IR 05000271/1993021
| ML20058A344 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 11/10/1993 |
| From: | Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20058A337 | List: |
| References | |
| 50-271-93-21, NUDOCS 9312010052 | |
| Download: ML20058A344 (23) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
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1 Report No.
93-21 i
Docket No.
50-271 Licensee No.
DPR-28 Licensee:
Vermont Yankee Nuclear Power Corporation RD 5, Box 169 Ferry Road Brattleboro, VT 05301 Facility:
Vermont Yankee Nuclear Power Station Vernon, Vermont inspection Period:
September 12 - October 9,1993 Inspectors:
Harold Eichenholz, Senior Resident Inspector Paul W. Harris, Resident inspector John T. Shedlosky, Project Engineer Brenda J. Whitacre, Reactor Engineer
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Approved by:
Eugene M.
elly, Chief
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bate Reactor Pr ccts Section 3A Scope:
Station activities inspected by the resident staff this period included Operations, Maintenance, Engineering, and Plant Support. Initiatives selected for inspection included the a review of the "one-for-one process," and the licensee's " Time To Boil" analysis for potential spent fuel pool heating.
Backshift and " deep" backshift including weekend activities amounting to 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> were performed on September 13, 16, 20, 21, 25, 26, and October 5. Interviews and discussions were conducted with members of Vermont Yankee management and staff as necessary to support this inspection.
Findings:
An overall assessment of performance during this period is summarized in the Executive Summary. Unresolved items were initiated regarding design control for the core spray suction strainers (Section 4.2), seismic monitoring deficiencies for Class 1 E electrical switchgear (Section 3.2.2), and degradation of the alternate cooling water system (Section 3.1.2).
9312020052 90333y
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EXECUTIVE SUMMARY
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Vermont Yankee Inspection Report 93-21
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Operations Material and structural conditions within primary containment during the outage were acceptable.
The voluntary entry into a 7-day action statement for the conduct of maintenance on the "B"
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emergency diesel generator was performed without implementation of the Vermont Yankee LCO Maintenance Guideline. The inspection and handling of the dropped fuel assembly were
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conducted safely. An inspection of two primary containment isolation sub-systems identified no.
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conditions adverse to system operability.
Maintenance and Testing Appropriate regard for minimizing shutdown risk was demonstrated during actions to identify
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and repair a grounded condition on the "A" startup transformer.
Inadequate preventive maintenance for the alternate cooling water system, including ineffective corrective action for a known condition, resulted in the accumulation of mud and silt in the deep basin of the tower; the evaluation of the safety significance and impact upon ultimate heat sink operability are unresolved. Tube phigging and repair of a recurrent failure of an impingement plate within the'
residual heat removal system heat exchangers were conducted. Load capacity testing of the
.Vernon Tie Line was successfully completed. Seismically deficient mounting of safety class IE distribution equipment was identified by field walkdowns and repaired, but the deficiencies had rendered the switchgear as seismically indeterminant since original construction. The conduct -
of spent fuel pool " Time To Boil" testing was safe, and confirmed decay heat removal capability and shutdown risk strategies.
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Engineering
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In-vessel inspections confirmed that industry-experienced core shroud cracking was not evident in the areas inspected. In response to generic industry experience regarding emergency core cooling system suction strainers, Vermont Yankee determined that the_ surface area of the core spray system suction strainers was insufficient to meet design requirements for net positive suction head under certain debris loading. A review of fifty "one-for-one" evaluations confirmed
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that appropriate design control measures were implemented, and engineering evaluationsjustified the replacements performed. Modification and post-maintenance testing of the residual heat'
removal and reactor water level systems were performed with comprehensive design change-instructions.
Plant Snpport
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Plant workers were cognizant of posting requirements and used good' radiological practices.
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Security access control at the entrances to the drywell and refuel floor was enhanced by the installation of physical barriers and remote video monitoring stations. Housekeeping and fire
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protection were good.
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TAHLE OF SUMMARY OF FACILITY ACTIVITIES Vermont Yankee Nuclear Power Station (VY) was safely operated during this period of shutdown operations for the conduct of maintenance / refueling outage (RFO) XVII. Outage activities included the installation of the reactor vessel water level backfill system, modification of the residual heat removal service water (RHRSW) system, and preventive maintenance on safety and non-safety systems. Inspections were performed on feedwater heaters, low pressure turbines, electrical distribution system, and RHRSW heat exchangers. Corrective maintenance was performed to repair identified deficiencies. In-vessel inspections verified that industry-experienced cracking of the core shroud had not occurred at VY. Other reactor vessel activities included friction testing of control rod drive (CRD) mechanisms, and replacement oflocal power range detectors and CRD position indication probes. Vermont Yankee also implemented short-term corrective actions to prevent recurrence of the September 3 and 9 refuel events and completed core refueling (section 2.3).
2.0 OPERATIONS (71707)
2.1 Operationni Snfety Verification Daily, the inspectors verified adequate staffing, adherence to procedures and Technical Specification (TS) limitir:g conditions for operation (LCO), operability of protective systems, status of control room annunciators, and availability of emergency core cooling systems. Plant tours confirmed that control panel indications accurately represented safety system line-ups and safety tagouts properly isolated equipment for maintenance.
Primary containment inspections verified no conditions adverse to containment integrity within the areas inspected. Within the torus, general corrosion on the torus pressure boundary was corrected and no significant surface indications existed. A minimum amount of deleterious debris was observed in the suppression chamber water and no clogging or plugging of the emergency core cooling system suction strainers existed (section 4.2). The strainers were integral and holes were clear. Minor surface corrosion existed on the welds connecting the torus spray nozzles to the ring header, however, the cognizant engineer stated that this situation was already assessed as acceptable. Within the drywell, a complete hand-over-hand inspection of the reactor vessel water level instrument lines verified that piping supports were installed, continuous downward slopes were provided, thermal-expansion joints exhibited freedom of motion, and pipe runs were not bent due to maintenance activities. Accessible portions of guard pipes were inspected and no deficient conditions were observed. Drywell paint was tightly adherent or was in a state of repair, Door grates were secured, and drywell floor and equipment drains were clear.
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2.2 Interpretntion of Technical Specifications for Refueling Operations
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On October 4, during refueling activities, VY entered a 7-day standby gas treatment (SBGT)
system LCO because the "B" emergency diesel generator (EDG) was removed from service for preventive maintenance. Documentation of the LCO condition referenced TS 3.7.B.1 and VY TS Interpretation No. 39. On October 9, VY completed refueling activities and exited the LCO.
Based on the NRC review of plant TSs, VY's TS Interpretation No. 39, and a review of documents placed on the public docket, two concerns were identified.
