ML20149L343
| ML20149L343 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee  |
| Issue date: | 02/14/1996 |
| From: | Conte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20149L328 | List: |
| References | |
| 50-271-95-25, NUDOCS 9602260194 | |
| Download: ML20149L343 (26) | |
See also: IR 05000271/1995025
Text
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Enclosure 2
U.S. Nuclear Regulatory Commission
Region I
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Report No. 95-25
Docket No. 50-271
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Licensee No.- DPR-28
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Licensee: Vermont Yankee Nuclear Power Corporation
RD 5, Box 169
Ferry Road
Brattleboro, VT 05301
Facility: Vermont Yankee Nuclear Power Station
Vernon, Vermont
l Inspection Period: November 7 - December 31, 1995
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Inspectors: William A. Cook, Senior Resident Inspector
Paul W. Harris, Resident Inspector
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Approved by: I [
Richard J. Conte // 'Date'
L Chief, Reactor Prtfjects Branch 5
Scope: Station activities inspected by the resident staff this period
included Operations, Maintenance, Engineering, Plant Support, and
Safety Assessment and Quality Verification. Backshift and " deep"
i backshift including weekend activities amounting to 21.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />
were performed on November 7, 8, 9, 10, 11 and December 4, 6, 7.
8. and 21. Interviews and discussions were conducted with members
of Vermont Yankee management and staff as necessary to support
- this' inspection.
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Findings: An overall assessment of performance during this period is
- sumniarized in the Executive Summary. Inspector review of the i
Vermont Yankee staff's evaluation and root cause of the December 8 :
reactor scram is being tracked as an unresolved _ item (URI 95-25- l
01). NRC staff review is planned for Vermont Yankee's HPCI
operability determination with HPCI pump suction aligned to the
- suppression chamber (IFI 95-25-02). NRC staff review of VY's
responses to Bulletin 95-02 and surveillance of ECCS suction
strainer performance is planned (IFI 95-25-03). Resolution of a
Technical Specification error involving the-specified test gas
mixture for advar,ced offgas system hydrogen monitor calibrations
is an unresolved item (URI 95-25-04). Further inspector review of
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9602260194 960215
PDR ADOCK 05000271
G PDR
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single failure and primary containment integrity concerns
involving the HPCI system suction valves logic design is an
unresolved item (URI 95-25-05). NRC review of system modification
impact and associated protective tagging controls is unresolved
(URI 95-25-06). Unresolved item (URI 94-13-02) regarding the
level of quality assurance applied to non-nuclear safety
components that retain reactor coolant system pressure was closed.
Violation (VIO 94-13-02) was updated to reflect recent inspection
observations of the PORC. Enforcement discretion was applied to
the violations described in LERs 95-01, 95-02, 95-18, and their
associate supplements.
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TABLE OF CONTENTS
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TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
1.0 SUMMARY OF FACILITY ACTIVITIES .................. 1
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2.0 OPERATIONS (71707, 71714) . . . . . . . . . . . . . . . . . . . . . I
- 2.1 Operational Safety Verification . . . . . . . . . . . . . . . I
2.2 (0 pen) URI 95-25-01: Reactor Scram . . . . . . . . . . . . . 1
2.2.1 Scram Recovery: Actions and Performance ....... 2
2.3 Cold Weather Preparations . . . . . . . . . . . . . . . . . . 3
2.4 (0 pen) IFI 95-25-02: High Pressure Coolant Injection
Operation and Testing . . . . . . . . . . . . . . . . . . . . 4
. 3.0 MAINTENANCE (62703, 61726) .................... 5
3.1 Maintenance Activities ................... 5
3.1.1 Alternate Cooling Tower Structural Failure ...... 5
3.1.2 Feedwater Regulation Valve Troubleshooting ...... 6
3.2 Surveillance Activities . . . . . . . . . . . . . . . . . . . 6
3.2.1 Single Rod Scram Time Testing . . . . . . . . . . . . . 7
3.2.2 Residual Heat Removal Suction Strainer Special Test . . 8
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3.2.3 (0 pen) IFI 95-25-03): Pump Suction Pressure
i Evaluation During Surveillance ............ 9
3.2.a (0 pen) URI 95-25-04: Augmented Off-Gas System
i Surveillance ..................... 9
4.0 ENGINEERING (37551, 71707) .................... 10
4.1 (0 pen) URI 95-25-06: Operations Impact of High Pressure i
Coolant Injection Design Change . . . . . . . . . . . . . . . 10
4.2 (0 pen) URI 95-25-05): HPCI Suction Valve Logic Design l
Observation . . . . . . . . . . . . . . . . . . . . . . . . . 12
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4.4 (Closed) URI 94-13-02: Quality Assurance of Non-nuclear )
Safety Components That Retain Reactor Coolant System )
Pressure .......................... 14 i
4.5 Review of Engineering Work Tracking . . . . . . . . . . . . . 15 l
5.0 PLANT SUPPORT (71750, 71707) ................... 16
5.1 Radiological Control s . . . . . . . . . . . . . . . . . . . . 16
5.1.1 Radiological Effluent Release Review ......... 16
5.2 Security .......................... 17
5.3 Fire Protectior. . . . . . . . . . . . . . . . . . . . . . . . 17
5.3.1 Inadvertent Fire Alarm ................ 17
5.3.2 Fire Loading Assessment . . . . . . . . . . . . . . . . 18
6.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (71707, 40500) . . . . . 18
6.1 (Update) VIO 94-13-01: Plant Operations Review Committee . . 18
6.2 Review of Written Reports . . . . . . . . . . . . . . . . . . 19
7.0 MANAGEMENT MEETINGS . . . . . . . . . . . . . . . . . . . . . . . . 22
- 7.1 Preliminary Inspection findings . . . . . . . . . . . . . . . 22
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Note: Procedures from NRC Inspection Manual Chapter 2515, " Operating Reactor
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Inspection Program" which were used as inspection guidance are parenthetically
listed for each applicable report section. -
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REPORT DETAILS FOR RESIDENT INSPECTION
No. 50-271/95-25
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1.0 SUMMARY 0F FACILITY ACTIVITIES
Vermont Yankee Nuclear Power Station (VY) operated at 100 percent rated
reactor power throughout this inspection period until December 8 when an
automatic reactor scram occurred due to a main turbine trip due to high
reactor water level. On December 10, following repairs and VY's post-trip
review, the plant was returned to full power operation. Minor reactor power
changes were also made this period to support surveillance and single rod
scram testing.
