual Heat Removal Systems Containment Isolation Valves Redesignated
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E2 Engineering Support of Facilities and Equipment...................... 32 E2.1 HPCI and RCIC System Motor Heater Follow-up
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E3 Engineering Procedures and Documentation......................... 33 E3.1 Battery Sizing Calculation Design Margin
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E7 Quality Assurance in Engineering Activities
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E7.1 Emergency Diesel Generator's Air Receiver Wall Thinning
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IV. Plant Support................................................
R1 Radiological Controls........................................
R3 Radiation Protection Procedures and Documentation................... 36 R3.1 External Exposure Controls............................... 36 i
R3.2 Internal Exposure Controls
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R3.3 Control of Radioactive Materials and Contamination, Surveys and M o nit o ri n g........................................... 38 R3.4 A LA R A Pro g r a m....................................... 39 R6 Radiation Protection Organization and Administration
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R6.1 Changes in the Radiological Controls Program.................
R7 Quality Assurance in Radiation Protectiors Activities................... 40 R7.1 Audits and Appraisals..................................
R8 Miscellaneous Radiation Protection issues
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R8.1 Review of UFSAR Commitments
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R8.2 (Update) URI 96-03-05: Removal of Reactor Vessel Shield Blocks at P o vv e r.............................................. 41 R8.4 Drywell Closecut Tour.................................
P3 EP Procedures and Documentation
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P5 Staff Training and Qualification in EP.............................
P6 EP Organization and Administration..............................
P7 Quality Assurance (QA) in EP Activities............................ 46 P8 Miscellaneous EP lssues......................................
P8.1 Updated Final Safety Analysis Report (UFSAR) Inconsistencies.....
P8.2 Ames Hill National Oceanic and Atmospheric Administration (NOAA)
Transmitter.........................................
P8.3 (Updated) URI 92-14-01: Technical Support Center (TSC)/ Control Room Ventilation Systems and TSC Shielding.................. 48 V. M anag em ent M eeting s..........................................
4 9 X 1 Exit M e eting Summ ary........................................ 49 X2 Management Meeting Summary
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X3 Review of Updated Finai Safety Analysis Report (UFSAR)
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INSPECTION PROCEDURES USED...................................... 50
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ITEMS OPENED, CLOSED, AND DISCUSSED.............................. 51
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PARTIAL LIST OF PERSONS CONTACTED................................ 52
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LIST OF ACRO NYMS U S ED......................................... 53
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j ATTA C H M E N T A.................................................. 54
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DETAILS Summarv of Plant Status
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Vermont Vankee (VY) operated at full power until September 6, when the unit was shutdown and the planned 1996 refuel outage was commenced ending Operating Cycle 19.
j The unit remained shutdown through the end of this inspection period.
During the week of August 26, a region based specialist inspection conducted a review in the area of emergency preparedness. During the week of September 16, region based i
specialist inspectors conducted reviews in the areas of electrical maintenance, inservice inspections, and the core shroud repair. During the week of September 23, a region based
inspector conducted a review in the area of radiological controls and radiation occupational
exposure. The results of these specialist inspections are integrated into this report.
i On October 11, VY announced that Jay Thayer, Vice President of Engineering would be
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leaving VY on October 21,1996 to join the executive recovery team at Northeast Utilities.
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i Also effective on October 21, Edgar Lindamood would assume the position of Director of I
Engineering, responsible for all VY engineering services including these provided by Yankee Atomic. Mr. Lindamood will report directly to Don Reid, Vice President of Operations.
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Operations
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01 Conduct of Operations'
01.1 (Open) IFl 96-09-01: Core Spray System Minimum Flow Valves Containment
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isolation Function
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At 2:48 PM on October 2, the VY staff notified the NRC staff (Event No. 31082) in accordance with 10 CFR 50.72, that an engineering evaluation had concluded that the lack
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of closure capability of the motor-operated core spray minimum flow valves (CS-SA and 58)
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was a condition outside the plant design basis. The licensee determined that the valve
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j wiring and logic prohibited minimum flow valve closure unless the core spray pump was running with injection flow. This valve logic and wiring condition resulted in the inability to
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close the minimum flow valves for containment isolation purposes.
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Prior to restart from the refuel outage, the VY staff modified the core spray minimum flow
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valve logics to provide a means to close them from the control room. The inspector plans
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to follow-up on the licensee's evaluation and corrective actions for this issue in a j
subsequent inspection period (IFl 96-09-01).
- 01.2 (Open) IFl 96-09-02: Diesel Generator Output Breaker Closure Mechanism Failure i
On September 13 at 8:30 PM, operators were implementing a protective tagout for planned j
preventive maintenance on the "A" emergency diesel generator (EDG) when they identified that the closing springs for the generator output breaker (type GE AM4.16 4kV Magneblast)
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' Topical headings such as O1, M8, etc., are used in accordance with the NRC
standardized reactn inspection report outline. Individual reports are not expected to address all outline topics.
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were discharged. With the closing springs discharged, the breaker would not have closed electrically or manually. This determination resulted in the September 14 notification (Event No. 31004) per 10 CFR 50.72 (b)(2)(iii)(A). Immediate follow-up by the VY staff concluded that the A EDG breaker failure mode was unique and did not affect other 4kV breakers at the plant. Accordingly, the licensee retracted the September 14,10 CFR 50.72 notification, on September 24.
The A EDG breaker was quarantined to ensure as-found conditions were not disturbed prior to a detailed follow-up investigation by the electrical maintenance staff. This investigation identified that the charging motor had failed (motor windings fused) apparently due to prolonged running current. The licensee concluded that, after the charging motor ratchet pawl hinge pin became disengaged (connects the charging motor driver via linkages to the closing springs), the charging motor ran until failure. The last time the breaker was cycled open was August 19,1996, for EDG surveillance testing. The hinge pin is held in place by cotter pins on both ends. One cotter pin was found missing and the hinge pin apparently worked its way out of the linkage after an unknown number of operating cycles. A focused inspection of all 4kV breakers by the licensee staff identified 18 of 49 breakers inspected were degraded (cotter pins were undersized, broken, and/or missing, but no other breakers found inoperable). Based upon these inspection results, the control room operators made another 10 CFR 50.72 notification (Event No. 31192) on October 22 per paragraph j
(b)(2)(iii)(B) and (D).
l The inspector verified that the licensee had taken appropriate corrective actions for this breaker concern prior to unit restart. Additional inspector follow-up is planned after the VY staff has completed their root cause evaluation and documented their corrective actions and safety assessment (IFl 96-09-02).
i 01.3 (Open) IFl 96-09-03: Residual Heat Removal System Pump Start Interlock On September 7, while control room operators were attempting to place the "D" residual heat removal (RHR) pump in a shutdown cooling configuration, the pump start interlock was not satisfied and the pump failed to start. The cause of the pump start failure was subsequently identified as an incorrectly specified limit switch rotor setting on the "D" RHR pump suction valve (RHR V10-15D). The limit switch setting error potentially impacted nine other motor-operated valves and the licensee reported this problem (Event No. 31046) in accordance with 10 CFR 50.72 on September 23, following the completion of their root cause investigation.
i VY staff review identified that RHR V10-15D and the nine other valve motor-operators were modified (two rotor limit switches were replaced with four rotor limit switches) per a 1995 Engineering Design Change Request (EDCR No.95-407). The rotor #1 (valve open limit)
and rotor #3 (valve open limit for pump interlock) settings and setting tolerances for all ten of these valves were the same. Verification by the licensee confirmed that only the RHR V10-15D valve was improperly set (when the valve was opened, rotor #1 stopped valve travel before rotor #3 made-up contacts to satisfy the pump start logic).
The inspector conducted a preliminary review of the licensee's actions to address this problem prior to unit restart and found them to be adequate. A detailed follow-up of the
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t licensee's root cause and corrective actions will be conducted in a subsequent inspection period (IFl 96-09-03).
07 Quality Assurance in Operations l
07.1 Spent Fuel Pool Cooling and Decay Heat Removal Capacity a.
Inspection Scope in preparation for observing refueling activities and using the guidance of Inspection Procedure 60705, the inspector reviewed the design capabilities and applicable operating procedures for the spent fuel pool cooling systems.
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Observations and Findinas The inspector reviewed Section 10.5, Fuel Pool Cooling and Demineralizer System, of the f
Updated Final Safety Analysis Report (UFSAR) and applicable shutdown and refueling procedures. The inspector also examined the VY staff projected schedule for the pending refuel outage and, in particular, the fuel shuffle. Based upon this review, the inspectors identified that under optimum conditions (although not planned for in the 1996 refuel outage) the VY staff could initiate and complete a normal (136 fuel assemblies) refueling discharge within six days after shutdown and a full (368 fuel assemblies) core off load within ten days after shutdown. Examination of the estimated fuel decay heat calculations (reference UFSAR, Section 10.5, Table 10.5.2) identified that the calculated decay heat load appeared to be greater than the available spent fuel pool cooling heat removal capacity under the full core discharge scenario.
The inspector discussed this postulated refueling scenario with VY representatives and determined that more recent spent fuel pool cooling system design calculations with supporting test data (including various pump and heat exchanger configurations) were available which support a higher decay heat removal capacity than stated in the UFSAR.
i The licensee stated that Table 10.5.2 would be reviewed to determine if a revision was i
necessary for clarification of the system design and operating limits. The licensee also initiated a revision to the reactor vessel and drywell reassembly procedure (OP-1201) to ensure that the spent fuel pool gates are not reinstalled until the Reactor Engineering staff had verified that spent fuel decay heat was within the SFP cooling systems' design limits.
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Conclusion The inspector concluded that the calculated spent fuel pool systems' decay heat removal capacities in conjunction with operating procedures, provided adequate assurance that the largest projected decay heat loading of the spent fuel pool would not exceed the systems'
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08 Miscellaneous Operations issues
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08.1 Operation of the Augmented Off-Gas (AOG) System in a Bypass Mode a
a. Inspection Scope (71707. 92901)
The NRC, in its letter dated April 18,1996 requested VY to address questions and concerns regarding the bypass mode of operation of the AOG system. Vermont Yankee, in its response dated May 17,1996, provided information related to the NRC's request for
information, and included the results of it's investigations related to these matters by the l
VY Investigation Team.
The purpose of this inspection was to review the information provided by VY to address the AOG bypass concerns, provide a regulatory perspective involving the conduct of operations
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using the bypass mode of the AOG system, and assess the adequacy of VY's response to
i the NRC's request for information pertaining to the issues associated with AOG system bypass mode.
In conducting this inspection, the inspector reviewed licensing documents (both VY and i
NRC generated), reviewed procedures and drawings, attended a combined meeting of the i
Nuclear Safety Audit Review Committee (NSARC) and the Plant Operations Review I
Committee (PORC), reviewed previously released NRC inspection reports, and conducted
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interviews with various members of the VY organizations. Where corrective actions were identified as being warranted, the inspector reviewed the appropriateness of the proposed or completed VY actions.
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Qbyervation and Findinas
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(1) Description of AOG System Bypesses.
i AOG Bvoass Line i
The AOG bypass line uses four manually operated butterfly valves located in the north off-l gas trench. Opening the two dryer /adsorber trala bypass valves OG-551 and OG-573, and closing both the adsorber train outlet OG-550 and dryer skid inlet valve OG-552 will effect a complete bypass of the AOG system. Use of these valves would result in bypassing all the
functions of the AOG system, except the two parallel recombiner subsystem trains.
Radioactive gaseous wastes would exit the recombiner(s) and enter the AOG system's final section of the delay piping downstream of the post charcoal radiation monitors (RAN-OG-3127/3128).
The inspector noted that this manual AOG bypass line is not shown on FSAR Figure 9.4.1, AOG System Simplified Schematic, and is not specified for use by plant procedures. No discussion about this bypass is contained in the FSAR, procedure OP 2150, Advanced Off-Gas System and Air Evacuation Equipment (other than the procedure's Appendix A Valve Lineup that has the valves OG-551 and OG-573 maintained in the closed position), system descriptions or Licensed Operator Training (LOT) Program lesson plans. However, the inspector noted that the Offsite Dose Calculation Manual (ODCM), Revision 17 dated May 31,1994, specifies that the dryer /adsorber subsystems may be bypassed if it becomes
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unavailable provided the releases are within Technical Specifications (TSs) limits. Also, the ODCM contains Figure 6-2, Radioactive Gaseous Effluent Streams, Radiation Monitors, and Radwaste System at VY, which shows the "Startup" bypass line depicted the same as FSAR Fig. 9.4-1 bu?. also depicts the AOG bypass line with two isolation valves.
The use of the AOG bypass lineup would result in the off-gas flow bypassing the post i
charcoal bed radiation monitors (RAN-OG-3127/3128) and the automatic isolation features
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inherent in the use of these monitors. However, off-gas flow though this lineup, if it were j
to be used, would be monitored by the stack gas monitoring system, which monitors all the radioactive gaseous wastes that are released to the environment via the main plant stack.
i The inspector noted that the valves located in the off-gas trenches are covered with massive concrete shield blocks. In this regard, the inspector determined that it would be a significant undertaking by VY staff to gain access to these valves for purposes of repositioning them. Due to the fact that these valves have not recently been the subject of direct observations, the VY Investigation Team appropriately determined that an entry was warranted into the trenches to verify valve positions and conditions. This action was taken on April 15,1996, with VY determining that valves were found to be in good condition and in accordance with the required valve lineup.
The inspector reviewed maintenance history on the non-safety related manual butterfly bypass valves located in the off-gas trenches, observed that the photographs of valves recently taken by VY showed that the valves located in the trenches were in good condition, and discussed the maintenance activity associated with these valves with performance engineers in the VY Engineering Department. The aforementioned review combined with discussions pertaining to AOG system performance with Operations i
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Department personnel, identified no specific preventive or corrective maintenance concerns pertaining to the manually operated butterfly valves located in the off-gas trenches.
Startuo Bvoass Line FSAR Figure 9.4.1 depicts a line with a single valve that is labeled startup bypass and has no assigned valve number (s), which bypasses the dryer and adsorber (or charcoal beds) of the AOG system. The written description in FSAR Section 9.4 provides the following information: "The dryer /adsorber subsystem may be bypassed if temporarily unavailable during normal reactor operation provided the releases are within the limits of 10CFR20.
With the dryer /adsorber subsystem bypassed, the air ejector off-gas is exhausted through the recombiner/ condenser subsystems, the 30 minute delay pipe, and a HEPA filter bank (F-9-18) located in the stack which otherwise is manually valved out of service."
The discussion section of procedure OP 2150 states that a bypass line is installed around the dryer and adsorber trains which may be used during AOG startup operation and during l
component failure in both dryer trains or the adsorber train section. Prior to this mode of I
operation, the B stack filter must be placed in service and the A stack filter isolated, because there are processing elements installed in the "B" stack filter but not in the "A" filter. Also, the inspector noted that the Licensed Operator Training Program's lesson plan (LOT-00-271), specifies that a bypass line is installed around the dryer and adsorber trains, which may be used during AOG start-up or cc,mponent failure. Procedure OP 2150, Section (
BB provides the instructions for bypassing the dryer and adsorber trains of the AOG syste These instructions r,pecify the use of keylock switches on control room panel 9-50 for valves OG-145 and i46, which are remotely actuated air operated valves.