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(1)
Vermont Yankee TS Interpretation No. 39, signed by the Manager of Operations on September 12, 1990, was VY's justification for the removal of the "B" EDG from service during refueling activities during which secondary containment is required. The
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basis for the interpretation was TS 3.5.H.4 that requires, in part, one operable EDG
during the refueling condition to satisfy minimum core and containment cooling system requirements. The NRC staff did not agree with the licensee that TS 3.5.H.4 justifies
the removal of the EDG from service during plant operations that require secondary containment. Technical Specification 3.5.H.4 addresses requirements for core and
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containment cooling, and cannot be applied to the requirements for SBGT and secondary -
containment, which are covered by TS 3.7.B and 3.7.C, respectively.
(2)
Based on conversations with the licensee on October 4, VY did not consider the
voluntary removal of the "B" EDG from service and concurrent entry into a 7-day LCO for the SBGT system as an LCO maintenance activity. The NRC staff disagreed with this assessment because TS 3.7.B.1 requires both SBGT systems and both EDGs be operable during plant operations requiring secondary containment. Guidance on' this.
determination is in the VY LCO Maintenance Guideline and NRC Inspection Manual i
Chapter 9900, " Ensuring the Functional Capability of a System or Component." The i
staff was concerned that the VY. LCO Guideline was not implemented to document: 1)
the net safety benefit gained from the voluntary removal of a safety system from service, and 2) the contingencies necessary to maintain a level of safety commensurate with the importance of secondary containment integrity during refuel operations.
The two concerns were of relatively minor safety significance because plant conditions and
safety system lineups met TS requirements. The precedent to allow one inoperable EDG (with established compensatory measures) during refuel operations exists _ for other utilities, and is reflected in the revised Standard Technical Specifications for BWR-4s. However, the current Vermont Yankee TS 3.7.B does not explicitly address EDG requirements during refuel operations, and requires both EDGs for SBGT and secondary containment operability.
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2.3 Refueling Activities On September 24, VY resumed fuel handling operations following NRC review of the licensee corrective actions (CAs) to improve the conduct of refuel operations and to prevent recurrence f
of the September 3 and 9 refuel events (NRC Inspection Report 93-19). An NRC Augmented
Inspection Team reviewed both events and documented findings in NRC Inspection Report 93-81. Appendix A to this report summarizes onsite verification of corrective actions implemented prior to refueling operations.
Inspection and Handling of the Dronned Fuel Assembly
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On September 30, the inspector observed the removal and transport of the dropped fuel assembly (LYN-831) from reactor core position 21-14 to the spent fuel pool. This operation was
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conducted safely with appropriate management oversight, procedures, and contingency measures.
Prior to this activity, VY inspected LYN-831 and verified that the fuel assembly was structurally sound and could support lifting a..d irvisportation to the spent fuel pool. Remotely operated video equipment was used to inspect me upper tie plate, fuel support casting, adjacent fuel assemblies, and the accessible sides of the LYN-831 fuel channel. No significant indications or loose parts were identified. General Electric (GE) independently analyzed the inspection video and confirmed VY.s assessment.
Refueling engineers from GE assisted VY during the
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inspections.
These inspections reconfirmed the structural conclusions.made immediately
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following the event, in that, the upper tic plate was not cracked or bowed, both channel fasteners were damaged, and the fuel channel was swagged over the lower tie plate by three inches.-.The fuel assembly was under constant visual surveillance by the VY and GE engineers during fuel
assembly lift, transfer, and seating.
To supplement the mechanical integrity of the fuel assembly during transportation to the spent I
fuel pool, VY fabricated a " bundle support restraint" (BSR). This device, based on a GE i
design, was designed to capture loose parts. A ' secondary function of the BSR was to prevent l
gross separation of the upper and lower tie plates (indicative of a complete failure of the eight i
tie rods); this failure scenario was deemed very unlikely by both VY and GE. Engineering i
evaluations verified that the fuel assembly could support the additional load and that there was no effect on fuel pin cooling. Vermont Yankee considered the device a refueling tool as described in the Final Safety Analysis Report (FSAR) and determined that a 10 CFR 50.59 safety evaluation was not required. The BSR was removed prior to landing LYN-831 in the spent fuel pool rack.
Pre-job briefs were performed prior to the inspection and transportation of LYN-831. Senior plant managers, radiation protection (RP) technicians, control room operators (CROs), Quality l
Services Division, and representatives from GE attended both briefs. ' The inspection plan and'
removal procedure (OP 1430, Rev. O, " LYN 831 Removal") were reviewed and questions were
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answered as they developed. Radiation work controls, monitoring, and administrative exposurc i
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limits were established. The Operations Manager (OM) discussed command and control, communications, and safety considerations at both pre-job briefs. Independently, the OM confirmed that his personnel were knowledgeable of procedure and RP requirements.
The inspector concluded that defense-in-depth was implemented during this fuel handling-activity. The implementation of OP 4130 involved independent reviews that resulted in a procedure detailing appropriate prerequisites and safety precautions. These department level reviews were augmented by a number of Plant Operations Review Committee (PORC)
recommendations. Conduct of operations was professional based on good command and control, accurate communications, and meticulous procedural compliance.
t identification of a Fuel Pin Failure
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Sipping operations of spent fuel assemblies identified the leaking fuel pin that caused the slightly clevated offgas activity levels observed during the previous operating cycle. The leaking' pin -
was located in a third cycle fuel assembly located in peripheral core position 37-10. -The claading failure was approximately 0.060 inches in diameter, occurred just below the top fuel
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pin spacer near the 140-inch elevation, and appeared to be caused by wear-induced fretting of the fuel pin surface. A secondary failure indication, zirc-hydriding of the fuel pin cladding caused by water intrusion into the fuel pellet region, was also observed. No loose parts were identified.
2.4 Engineered Safety Feature Walkdown - Primary Containment Isolation The inspector conducted a walkdown of the accessible portions of the primary containment isolation system (PCIS) associated with the containment radiation monitoring, drywell'
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equipment, and floor drain systems, and verified that no conditions existed that might degrade system performance. Field conditions matched as-built configurations documented in the system lineup procedures, electrical drawings, and operator training manuals. Electrical power supplies, valve line-ups, and switch positions were correct using system operating procedures OP 2152, Rev.15, "Drywell Equipment and Floor Drains," and OP 2125, Rev.16, " Containment Atmosphere Dilution System," as guides. Plant procedures for the conduct of PCIS Group 2.
and 3 surveillance testing provided appropriate precautions and instructions for the safe conduct of testing and met TS functional and calibration requirements. Field inspections confirmed independence of power supplies and separation of piping systems. The electrical components associated with system isolation valves were environmentally qualified (EQ) for VY accident conditions and maintained in accordance with the VY EQ program. Valves were also tested in
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accordance with 10 CFR Part 50, Appendix J leak rate testing requirements. Recent surveillance -
test results and valve maintenance history were reviewed and no discrepancies were noted.