During the week of November 13, a region based specialist inspector conducted
a routine inspection of VY's Security Program. Inspector findings and
conclusions are enclosed.
! This period, VY reorganized their Engineering Department into six major
functional areas reporting to a single Vice President Engineering. The
functional areas include: Project Engineering; Performance Engineering;
Technical Support; Nuclear Services; and, Design Engineering. The latter two
. departments previously reported and were part of the Yankee Nuclear Services
Division (YNSD) at Yankee Atomic Electric Company (YAEC). As stated in VY
information the reorganization was undertaken, in part, to combine VY and YNSD
engineering resources, to improve the organization's efficiency, to reduce the
bureaucracy, and to help foster the implementation of the " system engineering"
concept.
The Reactor and Computer Engineering Department was also reorganized
effectively splitting the functional disciplines into two separate groups.
However, both the Reactor Engineering Department and Computer Engineering
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Group continue to report to the Technical Services Superintendent.
! 2.0 OPERATIONS (71707, 71714)
2.1 Operational Safety Verification
The inspectors verified adequate staffing, adherence to procedures and
Technical Specification (TS) limiting conditions for operation (LC0),
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.
Safety tagouts properly isolated equipment for maintenance.
2.2 (0 pen) URI 95-25-01: Reactor Scram
On December 8, at 11:14 a.m., the reactor scrammed from 79 percent power due
to a. turbine trip on high reactor vessel level. The reactor vessel level
. transient'resulted from troubleshooting the "A".feedwater regulating valve
(FRV). Earlier in the morning, reactor power was being reduced via
recirculation flow to support removal of the "A" FRV from service to further
troubleshoot observed oscillations of the FRV detected by the operations
staff. When reactor power was approximately 80 percent, severe feedwater
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piping vibration and "A" FRV stem cycling were witnessed locally. A licensed
operator at the FRV, quickly took local manual control of the valve by
inserting a tapered stem locking pin. The feedwater pipe vibration stopped.
, Reactor vessel water level was maintained within the normal control band
throughout this transient.
i Operating procedures specify that an operator be stationed locally in direct
communications with the control room while a FRV is in local manual control.
This condition is specified to ensure proper manual control of the FRV should
a transient occur necessitating a reactor vessel level change beyond the
capacity of the "B" FRV automttc level control capability. This action was
implemented, however, due to a severe pipe shake discussed above, asbestos
laden dust was deposited tnroughout the feedpump room and the auxiliary
operator assigned the local FRV control duties was temporarily stationed in
the turbine lube oil room adjacent to the feedpump room. The decision to
locate the operator in an adjacent room was because he lacked adequate
asbestos worker training and qualifications to remain in the feedpump room
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while cleanup was in progress.
In the turbine lube oil room, the auxiliary operator was available to respond,
< but not in direct line of sight (behind a closed door) with the "A" FRV.
Subsequently, due to normal flow induced piping vibration and because the
tapered stem locking pin was not fully engaged (due to the difficulty
encountered in pinning the cycling FRV stem), the locking pin vibrated out and
the resultant unregulated feedwater flow caused reactor vessel level to rise
and the subsequent turbine trip / reactor scram before manual action could be
initiated. The inspector notes that during the intervening time that the FRV
was pinned and it vibrated out, crews were cleaning up the asbestos dust and
the plant staff was evaluating alternatives to reducing reactor power to
remove the "A" FRV from service. As discussed in detail in section 2.2.1
below, reactor conditions were quickly stabilized and the reactor mode
maintained in Hot Standby while the necessary repairs were made. FRV
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troubleshooting is discussed in Section 3.1.2.
At the end of the inspection period, the VY staff had not completed their
evaluation and root cause analysis for this reactor scram. Preliminarily the
inspector noted that the stem locking pin could have been better monitored and
potentially prevented from vibrating out of the stem locking device. Pending
inspector review of the licensee's evaluation and root cause analysis of this
reactor scram, this event is unresolved (URI 95-25-01).
4 2.2.1 Scram Recovery: Actions and Performance
Control room operator (CRO) actions and performance in response to the
transient effectively resulted in the safe reactor power transition to a hot
standby condition. The inspector observed prompt and accurate communications
regarding the status of all control rods, reactor power, level, pressure, and
-st atus of other safety systems. Clear instructions were.given to the reactor
operators (R0s) regarding reactor pressure control using the turbine bypass
valves and level control using a combination of reactor water cleanup and the
feedwater and condensate systems. Approximately one minute following the
scram, plant conditions were stable and well controlled.
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Within two minutes, post-scram recovery actions were implemented. The
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emergency operating procedures.were entered for the scram and for the
i assessment of plant parameters. Turbine control and reactor shutdown
- operating procedures were implemented in parallel with their investigation of
i the cause of the scram (reference Section 2.2). Fifteen minutes after the
i scram, the scram was reset and a control room brief was held. During the
- brief, the Shift Supervisor (SS) reviewed plant corditions, the cause of the
i scram, procedures in use, discussed plant support activities, and clearly
articulated plans to achieve and maintain a hot shutdown condition. The
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inspector also observed two subsequent briefs conducted by the SS.
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! Inter-departmental support following the scram contributed to a prompt
- assessment of plant conditions. An off-shift SS led, coordinated, and
- reported activities within the feed pump room and helped stabilize reactor
j water level control. The Reactor Engineering Department retrieved and
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evaluated computer generated scram times to assesc control rod performance
(reference Section 4.1). The on-shift SS effectively augmented his staff with
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'off-shift operators and shift engineers to assist in recovery actions. The
l- plant operations-management was cognizant of plant conditions, observed post-
[ safety.