VY has provided two redundant radiation monitor : (RAN-OG-3127/3128) for the AOG system. These monitors are equipped with automatic isolation capability. The AOG radiation monitors, RAN-OG-3127/3128 will close the stack isolation valve OG-FCV-11 at the stack under the following conditions: (1) when the AOG dryer skid and adsorber bed bypass valves OG-145 or 146 (i.e., the start-up bypass line) are closed and either radiation monitor has a "Hi-Hi" trip signal present for 30 minutes, or either radiation monitor downscale alarm is present or monitor function switch out of " Operate" for 30 minutes; or (2) when the AOG dryer skid and adsorber bed bypass valves OG-145 and 146 are open and either radiation monitor has a "Hi-Hi" trip signal present for 2 minutes, or either radiation monitor downscale alarm is present or monitor function switch out of " Operate" for 2 minutes. In addition to the aforementioned monitoring / automatic isolation capability,
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the off-gas flow will be monitored by the stack monitoring system prior to its exit from the plant stack.
The inspector reviewed VY's Radiation Protection Policy, VYP:107, effective date July 8, 1993, and noted in Section E - Discharge to the Environs, that for gaseous discharges: (1)
the steam jet air ejector effluent shall not be routinely discharged unless it is processed through the AOG system; (2) during plant start-up when bypass operation can facilitate bringing the system on line and in emergency situations, the system may be bypassed with shift supervisor approval.
(2) Licensing aspects of Bypassing the AOG System AOG Startuo Bvoass Significant efforts were needed for both the VY organization and the inspector to recover the licensing history associated with the AOG system, including the bypass aspects' of the system. After reviewing this information, it was understandable to see that the history of the bypass lines was not straight forward, and in part explains the discrepancies that appear to exist between the various VY AOG documents and drawings.
First, VY submitted information on the AOG system, including the depiction of a startup bypass line in 1972, as part of its submittal of Proposed Change No.1 to its license. Figure A-1, VY Off-Gas Radiation Monitors with Control Functions, which is contained in the document "VY AOG Modification Description and Operation," and was part of that submittal, shows the air operated valves OG-145 and 146 to be the bypass valves around the dryer /adsorber subsystem. Figure 4.1, VY AOG System Modification Simplified Schematic, depicted this line with a single valve labeled as "startup bypass." This figure was then used to generate FSAR figure 9.4-1. Subsequently in July 1973, VY revised Figure 4.1 to include a second bypass line with two valves and a statement in the submittal letter that the figure has been revised to show an offgas system bypass line that will allow the plant to operate when the AOG is unavailable. The Atomic Energy Commission, on August 29,1973, concluded in its letter to VY that the installation of a bypass line around the AOG system was acceptabl._
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The inspector noted that between 1974 and October 9,1984 (i.e., the issuance of
~ Amendment No. 83, the revised VY Radiological Effluent TS that implemented the requirements of Appendix l to 10 CFR 50) there were various off-gas isolation requirements imposed upon VY. Up until Amendment No. 83, the steam jet air ejector (SJAE) off-gas radiation monitors required an isolation of the steam supply to the air ejectors upon detection of a high radiation condition in the off-gas flow. Thit. was in addition to the
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isolation of the stack off-gas isolation valve FCV-11 provided by the AOG's post charcoal bed radiation monitors (RAN-OG-3127/3128), which was an installed design feature of the original AOG modification. Amendment 83 removed the requirements for the SJAE monitors to isolate the steam supply to the air ejectors on a Idgh radiation conditions. TS Section 3.2.D, Off Gas System isolation, states that during reactor power operation, the instrumentation that initiates isolation of the off-gas system shall be operable in accordance with Table 3.2.4. TS Table 3.2.4, Off-gas System isolation Instrumentation, specifies that at least one of the radiation monitors (i.e., RAN-OG-3127/3128) between the charcoal bed and the plant stack shall be operable during operation of the augmented off-gas system.
Since TS Table 3.2.4, as it had prior to the issuance of Amendment 83, also provided the requirements of maintaining operable the 2 minute and 30 minute timers, it was evident to the inspector that the AOG startup bypass line was a part of the licensing basis of the plant from the mid 1970s to the present time.
AOG Bvoass Line This bypass line is neither described nor permitted to be used by procedure OP 2150.
Valve lineups in Procedure OP 2150 have the respective valves closed and the procedure does not provide instructions for the use of these bypass lines. Regarding TS requirements, TS Table 3.2.4, Off-gas System isolation Instrumentation, specifies that at least one of the radiation monitors (i.e., RAN-OG-3127/3128) between the charcoal bed and the plant stack shall be operable during operation of the augmented off-gas system. Since the use of the AOG bypass lines would bring the off-gas flow downstream of the these monitors, VY would have to consider inoperable both of the monitors and the isolation instrumentation (e.g., the timers).
With the issuance of Amendment No. 83, the provisions of the automatic isolation of the off-gas flow by the a high radiation condition detected by the SJAE off-gas radiation monitors was removed. It is for this reason that VY has determined that the use of the AOG bypass line, which has its outlet located after the AOG's post charcoal bed radiation monitors, would result in an operation of the'off-gas system without any automatic isolation
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provisions and was therefore unacceptable. To preclude the operation of the plant in this manner, a procedure change to OP 2150 was initiated by VY on July 1,1996 to add a precaution that: (1) the dryer /adsorber subsystem manual bypass valves OG-551 and OG-573 must remain closed; and (2) these valves are not licensed for use without further analysis because they bypass the stack isolation feature (FCV-11) of the radiation monitors RAN-OG-3127 and 3128.
The inspector independently determined that VY actions in this regard were appropriate, based upon the inspector's review of Supplement 1 to Proposed Change No. 78, which provided VY's formal RETS license amendment request on January 23,1984. In this document, VY specified that removing the TS off-gas isolation function of the SJAE
radiation monitor instrumentation was acceptable because the radioactive gases will be able to pass into the AOG charcoal absorber vessels for holdup and decay. This was a safer action than allowing the gases to remain isolated in the main condenser.
Based upon the inspector findings and observations in sections (1) and (2) above, the inspector concluded with reasonable certainty that past plant operation of the off-gas system had not occurred with the AOG bypass in use. The inspector noted that for VY to bypass the AOG system using other than the startup bypass line would necessitate prior NRC review and approval via a TS or license amendment.
(3) Use of the AOG Startup Bypass Line In Inspection Repori 96-05, the NRC documented that VY used the startup bypass line of the AOG system in January 1984 for an approximately 29-hour period. The review conducted by the VY Investigation Team had encompassed the potential AOG internal bypass flowpaths. The Investigation Team issued a report entitled " Advanced Offgas Follow-up Report, which discussed bypass modes of operations.
The inspector performed a review of the circumstances of the events of January 19,1984, which involved the plant operators initiating the use of the startup bypass during power operations. Based upon extensive oversight of plant operations during the period of 1990 to present operations, and the conduct of interviews with VY personnel, the inspector was confident that the investigations Team's identification of the use of the bypass on this one occasion was an accurate portrayal of the facts regarding the frequency and need for this AOG operation. The investigation Team's statement that the use of the AOG startup bypass line was not routinely done was consistent with the inspector's observations and findings.
Regarding the events of January 19,1984, the inspector identified that NRC inspection report 84-01 reviewed the event involving a significant increase in condenser air inleakage and the use of the startup bypass (Note: the inspection report is not specific as to the bypass valves used but, the control room log for this event specifies the use of the OG-145 and OG-146 valves to bypass the dryers and adsorbers). The 1984 inspection also noted that the indicated stack gas release rates increased to about 70 uCi/sec (the TS limit was 72,700 uCi/sec) after the AOG adsorbers were bypassed. No unacceptable conditions were identified by the inspector at that time. As further verification during this current inspection, the inspector reviewed Rev.11 to OP 2150, dated January 20,1983,and s
identified no concerns. Based Lpon the inspector's licensing review enumerated above, the
use of the bypass in 1984 was in accordance with the TSs. The inspector confirmed that the VY Investigation Team report detailing AOG bypass operations was thorough and accurate.
(4) Resolution of Drawing /FSAR Differences in Detail, Potential Licensing issues, and Independent Review of Investigation Team Findings The inspector noted during the course of the inspection dealing with AOG system operations, that, extensive reviews were being performed by the assigned Investigation Team, reviews of team findings by the NSARC and PORC, and by supporting engineering and operations personnel. The inspector determined that efforts in this area indicated
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strong performance because, their was depth in these reviews as reflected in the nature of issues and discrepancies identified and the manner in which they were to be resolved or corrected. Examples included:
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During the combined NSARC and PORC meeting held on April 19,1996 for the purpose
of reviewing the reports of the AOG Investigation Team,it was noted by an NSARC member that the proposed response by the team stating that both bypass lines are
monitored by the AOG radiation monitors may not be correct. The AOG flow diagram
VY-E-75-OO1 showed the AOG bypass line as not bypassing the AOG post charcoal bed radiation monitors (RAN-OG-3127/3128). A PORC Follow item (96-036-02) was issued
to resolve this apparent discrepancy regarding the location of radiation monitors in the AOG process flow stream as depicted in the flow diagram. A July 1,1996
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Memorandum from the assigned performance engineer (PE) determined that, in fact, the AOG flow diagram was incorrect (as evidenced by interviews with personnel that had
recently reviewed the subject piping in the valve trench and an in depth review of plant documents related to this bypass line). Other drawing discrepancies, such as errors in depiction of valve type, were identified.
The PE also recommended that: (1) the AOG bypass line should not be used without l
further analysis since it bypasses the radiation monitors RAN-OG-3127/3128, which provide an isolation signal for closure of the stack isolation valve FCV-11. Also, a i
decision had been made to replace the simplified schematic drawing in the FSAR (Fig. 9.4-1) with the detailed flow diagram VY-E-75-001.
The inspector verified that discrepancies and enhancements to drawings, procedure OP 2150, and the FSAR were being a resolved by the icsuance of the applicable document change forms and actions were initiated. The inspector's observations of the combined meeting of the Committees determined that a comprehensive review
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reflecting probing questions of the subject matter had occurred.
i The Investigation Team identified that the FSAR simplified drawing, Figure 9.4-1 did not
match the Piping and instrument Diagram VY-E-75-001, in that, it did not indicate the
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presence of a second bypass line. A second issue identified by the Team involved the
fact the procedural guidance contained in OP 2150 directs the use of the remotely operated startup bypass valves OG-145 and OG-146, while original regulatory
correspondence implies that manual operated valves OG-551 and OG-573 would be used to bypass the system at power. A level 3 Event Report (ER), No. 96-0237 was i
generated on April 11,1996 to address these issues.
The inspector noted that the VY Investigation Team Leader also issued a memorandum on May 10,1996 to provide clarifying information on the above issues to ensure that a detailed and thorough review of concerns is accomplished. The ER evaluation was i
performed by the VY's Engineering Department's Design Engineering Group, and
contained root and contributing causes, as well as recommended corrective actions.
The ER was approved by the cognizant Department Head on October 1,1996. One of the recommended corrective actions involved a procedure enhancement (OP 2150) to limit the use of the startup bypass valves (i.e., remote air operated valves OG-145 and OG-146) to require PORC review and Plant Manager approval prior to opening these
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valves with the AOG system in operation. The Design Engineering Group was required
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by Commitment Tracking item ER960237-02 to provide guidance 'ior bypass operation by December 1,1996, so as to facilitate completion of this recor nendation by
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March 31,1996. This item also tracks the recommendation to r, vise OP 2150 to
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include mention of the manual bypass line, with a clear statement that the line may not
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be used during plant operations. The inspector considered these corrective action recommendations to represent a focus towards safe plant operations and helpful in ensuring that licensed conditions are understood and achieved.
c.
Conclusions The results of the NRC's review of plant operations with the AOG system in a bypass mode was consistent with those of the VY's Investigation Team. No Deficiency involving failure to meet regulatory requirements was identified by either VY's or the NRC's review of the
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manner in which the AOG system has been operated, including the use of the bypass mode.
The combined review by the NSARC and PORC contributed to VY's understanding of the AOG system operations, as a result of a thorough questioning and probing attitude. This
review also helped to ensure that the report that was to be submitted to the NRC was complete and accurate. A good questioning attitude was apparent in the manner in which documentation discrepancies were identified and corrected by VY personnel involved in reviewing AOG system operations. The use of the Event Report corrective action system positively contributed to irnproving an understanding of proper plant operation and enhancing the associated AOG operating procedure. Recommendations developed as part of the corrective action process represented a strong orientation towards safe plant
operation and helped to ensure that licensed condition are understood and achieved.
11. Maintenance M1 Conduct of Maintenance M1.1 Maintenance Observations a.
Inspection Scooe t
The inspectors observed portions of plant maintenance activities to verify that the correct parts and tools were utilized, t.pplicable industry code and technical specification requirements were satisfied, adequats measures were in place to ensure personnel safety and prevent damage to plant structures, systems, and components, and to ensure that equipment operability was verified upon completion of post-maintenance testing.
b.
Observations and Findinas i
The inspectors observed all or portions of the following maintenance activities:
Reactor refueling, observed September 11 and 12.
- The inspectors observed that the computer control system for the refueling bridge operated very well. The automatic indexing and automatic speed adjustments for the hoist and bridge were very precise and enhanced the efficiency of fuel movements. The video camera on the hoist provided positive identification of fuel bundles, and positive verification of
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grapple position. However, the inspector noted that the procedure for moving fuel, OP-1101, " Management of Refueling Activities and Fuel Assembly Movement," Ravision
29, did not address the use of the computer system indications. Although the indications on the main hoist control panel were adequate to perform all operations, the computer monitor provided enhanced displays that were more readily visible from the refueling bridge.
Control rod blade replacement, observed September 13.
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The inspector observed good procedure use by the senior reactor operator (SRO) on the
refueling bridge. The operation was performed slowly and deliberately.
Prevent ve maintenance on the primary containment air compressor and receiver units i
per Work Orders 96-00880, 96-00936, and 96-00881, observed on September 20.
Fire wrap installation per Engineering Design Change Request (EDCR)96-414,
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Job Order No. 9563, observed on September 23 and 24.
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The inspector observed various stages of the fire wrap installation and discussed the
installation processes and application limitations with the vendor technical representative,
who was providing direct oversight and quality assurance of the installation activities by the
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installers. The inspector noted excellent technical knowledge on the part of the vendor representative and conscientious oversight of each aspect of the installation process.
Preparatory work (setup, cutting, and honing) and installation of tie rods for the reactor
core shroud repair, observed September 29 through October 1.
Main steam isolation valve (V2-86A) actuator air pack installation, observed on
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Repack of HPCI system valve V23-19 and packing adjustments, observed October 8
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and 9.
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Reactor vessel stud ultrasonic examinations and core shroud bolt torquing, observed on October 9.
i Reactor vessel head stud tensioning (second pass), observed on October 9.
- Reassembly of main steam isolation valve V2-86A, observed October 8.
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Various portions of the "B" control rod drive pump repair work observed on October 10-14.
"A" EDG voltage regulator adjustment, observed October 15.
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During the ECCS integrated automatic initiation test (discussed in section M1.3 of this report), the magnitude of the voltage transients in response to starting major electricalloads was determined to be greater than discussed in the UFSAR. The licensee obtained vendor
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assistance to adjust the voltage regulators of both EDGs to obtain optimal transient response.