Adequate housekeeping, labeling, valve and instrumentation conditions were observed.
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3.0 MAINTENANCE AND TESTING (62703,61726)
3.1 Maintenance l
The inspectors observed selected maintenance on safety-related equipment to determine whether these activities were conducted in accordance with VY TS, and administrative controls i
(Procedure AP-0021 and AP-4000) using approved procedures, safe tagout practices and (
appropriate industry codes and standards.
Interviews were conducted with the cognizant
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engineers and maintenance personnel and vendor equipment manuals were reviewed.
3.1.1 Startup Transformer Ground i
l On September 10, CROs observed an intermittent, very short duration, ground on 4160 KV, non-safety class, bus I following the energization of the startup transformers to power in-house loads. At this time, the reactor was in the cold shutdown condition, both EDGs and the transmission line to the Vernon Hydro Station were available to power safety buses 3 and 4, and the main transformer was isolated for maintenance.
Ground isolation. techniques were implemented and the Maintenance Department was notified. The following day, department managers, engineers representing operations, and maintenance discussed potential causes, repair activities, and effect er. the current plant status. Immediate actions included calibration of electrical instruments, monitoring of ground currents and transformer performance, and continued ground isolation efforts. A concerted effort was also initiated to restore the main transformer from maintenance and commence backfeeding. Vermont Yankee credits their two 115 KV to 4 KV startup transformers as an alternate and independent offsite power supply.
Technical Specifications require both transformers operable for plant startup.
Despite the actions taken, the ground came in solid on September 14. Bus transfers were
conducted, bus 1 and the." A" startup transformer were isolated, and the EDGs were started as j
a precautionary measure to assure the continuity of power to safety buses 3 and 4.
By September 15, the ground was confirmed on the underground cabling between the "A" startup transformer and the switchgear of bus 1. Vermont Yankee identified that one of nine conductors for the "C" phase had a catastrophic insulation failure the size of a nickel. This conductor and
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the others within the subject cable chase were replaced. All cables associated with the secondary
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side of both transformers were mcggered and high potential (HiPot) tested for post-maintenance testing. A VY representative stated that the cable apparently failed due to an age-related load failure, aggravated by a fabrication deficiency. No abnormal surface indications or conduit conditions were observed.
Appropriate regard towards minimizing shutdown risk was demonstrated by operating the EDGs during bus isolation activitics and by delaying outage activities until independent offsite power
supplies were restored through the main transformer. Troubleshooting to identify the electrical-l ground was well controlled to not impact the operability of safety systems. Good management involvement and knowledge of repair activities were demonstrated during daily outage planning meetings.
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3.1.2 Silting of the Alternate Cooling Water System Deep Basin
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On September 24, during the daily VY outage meeting, the inspector learned that excessive amounts of mud and silt had accumsted in the alternate cooling water (ACW) deep basin.
Following this meeting, the inspector performed an inspection of the basin and observed approximately 600 cubic feet of packed silt had already been pumped out of the deep basin and was temporarily stored in the spray pond. The lead diver performing the underwater basin
inspection stated that the current mud levels underwater ranged in depth from 2-3 inches to 16-17 inches deep. However, a significant amount of mud was found in the service water strainer pit, and more diving was necessary to complete the basin inspection. The inspector was also shown a hand written map that identified the mud levels observed during the last refueling -
outage. The previous mud levels were similar, however, the distribution was different. That morning, the inspector discussed the as-found conditions, a concern regarding operability of the ACW system, and the applicability of 10 CFR 50.72 reportability requirements with the Operations Superintendent (OS). The OS stated that a Potential Reportable Occurrence (PRO)
report was issued to assess reportability and to evaluate as-found conditions.
On October 4, VY determined that the ACW water system was inoperable based on the significant amount of ',dt observed in the pump suction strainer pit.- Considerations were also given to the total amount of water displaced by the mud (500 to 600 cubic yards). A 4-hour report was made and a corrective action report (CAR) was assigned to the Maintenance Department to assess root cause and long term corrective ac_tions. The ACW system is a backup -
made of operation for the service water system in the event that water cannot be drawn from the Connecticut River by the service water pumps. It makes use a larger number of water stored in the basin of the west cooling tower and a recirculation path to the suction of the RHR service -
water pumps. Vermont Yankee cleaned the deep basin, and the RHRSW pump suction line from the deep basin, and declared the system operable. A design change was implemented to allow I
periodic cleaning of the subject service water line. The licensee also identified minor indications of microbe-induced corrosion (MIC) within the suction line, although the corrosion depth was.
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within established acceptance criteria.
At the end of this inspection period, the licensee had not completed the CAR nor determined-l when the last time the deep basin was pumped and cleaned. Based on this, the deposition rate of the mud and silt could not be approximated, and thus its historical affect on operability of the ACW system could not evaluated. A concern regarding preventive maintenance on the SW system was previously identified in Inspection 92-21, as were concerns for flow testing of the
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system in its design basis configuration. Pending evaluation of the safety significance, corrective actions and submittal of a written LER on this subject,it remains unresolved (URI 93-21-01).
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3.1.3 Residual Heat Removal Heat Exchanger Repair During the outage period, VY inspected the "A" and "B" RHRSW heat exchangers (HX) and corrected a recurrent failure of the RHR impingement baffle plates. In addition, hydrolyzing and eddy current inspection of the HX tubes identified tube walls below minimally acceptable wall thickness. These tubes were subsequently plugged.
Impincement Plate The function of the impingement plate is to prevent tube erosion caused by direct impingement of RHR water flow on the HX tubes. The original impingement plate was fabricated from one piece of metal and secured on one side to the tube sheet by threaded support rods and laterally -
supported at the other end by the baffle plate assembly. This support configuration allous differential expansion of HX components during temperature changes. The first failure of an
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impingement plate was identified in the "A" HX during the 1989 RFO. Vermont Yankee identified that the plate had skewed in orientation, because-the threaded connection of the-support rod failed from fatigue. To correct this condition, the support rod to tube sheet connection was modified to remove a stress riser caused by threading of the support rod. A new impingement plate consisting of five welded sections replaced the original, undivided plate. This modification allowed the installation of the plate into a partially disassembled HX. Inspection of the "B" HX was performed during the 1990 outage, however, the scope of this inspection was inadequate to verify the integrity of the support rod threaded connection.