3 The inspector concluded that following the reactor scram the plant systems
- were appropriately operated through a combination of proper and timely actions
i by the CR0s, implementation of procedures, strong inter-departmental support,
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and management oversight. The assessment of plant conditions was thorough and
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focused on key reactor parameters such as scram time data and reactor water
1evel.
I 2.3 Cold Weather Preparations
{ The inspectors reviewed VY's preparation for cold weather to assess whether
i reasonable actions have been implemented to preclude temperature related
- component and system failures as noted in past years. VY prepared systems for
cold weather in accordance with OP 2196, Preparation for Cold Weather
i Operations.
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) The inspectors conducted system walk-downs, reviewed OP 2196, and identified
- no concerns with VY's preparation for cold weather. The procedure was
i implemented in advance of seasonal cold temperatures. Management reviews were
routinely conducted to assess the status of heating systems for the emergency
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diesel generator (EDG)-fuel oil tank and-other plant systems. An engineering-
E evaluation was conducted to assess the performance of diaphragms located
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within certain reactor. building isolation dampers and the chemistry staff
4 closely monitored the pour point of EDG fuel oil. Winter preventive
maintenance was conducted on the cooling towers, the intake ventilation system
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was aligned for the winter, and heat trace circuits were energized. VY
- ,e . identified freezing of the service water chemical treatment pipe and a level
transmitter for the demineralizer storage water tank. None of the problems
mentioned above adversely affected plant operation.
The inspector independently confirmed the completion of a selected number of
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OP 2196 requirements. Inspector walk-down of the intake structure, EDG fuel
oil tank condensate storage water tank (CST), and the heating and ventilation
room with a thermography camera identified no concerns. Insulation was intact
and dead-leg piping runs were confirmed to be warmer than 32 degrees F. The
general area temperatures were warm and maintained by heating units. No
standing liquid was observed adjacent to the CST and EDG fuel oil storage
tanks. Access to the travelling screen and intake gates was unfettered by ice
and snow. An inspection of the alternate cooling tower confirmed sufficient
de-icing water flow to prevent freezing and access to outdoor fire fighting
equipment was unfettered by ice and snow.
2.4 (0 pen) IFI 95-25-02: High Pressure Coolant Injection Operation and
Testing
The inspector reviewed the operation and testing of the high pressure coolant
injection (HPCI) system with particular emphasis on HPCI operation with its
pump suction aligned to the suppression chamber (SC). As described in Chapter
6 of the Final Safety Analysis Report (FSAR), HPCI pump suction is normally
aligned to the CST and will automatically transfer to the SC on low CST level.
This design feature can be implemented manually via HPCI operating procedure
0P 2120, High Pressure Coolant Injection System, and during HPCI surveillance
procedure OP 4120, HPCI Surveillance. A manual transfer is allowable if torus
water level approaches 11.92 feet and if SC water temperature is less than 140
degrees F. An automatic transfer occurs if CST level falls to 4 percent
(approximately 75,000 gallons). Based on VY procedures, HPCI is operable
irrespective of HPCI pump suction alignment. The term operable, as used here,
is defined as the capacity for HPCI to provide 4250 gpm to the reactor during
post-accident conditions.
The inspector reviewed pre- and post-startup (circa 1971) and surveillance
testing and noted that (unlike the HPCI pump suction aligned to the CST) the
HPCI system has never been demonstrated operational with its pump suction
aligned to the SC. A calculation or evaluation demonstrating operability of
this flow path was also not found. A startup test was performed in 1971 to
verify an open SC-to-SC flow path, however, this was conducted at one-half
turbine speed, more indicative of a cleanliness flush, and not demonstrative
of HPCI flow capability to the reactor during post-accident conditions.
Inservice inspection and testing of the suction piping and valves has been
performed and provides additional confidence that these components are
materially sound and operable. The inspector also noted that based on tne
surveillance and pre-startup testing of the reactor core isolation cooling
(RCIC) system, a similar condition may exist.
Based upon the above observations and discussions with station management, VY
wrote an Event Report (ER) to initiate a review to ascertain whether a
calculation or evaluation exists that would further support HPCI operability
when aligned to the SC. At the conclusion of the inspection period, the
inspector had identified no immediate concerns regarding HPCI operability.
Pre-startup testing, inservice inspection and testing, full flow testing to
the CST, and adequate net positive suction head to the HPCI booster pump
provide reasonable confidence that HPCI can perform its safety function with
its suction aligned to the SC. The NRC staff plans further review of this
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issue (IFI 95-25-02).
3 . 0* MAINTENANCE (62703, 61726)
3.1 Maintenance Activities
The inspectors observed selected maintenance on safety-related equipment to
determine whether these activities W re effectively conducted in accordance
with VY TS, and administrative controls (Procedure AP-0021 and AP-4000) using
approved procedures, safe tag-out practices and appropriate industry codes and
standards. Interviews were conducted with the cognizant engineers and
maintenance personnel and vendor equipment manuals were reviewed. The
inspectors reviewed corrective maintenance on the IT and 79-40 345 kV
switchyard circuit breakers, repairs to the alternate cooling tower cell 2-1
(reference Section 3.2), and the failure of the downstream river water
sampler. These activities were conducted with proper safety tag-outs"and
received appropriate management reviews.
The problems associated with the 345 kV switchyard circuit breakers were
caused by cold temperatures. Specifically, the IT breaker inadvertently
opened on low system air pressure and the 79-40 breaker routinely alarmed due
to low sodium hexa-floride (SF6) gas pressure. The 79-40 breaker problems
have occurred during previous winters and have not been effectively resolved
to preclude recurrence. To compensate, the VY staff has instituted enhanced
monitoring of these breakers. These breakers are under the control of VelCo
(the power distribution and transmission :uthority) for major maintenance
activities.