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c.
Conclusions in general, and as noted above, the conduct of maintenance by the VY workers was good.
Appropriate procedural adherence was noted and good attention to detail was observed.
One minor procedural adequacy weakness was noted in the area of fuel handling.
M1.2 Surveillance Observations a.
Inspection Scope The inspectors observed portions of refueling surveillance tests to verify proper calibration of test instrumentation, use of approved procedures, performance of work by qualified personnel, conformance to limiting conditions for operation (LCOs), and correct post-test systems restoration.
b.
Observations and Findinas The inspectors observed all or portions of the following surveillance tests:
Main turbine overspeed trip testing, observed September 6.
- The test could not be completed because the governor reached its mechanical stop before turbine speed reached the overspeed trip setpoint. The inspector notes that this test was planned to be reperformed during plant startup at the completion of the outage. The inspector concluded that the licensee demonstrated conservatism in backing out of the test, rather than attempting to adjust the governor mechanical stop with turbine speed near the overspeed trip setpoint.
Residual heat removal subsystem A logic functional / calibration test, observed
October 2.
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The operating procedure, OP-4354, had been revised (revision 23) since it was last performed, to connect a timer into the logic circuitry for more precise timing of a relatively fast acting time delay relay. When the applicable timing step was performed, the DC power fuses for the A logic circuit blew. Investigation revealed that the timer used a single common (ground) for the two input signals. When the test step was initiated, the particular combination of contact states (open/close) in the logic circuit resulted in a short circuit via the timer common. The procedure change had been bench tested, however, the test assembly did not simulate enough of the logic circuitry to reveal this problem. As corrective action, the timer connection points in the logic circuit were changed to eliminate the short circuit.
Numerous steps in the procedure required use of an electrical jumper between terminals in the equipment racks. The components being tested were frequently distant from the jumper. Since the procedure required two-person verification of jumper installation, the technicians were using jumpers that included a switch. This allowed the jumper to be installed and verified prior to actually being inserted into the circuit; one technician could then relocate and observe the equipment response when the jumper switch was operated.
However, the procedure did not address the operation of these modified jumpers. As a
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result, the terms " install" and " remove" were interpreted as applying to either the physical attachment of the jumper to the terminal, or the electricalinsertion of the jumper into the circuitry. For example, the inspector noted that the technicians were interpreting " jumper
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removed" to mean that the jumper switch was open, rather than that the jumper was
physically removed from the terminals. The inspector was concerned that this interpretation resulted in the jumper being left physically connected in the equipment rack, without a
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i procedural step to remove it. The inspector noted that two jumpers remained connected to plant equipment at the completion of the procedure. However, these jumpers were removed as the technicians were collecting their test equipment.
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The inspector discussed this observation with department management. The managers indicated that their expectation was that the statement " jumper removed" should cause the
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jumper to be physically removed from the equipment. A procedure change was initiated to
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clarify operation of " switched" jumpers.
EDG Surveillance Testing, observed October 3.
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In preparation for reactor fuel movement, the "A" and "B" EDGs were operationally tested and declared operable on October 3,1996. During a routine inspection, the inspector noted i
that the load limit on the "A" EDG governor was set at 9.6. The required setting, as
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specified in the EDG surveillance procedure (OP-4126) was 10. As discussed in inspection j
report 50-271/96-08, the vendor recommended setting was fully clockwise (in the case of j
the "A" EDG, this corresponds to a setting of approximately 11 on the load limit scale). At j
the time of this observation, the EDGs were not required to be operable by plant conditions.
The inspector discussed this observation with operations department management. The i
"A" EDG load limit was promptly set to 10, in accordance with the current revision of
OP-4126. This failure constitutes a violation of minor significance and is being treated as a
Non-Cited Violation, consistent with Section IV of the NRC Enforcement Policy. Later in the
inspection period, OP 4126 was revised to change the required load limit setting to " fully clockwise." The inspector considered the incorrect setting of the "A" EDG load limit to be
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an example of imprecise watch-standing performance.
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Conclusion
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VY exercised conservative decision-making in aborting from the September 6 turbine overspeed trip test. Use of a switch-type jumper for RHR system logic testing was not clearly recognized in the surveillance procedure indicating both a procedure adequacy and adherence weakness. Operators' failure to properly adhere to the EDG surveillance test governor load limit setting requirement was viewed as imprecise watch-standing performance and was dispositioned as a Non-Cited Violation.
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M1.3 Emergency Core Cooling System integrated Automatic Initiation Test a.
Insoection Scope On October 10, the licensee conducted the emergency core cooling system (ECCS)
integrated automatic initiation test, OP-4100. The purpose of this test is to verify the ability of the ECCS to respond to automatic start signals concurrent with simulated low grid voltage. The test is performed by simulating parameters to produce an ECCS actuation, concurrent with simulating low voltage on the vital electrical busses.
b.
Observations and Findinas i
Several problems were identified by the test:
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The A-loop low pressure coolant injection (LPCI) system inlet isolation valve,
10-RHR.27A, failed to open as required during the ECCS initiation sequence. The cause I
was later determined to have been a design error attributed to a modification to the valve opening logic circuitry that was installed during the outage.
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The two pumps for the turbine building closed cooling water system failed to shed
when the vital busses de-energized due to the simulated low voltage. As a result, these
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loads started when the vital busses were re-energized by their respective diesel generators. Subsequent maintenance staff review identified that the pump control circuit time delay dropout relays had drifted out of tolerance (too long). These relays
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were re-calibrated and retested satisfactory.
The magnitude and duration of diesel generator voltage transients, as a result of major
loads starting, were larger than anticipated, but subsequently determined acceptable.
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Following correction of the equipment problems noted above, the ECCS integrated automatic initiation test was satisfactorily re-performed on October 18.
An operations staff performance problem occurred during restoration from the test. As an initial condition for the test, shutdown cooling was secured and the residual heat removal (RHR) system was aligned to prevent actual injection of water into the vessel as a result of the ECCS actuation. With shutdown cooling secured, the normal means for lowering i
reactor vessel water level (the reactor water cleanup system) was not available. By the test
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procedure, a contro! rod drive (CRD) system pump would be returned to service prior to restoring shutdown cooling, thereby causing reactor vessel level to slowly rise. This was of
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particular concern because, at the time of the test, one of the main steam isolation valves was disassembled. If reactor vessel water level were to rise to the level of the main steam lines, reactor coolant would spill over into the main steam lines and, in the case of the
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dismantled MSIV, out into the drywell.
The on-shift operations department personnel had recognized this potential problem prior to the test. It was anticipated that shutdown cooling (and therefore, the reactor water cleanup system) would be back in operation before the slow rise in reactor vessel water level, caused by operation of the CRD pump, would result in level approaching the main steam
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j lines. However, should a delay occur, the operators had established a level (below the j
steam lines) at which they would secure the CRD pump.
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Due to the complexity of the test, an off-shift senior reactor operator had been assigned as l
the test coordinator. While the shift supervisor retained sole authority to direct plant i
operations, the test coordinator was available to provide logistic support and, if required, to i
perform equipment manipulations. Following the ECCS initiation, parallel testing extended
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the duration of the test phase of the procedure. Since the test was taking longer than had been anticipated, the test coordinator independently initiated realignment of the RHR system i
in preparation for restoring shutdown cooling to service. Specifically, he directed that the l
low pressure coolant injection (LPCI, one of the operating modes of the RHR system) inlet
manual isolation valves (10-81 A/B, located in the drywell) be opened. Operation of these j
valves was specified by the procedure at a later point in the test. However, the test coordinator knew that valve 10-27A (LPCIinlet motor operated isolation valve) had not l_
opened during the test (due to malfunction) and incorrectly concluded that valve 10-278 l
was also closed. Although this operation was being performed out of sequence, the test
coordinator rationalized, at the time, that restoring shutdown cooling to service was i
important, and was attempting to make preparations in advance. The opening of 10-81 A
and 10-81B was directed and performed without the shift supervisor's knowledge end l
contrary to the surveillance procedure restoration phase sequence.
4 At the same time, operators in the control room were preparing to secure the CRD pump
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l due to reactor vessel water level approaching the high level point. However, after the CRD l
pump was secured, vessel level continued to rise at a more rapid rate than before. As the j
control room operators were attempting to determine what had happened, the Operations Manager (acting as the senior management observer for the surveillance test) noted that
valve 10-818 indicated open at the control panel. With valve 10-278 also open and the i
RHR' pumps running (both as a result of the ECCS test), this resulted in a flow path from the a-suppression pool to the reactor vessel. By the time that the operators understood the
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j situation and secured the associated RHR pump, approximately 3,000 gallons of suppression pool water had been pumped into the vessel and spilled out of the open MSIV and into the drywell.
There was no work in progress on the MSIV at the time of the event. The drywell had been evacuated prior to the ECCS test, so there were no personnel contaminated as a result of j
the spill, fhe cause of this event was determined by the VY staff to be cognitive ' personnel
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error, in that the test coordinator had taken actions out of sequence, in what was specified to be a verbatim compliance procedure. The licensee took prompt corrective action (including disciplinary action) to address this personnel performance error. The inspector confirmed that the licensee had prepared an appropriately detailed surveillance test and taken reasonable precautionary measures, including pre-briefings and management /
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supervisory oversight actions, to minimize the potential for reactor vessel overfill and/or
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personnel error in the conduct of the test. The inspector also confirmed that this procedural non-compliance was the result of a cognitive operator error. This licensee identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy.
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Conclusions Prior to conducting the ECCS integrated automatic initiation test, the licensee considered the possibility of a spill due to the ongoing MSIV maintenance..Although a vessel overfill and subsequent spill did occur, it was the result of a cognitive error made by a single individual, rather than inadequacy of the licensee's contingency planning. The procedural violation which caused this event was not cited. The October 18 re-test following corrective maintenance on equipment was appropriately conducted, and the corrective actione to address the operator error were timely and proper.
M1.4 (Open) IFl 96-09-04: Alternate Rod insertion Actuation due to Maintenance involving a Reactor Vessel Water Level Instrument On October 8, an Instrument and Contral (l&C) technician was performing operations to backfill the reference leg for one of the reactor vessel wide range water level instrument detectors. Filling a differential pressure icip) detector reference leg produces a higher than actual d/p which translates to a false low level detector output. The technician was not aware that this backfill operation would also result in filling the reference leg for two narrow range reactor vessel level detectors. These two detectors supply instrument channels that input to the alternate rod insertion system. When the technician commenced backfilling the reference legs, input to the two associated narrow range reactor vessel level instrument channels indicated that reactor vessel level was below the low-low level trip setpoint. This satisfied the trip logic for the alternate rod insertion system, which actuated to vent the scram air header.
This event had no effect on plant operations. Actual reactor vessel level was unchanged, and no rod motion occurred, since the reactor was shut down and all rods were already inserted. The licensee notified the NRC operations center (Event No. 31118) of this inadvertent ESF actuation as required by 10 CFR 50.72 (b), "Non-emergency events - four hour reports." Preliminary inspector review indicated that the job planning and the adequacy of procedural controls were root and/or contributing causes of this event. The inspector will examine additional details of this event during review of the licensee's event report submittal (IFl 96-09-04).
M1.5 (Open) IFl 96-09-05: Primary Containment Nitrogen Purge System isolation Valve Leakage On September 26, leak rate testing identified that the primary cnntainment nitrogen purge system inboard torus isolation valve was leaking in excess of the TS limit for any single valve. The cause of the leakage was determined to be misadjustment of the actuator mechanical stop.
The licensee determined that this condition constituted a serious degradation of the primary containment and was reportable to the NRC under 10 CFR 50.72 (Event No. 31064). The inspector will examine additional details of this event during review of the licensee's event report submittal (IFl 96-09-05).
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M1.6 ISI of the Reactor Pressure Vessel a.
Insoection Scooe (73753)
The scope of this inspection was to assess the inservice inspection (ISI) and nondestructive examination of the reactor pressure vessel welds, b.
Observations and Findinas
' The inspector observed the analysis of the ultrasonic (UT) data for the reactor pressure vessel (RPV) welds. The licensee noted five indications during the analysis and identified the indications for further evaluation. The NRC inspector reviewed the UT examination procedure, Southwest Research Institute Procedure VY-PDI-AUT-1, Revision 0, " Automated Ultrasonic inside Surface Examination of Ferritic Vessel Wall Greater Than 4.0 inches in Thickness," and VY-PDI-AUT2, Revision 0, " Automated Ultrasonic inside Surface Flaw Evaluation and Sizing." The examination techniques were demonstrated before the insurance companies representative, at the EPRI NDE Center, in accordance with ASME Code,Section XI, Paragraph IWA-2240. At the time of this inspection, the ANil was reviewing the details of the technique.
Volumetric examination of the RPV welds is required by 10 CFR 50.55a(g)(6)(ii). The volumetric examinations are to be performed in accordance with the American Society for Mechanical Engineers (ASME) Code,Section XI, " Rules for Inservice Inspection," in effect for the inspection interval. At Vermont Yankee, the 1986 edition of the ASME Code is in effect for the current inspection interval for inservice inspections (ISI). The examination techniques used at Vermont Yankee were qualified by the subcontractor at The Electric Power Research Institute (EPRI) NDE Center, in accordance with the Performance Demonstration initiative (PDl) program. The intent of the PDI program is to meet the requirements of ASME Code,Section XI,1989 Edition, Appendix Vill. VY requested, from the NRC, to use the PDI program and qualified techniques for the RPV UT examinations.
The 1986 Ec uon of the ASME Code,Section XI, Mandatory Appendix 1, invokes ASME Section V, Arnde 4 for performing the UT of reactor pressure vessels. ASME Code,Section V, Articie 4, Paragraph T-441.3.2.4, " Extent of Scanning," states in part, whenever feasible, the scanning of the weld volume shall be carried out from both sides of the weld on the same surface. Paragraph T-441.3.2.7, " Scanning for Reflectors Transverse to the Weld," states in part, the angle beam search units shall be aimed parallel to the welds and the scanning shall be done in two directions,180' to each other. Areas blocked by geometric conditions shall be examined in one direction.
The technique, qualified at EPRI by the subcontractor, was a 45 shear wave,55* shear wave, and two SLIC 40 transducers (SLIC 40 transducers are a Southwest Research Institute model name). The technique was qualified by scanning the flawed specimen blocks at EPRI in two directions, simulating one direction parallel to the weld and one transverse to the weld. A supplemental technique was developed to augment the PDI
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qualified technique. The supplemental examination was used to interrogate the Code
j required weld volume (IWB-2500, Figure IWB-2500-1 and 2) beneath the clad cracks.
General Electric published a Service Information Letter (SIL) alerting the owners of boiling
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i water.eactors (BWR) to a clad cracking issue. At VY the manually welded portion of the
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clad was found to have cracks. The clad cracks were first identified at VY during the 1993 refueling outage. The supplemental examination technique was demonstrated by the subcontractor before the ANil and the NRC, at the subcontractors facility, prior to performing the RPV UT examinations.
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Contrary to the ASME Code requirements, the detection technique used by the subr ontractor was scanning from one side of the weld, and in one transverse direction.