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On September 2, the licensee identified that both the "A" and "B" HX impingement plates failed in a similar fashion as identified in the "A" HX during the 1989 RFO. The preliminary root cause for both failures appeared to be an inadequate weld fusion of the support rod versus fatigue failure. Based on this, VY again redesigned the support rod _to tube sheet connection by pinning the support rod and increasing the height of a cup in which the support rod sits. This work was performed under a maintenance request. "One-for-one" evaluations93-104 and -136 were written to document the evaluations for the design changes performed.
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The inspector reviewed the one-for-one evaluations and concluded that appropriate engineering evaluations were made. The changes in rod material, support rod design (pin connections, socket fitting, and chamfering), and plate seal welds were assessed with respect to their critical design characteristics. One weakness was observed, in that, the "one-for-one" evaluated the safety function of the HX versus the safety function of the modified baffle plate. Because of this, an assessment regarding the safety function of the impingement plate (to reduce erosion and ventilation of the heat exchanger tubes) was not performed. Design control measures were implemented in accordance with the Yankee Atomic Quality Assurance Program (YOQAP),
Chapter 3, " Design Controls."
Based on visual and eddy current inspections, VY concluded that the skewed impingement plates caused minimal damage to the HX tubes and baffle plate. Some increased vibrational wear at the tube supports and shell side inlet and corrosion pitting was observed. Heat exchanger
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performance monitoring by the Operation Department did not identify a degradation'in HX efficiency during this period. The licensee established acceptance criteria for wall thickness based on GE and Philadelphia Electric Company discussions. Long term corrective actions included the development of a preventive maintenance program for the HXs.
Tube Plugging The "A" HX had seven of 1664 tubes plugged during the 1989 RFO. Forty-eight additional tubes were plugged this outage. Of the 48 tubes, one was totally blocked preventing ultrasonic q
testing and the other 47 indicated wall loss of 50 percent or greater. There were no indications of tube sheet leaks. Based on the vendor review of data, the RHR heat exchanger tubes were croding at a rate of 10.5 percent wall loss per year assuming linearity. Seventeen tubes were plugged in the "B" HX.
t The licensee stated that the design heat transfer surface area in the RHRSW heat exchangers exceeded that required by a 10 percent margin.
Based on this, VY concluded that HX
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performance (differential pressure, differential temperature and flow characteristics) would not be significantly changed due to tube plugging. Vermont Yankee also assessed that the increased fluid velrity as a result of the reduction in now area would not significantly contribute to tube erosion. Structural analysis indicated that the tubes can meet code stress limits with 31 percent wall thickness remaining and a tube wall acceptance criteria was' established following the l
identi5 cation of wall thinning.
A Quality Assurance (QA) audit performed at the manufacturing plant identified no signi0 cant concerns. The test plugs were veriGed to be of proper material composition and of the same heat. Inspections were conducted following mock-up testing and after permanent installation into the HX. Hydrostatic testing to 1.5 times design pressure was performed on the mock-up.
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Welder qualifications were required. The explosive tube plugging technique was qualified and the procedure was reviewed by a Yankee Nuclear Services Division (YNSD) welding engineer, Tube plugging is an acceptable code repair for safety class 1 systems and was~ applied to the '
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safety class 2 RWRSW heat exchangers.
This corrective. maintenance was well coordinated. The explosive tube plugging technique -
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lowered radiation exposure limits. Appropriate security and fire prevention. contingencies were incorporated due to the introduction of explosives. into the reactor building. To prevent failure of adjacent tubes during the plug installation, tube support fingers were installed. Quality
Assurance peer inspections were performed to measure critical dimensions. The licensee conservatively increased the scope of the original inspection effort based on the as-found conditions in the " A" HX.
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3.1.4 Service Wnter Valve Refurbishment Program (Update of URI 91-21-02)
As part of VY's service water valve refurbishment program, several isolation valves within the alternate cooling system were incorporated into the preventive / predictive maintenance program.
During this period, selected maintenance of service water valves (V70-11, V70-16A, and V70-17) within the ACW system was observed. This. included valve cycling in the as-found
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condition, valve disassembly, and inspection of the valve internals.
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Overall, no conditions were observed that potentially affected valve functionality. Valve i
operations were smooth and required little or no physical effort by maintenance personnel.
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Material conditions of the valve seat and adjoining piping showed no erosion and minimal
I corrosion. The valve seat and disk were free of galling, pitting, and appeared in good condition.
A licensee representative stated that MIC and silt were also present inside the piping, however, the amounts observed were not significant. The work packages were adequate and supervisory oversight was provided. The concern regarding SW system preventive maintenance has been previously documented in NRC Inspection Report 91-21 and remains unresolved.
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3.2 Testing (61726)
The inspector reviewed procedures, witnessed testing in-progress, and reviewed completed surveillance record packages. The testing described below was found effective with_ respect to i
meeting the safety objectives of the. surveillance program. The inspector observed that all tests were performed by qualified and knowledgeable personnel, and in accordance with VY TS, and
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administrative controls (Procedure AP-4000), using approved procedures.
3.2.1 Vernon Tie Capacity Testing l
_ On September 16, the inspector observed the load capacity test of the 4160 volt Tie line on the Vernon Hydro Station and verified that results met acceptance criterion. The test was conducted j
in accordance with plant procedure OP 4142, Rev. 3, "Vernon Tie Surveillance," and demonstrated that the Vernon Tie was capable of meeting 80 percent of design station blackout load (2300 KW) for one hour. Bus voltage and amperage instruments in the control room indicated that the test was conducted at 1928 KW assuming a 0.85 power factor.
The surveillance procedure implemented precautions, prerequisites, and requirements to assure l
'the proper conduct of the test. This included independent verification of the electrical breaker
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l lineup and the lifted leads and jumpers preventing the inadvertent generation of a loss-of-normal l
power signal during the test. Supervisory oversight and pre-test coordination contributed to the l
safe conduct of the test. No unexpected or abnormal conditions were observed. ARC Inspection
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Report 93-19 documented a review of the VY design change implemented to improve the capacity and reliability of the Vernon Tie.
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3.2.2 Seismic Qualification of Electrical Switchgear On September 18, VY identified inconsistencies between the as-found and as-required design anchoring of safety class electrical buses 3 and 4 (4160 volt) and 480 volt motor control centers (MCC) 8 and 9. The deficient conditions included the lack of substantial welding of switchgear frames to concrete imbedded angle irons and inadequate bolting of MCC frames to similarly
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configured foundations. The seismically deficient electrical equipment existed since' plant construction and determined insufficient to meet plant seismic design criteria.