The failure of downstream river water sampler was also recurrent. This
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sampler generally fails when the Connecticut River water level increases
during Spring and/or Fall run-offs. Also, the design of this sampler tends to
entrain river silt in the process line degrading the operation of the sample
pump. With the sampler out-of-service, TS radiological sampling requirements
were satisfied by daily grab samples. The inspector verified that an ER was
initiated to assess this condition.
3.1.1 Alternate Cooling Tower Structural Failure
Twice a year VY inspects, performs preventive maintenance, and repairs
identified deficiencies of the forced-air cooling towers. As previously
documented in NRC Inspection Report 95-17, some timbers that make up the
lattice structure of the towers have failed or degraded to the point that
replacement was necessary. These prior problems were limited to the non-
safety related, non-seismic section of the cooling tower system. This period,
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VY identified that three vertical supports and one horizontal beam had t' ailed
in cell 2-1. This cell is safety related and seismically qualified and acts
as the ultimate heat sink should the cooling capacity of the Connecticut River
be =significantly reduced.
Vermont Yankee immediately commenced repair of the identified problems and
initiated an ER to ascertain whether problems exist with the design,
maintenance, and/or inspection of the entire cooling tower system. VY entered
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the applicable seven-day LC0 during this maintenance. VY also determined that
they have adequate confidence that cell 2-1 would remain operable until the
next scheduled inspection (Spring.of 1996). The inspectors had no concerns
regarding VY actions.
3.1.2 Feedwater Regulation Valve Troubleshooting
As previously discussed in Section 2.2, activities related to the downpower to
troubleshoot the "A" FRV lead to the December 8 reactor scram. The inspector -
was aware of earlier attempts (prior to December 8) to diagnose the minor
oscillation observed in the "A" FRV by the Instrumentation and Controls (I&C)
Department. This diagnostic troubleshooting involved pinning the valve
locally (per procedure) and cycling the controller to evaluate input and
output response. The I&C staff employed a vendor to assist in this type of
troubleshooting and was still awaiting the results of this diagnostic review
when the Decembe, 8 downpower to remove the FRV from service was conducted. ,
Subsequent to the December 8 reactor scram (the vendor had completed the data
analysis and.had attempted to communicate the results the day of the scram),
the VY I&C staff received the results which indicated that the FRV controller
was functioning properly and that the oscillation problem was associated with
the mechanical operation of the valve or valve internals. Vermont Yankee
decided to proceed with the reactor downpower maneuver without the "A" FRV
pinned and under local manual control, and without a status report on the
subject data analysis. This action reflected weak oversight of the problem by
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maintenance management.
3.2 Surveillance Activities
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Th inspector reviewed procedures, witnessed testing in-progress, and reviewed
completed surveillance record packages. The surveillance tests which follow .
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were reviewed and were found effective with respect to meeting the safety
I 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 administrative controls (Procedure AP-4000), using TS approved
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procedures.
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e OP-4400, Calibration of the Average Power Range Monitoring System to
- Core Thermal Power, performed on 11/8/95
! e AP 0164, Operating Department Inservice Testing, performed on 11/8/95
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e OP-4115, Primary Containment and Surveillance
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e OP-4152, Equipment and Floor Drain Sump and Totalizer Surveillance
e OP-4113, Main and Auxiliary Steam System Surveillance, performed on
11/7/95
e OP-2403, Control Rod Sequence Exchange With the Reactor On-Linn,
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performed on 11/7/95
e OP-4424, Control Rod Scram Testing and Data Reduction, performed on
11/7/95
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3.2.1 Single Rod Scram Time Testing
On November 7, VY conducted TS required single rod scram testing of 45 control
rods. The notch 46 drop-out time for the 45 rods tested had increased from a
beginning-of-cycle (B0C) average of 0.317 seconds to 0.347 seconds. With the
.45 tested rod times averaged in to the remaining 44 rods (tested at B0C) the
core-wide average for notch 46 drop-out. increased from 0.317 to 0.333 seconds.
The TS 3.3.C.1.1 core-wide average for notch 46 is 0.358 seconds.
VY management and the Plant Operations Review Committee (PORC) reviewed this
scram time degradation and determined that the plant could continue operation
for a-limited period of time, however, contingencies would need to be
immediately initiated. The licensee extrapolated the degradation and
determined that the core-wide average would approach the TS limit in January
1996. In the interim, reviews were conducted to assess control rod drive
(CRD) maintenance, the scram time data retrieval system, reactor protection
system voltage applied to the scram solenoid pilot valves (SSPVs), CR0 air
quality, and hydraulic control unit pressures. An industry search was
initiated to determine whether other nuclear utilities experienced similar
time degradation. Discussions with General Electric (GE) and Automatic Switch
Company (ASCo), supplier of the SSPVs, were initiated.
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On November 9, five control rods were scrammed for troubleshooting purposes.
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Results were similar, the notch 46 drop-out time was approximately 30
milliseconds slow. No problems were identified with the any of the supporting
, systems. On November 15, the SSPV assembly for CRD 42-23 was removed and
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bench tested. Results indicated that the cause of the slowed scram times was
! SSPV degradation. The rod 42-23 SSPV assembly slowed from 0.047 to 0.107
, seconds. Two additional sets of SSPVs were removed and troublestcoting
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specific to SSPVs was commenced. On Novnber 21, VY determined that the SSPV
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diaphragms experienced elastic deformat0cn while in use. In particular, the
VIT0N elastomer diaphragm (ASCo model number HV-266000-2J) chemically reacted
with the SSPV end cap resulting in the diaphragm " sticking" to the end cap.
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The licensee also determined that the '118' SSPV was the primary contributor
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to the slowed scram times. Preparations to replace the diaphragms and end-
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caps began. The inspector noted that if the diaphragms stick to the end-cap,
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a higher differential pressure (hence more time) would be needed to cause the
< diaphragm to flex and vent air off the scram valves.
On December 8, a reactor scram occurred (reference Section 2.2) and the core-
wide notch 46 drop-out time was 0.355 seconds, representing a slightly quicker
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degradation rate than previously assumed. VY management decided to replace ,
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the '118' end caps, o-rings, and diaphragms; the '117' SSPVs were not changed
due to the unavailability of parts. On December 10, the '118' replacements
were completed and single rod scrams resulted in a core-average notch 46 drop-
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out of 0.329 seconds. The plant was returned to full power.