The technique was successfully demonstrated at EPRI for the PDI program. The NRC inspector requested the PDI steering committee on RPV examinations to clarify the
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l expectations of the scanning requirements on the RPV welds. The PDI steering committee offered no specific guidance on this issue. NRC NRR accepted the single sided scan based on the performance demonstration and the ANil's acceptance of the technique. The disparity between current ASME Code compliance, the PDI, and the Code of Federal Regulations is being addressed generically by the NRC staff.
l c.
Conclusion l
The RPV ISI was performed in accordance with established procedures. The analysis of the UT data was performed by qualified technicians. The UT indications were appropriately identified for further evaluation. The licensee had appropriate interaction and oversight of l
the ongoing NDE/ISI activities.
M1.7 Core Shroud l
l a.
Inspection Scope The scope of this inspection included assessment of the VY core shroud repair modification design review, materials conformance, manufacturing procedures, ultrasonic examination of the vertical welds inspected, and quality assurance of the repair procedure. Review was
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made of the core shroud repair modification design, fabrication of the core shroud modification components, core shroud modification quality assurance, and assess the l
ultrasonic examination of the vertical welds and accessible portions of welds H-8 and H-9 l
cn the core shroud.
b.
Observations and Findinas Core Shroud Repair Modification Desion Review l
The inspector reviewed the core shroud repair modification design, and found it to be in
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accordance with 10 CFR 50.55(a)(3)(i) through use of an NRC accepted alternative to the requirements of the ASME Boiler and Pressure Vessel Code Section Ill, Subsection NG,
" Core Support Structures." The modification design meets the criteria developed by the Boiling Water Reactor Vessel and internals Project (BWRVIP), "BWR Core Shroud Repair Design Criteria." The design provides for a system of four equally circumferentially spaced tie rods that prevent axial separation of core shroud segments in case any circumferential j
welds become cracked through-wall completely around the circumference of the core
shroud. Furthermore, radial supports are provided to preclude lateral motion of shroud supported core bundle.
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The inspector found the licensee's evaluation of the modification design, specifically the ability of the core shroud to sustain the load combinations specified in the Updated Final Safety Analysis Report (UFSAR) in accordance with ASME Boiler and Pressure Vessel Code for Nuclear Vessels Section lil, Subsection NB. The loadings considered in the evaluation included: the UFSAR design pressure differentials allowing for future potential core flow
increases and/or power up-rate; seismic loadings combined in accordance with NRC
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Regulatory Guide 1.92; and transient pressure effects resulting from a recirculation line break loss of coolant accident (LOCA). Flow induced vibration of the modification tie rods
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were evaluated to sustain fatigue loading due to flow excitation. Other considerations included loss of pre-load in the tie rods, and design attributes to preclude the deleterious e
effect of parts loosened during operation. The calculation methods included use of state-of-the-art digital computer techniques.
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The inspector reviewed the core shroud modification material Certificates of Conformance
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for each hardware component of the modification. For the 22 elements of the core shroud modification, several deviations from the specified requirements were noted by the licensee
and the effect of these deviations were evaluated to justify use of the part or replacement with a part with characteristics satisfying the requirements. These deviations, and their resolutions, were reflected in non-conformance reports (NCRs) or Contract Variation Approval Requests (CVARs). For example, Alloy X-750 material heats were accepted using air / fan cooling instead of oil or water quench because the materials were " cooled to black" within 10 to 12 minutes, in accordance with the purchase order requirements. Acceptance was based on microstructure examination of grain size and inclusion ratings, and the results of rising load tests. In the case of a marginal material deviation or non-conformance, the inspector found that VY engineering proceeded in a rigorous technical investigation of the deviation by analysis and/or test to allow acceptance of the material.
The inspector noted that X-750,304 or 304L, and (F)XM-19 stainless steel has been used in other BWR components and has not incurred corrosion problems. Carbon in type 304 alloys was found to be less than 0.03 percent and (F)XM-19 less than 0.04 percent. The Alloy X-750 allowable stresses are given in Code Case N-60-5. Pickled materials are required to have 0.010 inches removed from the surface before use. In general, emphasis has been placed on use of materials and conditioning to reduce the probability of incurring intergranular stress corrosion cracking (IGSCC).
The materials chosen for the core shroud modification were found acceptable in the NRR SER.
Fabrication of the Core Shroud Modification Components VV contracted the fabrication, installation of the core shroud modification to Framatone Technologies incorporated (FTI). FTl had the responsibility for materials procurement, fabrication, inspection, installation, and quality assurance of the core shroud modification components. Although the modification component parts had been delivered onsite, they were not installed on the reactor core shroud at the time of this inspection. The inspector reviewed the design concept developed by MPR Associates, and found the installation of the modification components to be feasibl ;
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Core Shroud Modification Quality Assurance Quality assurance (QA) of the core shroud modification components was performed by FTI.
They were responsible for attainment of the quality of the component parts and the
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installation. The inspector reviewed the planned and completed status of the quality
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assurance program to be performed on the core shroud modification. The program included a compatibility assessment of the quality assurance program with purchase order requirements, vendor verification, personnel certification and qualification, procedures for data evaluation, materials documentation, installation and test procedures, inspection tool application, compliance with vendor and VY procedures, and interface between FTl and VY.
The inspector considered the quality assurance program appropriate, with the exception that no independent VY staff verification of the tie rod pre-stress tightening had been planned at the time of this inspection. Subsequent to the onsite inspection, the inspector determined that the licensee did include and perform additional quality verifications of the tie rod pre-stress tightening via the shroud repair implementing procedure.
Core Shroud Vertical Weld Ultrasonic Examination The design of the repair for the core shroud at VY is dependent on the vertical welds having sufficient length of unflawed material. The subcontractor performing the ultrasonic
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examination of the core shroud qualified the examination techniques at EPRI, per the BWR Vessel Intemals Project (VIP) guidance. The examination technique uses a 45* shear wave, 60* longitudinal wave,80* creeping wave, and 2 eddy current probes (1 pancake and 1 cross-wound coil). The accessibility and examination of welds H-8 and H-9 was approximately 25 percent and 22 percent, respectively.
The inspector reviewed the approved procedures and observed the acquisition and analysis of the ultrasonic data for two vertical welds.
c.
Conclusions The inspector found the VY core shroud repair modification design review, materials conformance, manufacturing procedures, ultrasonic examination of the vertical welds inspected, and quality assurance of the repair procedure was performed in a manner meeting 10 CFR Part 50 regulatory guidelines and the relevant approved requirements of the ASME Boiler and Pressure Vessel Code for Nuclear Vessels.
The licensee performed the UT examination of the core shroud in accordance with the qualified procedures and techniques. The licensees analysis methodology for the UT data was performed satisfactorily. No recordable indication were noted by the licensee for the UT examinations. The licensee maintained good oversight and interaction with the subcontractor.
M1.8 In-Vessel Visual inspections a.
Inspection Scope The scope of this inspection was to review the final report of findings for the in-vessel visual inspection _ _ _
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Observations and Findinos
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As part of the ISI program, the licensee was required to perform a visual inspection of the reactor vessel intemal components. The BWR Owners' Group Vessel Intemal Project provides guidance for performing and evaluating the visualinspection. The inspector reviewed the procedures and the final report of the visual inspections.
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Conclusions I
The visualinspections were perfomled in accordance with approved procedures and with qualified technicians. No recordable indications were noted by the licensee.
M2 Maintenance and Material Condition of Facilities and Equipment l
M2.1 Main Steam isolation Valves Corrective Maintenance a.
Inspection Scope Leak rate testing, performed early in the outage, identified that outboard main steam isolation valve (MSIV) V2-86A was leaking in excess of its TS allowable limit of 11.5 standard cubic feet per hour (scfh) at 24 psig. After packing adjustment and additional testing, the source was determined to be seat leakage. The inspector observed various portion of the corrective maintenance performed on the valve, including valve reassembly and testing.
b.
Observations and Findinas The inspector noted no worker performance problems during observation of valve reassembly; however, during discussions with maintenance personnel, the inspector was informed of an additional problem that had been identified with the valve's air actuator. The as-found i
orientation of the actuator had been such that one of the two air exhaust pipes was angled upward. At some time during the operating cycle, packing leakage had developed from a valve above the upward pointing exhaust pipe which resulted in an introduction of water into the actuator. Although this condition was determined to have not affected operability of the
valve, some minor corrosion was noted inside the actuator where the water had pooled. As a result, the air actuator was replaced.
During closer examination and comparison of all eight MSIVs, the inspector noted that not all air exhaust pipes had 90-degree elbows installed on the ends. Although the elbows were i
presumably installed to prevent introduction of foreign material by creating a downward i
pointing vent, their orientation, where installed, was not always with the port down. The inspector concluded that the configuration of the air exhaust pipes and elbows was not controlled to the degree necessary to ensure that the vents would be pointed downward. This l-observation was discussed with maintenance management who indicated that this condition l-would be addressed.
j Later in the outage, additional leak rate testing identified excessive seat leakage from three l
other MSIVs (V2-80A, - 800, and - 86D). Lapping was successful in correcting the V2-86D leakage; however, weld buildup of the seats was required for V2-80A and -80C. Welding and
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j machining of the hard steel alloy (stellite) seats was performed by a contractor using
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,-, specialized equipment. This work represented a significant scope increase and required approximately one week to complete.
Shortly before final closecut, the inspector toured the drywell and noted that the configuration of the MSIV air operator exhaust pipes was still inconsistent (elbows missing or not pointing downward). The inspector also noted the same condition existed for the four MSIVs in the steam tunnel. It appeared that no action had been taken to address this item since the inspector's earlier discussion with the VY maintenance staff. After the condition was again discussed with the licensee, the situation was promptly addressed.
c.
Conclusions The licensee's corrective actions were poor in addressing a configuration problem (introduction of water into the upward pointing vent port) with a MSIV air actuator. Neither the discovery of water intrusion into the V2-86A actuator, requiring actuator replacement, nor the inspector's initial prompting caused the maintenance staff to closely examine the cause for the water intrusion and define an appropriate resolution. Proper corrective action was taken by the end of the inspection period, but only after further inquiries by the inspector.
M3 Maintenance Procedures and Documentation M3.1 (Open) VIO 96-09-06: Inadequate Battery Service Test Acceptance Criteria a.
Inspection Scope Industry Standards (IEEE-450) describes two different battery discharge tests. The performance test, which is the manufacturer's rated discharge current for a unit of time, determines cell aging. The service duty test, which is a calculated load profile, demonstrates that the battery has the capability of providing power for the design basis load profile.
The inspector reviewed the main battery surveillance discharge test procedure, OP 4215, Revision 6, " Main Station Battery Performance / Service Test," to determine the discharge test load profile and minimum acceptable battery voltage applied to the battery service test. These test requirements were compared with the related de system calculations.
b.
Observations and Findinas The inspector reviewed the recent battery maintenance with particular attention to the acceptance criteria associated with the service test. The inspector found that the licensee's procedure, OP 4215, did not contain any appropriate acceptance criteria for the battery service tests. The inspector questioned the basis for the test shutdown value of 105 Volts and alarm value of 106.7 Volts at the battery terminal during the surveillance test. The inspector observed that the dc voltage drop study (Calculation VYC-1349, Rey. O) was performed with minimum battery voltage inputs of 107 and 110 Volts for the main station batteries R-M A and B-1-18, respectivel.. _ _ - _ _ _ _ _ _ _ _ _ _._ _ ___ _.___.____ ____.
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Conclusion
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l There was no basis for the acceptance criteria contained in the battery surveillance procedure.
UFSAR, Section 1.9, states that the VY Quality Assurance program is in compliance with 10 CFR Part 50, Appendix B and ANSI N18.7-1976.10 CFR 50, Appendix B, Criterion XI,
" Test Contr01," and ANSI N18.7, Section 5.2.19.3, " Test Control," require test procedures to incorporate acceptance limits contained in applicable design documents. Contrary to the l
above, OP 4215, Rev. 6, Main Station Battery Performance / Service Test, did not contain appropriate acceptance criteria for the battery service tests. In aadition, the informal
acceptance criteria in the form of the test shutdown setpoint, had no basis in any design l
document. This is a violation. (VIO 96-09-06).
M3.2 Battery Service Test Automatic Data Recording a.
Inspection Scope The inspector reviewed the results of the surveillance tests of the main station batteries 1A and 1B to determine if the data recorded during the test documented the true condition of the battery.
b.
Observations and Findinas The inspector observed the automatic battery tester was programmed to print all cell and battery voltages and the discharge current every 15 minutes. However, the inspector found the 15 minute print sequence did not printout the highest (one minute) load peaks on the 1 A and 1B battery test voltage profile. The tester was programmed with an alarm at 106.7 volts and a test shutdown at 105 volts and the inspector verified that no battery alarm was recorded. When questioned by the inspector about the one minute load peak, the licensee responded by searching the battery tester computer disc for all of the recorded test data and printed the voltage values for the high one minute discharge,s. An attempt was made to retrieve similar data from previous battery service surveillance tests. The inspector was informed that the computer discs from all previous tests were overwritten and the data was lost.
The inspector reviewed with responsible maintenance engineer the one minute voltage dips that were recovered from the computer disc. The inspector verified that the battery voltages
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did not drop below the minimum calculated voltage used in the de voltage drop analysis. The inspector also confirmed that a review of the one minute load peak voltages was not previously performed by the VY staff for this test.
c.
Conclusion l
The inspector determined that the licensee considered the battery service test as a go, no-go test and was not going to either interpret the results for margin or use the results to trend j
battery performance. The inspector concluded that this limited use of available battery test
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data was a performance weakness.
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M3.3 Battery Discharge Test interruption Time Limitation a.
Inspection Scope The inspector reviewed the procedure used for the battery discharge tests to determine whether sufficient precautions were noted in the procedure.
b.
Observations and Findinas
The inspector noted that the procedure guidance for jumpering a bad cell during a discharge test failed to provide sufficient instructions for the maximum acceptable time the discharge could be interrupted, during the jumpering process, without negating the results of the test.
During an interruption of a discharge test, the battery will recover some capacity and this could skew the results of the test. The inspector observed that the service test for the 18 main station had been interrupted for approximately four minutes. The maintenance engineer indicated he was present during this test interruption and was aware of present industry
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guidance, contained in IEEE 450-1995, to restrict discharge test interruptions to less than six minutes.
c.
Conclusion The inspector concluded the test procedure was weak in the area of non-continuous testing guidance. However, the test interruption documented for the 1B battery test was sufficiently controlled by the maintenance engineer, so as not to void the test results.
M3.4 Battery Operation with 59 Cells a.
Inspection Scope
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The inspector reviewed the calculations to determine the basis statement for TS 3.10 which permits operation of the main battery with 59 cells.
I b.
Ooservations and Findinas The inspector noted the TS 3.10 basis statement permits one cell to be out of service. The inspector confirmed the battery sizing calculation (VYC-298) determines the required size of the main station batteries with either 59 or 60 cells. However, the inspector noted that neither
the de voltage drop analysis (Calculation VYC-1349) nor the battery service discharge test (OP 4215) addressed the condition of a 59-cell battery. Neither the engineering, maintenance nor operations personnel interviewed by the inspector were aware of ever operating with only 59 cells. The inspector reviewed the results of the recent 60 cell service test and observed that sufficient voltage margin existed to subtract the voltage contribution of an additional cell and still demonstrate the battery was operable.
c.