An NRC -
notiGcation was made, concluding that the unanalyzed condition would have significantly compromised plant safety if identified during plant operation. These buses provide redundant electrical distribution for safety-related equipment such as RHR, SW, and core spray.
Independent class IE power is supplied to buses 3 and 4 from the EDGs and supplemental station blackout power from the Vernon Tie. The MCCs distribute power to motor operated valves associated with the above fluid systems. The deficiencies were identified by YNSD during field walkdowns for the Seismic Qualification Up Grade Program.
The inspector reviewed the as-built electrical switchgear drawings, inspected the subject electrical components, and concluded that inadequate instructions were provided to assure the proper installation of the seismic fasteners. The vendor drawings and instructions for the applicable MCCs and switchgear were generic and reflected typical installation requirements.
The plant construction contractor, EBASCO, updated the drawings based on as-built conditions, however, this effort was also of insufficient detail. Vermont Yankee was unable to provide
detailed documentation regarding original installation requirements and/or quality control inspections. The periodic switchgear and MCC inspections performed by the licensee did not include frame mounting inspections. Based on the above, the licensee's preliminary root cause determination that the deficiencies were a result of original construction deficiencies appears appropriate. The inspector noted that the lic'ensee had failed to take actions in response to NRC Information Notice 80-21, Anchorage and Support of Safety-Related Electrical Equipment, that would have detected this deficiency earlier.
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The deficient conditions were idemified and repaired during the shutdown mode of reactor operation, when emergency core cooling systems were not required. Plant management delayed changing the reactor condition until all inspections and repairs were completed. All safety-related buses and MCCs, reactor protection distribution panels, and vital AC and selected DC distribution panels were inspected. A nonconformance report (NCR) was initiated to determine root cause and document corrective actions. On September 21, the inspector observed that the review performed' by PORC was thorough, including a detailed discussion of as-found conditions. Repair activities were scheduled and prioritized with respect to shutdown conditions and outage activities. Preliminary documentation reviewed by the inspector included seismic analysis of the repair methods and the as-found and as-left configurations. The inspection effort following the identification of the deficiencies was comprehensive. Appropriate personnel safety considerations were impicmented during bus inspections. Yankee Nuclear Services Division
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assisted VY in the seismic qualification of the electrical components. Pending receipt of an LER, including the licensee's evaluation of safety consequences and proposed corrective actions, j
this issue remains unresolved (URI 93-21-03).
3.2.3 Spent Fuel Pool " Time to Boil" Analysis
Special test procedure (STP)93-001, " Reactor Time To Boil," was implemented four times this outage to obtain actual reactor cavity, spent fuel pool, and dryer separator pit temperatures during different modes of shutdown operations. The data will be used to validate assumptions made in the VY " Time To Boil" model which calculates the time to reach boiling in the spent fuel pool and reactor cavity in the event of a loss of decay heat removal capability. This
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determination is dependent on water inventory, thermal stratification, and decay heat loads. The model was developed to enhance the assessment of shutdown risk during refueling operations.
A safety evaluation performed by the licensee determined that this testing did not constitute an
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unreviewed safety question.
On September 16 and October 5, the inspector observed the conduct of this test and verified that plant conditions were in accordance with procedural requirements. STP 93-001 implements
administrative requirements for test oversight, establishment of initial and final water
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temperatures and plant conditions, and the installation of temperature instruments to augment normal water temperature instrumentation. Control room operators were knowledgeable of the test and trende/ he reactor cavity water heat up rate. Outage activities were appropriately j
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scheduled to r. affect the conduct of this test. Time to boil information was distributed to the operating crews and discussed at daily outage meetings. Analyses were performed to confirm that TS limits for reactor (212 degrees)'and spent fuel pool (150 degrees) water temperatures would not be exceeded prior to the re-establishment of effective. shutdown cooling. The inspector audited the 10 CFR 50.59 safety evaluation and identified no safety concerns.
4.0 ENGINEERING 4.1 Core Shroud Inspections Supplemental inspections of core shroud surfaces and weldaments were performed to evaluate shroud integrity in response to recent crack indications found at other nuclear power utilities.
General Electric Service Information Letter (SIL) No. 572, " Core Shroud Cracks," and RICSIL No. 054, " Core Support Shroud Crack Indications," describe findings observed at these utilities.
Recommendations regarding inspection techniques, criteria, scope, and corrective actions were provided. The cracking was found in Type 304 stainless steel core shroud welds near the top guide support ring and core beltline seam. The welds were on'the inner and outer shroud surfaces in the weld sensitization / heat affect zones. General Electric considers the cracking to be caused by a stress corrosion mechanism. Contributing elements included neutron fluence, material composition and orientation, corrosion oxide wedging, and/or the presence-of intergranular stress corrosion.
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Based on preliminary inspection results, VY concluded that no crack indications existed in the; areas of concern. This assessment was based on visual inspection techniques incorporating 1-mil wire resolution criterion, and independently confirmed by YNSD,and GE.
Vendor recommended ultrasonic testing was not performed. Inspections of the inner shroud surface included 100 percent inspectior. of two of four vertical welds and two circumference welds (below the top guide supoort ring at the 270 degree azimuth for 80 inches and the middle weld at 270 and 115 degrees for 160 inches total). Portions of the outer shroud upper weld near the~
core spray downcomer, top guide support ring, and 30 percent of the total length of welds associated with the shroud annulus area near the jet pumps, were also examined. Very little oxide buildup v as observed, and no crack indications were found on the steam separator to shroud hold-down bolts. These latter observations were used as indicators and precursors of.
core shroud cracking.
General Electric considers VY a low risk plant, in part, because the top guide supporting ring l
is fabricated with no exposed plate edges using an ASTM, A-182 F304 forging. The top guide was machined to finished size and was subject to relatively little cold working.
Other considerations included relatively low reactor water conductivity [VY ranks in the top 30 percent of all utilities based on Electric Power Research Institute (EPRI) water quality guidelines] and low neutron fluence on shroud welds (due to relatively high neutron attenuation caused by a large water gap between the shroud and irradiated fuel). The carbon content was stated as being higher than desirable, however, acceptable.
The reviews conducted by VY of this issue were timely.. Early communications with the Brunswick Nuclear Power Station staff contributed toward VY's knowledge of the cracking l
phenomena. Recommendations by YNSD, based on EPRI communications, were reflected in
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the VY position to inspect accessible portions'of the vertical and circumference welds of the -
i inner shroud diameter. Following completion of the inspections, the results were independently J
verified by GE and YNSD and confirmed to meet the intent of GE SIL NoJ572. NRC Information Notice 93-79, " Core Shroud Cracking at Beltline Region Welds in Boiled Water
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Reactors," provides amplifying information regarding the core spray cracking phenomena.