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s In summary, VY aggressively, pursued this problem . informed other nuclear power
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plants of this generic concern, and pro-actively established an accelerated
single rod scram testing schedule to monitor for further degradation.
Additional end-caps, 0-rings, and diaphragms were being procured to replace
the '117' SSPVs. A few negative aspects of VY's approach to resolve this
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problem were noted, such as the slow development of a statistically
representative sample size for the assessment of core-wide scram time
, performance and a weak equivalency evaluation for the new diaphragm end-caps.
These aspects were minor and did not significantly detract from the overall
good safety focus demonstrated by the plant staff.
3.2.2 Residual Heat Removal Suction Strainer Special Test
, NRC Bulletin 95-02, Unexpected Clogging of a Residual Heat Removal (RHR) Pump
Strainer While Operating in Suppression Pool Cooling Mode, alerts licensees to
a recent industry event and requests, in part, that licensees show by
demonstration and administrative controls that the RHR system would remain
operable during post-accident SC cooling operations. The inspectors reviewed
VY's response to Bulletin 95-02 and evaluated the conduct of VY special test
i procedure (STP) 95-12, RHR Suction Strainer Special Test, to ascertain whether
, VY adequately addressed the generic safety concern described in the bulletin.
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VY letter dated November 16 entitled, 30-Day Response to NRC Bulletin 95-02,
accurately represented the actions performed and credit taken by VY in their
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assessment of Bulletin 95-02. The inspectors independently confirmed by
inspection that the SC was cleaned during the 1995 refueling outage; foreign
material exclusion controls and conduct of primary containment close-out
inspections for the drywell and SC have been adequate; and, the emergency core
cooling system (ECCS) pump suction strainers were appropriately sized. By
letter dated December 18, VY reported the results of their testing and
conclusion that no suction strainer clogging occurred during the conduct of i
i the testing. The inspectors confirmed that these results were also accurate. l
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Further NRC staff review of the licensee's response is planned. '
,
The inspectors reviewed STP 95-12, observed portions of the test, and
concluded that the test was conducted safely. Test coordination was provided
. by a SS and management oversight of the test was provided by the Assistant
! Operations Manager. The pre-test brief focused on command and control,
- communications, acceptance criteria, and the sequence of events. Particular
emphasis was placed on test termination criteria and the recognition of
strainer clogging and pump problems.
"
STP 95-12 was reviewed by the Quality Assurance group, approved by the Manager
of Operations, and reviewed by a subcommittee of the Nuclear Safety Audit and
Review Committee. Procedure steps were succinct and clearly written. Single
and dual verifications were used throughout the STP. Appropriate instructions
, and descriptive drawings were provided for the installation and control of
temporary pressure instruments. Test acceptance criteria were selected to
provide margin to any adverse condition caused by the testing and were
reasonably based on the accuracy of test instruments. The 10CFR50.59 safety
evaluation supporting STP 95-12 was complete and sufficiently justified VY's
- determination that no unreviewed safety question existed for the conduct of
this test. Overall the ECCS suction strainer test.was thoroughly pre-planned
and evaluated. The related procedure and implementation reflected a well
controlled evolution with enhanced management oversight.
,
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3.2.3 (0 pen) IFI 95-25-03): Pump Suction Pressure Evaluation During
. Surveillance
The inspector evaluated pump performance data obtained during the surveillance
< testing of core spray (CS), high pressure coolant injection (HPCI), reactor
1
core isolation (RCIC), and RHR pumps and noted'the following. First, an
acceptance criteria of >0 psig for pump suction was established for the CS,
e pumps. Second, pump suction pressures are always greater than 0 psig (during
- standby or pump operation) because of system orientation and hydraulic
performance; and, therefore, of little value for the measurement of system
performance.
The inspector noted that a more representative operational limit for pump
suction pressures could be based on a deviation from a normally expected
i value. For suction pressures, this type of acceptance criteria could be
indicative of a loss of net positive suction due to strainer clogging, as 4
'
represented in NRC Bulletin 95-02. As described in Section 3.2.2, this type
of acceptance criteria was used in combination with high accuracy pressure
gages.
' These observations were discussed with the Operations Department In-Service
Test (IST) Coordinator. At that time, the inspector was informed that an
internal VY commitment item was still open regarding possible system
,
improvements to enhance the monitoring of ECCS suction pressures. The
,
inspector was also informed that there was no readily available justification
for the 0 psig or greater acceptance criteria and that the installed pressure
'
'
gages were of insufficient accuracy to effectively monitor suction strainer
- clogging (the gauges are adequate for normal system operation and test).
I These pressure gauges are original plant equipment and design.
I In summary, VY's testing of ECCS pumps met regulatory requirements, however,
- the testing methodology and procedure acceptance criteria during quarterly
surveillance testing provided limited value for the evaluatior, of long-term
,
suction strainer performance. During some RHR and RHR ser" ice water testing,
. high accuracy pressure gages are installed to enhance pressure c csurements.
Further NRC staff review is planned to assess VY's Bulletin 95-02 responses
"
and ECCS suction strainer performance monitoring (IFI 95-25-03).
3.2.4 (0 pen) URI 95-25-04: Augmented Off-Gas System Surveillance
,
Vermont Yankee identified and documented in ER 95-681 that the composition of
the test gas used to calibrate the augmented off-gas (A0G) system hydrogen
monitors (H,AN-0G-2921A/B and H,AN-0G-2922A/B) was different than that ]
described in the TS. This discrepancy was identified during a procedural
review by an I&C engineer who was investigating a report that the monitors
were indicating hydrogen concentrations that differed by more than ten
.
> u percente Procedure OP 4380, " Functional Calibration of. Hydrogen Detection
System," prerequisite 1.a. states to use a test gas of 22% H, in air. TS
. Table 4.9.2, note 4, states that standard gas samples containing suitable
concentration of hydrogen balanced nitrogen shall be used for instrument l
calibration. l
!