Conclusion The battery service test procedure did not provide sufficient guidance to justify operation of
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the main station batteries with only 59 cells. However, it appears that the licensee may not have ever operated with less than 60 cells and the recent service test results indicated
sufficient voltage margins, at the tested electrolyte temperature, to enable the licensee to justify 59 cell operation.
M3.5 DC System Low Voltage Alarm a.
Inspection Scope The 125 Volt de voltage drop study (Calculation VYC-1349) indicated that with 107 volts available at the A station main battery and 110 Volts available at the B station main battery, sufficient voltage would be available at the safety related de loads. The inspector reviewed the instrumentation and alarms available in the control room to allow the operators to assess the condition of the de system.
b.
Observations and Findinas The inspector leamed that no de meters were available in the control room to inform the operators of the de system voltage. The control room annunciator for low dc voltage was set
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at 125 Vde, an acceptable setpoint. However, the response procedure contained a caution l
statement which led the control room supervisor, interviewed by the inspector, to infer that the de equipment was operable down to 105 Vdc. The shift supervisor interpreted this to mean that only problem investigation and monitoring action was required following receipt of the low voltage alarm until the voltage dropped to 105 Vdc. At that point, the connected equipment would be required to be declared inoperable.
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Conclusion if the voltage had dropped to a value to trigger the low voltage alarm, it would mean that the battery was being discharged. The de system analyses and the battery surveillance tests are based on a fully charged battery. If the de voltage was left to discharge to 105 volts, there would be no assurance that sufficient capacity would remain to power the safety-related loads in the event of an emergency. This particular design information was apparently not fully communicated from engineering to operations (weak interface also addre ssed in M8.3).
M4 Maintenance Staff Knowledge and Performance M4.1 Battery Weekly Temperature Trending a.
Inspection Scope The UFSAR, Section 8.6.4, indicates that the minimum design temperature for the main station batteries was 60*F. Battery tempersture affects capacity. A previous NRC inspection (inspection report 50-271/92-81) documented that no temperature indication or alarm existed for the battery room. The inspector inquired into the history of battery room temperature and the temperature during the service tests.
b.
Observations and Findinas The inspector observed the cell electrolyte temperature measured at the beginning of the 1A main station battery test was recorded as 78"F. This temperature would provide j
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l approximately 11% additional capacity above the battery room minimum design temperature of i
60*F. Because there was initially no indication how much margin existed above 106.7 volts i
l-during the critical times in the discharge, there was no assurance that the battery would be i
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capable of providing its design load under the design minimum temperature conditions of l
60*F. The inspector confirmed the battery weekly surveillance procedure (OP 4210) Section
1.1.3 requires the pilot cell temperature be recorded. The inspector reviewed the plot of
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average temperatures recorded during the 1995 weekly surveillances that had been prepared
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j by the electrical maintenance engineer. The inspector observed that the plot of the main l
station batteries never dropped below 70*F.
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Conclusion i
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The inspector agreed with the licensee that a battery service test does not confirm the l
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adequacy of the battery at minimum design temperature. Therefore, the inspector noted the i
VY battery service test data cannot be trended. However, it appeared that the minimum
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l design temperature for the main station batteries may be conservative by at least 10*F.
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Therefore, the inspector concluded the "as found" service test temperature had minimal impact
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on the results of the test.
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M4.2 Battery Service Test Data Anomalies
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a.
Inspection Scope
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l The inspector reviewed the battery discharge tester cell and battery voltage printout to confirm the battery was tested in accordance with the required test profile.
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Observations and Findinas l
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The inspector identified some anomalies in the voltage printouts. For example, the one l
minute, three second report on the A ba+tery which had a higher overall voltage than the sum of the individual cells. The battery voltage had also increased by 7.4 volts from the reading
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only three seconds earlier with no change in test current. Another example was the B battery l
report at three minutes, six seconds, which also had similar anomalies. The responsible t
electrical maintenance engineer indicated that the anomalies were related to the computer
i scan rate and verified with the battery tester vendor that the scan rate and scan order could
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affect the logic of the stored results. The vendor indicated the computer scan rate was four seconds and the scan order was all 60 cells followed by overall battery voltage and then the l
test current. The licensee also stated that the vendor indicated the differences noted could
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also be attributed to rounding off the measured values.
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c.
Conclusion The anomalies observed by the inspector did not significantly affect the results of the test.
However, the inspector concluded that the maintenance engineering review of the service test
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results was not thorough.
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M4.3 Craft / Supervisory Performance - Personnel Error History
a.
Inspection Scope (62703)
l Using inspection procedure 62703, the inspector observed portions of selected maintenance
i activities to ensure workers used approved procedures to im@ ment proper work practices
i and received a proper level of supervision. Specific attention was directed at assuring that
l contract workers received monitoring equivalent to that afforded licensee workers. In this
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l regard, plant personnel were interviewed during observations of field activities. This
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inspection was part of an on-going NRC regional initiative to focus attention on maintenance
personnel error history detected in the prior SALP period. The following activities were
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I Outage Motor Operator Valve Maintenance
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EDCR 95-407, RCIC-20 Valve - Altemate Shutdown Installation and Test
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Observation and Findinas
During field observation of work activities, the inspector observed that approved written procedures were in use and the instructions were being followed by plant wc*rkers. Safety j
tagging for plant and personnel safety was properly being used. Where wiring terminations j
were being performed, the inspector verified that a duel verification practice was being employed to assure appropriate work quality. During the inspector's review of Engineering i
Design Change Request (EDCR) No.95-407 work activities at Motor Control Center DC-28 in j
i the reactor building's RCIC room, it was noted that the two workers were contractor personnel.
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Both individuals were knowledgeable of the job requirements and the identity of their assigned
foreman and W cognizant Maintenance Department supervisor. According to the workers, q
l they received technical training to perform their plant specific tasks at the training facilities at i
W's corporate offices. Also, the workers informed the inspector that the W maintenance
supervisor had earlier in the day visited to job site to review on-going activities and was noted i
to frequently observe and participate in field activities.
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Conclusions
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Knowledgeable personnel were observed to perform maintenance related activities in a l
professional manner, utilizing safe work practices and quality features in accordance with
approved procedures. The work activities associated with the portion of EDCR 95-407 that involved the RCIC system demonstrated a strong level of W mairitenance supervision
. involvement in field activities.
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M8 Miscellaneous Maintenance issues
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M8.1 -
(Closed) VIO 96 05-02: Testing and Inspection of the Suppression Chamber Cooling and Spray Modes of the Residual Heat Removal System i
j Violation 96-05-02 was issued because the licensee failed to perform a surveillance test on a
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containment spray header. In response to the violation, the licensee agreed to perform the i
required test, include all open-ended pipes in the surveillance program, audit the ISI program,
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and develop training for the W staff on the lessons leamed for this event. Except for the completion of W staff training, these corrective actions were to be completed by September 1996.
The inspector verified the surveillance test was completed and accepted, and reviewed the audit of the ISI program. During the review of the ISI program, the licensee identified one other component which was not tested. The licensee properly initiated an Event Report to disposition this additional missed surveillance test. The inspector verified the components j
i were placed in the ISI program for future examinations.
The inspector concluded that the corrective actions were appropriate to address the initial testing failure and to prevent further programmatic failures. Staff training on the missed surveillance tests was scheduled for December 1996. With the exception of the pending
training, W has completed their corrective actions and demonstrated an appropriate resolution to the violation.
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M8.2 (Closed) VIO 95-11-01: Inadequate inspection of Interior Drywell Head a.
Inspection Scope The inspector reviewed W's response to this violation for adequacy and verified appropriate implementation of the corrective actions.
b.
Observations and Findinos By letter dated August 11,1995, W responded to the July 14,1995 Notice of Violation. W
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i agreed with the violation and attributed the inadequacies of previous interior drywell head inspections to procedural weaknesses. To address this root cause two applicable procedures have been revised to ensure proper inspection of the physical condition of the interior drywell head. The inspector reviewed Operating Procedure (OP) 4029, Type A - Primary Containment Integrated Leak Rate Testing, revision 9, dated March 15,1996, and OP 5250, Maintenance / Inspection of Primary Containment Interior Surfaces, revision 3, dated July 18, 1996, and verified that clearly stated interior drywell head inspection attributes were specified and that inspection sign-offs attest to the as-found and as-left condition and any corrective l
actions taken.
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During the 1996 refueling outage, the inspector examirsed the interior drywell head and j
observed maintenance workers removing allloose or flaking paint with non-abrasive tools per OP 5250. Appropriate protective measures for radiological and potential occupational health hazards were noted by the inspector.
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c.
Conclusions The W staff's revision of applicable maintenance and testing procedures for periodically verifying the condition and integrity of the interior drywell head appropriately resolved the previously identified item of noncompliance. This violation is closed.
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M8.3 Maintenance - Engineering Interface
I a.
Inspection Scope I
The inspector reviewed the main battery discharge test procedure and associated references to engineering documents to detem3
'he basis for the required surveillance test acceptance criteria (also addressed in M3.1).
b.
Observations and Findinas The inspector observed that the only calculation referenced was the battery sizing calculation, WC-298, Rev. 9. The inspector confirmed that this calculatioa developed the load profile used in the service test for the main station batteries and also calculated the minimum expected cell voltage for both a 60 cell and a 59 cell battery. The inspector noted that the calculation for the dc voltage drop study, WC-1349, Rev.0, was not a referenced calculation.
The voltage drop study had been performed to demonstrate that sufficient voltage would exist
at the safety related loads fed from the main station batteries. Minimum battery voltages of i
107 and 110 Volts, obtained from Rev. 8 of calculation WC-298, were used as the input values for the voltage drop studies of 60 cell main batteries B-1-1 A and B-1-1B, respectively.
Via interviews, the inspector determined that the responsible maintenance engineer was not aware of these calculationallimits.
c.
Conclusion j
l The interface between the engineering group located in Bolton, MA, and the maintenance engineering department located at the W site for station battery design and testing was weak.
Current revisions to engineering documents that impact operating and maintenance procedures had evidently not been forwarded to the appropriate site personnel.
M8.4 (Closed) IFl 96-03-01: Recirculation Pump Trip Due to Maintenance Personnel Error a.
Inspection Scope During the performance of the calibration of ammeters for station service transformer T-7-1A on March 26,1996, an inadvertent actuation of an overcurrent relay tripped the supply breaker to switchgear 7. This resulted in a trip of the "B" recirculation pump, and caused the plant to enter single recirculation loop operation. The workers performing the activity were W j
contractor personnel. Event Report (ER) 96-0180 was initiated and assigned a severity level 2 significance that required a root cause assessment (RCA). The inspector reviewed the RCA j
on April 9,1996 which was performed by a W qualified investigator.
b.
Observations and Findinas
)
The RCA concluded that the root cause was related to work practices since there was a
,
failure to self-check / STAR (Stop, Think, Act, Review) during work order implementation.
Contributing causes were assigned to: (1) the procedure and work order in use lacked detail; l
(2) inadequate labelling, and (3) lack of direct supervisory involvement during implementation.
l The ER's barrier analysis worksheet also assigned weak, missing, or ineffective barriers to i
,
_ __ _ _ _ _ _ _ _ _ _ _
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pre-job briefing, system design, and drawings. Based upon a review of the details contained
.
in the RCA, the inspector concluded that another root cause could have been procedure l
!
deficiency, in that, their was an apparent lack of procedural and/or work order details (i.e., the
!
l development of step text in the work order) to have controlled the work and assured the
,
requisite level of quality.
l l
l Notwithstanding the designation of the root cause, corrective measures for this event were
.
determined by the inspector to be comprehensive and thorough, including short and long term
'
l measures to deal with procedural / work order step text instructions. The inspector was
,
j concemed that inappropriate designation of root cause could potentially " skew" the results of l
l trending assessments being performed as part of the corrective action process, and therefore i
l lead to the potential that there would be a failure to identify more significant program or
{
'
process weaknesses that need to be addressed.
'
The inspector also reviewed severity level 2 significance ERs 96-0281 and 96-0354 and noted l
that both of these were related to the aforementioned ER due to the fact that personnel error
.
- had also occurred by contractor personnel performing activities in the area of metering and relaying (M&R). As with the previous ER, the same qualified investigator performed the
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required RCA for these ERs.
i
- ER 96-0281 documented a May 1,1996 event which involved the lifting of a wrong lead performed as part of a meter calibration which resulted in an unexpected control room annunciator and the partial loss of overcurrent protection for the feeder breaker (3T1) to safety related bus 3. The W assigned root cause of the event was work practices; self-checkir:g not applied to ensure correct component. The inspector noted that the barrier analysis worksheet did not thoroughly assess this event, in that, factors such as pre-job briefings, equipment labeling, and supervisory involvement were not appropriately identified. In the area of written procedures and documents (e.g., work order, procedure); the barrier analysis stated that the instructions were correct, but were not expected to carry the detail required to specify the exact location of the correct wire and terminal board. This statement reflected a short-sighted analysis since another potential root cause was the level of detail in the procedure.
<
l ER 96-0354, which documented a sune 7,1996 event involving the failure to re-connect the ammeters for service water pump P7-1B following calibration, documented a clear example of procedural non-compliance involving the required restoration of installed test devices. In this case, two contractors performing M&R related activities failed to perform the required activity, including the performance of a verification of system restoration. The ER documented that one of the two contractor individuals was also involved in the two aforementioned ERs. The
inspector determined that the W root cause for this event (documents not followed correctly)
was appropriate. However, the barrier analysis was not thorough, in that neither the pre-job briefings nor the supervisory involvement were identified as failed barriers.
The long term corrective actions for ER 96-0354 included assigning a W electrician to M&R efforts and instructing all personnel performing M&R work in the following: (1) use the W
'
drawing system; (2) procedural compliance; (3) self-checking techniques; and (4) attention to detail. While the ER 96-0354 evaluation by W benefitted from the RCA taking into acccant that three events involving personnel error had occarred in the area of M&R work, the
,
l procedural utilization consideration did not appear to the inspector to be sufficiently highlighted
'
when viewing all three events in the aggregate. Notwithstanding this observation, the inspector considered the corrective actions for ERs 96-0281 and -354 to be good.
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To understand the relationthip of the above enumerated personnel error events in the context
!
l of the broader W maintenance staffs procedural adequacy and use performance, the i
inspector reviewed three recent 1996 Functional Area Assessments. These were the j
assessments performed by the Maintenance Department, the Instrumentation and Control
!
Department, and a general plant performance assessment conducted by the Quality Assurance Department (QAD). These assessments were determined by the inspector to
,
i provide valuable insights into W's self recognition that procedural quality (or adequacy) and j
adherence warrants continued attention, and that the three events and their causes were being addressed more globally by the action plans contained in the assessments performed
,
by the Maintenance Department and the QAD.
Specifically, the Maintenance Department's assessment described well directed efforts to
,
[
provide additional corrective actions that include: the conduct of " standards" meetings to be
,
l held for procedure writers and reviewers; targeting a department self-assessment to address
'
!
procedural compliance issues (including issues associated with the need for work order step
!
text and need for the additional procedures to benefit quality); and requesting that quality l
oversight activities (i.e., audit and surveillance) are performed in the areas that the
!
Maintenance Department is responsible for to ensure continued improvement. The inspector
noted that this latter action, in part, ascribed to procedure quality and effective written communication being an area of importance to the W staff. The QAD assessment also identified that procedural adequacy continued to warrant attention and that this, and human
'
performance, were elements to be routinely considered during their assessment process and i
are to be focused on as areas in need of improvement.