4.2 Undersized Core Spray Suction Strainers During this outage, VY inspected the core spray system suction strainers and determined that the strainers were smaller than assumed in design calculations. In this condition, strainer surface.
area was inadequate to assure flow and net positive suction head for the core spray pumps under accident cuditions with assumed worst case debris accumulation in the torus. The strainers are i
safety class 2, seismically qualified, and designed with 1/8-inch holes on 3/16-inch centers in-the shape of a can with a 16-inch diameter base. The as-found strainers, installed since original plant construction, were sized to a 12-inch diameter base. The. inspections were conducted in response to industry and NRC concerns identified as a result of problems that occurred at the
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Perry Nuclear Power Station.
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Vermont Yankee replaced the original suction strainers on October 13 and 14,1993 using the design change process under Procedure AP 6004, Rev.15, " Engineering Design Change -
Request. " Engineering evaluations were conducted to assess the impact on existing plant
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systems (operational and ruaintenance) and design bases (hydraulic and structural). A safety evaluation determined that design change EDCR 93-406 to replace the strainers did not create an unreviewed safety question. Drawing changes have been implemented to reflect the change
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in plant configuration. Management reviews were performed in accordance with AP 6004. An NRC notification was made reporting that the strainers would not assure continued system operability following a design basis accident. A corrective action request (CAR) was initiated to assess root cause.
i Vermont Yankee was previously aware of industry concerns regarding clogging of emergency core cooling system (ECCS) suction strainers. NRC Generic Letter 85-22, " Potential for Loss of Post-LOCA Recirculation Capability Due to Insulation Debris Blockage," recommended guidance for licensee reviews dealing with the modification of thermal insulation. NRC Information Notices 92-71 and 93-34 were also issued describing a related event at a foreign boiling water reactor and providing amplifying information, respectively. NRC Bulletin 93-02,
" Debris Plugging of Emergency Core Cooling Suction Strainers," requested licensees to respond in writing to actions taken in association with this bulletin. During the first quarter of 1993, previous NRC evaluation of debris effects on ECCS had noted that the licensee was imable to substantiate the size of the core spray suction strainers because detailed as-built drawings did not exist. Vermont Yankee had previously performed flow rate and differential calculations based on an approximation of strainer size. Direct measurement of strainer size had also been recommended by GE in a letter dated January 22, 1982, based on the vendor's review of insulation debris clogging of ECCS suction strainers (GE report MDE-184-0885, DRF A00-01713. Revision 1). Pending review of the licensee's evaluation of the safety significance of this condition, and their proposed corrective actions, this item remains unresolved (URI 93-21-02).
4.3 One-For-One Evnluations The "one-for-one evaluation" process was reviewed to determine whether:
(1) the implementation of the process was in accordance with' AP 0008, Rev,1, "One-For-One Evaluations " (2) AP 0008 provides sufficient guidance as to the proper level of engineering evaluation and review, and (3) whether system and/or component design changes were made with appropriate design control measures. To support this inspection, the inspector reviewed fifty 1993 "one-for-one" evaluations, and procedures AP 6000, Rev.16, " Plant Design Change Requests," and AP 6004, Rev.15, " Engineering Design Change Requests." The YOQAP '
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manual and ANSI Standard N45.2.11 were used as inspection guides.
Vermont Yankee defines a "one-for-one," in part, as a replacement that is not exactly identical to the original but will satisfactorily perform all required design functions and is equal to or better than the original. Based on the difficulty of installation, required modification of other systems, and safety classification, the implementing engineer and department manager determine-whether the replacement is a "one-for-one" or a design chang a
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Three levels of complexity were observed with the "one-for-ones" reviewed. The least complex involves the " classical" one-for-one... an equivalent replacement of a part no longer available.
This replacement parallels the equivalency evaluations performed by the Procurement Engineering Department during purchasing and receipt inspection. No concerns regarding this
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practice were identified, however, the procurement engineering procedure VYP:329,-
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" Equivalency Evaluation Procedure," is more rigorous in documentation and evaluation of form, fit, and function. The design change screening criteria were also more detailed and less subject to interpretation. The licensee acknowledged these observations and had already planned to combine the two procedures based on a QA audit finding.
The second level is associated with changes to systems and components as a result of vendor improvements to existing designs.
Within this category, the inspector observed that.
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communications between the vendor and VY were typically documented within the "one-for-one" evaluation to support the design improvement.
Critical design characteristics, system performance differences, changes to the FSAR, drawings, and procedures are reviewed by the-licensee prior to implementation of a new component.
The most complex "one-for-one" tends to involve corrective maintenance of systems and components. A number of examples exist in which VY, in effect, re-designed components to improve performance and/or increase service life and reliability.
Examples included the-modification of the RHRSW heat exchanger impingement plate to improve rigidity and to
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facilitate installation (section 3.1.3) and the modification of the torus /drywell vacuum breaker lever arms to remove excessive ' clearances.
Typically, drawing and vendor design
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documentation changes are required and timeliness of repairs are dependent on TS LCO
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requirements. The inspector verified that design control measures delineated in YOQAP, Chapter 3, " Design Control," were implemented for these "one-for-ones," however, AP 0008 does not provide guidance or requirements to assure the consistent application of design control-measures.
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Overall, the inspector concluded that the "one-for-ones" reviewed were in accordance with l
procedural requirements and design control measures were incorporated. Inter-departmental l
coordination and reviews, and calculations for seismic loading and stress analysis, material assessment of shear, stress, corrosion, and failure analyses were of appropriate detail and accurately evaluated the components replaced. A QA finding regarding inadequate evaluation of critical design characteristics was not repeated in the one-for-ones reviewed.
4.4 Residual IIcal Removal Service Water Modifications The licensee modified the flow control valves at the SW outlet of the RHR heat exchangers to improve their reliability. There have been several failures in the past of the valve motor operator that the licensce's root cause analysis attributed to cyclic stress and flow vibration (NRC Inspection Reports 93-13, section 4.1.1 and 93-19, section 2.2 and 3.2). As originally designed, the system automatically throttled flow at the heat exchanger outlet to maintain SW j
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within the motor operator.
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The system changes prescribed within EDCR 92-404 were intended to reduce system vibration through the use of appropriately selected Dow control valves. The original control valves [V10-89A(B)] had 12-inch throats with reduced trim.. The valves operated in a narrow range, near fully shut, to develop about 350 psid at 2700 gpm. The valves were replaced with 8-inch flow control valves that have a linear characteristic over the first six inches of stem travel and quick open operation over the remaining two inches. The 12-inch upstream manual isolation valves were also replaced with 8-inch gate valves and the downstream isolation valves were replaced with globe valves for unique operating conditions when SW temperature is very low and
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additional pressure drop is required. The valve and interconnecting pipe material were also -
l changed from carbon steel to stainless steel. The automatic differential pressure control circuit
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was removed and replaced with a remote manual valve position control that is interlocked with the pump motor start circuit. Control room indication and system operations remain essentially
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unchanged.