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'
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The licensee evaluated this condition and concluded that their current
- calibration of the A0G hydrogen monitors was correct, however, TS Table 4.9.2
note 4 was in error and required revision to reflect the proper test gas
-composition. The licensee determined that the installed instrumentation
required oxygen balanced nitrogen because the sensing process needs oxygen to
initiate a catalytic reaction. This assessment was confirmed by the vendor of
the hydrogen sensing instruments.
The inspectors confirmed that VY management ensured a timely review of this
problem and directed that the resolution be completed prior to reactor startup
from the automatic scram (reference Section 2.2). The Chemistry Department
conducted chemical analyses and cross-checks to ascertain hydrogen
concentration within the A0G system verifying that the instrumentation was
properly working. The maintenance staff reviewed the preventive and
corrective maintenance of the A0G system and identified no significant
concerns. The inspectors verified that the hydrogen monitoring
instrumentation installed to assure proper performance of the advanced offgas
system required oxygen balanced nitrogen to operate.
Preliminarily, the inspectors have determined that VY has adequately resolved
the problem, however, a number of weaknesses were evident. First, the ,
Chemistry Department did not accurately interpret the hydrogen concentration
within the A0G system during the initial laboratory analyses and cross-checks
performed immediately after problem identification. Although subsequent
evaluations were correct, the incorrect analyses demonstrated a weakness in
hydrogen concentration evaluation and laboratory quality assurance methods.
Second, the I&C Department did not initially fully understand the operation of
the A0G hydrogen monitoring system as demonstrated by their lack of
understanding of instrument operation. Third, the A0G hydrogen monitoring
instrumentation TS Table 4.9.2, note 4, does not correctly reflect the test
gas composition used to calibrate the instruments and appears to have been
incorrect since the early 1980's. This latter problem also indicated that the
biennial procedural reviews for OP 4380 were not entirely effective, in that, i
procedural review requirements require verification that the procedure
properly implements TS requirements. Pending licensee resolution of this TS ;
error, and further review of the implementation of biennial procedure review l
requirements, this item is unresolved (URI 95-25-04).
4.0 ENGINEERING (37551, 71707)
4.1 (0 pen) URI 95-25-06: Operations Impact of High Pressure Coolant
Injection Design Change j
On December 7, the inspector observed VY install a new type of a HPCI turbine
trip pushbutton. As described in Engineering Design Change Request (EDCR) 95-
408, depressing the old pushbutton caused a turbine trip and holding the
button in for approximately two minutes inhibited the turbine automatic
-restart function. The new pushbutton maintains the push-to-trip function and ,
includes an integral selector switch to provide a concurrent trip-and-inhibit I
feature. If the pushbutton collar is rotated to the trip / inhibit location,
'
the turbine will trip (similar to depressing the button) and the inhibit
signal would be locked-in, freeing the CR0 from depressing the button for two l
.
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minutes. Emergency Operating Procedure 3107, Appendix G, provides
instructions to the CR0s regarding the use of this new switch.
Prior to the conduct of the design change the inspector independently verified
that the change did not result in an unreviewed safety question or change to
i TSs. EDCR 95-408 received the required management and PORC reviews and
implementation of the EDCR met the requirements described in plant procedure
AP 6004, Engineering Design Change Request. This work was pre-planned and
'
scheduled.
^
The inspector observed two weaknesses associated with the implementation of
<
the HPCI turbine trip / inhibit pushbutton selector switch design change. The
'
first weakness was that training was not afforded to the operating staff prior
- to installation of the design change. Based on interviews, the on-shift CR0s
and operations department management did not know exactly how to operate the
trip /pushbutton and incorrectly assumed that the button worked like others
l already installed on the control room panels. After the new pushbutton
installation and inspector discussions with operations management, training
,
was conducted. Secondly, the inspector noted that the new pushbutton position
indication is not visible to the operator during operation. This poor human-
system interface was similar to some refueling system controls observed
. previously by the NRC staff (NRC Inspection Report 93-81, Section 6.1) and
reflected less than fully effective implementation of human factors guidance
"
as described in NUREG 0700, " Guideline for Control Room Design Reviews,"
Section 6.0.
! The operations staff was unaware of all of the consequences to the HPCI system
resulting from de-energizing HPCI logic control power. In particular, when
'
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the fuses were pulled, the HPCI suction transfer logic enabled causing two
i
motor-operated valves (HPCI-57 and 58) to open aligning HPCI pump suction to
the SC. Because the CST suction valve (HPCI-17) remained in its normally open
position, HPCI was also aligned to the CST. The Supervisory CR0 recognized
I this abnormal lineup and shut HPCI-17 thus leaving HPCI suction aligned to the
1 SC. ER 95-689 was written to evaluate and identify corrective actions for the
i tag-out problem. Three corrective actions were immediately identified and l
4 implemented: (1) the HPCI-17 valve was shut to prevent CST drainage into the
! SC; (2) the EDCR was changed to account for the system change caused by the
tag-out; and, (3) department managers discussed the problem with the cognizant
engineers. The inspector noted that primary containment integrity was not
questioned (reference section 4.2) and no corrective actions were assigned to
the Operations Department.
As described in plant procedure AP 0125, Plant Equipment Control, prior to the
removal of TS equipment from service, the SS will ensure that a detailed
review of the loads impacted by the de-energization of the power supply is :
completed. As demonstrated, this particular SS review was apparently
ineffective. At the conclusion of the inspection period, VY was still
evaluating the events captured in ER 95-689. NRC review of administrative
controls used to ensure that: (1) modification activity will not have adverse
impacts on plant operations; and (2) operational reviews, including tag-out
controls, are sufficient to detect adverse system interactions when
implementing design changes is unresolved pending the completion of the
Vermont Yankee review (URI 95-25-06).
4
.
.