!
j c.
Conclusions
The three Event Reports that were evaluated contained instances of deficient Maintenance
.
!
Department performance in the area of procedural adequacy and adherence. This performance was contrary to Technical Specification 6.5, Plant Operating Procedures.
.
However, this licensee identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. The corrective
,
]
actions for these Event Reports were appropriate, but the depth and precision of root cause analysis for these events were identified as an area for improvement.
!
111. Engineering E1 Conduct of Engineering E1.1 (Open) URI 96 09 07: Core Spray and Residual Heat Removal Systems Containment isolation Valves Redesignated i
s.
Inspection Scope i
The inspector reviewed the W staffs actions to address the local leak rate testing failures associated with the core spray (CS) system inside containment injection check valves
1 (CS-13A/B and CS-30A/B), outside containment test isolation valves (CS-11 A/B), and the
'
residual heat removal (RHR) system inside containment injection check valves (RHR-46A/B),
j and outside containment test isolation valves (RHR-25A/B).
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j Backaround
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Prior to the 1996 refuel outage, the W staff conducted a comprehensive review of their l
Appendix J testing program (reference Licensee Event Report 96-004, dated March 1,1996)
.
and identified a number of deficiencies. Inclusive of the testing deficiencies were the CS and
t
!
RHR valves mentioned above. Rather than seeking exemption requests for not testing these i
valver, the W staff attempted to demonstrate, during the 1996 refuel outage, that these
valves could p ass a 44 psig air local leak rate test (LLRT). To facilitate this testing, minor
'
i modifications (small bore testing taps and isolation valves) were installed. However, by l
September 23, the VY staff concluded that none of the valves could pass an as-found LLRT.
I Because of the types of valves, their orientation in the flow stream, accessibility for i
j maintenance, and ALARA concems, the W staff explored attemative means by which to demonstrate the containment isolation functions and reliability. Consequently, the W staff has j
utilized Regulatory Guide 1.141 and ANSI N271-1976 (and the more recent revision l
ANSl/ANS 56.2-1984) to support the redesignation of the CS and RHR systems injection line
containment isolation valves via a 10 CFR 50.59 process.
!
b. : Observations and Findinas
!
l The inspector reviewed the engineering staff's safety evaluation for redesignation of the CS
and RHR isolation valves approved on October 12 and subsequently reviewed and approved
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by the Plant Operation Review Committee (PORC Meeting No.96-119) on October 16. Based i
upon a review of Regulating Guide 1.141 and ANSl/ANS 56.2-1984, which provide guidelines
for satisfying General Design Criteria 55 and 56 via some "other defined bases"(reference i
ANSI /ANS 56.2-1984, paragraph 3.6) the inspector determined that the W staff appeared to j
have adequately satisfied the criteria for an attemative design configuration. A summary of
,
j this safety evaluation was provided to the NRC staff by W letter, dated October 15,1996.
i i
The Region I staff plans to refer this issue to NRR and pending further NRR staff review of this 10 CFR 50.59 evaluation to support the redesignation of the CS and RHR system
,
j containment isolation valves, this issue is unresolved. (URI 96-09-07)
c.
Conclusions The W staff took appropriate action to identify and resolve longstanding 10 CFR 50, i
Appendix J, containment isolation valve testing deficiencies. The specific resolution of the CS
!
and RHR systems' containment isolation valves by redesignation of the isolation functions is i
pending further NRC staff review. (URI 96 09 07)
!
E2 Engineering Support of Facilities and Equipment E2.1 HPCI and RCIC System Motor Heater Follow-up i
a.
Inspection Scope j
l The inspector re-examined the high pressure coolant injection (HPCI) and reactor core j
isolation cooling (RCIC) systems motor heater issue (reference inspection report 50-271/
j 96-06, section E.2.1) to review the environmental qualification (EQ) requirements of both
systems and their associated components.
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b.
Observations and Findinas I
j The inspector reviewed controlled wire diagrams and the applicable portions of the EQ Program Manual with the responsible VY EQ engineer to confirm the EQ categorizations of
'
the RCIC and HPCI motors in question (RCIC gland seat vacuum pump and vacuum tank
,
condensate pump motors and HPCI gland seal condenser blower and condensate pump
-
motors, and HPCI auxiliary oil pump P85-1 A motor). The inspector verified that the EQ j
category for all of the above stated motors is category "C" for a steam line break within either
the RCIC or HPCI room. The same motors are EQ category "E" for the remaining analyzed j
(loss of coolant, main steamline, reactor water cleanup system or house heating boiler) high
!
energy line break accident scenarios. EQ category "C" identifies equipment that will
experience harsh environmental conditions during the design basis accident for which it need j.
not function for mitigation of that accident and whose failure (in any mode) is deemed not
_
i detrimental to plant safety or accident mitigation. EQ category "E" identifies equipment that
]:
will not experience harsh environment conditions during the specified design basis accident.
The inspector verified the technical basis for these above stated EQ categorizations and
.
confirmed that neither RCIC or HPCI systems are required to mit' gate large break " design
basis" LOCAs. However, HPCI is credited for small break LCiCA1 for up to two hours. The inspector notes that for large break LOCAs the reactor is rapidly depressurized and thus, no j
high pressure injection sources are needed or credited. For Se small break LOCA, the two l
hour crediting of HPCI availability is assumed because no fu'sl failure is postulated for small j
break LOCAs and thus a mild environment is preserved. Fcr high energy line breaks (HELB)
!
the EQ qualified safety systems are the safety relief valves (automatic depressurization
!
system) and the "A" and "B" CS systems. Notwithstanding. the EQ Prograin Manual states i
that the CS system: would only be used if the HELB made. HPCI and/or ROIC unavailable.
!
E c.
Conclusion I
l Based upon review of the HPCI and RCIC systems environmental qualification categorizations
- .
and supporting technical bases, the inspector verified that neither system was credited for accident mitigation for LOCA or HELB scenarios resulting in harsh environmental conditions in
'
j their respective rooms. Accordingly, the HPCI and RCIC motor heater deenergizations do not
- -
degrade the systems' safety function or Technical Specification defined operability.
a
,
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E3 Engineering Procedures and Documentation
~
E3.1 Battery Sizing Calculation Design Margin i
!
a.
Inspection Scope i
!
The inspector reviewed battery sizing calculation VYC-298, which formed the basis for the i
minimum battery voltage input for the de voltage drop study, to determine the correction
'
factors used to compensate the calcuiated minimum cell size for aging, minimum electrolyte
,
temperature, and design margin.
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b.
Observations and Findinas
'
The inspector observed that the temperature correction factor and the design margin were
unchanged from Rev. 8 to Rev. 9, but the aging correction factor had increased from 1.11 to 1.25 in Rev.9. The lower aging factor resulted in a higher calculated battery voltage in i
Rev. 8. The inspector found that the battery sizing calculation used a design margin of 1.0.lEEE Standard 485-1983, which was the referenced industry standard used for the battery sizing calculation, defines the purpose of design margin not only for future load growth, but also for "...less than optimum operating conditions," (including margin for improper
,
maintenance and recent discharge). Cell specific gravity is related to cell capacity. The I
inspector confirmed that the battery weekly surveillance procedure, OP 4210, Rev. 26, acceptance criterion 1.3, permits a cell to be considered in service as long as the specific gravity of the cell is at least 1.190. The LC-31 cells which make up the main station batteries A and B are considered fully charged with a specific gravity of 1.210. Therefore, a design margin of 1.0 is not conservative because it does not account for the permitted cell-specific
gravity below 1.210. This will also affect the calculated minimum battery voltage. However, potentially compensating for these larger correction factors, the inspector noted that Rev. 9 to the battery sizing calculation resulted in a lower demand on the 1 A battery, which would increase battery voltage. This was not the case for the 1B battery, but its load requirement was still lower than the 1 A battery. The inspector also noted that the calculated required cell size in both Rev. 8 and Rev. 9 of calculation VYC-298 was less than the installed cell size, providing additional design margin.
c.
Conclusion The methodology used for sizing the battery indicated sufficient margin existed for a minimum battery voltage of 105 volts. By not including some of that design margin in the minimum battery voltage calculation to account for less than optimum maintenance, the calculated voltage used as the input to the de voltage drop analyses was not conservative. By adding a factor for design margin, the calculated voltage input for the de voltage drop study would have been lower. In addition, the aging factor increased from 1.11 to 1.25 in Rev. 9. However, the decrease in the load current for battery 1 A in Rev. 9 would essentially balance the increase in the correction factors. Therefore, this deficiency did not alter the calculated required battery size.
E7 Quality Assurance in Engineering Activities i
E7.1 Emergency Diesel Generator's Air Receiver Wall Thinning
'
a.
Inspection Scope On October 11, the inspectors were approached by the VY staff with their resolution of two identified problems with the emergency diesel generators' (EDGs) starting air receivers. One item involved the air receiver's relief valve setpoint rating versus the air receiver design
,
pressure rating. The other item involved the resolution of recent ultrasonic testing (UT) results of air receiver as-found wall thickness versus ASME Code Section Vill minimum wall thickness requirements. The inspector examined these system operability concems and assessed the adequacy of the licensee's resolution _- -
.- -
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.
l
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b.
Observations and Findinas a
j Following a briefing by licensee representatives on the basis for concluding that neither of the above mentioned discrepancies compromised EDG operability, the inspectors examined the
'
supporting technical documentation (reference Yankee Atomic-Bolton memorandum VYM 203/
'
96, dated October 10,1996). The inspectors noted that the design engineering staff's
'
evaluation of the relief valve rating of 255 psig, (setpoint 5 psig higher than the 250 psig
'
nameplate rating of the air receivers), was appropriate, in that, the current calibration setpoint is 252.5 psi +/- 2.5 psi (250 to 255 psig). Per the applicable ASME Code Section Vill,
,
!
UG-134(d)1, the allowable relief valve setpoint tolerance of +/- 3 percent or +/- 7.5 psi, provides for the bounding of the installed relief valves setpoints within the receivers' 250 psig nameplate design pressure rating (242.5 to 257.5 psi). Further, the inspectors noted that the
air receivers' manufacturer data reports document a hydrostatic test pressure of 380 psig
. which provides significant margin between the normal operating pressure (225 to 250 psig).
Per the October 10,1996 memorandum, the design engineering staff dispositioned a below l
minimum value as-found wall thickness measurement (per UT examination technique) on the i
j SR-72-6C air receiver elliptical lower head by comparing the as-found UT measurement to a
'
!.
less restrictive calculated radiographic technique (RT) minimum wall thickness value. The i
inspector found this aspect of the evaluation unacceptable because the RT minimum wall i
. thickness value could only be applied if the as-found wall thickness value was measured by
RT. This conclusion was shared with the VY staff and following closer examination by the i
design engineering staff of the ASME Code Section Vill, the calculated minimum wall j
thickness values (using UT) were found to be in error.
Based upon the correct calculated minimum wall thickness of the air receiver elliptical head of f
0.265 inches, the licensee concluded that the as-found minimum thickness in one localized i
area of 0.261 inches (0.004 inches below the ASME Code minimum thickness) was acceptable for another operating cycle. In consultation with region based specialists, the j ~
inspector found the technical basis for the licensee's conclusion (which included a quantitative
!
]
stress analysis and qualitative Code review) appropriate. The inspector noted that the 0.004 j
inch difference between as-found and Code required wall thickness was within the accuracy of -
the UT examination instrumentation.
i c.
Conclusion l
)
VY's identification and short term resolution of EDG air receiver inservice testing and
inspection results was appropriate. Design engineering's initial dispositioning of the bottom i
elliptical head wall thickness issue lacked quality and precision, but was adequately revised.
t a
j IV. Plant Support
j R1 Radiological Controls l
' The licensee's program for occupational radiation exposure and radiation safety was reviewed.
l Specific areas reviewed included: audits and assessments; changes in personnel, procedures, and equipment; extemal exposure controls; intemal exposure controls; control of F
i
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.
-
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-
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-- -
radioactive materials and contamination, surveys and monitoring; and the program for maintaining personnel radiation exposures ALARA. The inspection also included a review of previously identified items and implementaticn of the UFSAR.
R3 Radiation Protection Procedures and Documentation R3.1 External Exposure Controls a.
Inspection Scope (83750)
i The inspectors reviewed the implementation of extemal exposure controls through tours of the facility, reviews of documentation, and interviews with various licensee individuals. The
'
controls included posting and barriers for high radiation and very high radiation areas, posting of current plant status and dose information, ALARA caution signs, and the personnel dosimetry program. The inspectors made observations during tours of the drywell and discussed radiological posting practices with technicians and supervisors.
b.
Observations and Findinas Postings and barriers were appropriately used throughout the facility to wam workers of high radiation areas and to prevent inadvertent entries. Areas with dose rates above 1000 millirem per hour were locked and controlled by radiological controls personnel to prevent unauthorized
,
entry. Very high radiation areas were locked and required administrative approval prior to
)
entry.
VY sent all thermoluminescent dosimeters (TLDs) to the Yankee Atomic Laboratory for processing. The licensee's personnel dosimetry system had passed the laboratory testing performed by the National Voluntary Laboratory Accreditation Program (NVLAP). The laboratory testing and onsite assessment are required every two years for NVLAP accreditation. The NVLAP accreditation is required by the NRC for TLD systems.
Perst inel were observed by the inspectors wearing the appropriate dosimetry. The licensee used.adiation work permits (RWPs) to control exposure and other radiological conditions. An automated access control system that interfaced with the alarming digital dosimeters was also used to track and control exposures. However, the dose recorded from the digital dosimeters was actually lower (20 - 30%) than the dose assigned from a TLD for the same monitoring period. The lower readings were recently identified by the licensee's staff after some enhancements were made to the system software. Previously, the TLD dose was typically lower than the digital dosimeters and the licensee's staff was trying to eliminate this bias. This was identified as a minor program weakness by the inspectors since the digital dosimeter dose was used to control personnel exposure to avoid exceeding a regulatory or administrative dose limit. However, the potential for exceeding a limit was low due to other administrative controls, such as, processing the TLDs when a lower dose was accumulated by digital dosimetry. The licensee's staff was still evaluating the causes and effects of recent changes, as well as, potential solutions to improve the precision of the dose tracking system.
Current survey information was posted at the main entrance to the radiologically controlled area (RCA). The posted surveys were current and had sufficient level of detail to properly inform workers regarding radiation dose rates and contamination levels in work area The licensee provided good pre-job briefings for radiation workers entering the drywell. There were also radiological postings in the drywell. On all levels, ALARA warning signs were posted for areas where the dose rates significantly increased from background levels. The licensee used a locking ladder cover and posting on the vertical access ladder to the upper reaches of the drywell that prohibited access when fuel movement or control blade movements were occurring.
The inspectors reviewed records of personnel exposures for individuals who were required to be monitored as per licensee procedures and NRC regulations. The records were maintained in good order and no deficiencies were identified.
c.
Conclusions in summary, the licensee provided very good controls for external exposure. High radiation areas were appropriately barricaded and/or locked. Extemal dosimetry was appropriately used by licensee personnel. Radiological work was well controlled through the use of RWPs and the automated access control system. Current radiological and plant information for work areas were available to workers. The licensee provided good radiological briefings for drywell workers. Minor program weakness was identified with the dose assignment process from the electronic dosimeter system. Records of extemal exposure and total occupational exposure were appropriately maintained.