The inspector reviewed the design change documents, interviewed personnel involved with design and construction oversight, and observed work in progress at various stages of system modification. The engineering documents reviewed by the inspector included the design change package and drawings, the safety assessment and 10 CFR 50.59 safety evaluation and the installation and test procedure. The design change packages conformed to the requirements of-l administrative procedure AP 6004, Rev.15, " Engineering Design Change Requirements." The -
inspector observed the work practices, radiological controls and housekeeping; good practices were in place. The inspector found the installation and test procedure to be of adequate detail describing this activity. The procedure also required quality control verifications of all wiring changes. This was viewed as a strength. The RHR system operating procedure was revised to incorporate changes resulting from this modification. During system operation, the inspector observed that noise and vibration levels were much reduced from conditions observed prior to
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the EDCR and the CROs have stated that system control has improved. The inspection follow item regarding root cause analysis for the failures of the flow control valve motor operators is closed (IFl 93-13-02).
'i 4.5 Reactor Yessel Water Level Reference Leg Modification The licensee modified the reactor vessel water level system by installing a continuous fill system
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for the constant head reference legs. This system was installed to address an NRC concern
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involving the accumulation of non-condensible gases in the reference legs of the reactor vessel water level system potentially causing inaccurate water level indication. The design implemented
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uses a metered flow of water to each of the four reference legs from the control rod drive mechanism charging water header. Water is supplied to each leg independently through its flow element and throttling valves. Flow is displayed locally to assist in system operation and i
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balancing flow to each leg. Previous inspections related to the reactor water level system were documented in NRC Inspection Reports 92-21 (section 6.1), 93-08 (section 2.4), and 93-13 (section 6.2).
The inspector reviewed the design change documents, interviewed personnel involved with the design and installation, and observed work in progress at various stages of installation. The
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engineering documents reviewed by the inspector included the design change package, the safety.
assessment and 10 CFR 50.59 safety evaluation, and the three installation and test procedures.
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The design change package conformed to the requirements of administrative procedure AP 6004 The inspector observed the modiGcation at various stages ofinstallation and test, and found that the fabrication and connections to plant systems were clearly detailed.
Construction documentation was thorough, detailed, and followed design requirements. Controls for flushing, i
hydrostatic testing, and performance testing (to examine the effect on indicated reactor vessel water level) were established. Prior to the end of this inspection period, the performance testing and changes to the control rod drive system opernting procedure reflecting the operation of the reference leg fill sub-system were in progress.
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4.6 Review of Written Reports The inspectors reviewed Licensee Event Reports (LERs) submitted to the NRC to verify i
accuracy, description.of cause, and adequacy of corrective action. The inspectors considered the need for further information, possible generic implications, and whether the event warranted further onsite followup. The LERs were also reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in NUREG 1022.
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LER 93-01. Supplement 2 Degraded Fire Barriers Due to Inadequate Documentation
of Assumption and Inadequate Procedures
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NRC review of the circumstances involving the identification, repair, and initiation of corrective actions associated with degraded fire barriers were documented in NRC Inspections Reports 93-
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02, 93-05, and 93-08.
LER 93-04, Supplement 1 Jet Pump Operability Surveillance Not Performed During
Single. Loop Operations as Required by Technical SpeciDeations Due to Inadequate Plant Procedure This issue was dispositioned in NRC Inspection Reports 93-03 and 93-12 as a violation of TS requirements. The inspector verified that plant procedures OP 4110, Rev. 21 " Reactor Recirc
. System Surveillance" and OP 2428, Rev. 8, " Single Loop Operation" were revised to include the required changes.
Vermont Yankee committed to revise the TS regarding jet pump.
surveillance testing. ' NRC assessment of VY's corrective actions in response to the violation is planned (Reference NOV 93-12-01).
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- LER 93-05, Supplement 1 Control Rod Scram Times Greater Than That Required by Technical Specifications Due to Scram Solenoid Pilot Valve Components The inspector verified that changes to procedure OP 4424, Rev.17, " Control Rod Scram Testing and Data Reduction," regarding the establishment of an administrative limit for the notch 46 drop-out time are scheduled for management review prior to m-tup from RFO XVII. Lesson plans are in development for the training of individuals associated with scram time testing.
These changes are expected to include a review of TS 3.3, changes to OP 4424, and lessons learned from the April 1993 event. Both actions are in response to LER long term commitment Items 3 and 4. With reference to long term commitment Item 2 (review of TS 3.3 to determine if enhancements are necessary to remove ambiguity), VY concluded that no change to the TS was necessary.
Vermont Yankee credits a continuing initiative, chartered to review the surveillance aspects of the TS, as a broad-based approach to improve their ability to perform TS-required surveillances. Items 1 and 5 are scheduled for completion in 1994 and are followed by the VY commitment tracking system (Reference NOV 93-09-01).
- LER 93-09
"B" Core Spray System Declared Inoperable Due to Instrument Out of Tolerance as a Result of Personnel Error.
This LER was documented in NRC Inspection Report 93-13.
- LER 93-11 Group IV Primary Containment Isolation on Initiation of "B" Shutdown Cooling System Due to Pressure Spikes This event was reviewed during the previous inspection period and documented in NRC Inspection Report 93-19, section 2.3. The inspector found that LER 93-11 accurately described the details of the event and the licensee's plans for continued investigation of the issue.
5.0 PLANT SUPPORT (71707)
5.1 Rndiological Controls Inspectors routinely observed and reviewed radiological controls and practices during plant tours.
The inspectors observed that posting of contaminated, high airborne radiation, radiation and high -
radiation areas were in accordance with administrative controls (AP-0500 series procedures) and plant instructions. High radiation doors were properly maintained and equipment and personnel were properly surveyed prior to exit from the radiation control area (RCA). Plant workers were observed to be cognizant of posting requirements and using good radiological practices during refueling activities and maintenance on the ECCS and turbine systems. Personnel radiation exposures were reduced, in part, by effective planning for the RHRSW HX maintenance and security activitie _.
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i The inspector verified that security conditions met regulatory requirements and the VY Physical Security Plan. Plant tours during regular and backshift hours verified that compensatory measures for disabled security alarms were in accordance with approved procedures.
i Devitalization of the reactor core isolation cooling system and "B" EDG rooms were conducted in accordance with security instructions. Shift rotations were evnducted at an appropriate frequency to prevent fatigue.