<
12
In summary, the weaknesses described above indicated both poor engineering
preparation and poor operations department staff review / verification of the
system protective tag-out. Despite the normal procedure controls established
-to assure the safe implementation of design changes and tag-outs, the effect
, of the tag-out on HPCI system conditions was not fully understood by the
operating and engineering staffs. This resulted in an unanticipated change in
- plant conditions and an unnecessary challenge for the operating crew.
4.2 (0 pen) URI 95-25-05): HPCI Suction Valve Logic Design Observation
The inspector performed a detailed review of the abnormal HPCI system lineup
caused by the HPCI pushbutton tag-out (Section 4.1) and noted that no system
damage or personnel injuries resulted. By design, the CST suction valve
(HPCI-17) will start to shut when the SC suction valves start to open. This
valve sequencing maintains HPCI pump suction pressure thus preventing a HPCI
trip on low suction pressure. This specific sequencing contributes to reactor
i
safety during post-accident conditions by maintaining the un-interrupted
injection of high pressure cooling water. However, during the design change
as discussed above, the interim piping line-up resulted in a direct water
pathway between the SC and the CST vent-to-atmosphere. The only physical
barriers between the SC and CST vent were one 14-inch check valve (HPCI-V-32)
and the column of water existing between the HPCI pump suction and the CST.
- The inspector was unable to determine if this unanticipated system
configuration (all three motor-operated suction isolation valves open
simultaneously) potentially compromised primary containment integrity. The
inspector was able to determine that the 14-inch check valve (HPCI-V-32) has
not been inspected or tested in the reverse flow direction per the Inservice
Testing Program.
.
The failure to perform inservice testing of the check valve represented
another example of a recognized weakness in VY's IST Program (reference NRC
Inspection Reports 95-22 and 95-23). The inspector noted that as a result of
these previous NRC findings, VY is currently performing a complete IST Program j
review, VY management acknowledged the inspector's observations and initiated
reviews to: determine whether primary containment integrity was compromised
during the interim lineup; assess the CST suction transfer instructions; and
determine whether the CST /SC suction transfer logic circuitry is required to i
'
meet the single failure criterion. The licensee also confirmed that the 14-
inch check valve (HPCI-V-32) should have been in their IST program. The
status of primary containment integrity during the interim piping lineup and I
the application of the single failure criteria to the SC/ CST suction transfer I
logic circuitry is unresolved (URI 95-25-05).
4.3 Loss of Stator Cooling Transient Followup
NRC Inspection Report 95-17 documented VY's initial resolution of a loss of
stator cooling (LOSC) transient. The LOSC transient, as described in GE
, ~ Service.Information Letter (SIL) No. 581, is applicable.to boiling water
nuclear power plants that have high turbine bypass capability, such as VY. '
Assuming no operator action, this transient could result in fuel element ,
failure. This failure could have consisted of excessive mechanical stresses i
within tne fuel pellet and a potential for fuel clad breach. Procedure ;
. .. - - -.- _ - .. - . - . . .- .
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13
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revisions were immediately implemented to resolve this problem. YNSD and GE
-
were' charged to perform a computer analysis of this transient. This period,
! the inspector reviewed VY's root cause evaluation, completion of long-term
. corrective actions, and assessed the overall handling of this industry
information by the licensee.
l The six member task team, chartered by VY to perform the root cause assessment
and technical evaluation of the LOSC transient, was well balanced. Management
j oversight was provided by the Technical Services Superintendent and the task
team chairperson was the Reactor and Computer Engineering Manager. Technical
- LOCA analysis, reactor physics, and fuel performance. An operations-oriented
i perspective was also included in the team. Transient and fuel performance
l information from GE was also utilized.
4
The technical evaluation of the LOSC transient was comprehensive. To bound
4
the LOSC transient, an approximate two percent margin increase to the
applicable core thermal ifmits was imposed. This change was permanently
,
installed into the plant process computer. No changes to TS were required.
An update to the FSAR is planned. The task team appropriately reviewed and
referenced VY's design bases in their safety and technical assessments. They
also reviewed license commitments and regulatory requirements. Transient case
studies were run at differing initial conditions to ascertain worse-case fuel
performance conditions. The analytical methodologies for these case-studies
] were verified and validated to assure accuracy. A historical review confirmed
j that the plant operated within design during previous operating cycles. The
! inspector verified that the transient and fuel performance analyses used by VY
- were reviewed and approved by the NRC staff and referenced in the VY design
basis.
The VY team identified the root cause as the failure to identify the LOSC
l transient as a limiting event during original plant licensing (circa 1971).
'
The apparent causes involved Vi's evaluation of its design basis adequacy
, relative to the FSAR transient analyses and YAEC's evaluation of VY's
,
licensing basis when it was obtained from GE (circa 1980). The contributing
! causes were a delay in fully evaluating the LOSC transient and then a failure
'
to recognize the need for prompt corrective actions. The inspector noted that
.
the team identified apparent causes along with root and contributing causes.
' This is inconsistent with the VY Root Cause Guideline (RCG) (only apparent ;
causes DI root and contributing causes, not all three).
4
l
The corrective actions (CAs) were classified as Type A Commitments (the
- highest commitment prioritization available) and had estimated completion
dates (ECDs) commensurate with the importance or significance of the
particular action. However, seven of ten commitments had their ECDs extended
.
i
i
without documented management review and five of ten were completed beyond
! their ECDs (even with their ECDs extended). The inspector also reviewed the
+ ~ < completion 2 status -of. ER 95-244 written for the problems. associated with the
! main station battery (reference NRC Inspection Report 95-06) to ascertain the
'
breadth of the above observation and noted similar commitment management
problems. Of sixteen Type A commitments assigned to ER 95-244, seven were
3 completed overdue and two were still working and overdue. Although the ;
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14
commitments were not rigorously administered, no safety concerns were
identified.