R3.2 Internal Exposure Controls a.
Inspection Scope (83750)
The inspectors reviewed the implementation of intemal exposure controls through tours of the facility, reviews of documentation, and interviews. Controls included air handlir.g systems or other engineering controls for potential airbome areas, air monitoring, posting of airbome areas, use of respiratory protection, and intemal dose assessments.
b.
Observations and Findinas The inspectors verified through tours that air monitoring and ventilation equipment was available for use in potential airbome areas. Although no areas were posted as an airbome area, HEPA filters were provided for decontamination areas. There was only one respirator issued for radiological control purposes during the refueling outage. This low use of respiratory protection was a result of successful controls to limit the concentrations of airbome radioactivity in the work areas.
The inspectors reviewed intemal dose assessments and assignments during 1996. The assignments were derived through a calculation based on the workers' stay times in an area and measured concentrations of airborne radioactivity, as well as, bioassay (whole body counting) measurements.
During 1996, the highest individual committed effective dose equivalent (CEDE) assignment was 26 millirem. NRC regulations allow a total occupational dose assignment (intemal plus extemal dose) up to 5000 millirem per year. The dose assessments were derived using the licensee's approved procedures and technically acceptable assumption.
.
_
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.
.
__
Also reviewed were the records and reports required after the workers had terminated employment at the site. The reports were in compliance with 10 CFR 20 and liceasee
,
procedures.
c.
Conclusions Overall, the licensee effectively provided very good intemal e.vposure controls. Engineering
,
controls were made available to help limit airbome radioactivity and intemal intal;es. Air
,
monitoring was performed to assess the concentration of radionuclides in the work area.
Intemal dose assignments were very low as compared to regulatory limits and total assigned
dose. Records and reports of intemal dose assignments were thorough and well documented.
.
The licensee demonstrated very good contamination controls during the outage and provided i
very good air sample monitoring program with the result of very low internal exoosures to i
personnel.
.
,
R3.3 Control of Radioactive Materials and Contamination, Surveys and Monitoring
,
a.
Inspection Scope (83750)
l The inspectors reviewed the implementation of the controls of radioactive materials and contamination, surveys and monitoring through tours of the facility, reviews cf documentation, and interviews. These controls included posting and identification of contaminated areas,
~
labelling of radioactive materials, monitoring and frisking equipment, use of protective clothing, and radiological surveys of work areas.
'
b.
Observations and Findinas il
!
Control of radioactive materials was good throughout the RCAs of the plant. Caution labels
,
were attached to bags of trash, storage bins and cabinets, vacuums, and miscellaneous equipment. Allitems with caution labels were also labelled with other appropriate information such as dose rates, contents, and date of survey.
,
i Contamination controls were generally good. Contaminated areas were posted with waming j
signs and delineated with rope boundaries. Step-off pads were provided to mark entry and exit points from the contaminated areas. Containers were prnvided for potentially contaminated protective clothing at the exits from the contaminated areas. Workers in i
contaminated areas were observed wearing the appropriate protective clothing. Current contamination survey information was posted at the main entrance to the RCA.
The inspector observed a technician performing a contamination survey to release items from r
a contaminated area. The technician performed the survey in accordance with the licensee's I
.
'
procedure. Discussions with the technician indicated a sensitivity to items with potential intemal contamination.
Monitoring and frisking equipment were available throughout the plant at various locations.
The inspectors verified through random reviews that the equipment in the field was within the current calibration period and had documented daily performance checks.
,
.. _._
__.-_.__.-_.______.__..___.__.___.mm___
_
i
,
J
,
i c.
Conclusions i
,i
. The licensee provided good controls for radioactive materials and contamination. Caution
,
'
labels and postings were used appropriately. Contamination controls were generally good.
!
Surveys performed to release items for unrestricted use were performed appropriately.
!
Equipment for monitoring and control of contamination was maintained and made available to
!
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workers throughout the facility.
R3.4 ALARA Program a.
Inspection Scope (83750)
!
!
The inspectors reviewed the implementation of the ALARA program through tours of the facility, reviews of documentation, and interviews with various licensee individuals.
,
'
l
!
b.
Observations and Findinas
a
!
The licensee had established a goal for less than 180 person-rem for work activities
!
performed during the refueling outage. The actual total exposure to all workers was
approximately 80 person-rem as of September 26,1996. The actual exposure was less than the exposure accrued in previous outages. The licensee attributed this lower exposure total to i
program initiatives including various dose reduction ideas and lower dose rates in most areas i
of the plant. The highest individual total dose for the year was less than 2 rem. The annual l
occupational exposure regulatory limit is 5 rem.
l Some of the exposure reduction initiatives included the use of cameras for the firewatch in the i
drywell, trial use of a radio digital dosimeter system, increased shielding, the use of system
l flushes, and the use of mock-ups or pictures of components for pre-job briefings.
l i
Worker involvement in the ALARA program was good. When questioned by the inspectors, i
l several workers were aware of dose rates and methods to lower the total exposure.
I l
The inspectors found that the ALARA reviews were well documented, including pre-job
{
reviews and active reviews cf ongoing work. Although the active reviews of ongoing work j
were not always filed with the ALARA review documents, the W staff produced various j
documents that contained usefulinformation regarding these reviews. The post-job reviews j
had not yet been completed because most jobs were still in progress.
j a
!
c.
Conclusions i
l
{
The licensee's staff had established aggressive and realistic personnel radiation exposure t
goals for the 1996 outage work. Dose reduction initiatives were implemented for the refueling j
outage activities. The W staff was successfully using the information to continue to imptove
processes and procedures and lower workers' radiation exposures.
f
1
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...
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, _ _ _ -.
. - - - - - - - - -
_ -.
R6 Radiation Protection Organization and Administration R6.1 Changes in the Radiological Controls Program u.
Inspection Scope (83750)
Changes to the radiological controls program were reviewed by the inspectors through interviews with VY personnel.
b.
Observations and Findinas The licensee had made some temporary changes in the radiological controls organization for the refueling and maintenance outage. in addition to the normal staff of 15 radiation protection technicians and six radiation protection supervisors, the licensee had approximately 80 contract health physics technicians to provide oversight of radiological work activities. This
created a large number of contract employees per each licensee supervisor; therefore, the licensee management designated lead technicians from the permanent staff for each shift in
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varioas areas of the plant. These lead technicians, along with the supervisory staff, provided oversi3 t and guidance to the contractor workers. The inspectors determined that the outage h
organization was effective and no performance problems were observed.
c.
Conclusions The temporary staffing changes made to the radiation protection organization for the refueling and maintenance outage were effective and no negative consequences were observed.
R7 Quality Assurance in Radiation Protection Activities R7.1 Audits and Appraisals a.
Inspection Scope (83750)
Audits, surveillance reports, and internal assessments of the radiological controls program conducted since the last NRC inspection were reviewed by the inspectors.
b.
Observations and Findinas There had been no formal quality assurance (QA) audits of the radiological controls program conducted since the last NRC inspection. The licensee's QA staff had performed various surveillances of radiological control activities and the associated surveillance reports documented a few minor problems. In response to these QA identified problems, the licensee initiated timely and technically acceptable corrective actions to prevent recurrence.
An intemal assessment had been performed by the licensee's Radiation Protection Manager for the period from June 1995 through May 1996. Areas assessed included administrative controls, operational radiological controls, instrumentation, radiation dose assessment, the ALARA program, and the radwaste program. The assessment was of good quality and probed for systematic problems. The licensee's staff identified some minor areas for improvement and suggested an action plan for the next one-year period. The action plan was _
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based on performance / risk-based assessment. The areas of corrective actions, self-
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assessment, high radiation area controls, external monitoring, and receipt of radioactive materials were listed as areas needing improvement.
c.
Conclusions The licensee continues to improve the quality of the radiological controls program through the self-identification and correction of minor deficiencies and program areas for improvement.
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R8 Miscellaneous Radiation Protection Issues R8.1 Review of UFSAR Commitments a.
Inspection Scope (83750)
The inspectors reviewed the implementation of the Updated Final Safety Analysis Repc-t (UFSAR) in the area of radiological controls (Section 13.4). Specific items included personnel access control, personnel monitoring, and radioactive material controls.
b.
Observations and Findinos A recent discovery of a licensee operating its facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR description. While performing the inspections discussed in this report, the inspectors reviewed the applicable portions cf the UFSAR that related to the areas inspected. No inconsistencies were noted between the wording of the UFSAR and the plant practices, procedures, and/or parameters observed by the inspectors.
As stated in the UFSAR, the access control system was used to prevent inadvertent access to high radiation areas. The personnel monitoring systems were assigned by the Radiation Protection Department and the equipment was available on a daily basis. Records of radiation exposure were also maintained by the Radiation Protection Department. The licensee had performed a radioactive source inventory in January 1996 and July 1996. The UFSAR stated the source accountability and inventory records are updated semi-annually.
c.
Conclusions The bcensee was effectively implementing the UFSAR commitments. No inconsistencies were identified in the radiation protection program activities, as described in the UFSAR.
R8.2 (Update) URI 96-03-05: Removal of Reactor Vessel Shield Blocks at Power A potential violation was previously identified in inspection report 96-03 regarding the removal of the reactor shield blocks at power. VY staff review of plant refueling practices identified that preceding the 1990 and 1992 refuel outages all three layers of reactor vessel shield blocks were removed while at power. This condition was determined to have been in conflict with the plant design basis. The apparent root cause of this problem was inadequate procedural guidance, but further evaluation was ongoing. This issue was unresolved pending VY completion and inspector review of the final root cause evaluation.
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These events were outside the plant design basis with respect to the 30-day radiation
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exposure to personnel in the Technical Support Center (TSC) following a design basis
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accident. Based upon conservative estimates, W concluded that the total dose to personnel
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in the TSC could potentially exceed five REM, which conflicts with the requirements of i
NUREG 0737, item II.B.2, and the W design basis (reference LER No. 96-03).
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l The inspector determined that a procedure revision implemented prior to the 1995 refuel
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outage prevented more than ons layer of shield blocks from being removed prior to that reactor shutdown and subsequent refueling. Follow-up by the inspector also identified that, in addition to radiation shielding, the reactor vessel shield blocks provide significant mechanical
barrier protection of the primary containment against tcmado or high wind generated missiles.
Similar to the radiation shielding minimum thickness calculations developed by the W staff, I
the minimum missile protection requirements (thickness of concrete) provided by the reactor i
vessel shield blocks is 18 inches of concrete (reference FSAR Section 5.2). Accordingly, one layer of shield blocks (24 inches in depth) provides sufficient missile protection under the
postulated design basis event. At the close of the inspection period, W had not completed
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their root cause evaluation of this issue and had preliminarily attributed the cause to a lack of
l formal procedural guidance for the removal of vessel shield blocks. This unresolved item j
remains open.
I R8.3 Housekeeping Observations I
i During the outage, the inspector toured normally inaccessible arear, of the plant (the drywell, condensate and heater bays, and the steam tunnel). Overall material conditions were good;
the inspector identified very few material discrepancies that were not already planned for
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repair. As the outage neared completion, the inspector focused on housekeeping conditions.
l General plant cleanliness was very good, and restoration efforts 'ollowing the 5A/B feedwater heater replacement were particularly noteworthy. Significant clealup effort was also evident in the steam tunnel, which had been the site of numerous extensive maintenance activitiec.
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R8.4 Drywell Closeout Tour i
j The inspector accompanied the licensee during the tmal closecut tour of the drywell.
l Cleanliness of the downcomers and the ring header was very good. No temporary postings or placards (i.e., ALARA postings, confined space postings, and step-off pads) that could cause
j blockage of the suppression pool suction strainers were found, and no remaining temporary
material storage locations were noted. Overall cleanliness of the drywell was very good. The
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inspector concluded that material and housekeeping conditions in the drywell were satisfactory j
for reactor operation. Additional observations are addressed in Section M8.2 of this report.
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P1 Conduct of Emergency Preparedness (EP) Activities
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a.
Inspection Scope (82701)
The inspector reviewed the licensee's action item tracking system and the Emergency
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Planning self-assessment program to determine the effectiveness of licensee controls.
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b.
Observations and Findinas
Using an Event Report (ER) involving the Ames Hill transmitter (see section P8.2 below) and
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other EP related ERs and action items, the licensee's tracking systems wat. checked for
completeness in accomplishing corrective actions and for timeliness'of closure. Additionally, i
the inspector reviewed the licensee's self-assessment program used to identify areas for i
improvement in the EP program. Some of the improvement areas identified included,
additional support for the State of Vermont for emergency response activities, thorough review
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of the emergency action levels and basis document, and 10 CFR 50.54(q) reviews of
emergency plan implementing procedure (EPIP) changes.
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c.
Conclusions
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For those EP items reviewed, the ER corrective action and tracking system was found to be l
complete and useful. Additionally, the self-assessment program was being implemented in an
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acceptable manner and appeared to be effective.
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P2 Status of EP Facilities, Equipment, and Resources
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a.
Inspection Scope (82701)
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l The inspector conducted an audit of emergency equipment in the Control Room, Operations j
Support Center (OSC), Technical Support Center (TSC), and Emergency Operations Facility l
(EOF). The inspector also reviewed facility equipment inventories and surveillance test
i records conducted during the past six months for compieteness and accuracy.
l b.
Observations and Findinas
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j The inspector toured the control room, TSC, OSC and EOF and found them to be
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o'perationally ready. Also, the inspector checked the inventory of several emergency kits for
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completeness.
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l The inspector reviewed the March through August 1996, emergency facility inventories and
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surveillance test records and found them to be complete and conducted on a timely basis.
The inspector noted two anomalies; 1) the TSC continuous air monitor (CAM) was out of i
service for a period of six months because of the unavailability of parts, thus requiring the use
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of additional habitability surveys if the facility was required to be activated; and,2) survey instruments located in the emergency kits and maintained by radiation protection, were discovered to be out of calibration during several monthly EP inventory checks. EP
immediately replaced the instruments, however, the inspector noted that the EP Coordinator
(EPC) did not seek an explanation from radiation protection (RP) as to why instruments in the emergency kits were not replaced in a timely manner. The inspector stated that the EPC j
needed not only to review the inventories for completion on a monthly basis, but also needed to review them to determine if any adverse trends were developing over a period of time. The
EPC, after further investigation into these matters, immediately prepared ERs for RP to j
determine why the replacement of instruments in emergency kits had not been done on a
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timely basis. Also, the inspector noted the calibration sticker on a stabilized assay monitor in
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the EOF, which is one of the instruments used to determine radioactive iodine content on
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silver zeolite cartridges, was not current. Additionally, the EPC indicated that the parts for the j
TSC CAM had arrived, and the CAM was being repaired.
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c.
Conclusions l
The inspector found the inventories to be complete. Instruments, except as noted, were
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calibrated, and those found to be out of calibration were immediately replaced. The facilities were generally in a state of readiness. However, inventory findings received minimal
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supervisory attention to determine if any adverse trends are developing. The established ER system was not used until addressed by the inspector.
P3 EP Procedures and Documentation
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a.
Inspection Scope (82701)
l The inspector reviewed recent Emergency Preparedness implementing Procedure (EPIP)
changes submitted under 10 CFR 50.54(q) to assess the impact on the effectiveness of the EP program. The inspector also assessed the process that the licensee used to review EPIPs and changes made to them.
b.