Perimeter and supplemental lighting.were adequate.
No significant deficiencies were observed with personnel and vehicle access controls. OfScers assigned to control access duties at the drywell and refuel floor entrances were alert and cognizant of post orders.
Physical boundaries and video camera monitors enhanced the effectiveness of access control in these areas.
5.3 llousekeeping and Fire Protection
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During tours of the reactor and turbine buildings. goed housekeeping and fire protection were observed. Few transient materials and combustibles were observed during the "B" EDG cylinder liner replacement (NRC Inspection Report 93-20), ano in the emergency core cooling corner rooms during modification of the RHRSW system (section 4.4) and maintenance on the core
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spray systems. Excellent housekeeping was maintained at the worksite associated with the reactor vessel water level modification (section 4.5) based on the control of materials near emergency core cooling system instrumentation. On a frequent basis, the inspector observed the
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Plant Manager, Technical Programs Manager, and Operations Manager conducting tours in ~
equipment spaces containing safety systems. The inspector verified that a sampling of VY-identified deficiencies were corrected.
The Shift Engineer was cognizant of maintenance and plant conditions that potentially affected fire loading. During explosive tube plugging of RHRSW heat exchanger tubes (section 3.1.3),
hot work for the RHRSW modification (section 4.4), and activities in the high pressure coolant-injection room, fire permits accurately described the conditions and compensatory measures.
.l 6.0 ADMINISTRATIVE
.i 6.1 Preliminary inspection Findings
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Meetings were held periodically with VY management during this inspection to discuss
inspection findings. A summary of preliminary Endings was also discussed at the conclusion
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of the inspection in an exit meeting held on October 12. No proprietary information was
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identified as being included in this report.
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ATTACIIMENT A i
VERIFICATION OF CORRECTIVE ACTIONS IMPLEMENTED PRIOR TO REFUEL OPERATIONS Based on inspector reviews of selected corrective actions (CAs), discussions with VY plant
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management, and independent assessment performed by the NRC Augmented Inspection Team (AIT), the NRC concluded that the corrective actions implemented provide reasonable assurance that the conduct of future refueling operations would be safe.
A summary of the CAs from the licensee's assessment and the NRC AIT Inspection Report 93-81 were docketed by VY letters to the NRC, dated September 20 and 22. Licensee CARS 93-43 and 93-46 documented methodologies used to assess the causes and contributors of the events
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and initial CA recommendations. Potential Reportable Occurrence Reports 93-88 and 93-89 assessed the NRC reportability requirements for each event. Additional recommendations from
the offsite Nuclear Safety Audit and Review Committee regarding training and documentation of lessons learned were also implemented by the Manager of Operations prior to refueling. The listing below summarizes portions of the corrective actions reviewed.
Procedure Revisions:
OP 1101, " Management of Refueling Activities & Fuel Assembly i
Movement" was revised to clarify duties and responsibilities for refueling personnel, require self-checking techniques and second verifications to assure the proper movement of fuel, and to remove ambiguous, non-descriptive statements regarding abnormal conditions, problems, and l
occurrences. Detailed steps were also added for the handling of peripheral fuel assemblies and
to differentiate between " action" and " verification" steps. Reactor and Computer Engineering Department memorandum, dated September 23, separated the administrative and fuel handling
responsibilities of the two refuel floor Reactor Engineers to provide further assurance that critical refuel handling steps are independently verified.
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Onerator Traininc: Classroom training and a read-and-sign were performed to instruct operators on the revisions to OP 1101. Training was also conducted by the Plant Manager emphasizing duties and responsibilities, procedural. adherence, lessons learned, command and control, i
communications, and plant safety. By memorandum dated September 19, the Plant Manager
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articulated his expectations regarding procedural adherence to Department Managers and Superintendents. On-the-job (OJT) refuel training using the revised OP 1101 was conducted by the Operation Manager (OM) and independently assessed by YNSD Quality Services Division.
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The OJT emphasized communications, command and control, and self checking techniques. Job performance standards were established and completed. Shift Supervisor training was conducted by the Operations Manager stressing, in part, management oversight, authority, and procedural adherence.
The operator classroom training was conducted by the Operations Training Supervisor using industry guidance, procedure OP 1101, and pre-established lesson plans. Detailed discussions regarding procedural precautions, prerequisites, and fuel handling steps were observed.
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Examples were provided to operators regarding so called " critical phases". of fuel handling, however, subsequent clarification was necessary and provided to all operators by Training
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Department memorandum dated September 23. Industry guidance regarding:
(1) human performance techniques to reduce the occurrence of plant events, and (2) the conduct of infrequently performed tests and evolutions were incorporated into the training plan. The inspector verified that the Shift Supervisors and operators performing fuel handling attended classroom training and performed OJT.
Effectiveness of Operator Traininc: The inspector conducted interviews with Shift Supervisors and refueling operators and concluded that the training was adequate.
Operators were l
l knowledgeable of the procedure revisions, self-checking techniques, and management j
expectations regarding procedural adherence. The operators adequately described the causes of j
the September 3 and 9 refuel events. The operators were also knowledgeable of the refuel bridge modifications to improve human factor characteristics (joy stick direction and grapple -
indication light) and the grapple interlock. The inspector placed the operators in hypothetical situations involving abnormal refueling situations and observed that appropriate references to procedural guidance and requirements were made. A procedure walkthrough of fuel transfer steps was alsn performed. One concern regarding the lack of detail for the handling of peripheral fuel assemblies was identified. Vermont Yankee acknowledged this observation and revised the specific steps of the OP 1101. The operators interviewed were professional and reflected appropriate regard for the safe conduct of refuel operations.
The inspector observed the conduct of OJT and determined that it met the intent of the lesson plan and simulated actual fuel handling operations. The OJT consisted of one fuel handling
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operation with multiple performance standards. The Operation Manager (OM) stated that this.
format was sitnilar to OJT performed during normal licensed operator training. During the OIT, discussions between the operators and the OM regarding communications and pre-shift briefs were observed, however, the operators were not prompted to meet performance standards. No operators required remedial training.
Supervisorv Oversight During Refuel Activities: A log book was maintained and updated on the
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refuel 'loor to reflect the observations made by supervisors assigned to independently assess the conduct and safety of refuel operations. A checklist was used by all supervisors to assure that the refueling shifts were judged against pre-established criteria.
Comments regarding communications, refuel bridge mechanical deficiencies, procedural adherence, and the conduct of refueling operations were made. On two separate occasions, the Plant Manager was observed.
to assess refuel floor activities; QSD was also observed on a number of occasions. The inspector reviewed the log and verified that no safety signi0 cant issues were identified.
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