Observations and Findinas The inspector performed an in-office review of revisions to the EPIPs submitted by the licensee between May and August 1996. Listed below are the specific EPIPs reviewed.
Procedure Procedure title Revision (s)/ Change (s)
Number Reviewed OP 3507 EMERGENCY RADIATION EXPOSURE
CONTROL OP 3508 ONSITE MEDICAL EMERGENCY
PROCEDURE OP 3511 OFFSITE PROTECTIVE ACTION
RECOMMENDATIONS OP 3524 EMERGENCY ACTIONS TO ENSURE
INITIAL ACCOUNTABILITY AND SECURITY RESPONSE OP 3534 POST ACCIDENT SAMPLING OF
l PLANT STACK GASEOUS RELEASES i
c.
Conclusions The revisions met the 10 CFR 50.54 (q) requirements and did not reduce the effectiveness of the emergency plan.
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j P5 Staff Training and Qualification in EP a.
inspection Scope (82701)
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The inspector reviewed EP training records, training procedures, lesson plans and the emergency plan, to evaluate the licenses's EP training program. The inspector also reviewed the EPIPs associated with on-shift dose assessment to gather information for NRC's Temporary Instruction 2515/134 " Licensee On-Shift Dose Assessment Capabilities."
i b.
Observations and Findinas The inspector reviewed training records for operations personnel, emergency directors and RP personnel to determine that they had received required training. In addition, the inspector observed a demonstration of the offsite dose projection system (ODPS) in the simulator control room by the acting Training Manager. The Training Manager went through the ODPS procedure step by step. The simulator generated meteorological information (e.g. wind direction, wind speed, and delta temperature) for the meteorological data, and radiation data for a stack release. The inspector observed that the ODPS was functional for a monitored release only. If the release is through an unmonitored pathway, the operations staff and the chemistry technician / control room communicator are trained to use the nomogram backup method. The RP staff is trained to operate ODPS, the Meteorological Post Accident Computer model dose projection system, and the backup nomogram.
Additionally, while the inspector was touring the plant control room, the inspector verified with the on-duty Shift Supervisor that training was provided on the ODPS, the computer model, and the backup method.
c.
Conclusion The operations personnel, emergency directors, and RP staff were being trained and that the training program was being effectively implemented. Additionally, the licensee has appropriate provisions for on-shift dose assessment and the necessary personnel have received adequate training.
P6 EP Organization and Administration a.
Inspection Scope (82701)
The inspector reviewed the EP group staffing and management changes since the last program inspection (May,1995) to determine if any changes had an adverse effect on the EP program.
b.
Observations and Findinas
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During the last inspection, the inspector noted that, after the company reorganization in August 1994, the EPC reported through the Operational Support Manager (OSM) to the Vice President, Operations (VP-Ops), who reports to the President. This resulted in the EP Group being one additional level removed from the President. During this inspection, the inspector discussed this matter with the EPC. The EPC stated that he had daily contact with the OSM
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l and that he attended the President's Monday moming manager's meeting where he could raise EP issues, if necessary. The EPC stated that since the EP group was now in a more j
technical reporting chain, its interface with Operations had been increased.
I The inspector found that the EP group was stable and had been enhanced by the addition of
one full-time individual with health physics expertise from the Yankee Nuclear Services Division.. The individual was previously with the VY EP Group on a part-time basis.
The inspector also interviewed the OSM, VP-Ops, and the President and Chief Executive Officer (CEO) to determine management involvement in the EP organization. The OSM and i
VP-Ops were both qualified as site recovery managers in the Emergency Response Organization and were very aware of current EP issues. The President and CEO had been with VY for only three months. He was well informed of EP issues and indicated that the EP group had been spending a large amount of time assisting the State of Vermont with emergency planning issues.
c.
Conclusions The emergency planning staff was stable and no major program changes had been made since the last inspection. Additionally, the inspector concluded that management involvement and oversight of the EP program were excellent.
P7 Quality Assurance (QA) in EP Activities a.
Inspection Scope (82701)
The inspector reviewed the QA audits of the EP program, required by 10 CFR 50.54(t), that
. were conducted in 1995 and 1996.
b.
Observations and Findinas The 1995 audit had one finding and eight recommendations. The 1995 finding was related to the correctness of the quarterly telephone updates. The 1996 audit had two findings and seven recommendations. The 1996 findings were minor problems. The recommendations made in each audit were program enhancements. Both audits were performed by a Yankee Nuclear Services Division QA auditor and independent contractor personnel. The audits were thorough and met all of the 10 CFR 50.54(t) requirements, including the offsite interfaces.
The audit reports had been submitted to the appropriate management personnel. The
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inspector also noted that there were no recurring items in either of the audit reports.
l The inspector also reviewed copies of transmittal letters that forwarded the executive summary, and the results of the state interface portion of the audit to the Emergency i
Management Directors for the States of Vermont and New Hampshire and the Commonwealth of Massachusetts, as required.
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Conclusion
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The licensee had conducted audits in accordance with 10 CFR 50.54(t) requirements.
P8 Miscellaneous EP issues l
PS.1 Updated Final Safety Analysis Report (UFSAR) Inconsistencies l
A recent discovery of a licensee operating its facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, l
procedures, and/or parameters to the UFSAR description. Section 13.6 of the UFSAR refers to the Emergency Plan (EP). Since the UFSAR does not specifically include EP requirements,
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the inspector compared licensee activities to the emergency plan. The inspector reviewed on-
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shift dose assessment capabilities and training as discussed in Section PS. No discrepancies were noted.
P8.2 Ames Hill National Oceanic and Atmospheric Administration (NOAA) Transmitter i
a.
Inspection Scope The inspector reviewed two notifications made to the NRC on December 25,1995 (later l
withdrawn) and February 7,1996, which concerned the operability of the Ames Hill NOAA l
transmitter. The Ames Hill transmitter is part of the public notification system for the Vermont Yankee Nuclear Power Station and has had several problems over the past few years. The inspector held discussions with the licensee and reviewed the closeout documentation for Event Report 96-0089 which addressed the NOAA transmitter problems.
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b.
Observation and Findinas The inspector found that JPS Communications, which is the contractor that maintains the public notification system for the licensee, had made information only calls to the VY control room on December 25,1995, at 1:45 p.m. and February 7,1996, at 9:30 a.m., to inform them l
that there may be problems with the Ames Hill NOAA transmitter. The control room had no criteria on how long the transmitter could be out of service (planned or unplanned) before notification to the State and NRC are required. Additionally, the Burlington National Weather Service link to the Ames Hill transmitter could be out of service and not affect the operation of the Ames Hill transmitter, because the backup from WTSA Radio Station studio to transmitter link could be used to activate the public notification system. This lack of criteria resulted in the control room operators making notifications to the NRC on the previously mentioned dates.
On March 21,1996, the EPC held a meeting with Operations, Operations Training, Emergency Preparedness, and JPS Communications personnel. The purpose of the meeting was for JPS l
Cornmunications to explain how the NOAA transmitter link operated and how it affected the l
pubhc notification system, and to establish criteria for control room operators to make the notifications to the NRC and State of Vermont Emergency Management.
As a result of the meeting, two recommendations were implemented: 1) JPS Communications guidance was revised in an attempt to provide the control room with clearer messages when
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problems with the Ames Hill transmitter occur, and 2) criteria were established and incorporated into procedure AP 0156 to provide operators with better guidance for NOAA transmitter out of service required notifications.
c.
Conclusion l
The licensee had taken appropriate corrective action to address the notification problems to
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the NRC and the State of Vermont. Proper action was taken to provide clearer messages from JPS Communications personnel to the W control room operators involving the status of the Ames Hill NOAA transmitters. The apparent root cause of the repetitive reports to the NRC on the Ames Hill transmitters being out of service was a lack of guidance to control room operators for assessment of the loss of emergency communication systems capabilities.
P8.3 (Updated) URI 92-14-01: Technical Support Center (TSC)/ Control Room Ventilation Systems and TSC Shielding
a.
Inspection Scope This item was opened following inspector walkdown of both the ventilation systems to assess the adequacy of these systems for maintaining habitability within the TSC and CR under postulated accidents. During this inspection period, the inspectors examined the licensee's procedural guidance in the event that the TSC became uninhabitable for radiological considerations.
b.
Observations and Findinas The inspector examined Operating Procedure (OP)-3507, " Emergency Radiation Exposure Control," Revision 27, dated August 27,1996, which specifies emergency worker dose and emergency response center habitability guidelines. Appendix B to OF 3507 provides the specific protection action criteria for the TSC and Operations Support Center (OSC). Closer examination of these criteria and discussions with the responsible W staff determined that, although action levels were established for evacuation of the TSC for habitability considerations, no written guidance was provided for relocating or transferring the essential technical support and EP management functions provided by the TSC staff. In the absence of a safety related and fully qualified TSC ventilation system, the licensee agreed that more prescriptive guidance was appropriate to ensure a smooth transition of the essential TSC functions in the event the TSC became uninhabitable.
During the preliminary discussions with the W staff on this matter, the engineering staff prepared a position paper (intemal memorandum) addressing the vulnerability of the TSC to postulated unfiltered plant releases The W engineering staff concluded that there were no limitations on air inleakage to the TSC to ensure the General Design Criteria occupational dose limits were not exceeded. One of the reasons provided for this conclusion was that in 1994 the licensee modified the turbine building ventilation system to exhaust directly to the plant ventilation stack vice the turbine building roof vents. Although the turbine building i
l ventilation system is not powered from a safety related electrical source, the engineering staff l
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t concluded, using probabilistic risk assessment, that the recovery from a less of offsite power
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(assumed coincident with the loss of coolant accident) could be achieved within 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> (with
a probability of 99%).
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Conclusion
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i The inspector found the licensee's intemal analysis of TSC habitability reasonably founded, j
j with the exception of the use of probabilistic assessments to demonstrate the time to recover
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from a loss of offsite power. The addition of definitive guidance for transferring critical TSC l
j functions to other emergency response centers in the event the TSC becomes uninhabitable l
l was found appropriate. The final review of this unresolved item was still pending NRR staff-
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j review at the conclusion of the inspection period. This unresolved item remains open.
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V.
Management Meetings -
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X1 Exit Meeting Summary
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The inspectors met with licensee representatives periodically throughout the inspection and following the conclusion of the inspection on November 20,1996. At that time, the purpose and scope of the inspection were reviewed, and the preliminary findings were presented. The i
licensee acknowledged the preliminary inspection findings.
X2 Management Meeting Summary l
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On September 16, VY managers met with the Regional Administrator and his staff in the Region I office to discuss VY's Design Basis Document Project, recent Emergency Operating l
Procedures program issues, and other recent plant and engineering staffs initiatives. The i
hand-out and slide presentation made by VY is attached to this report as Attachment A.
X3 Review of Updated Final Safety Analysis Report (UFSAR)
A recent discovery of a licensee operating its facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures, and parameters to the UFSAR description. While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. Other than discussed in previous sections, no additional discrepancies were noted.
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INSPECTION PROCEDURES USED
73753 Inservice Inspection 83750-Occupational Radiation Exposure i
Tl 2515/134 Licensee On-Shift Dose Assessment Capabilities
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82701 Operational Status of the Emergency Preparedness Program
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86750 Radioactive Waste Management and Transportation 71707 Piant Operations i
62707 Maintenance Observations -
i 61726 Surveillance Observations J
60705 Preparations for Refuel
37550 Engineering 37551 Onsite Engineering 71750 Plant Support Activities 60710 Refueling
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37001 50.59 Reviews I
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ITEMS OPENED, CLOSED, AND DISCUSSED OPENED IFl 96-09-01 Core Spray System Minimum Flow Valves Containment isolation Function IFl 96-09-02 A-Diesel Generator Output Breaker Closure Mechanism Failure IFl 96-09-03 Residual Heat Removal System Pump Start interlock IFl 96-09-04 Alternate Rod Insertion Actuation due to Maintenance involving a Reactor Vessel Water Level Instrument IFl 96-09-05 Primary Containment Nitrogen Purge System isolation Valve Leakage VIO 96-09-06 Main Battery Service Discharge Test Did Not Contain an Acceptance
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Criteria That Could be Related to the System Design URI 96-09-07 Core Spray and Residual Heat Removal Systems Containment isolation i
Valves Redesignated CLOSED l
VIO 96-05-02 Demonstrate Design Capability of RHR Cooling and Spray Mode VIO 95-11-01 Inadequate Inspection of Interior Drywell Head IFl 96-03-01 Recirculation Pump Trip Due to Maintenance Personnel Error
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UPDATED URI 96-03-05 Removal of Reactor Vessel Shield Blocks at Power
URI 92-14-01 TSC/ Control Room Ventilation Systems and TSC Shielding j
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PARTIAL LIST OF PERSONS CONTACTED
R. Barkhurst, President and Chief Executive Officer R. Wanczyk, Plant Manager i
G. Maret, Operations Superintendent l
E. Lindamood, Director of Engineering l
L. Doane, Operations Manager
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l M. Watson, I&C Manager i
F. Helin, Reactor Engineering Manager
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M. Desilets, Radiation Protection Manager l
S. Skibniowsky, Chemistry Manager i
G. Morgan, Security Manager D. Calsyn, QA Supervisor, YAEC J. Cox, Radiation Protection Supervisor l
J. Geyster, Plant Health Physicist l
P. Guido, Radiation Protection Supervisor
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R. Morrissette, ALARA Engineer D. Reid, Vice President, Operations l
R. Sojka, Operations Support Manager
M. Thomhill, Radiation Protection Supervisor D. Andrews, Radiation Protection Technician l_
G. Bristol, Community Relations Coordinator l
T. Burda, Emergency Planner A. Chesley, Technical Support Training Supervisor E. Porter, Emergency Plan Coordinator
E. Salomon, Emergency Planner
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J. Thayer, Vice-President - Engineering l
D. Amidon, Performance Engineer B. Dondoun, Maintenance Engineer S. Smiler, Manager, Design Engineering j
B. Wittmer, Maintenance Production Supervisor l
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l LIST OF ACRONYMS USED VY Vermont Yankee l
TS Technical Specifications l
UT Ultrasonic Testing EDG Emergency Diesel Generator ALARA As Low As Reasonably Achievable TLDs Thermoluminescent Dosimeters NVLAP National Voluntary Laboratory Accreditation Program RCA Radiation Control Area RWP Radiation Work Permit CEDE Committed Effective Dose Equivalent QA Quality Assurance UFSAR Updated Final Safety Analysis Report TSC Technical Support Center CAM Continuous Air Monitor EP Emergency Preparedness EPIP Emergency Plan implementing Procedure EOF Emergency Operations Facility i
NOAA National Oceanic and Atmospheric Administration ODPS Offsite Dose Projection System OSC Operational Support Center RP Radiation Protection ISI Inservice inspection BWR Boiling water reactor i
LOCA Loss of Coolant Accident IGSCC Intergranular Stress Corrosion Cracking RT Radiographic Technique
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EPC EP Coordinator OSM Operational Support Manager CEO Chief Executive Officer LLRT Local Leak Rate Testing RHR Residual Heat Removal CS Core Spray l
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l ATTACHMENT A j
September 16,1996 l
Management Meeting Handout
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