The inspector also reviewed the CAs and found that CAs were not assigned to
the root or apparent causes. The RCG indicates that a root cause should have
a corrective action to fix the problem and prevent recurrence. Of the ten
CAs, eight focused on the resolution of technical problems to assure safe
reactor plant operations. The remaining two CAs addressed the contributing
causes. Although its too early for the inspector to evaluate the
effectiveness of all CAs, the CAs to resolve the technical problems appeared
comprehensive and those assigned to resolve the communication problems
appeared adequate. The communication CAs hinge on VY's anticipation that the
engineering reorganization (see Section 5.4) will improve the four
communication weaknesses identified by the team. The inspector noted that
VY's documentation justifying the closure of these CAs was not included in
their response to ER 95-436.
The inspector also noted that the problem statement was not clearly stated to
effectively focus the team's effort and that the review of "potentially
similar conditions" was not performed. VY defined the problem statement as,
"More limiting [ moderator temperature decrease] transient than previously
identified." Although this was factual, the problem was that operating
experience was not effectively evaluated by the VY organization (as the
contributing causes would indicate). From this perspective, the causes
correlated with the problem statement and corrective actions precluded
recurrence. The identification date for the LOSC transient was when GE SIL
581 was received (April 4,1994), not when the plant was originally licensed
as the team's root cause would indicate. The team's review of potentially
similar conditions focused on prior opportunities to fully evaluate LOSC-type
It appeared to the inspector that the handling of this operating experience
- was the central problem to resolve. The inter-organizational effectiveness
between VY and YAEL on this technical problem was weak, with respect to the
timely resolution of this potential safety issue. This inter-organizational
,
weakness was indicative of problems noted during past inspections in the motor
operated valve (MOV) and 10 CFR 50 Appendix R programs. The VY root cause
analysis appeared to have been not well focused on this central theme.
Because of the CA's associated with the MOV and Appendix R problems noted
above, the inter-organization weakness was being addressed by VY.
In summary, the handling and resolution of the technical problems associated
with the LOSC transient were comprehensive and-focused on plant safety. No
safety concerns were identified by the inspector or VY. The experience and
expertise of the task team members contributed to the success of their
technical evaluation. However, the weaknesses identified in the root cause
In particular,
,
evaluation diminished the quality of the task team's product.
the.VY~ Root Cause Guideline was not effectively implemented for the
determination of the problem statement, cause determination, and review of
potentially similar conditions. In addition, the Type A commitment items for
the ERs reviewed were not rigorously administered.
._
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.
15
4.4 (Closed) URI 94-13-02: Quality Assurance of Non-nuclear Safety
Components That Retain Reactor Coolant System Pressure
Unresolved item 94-13-02 involved the level of quality assurance applied to
reactor coolant system (RCS) pressure boundary components that have been
designated by the licensee as non-nuclear safety (NNS). The inspectors noted
that quality controls as described in 10CFR50, Appendix B, Quality Assurance,
were not applied to NNS components that retain RCS pressure. The particular
component of concern was a pressure switch connected to the core spray system
via a 1/2-inch pipe.
On September 19, 1995, VY completed their review of this concern and concluded
that Appendix B quality assurance elements do not apply to components that
retain RCS pressure as long as they are classified as NNS. This determination
was based on VY's Safety Classification Manual (SCM) definition of NNS
components and their determination that the 1/2-inch line was not part of the
reactor coolant pressure boundary.
Using the NRC Standard Review Plan (NUREG-800, section 3.2.2), as a guide, the
inspector reviewed VY's determination and identified no concerns with the
licensee's conclusion. The VY Quality Assurance Manual (YOQAP-1A) commits to
Regulatory Guide 1.26, Quality Group Classifications and Standards, and the
licensee implements this NRC safety classification and quality control
guidance via their SCM. The pressure switch described above and other similar
components would have a level of quality assurance commensurate with their
safety function and be subject to manufacturer and ANSI B31.1 standards to
provide some level of assurance that NNS components meet appropriate material
and design specifications.
4.5 Review of Engineering Work Tracking
The inspector conducted a review of the engineering Work Tracking System (WTS)
to understand its safety function, use, and content. The inspector determined
that the current engineering staff WTS has been in use for approximately one
-
year. It is a computer data-base system which receives manual input via a
standard form entitled "VY Engineering & Construction Work Order". The
engineering work activities entered into the system include a broad range of
'
items (15 specified activities) from Engineering Design Change Reports,
commitments, setpoint changes, and Event Reports to training courses and
vacation times for individual engineers. The WTS provides individual
engineers their list of work tasks to be performed with assigned priority and
estimates for completion. It also provides a means by which engineering
managers can track the recorded progress each engineer has made towards
completion of these assigned tasks.
Based upon s sampling of individual engineer weekly WTS reports (Manhour
Scheduling Reports) and discussions with responsible engineering managers, the
. inspector-found varying degrees of use and accuracy of this system.
Discussions with engineering managers identified that this observation was
previously recognized by the engineering staff and was being addressed by the
new engineering re-organization and management team. The WTS is currently
viewed as a tool for the engineering staff and not solely depended upon for
l
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j tracking such work activities as: engineering design changes, temporary and
- minor modifications,. equivalency evaluations, comitments, and Event Reports.
These activities, and others not specifica11y' mentioned, which involve !
- engineering resources to resolve each have a stand-alone tracking system that
'
is monitored more closely by both the engineering and station operating
,
staffs.
j For example, the Major Projects Work List, Engineering Department Monthly
- Status Report, and the' Weekly-YNSD VY Project Report provide a sumary listing
of the various key engineering activities and their status with respect to
- established performance goals and schedule milestones (maintenance and
,
refueling outages). These periodic sumary reports highlight the significant
-
work items in the engineering work backlog and the established priorities for
,
their completion. Based upon a sampling review and discussion with VY
- managers, the inspector determined that these reports were being used by
j engineering and plant management to monitor, and adjust as necessary, '
,
engineering resources to meet schedular comitments and to achieve the
,
- established performance goals.
l In sumary, the WTS was viewed by the VY engineering staff as a management
,
tool and not a fully matured engineering work control process, having been in
. use only one year. Specific types of engineering work activities hwe their
own unique tracking system and are periodically (weekly and monthly, at a
.
'
minimum) examined and reported on via sumary reports to engineering and
station management. The inspector found these sumary reports adequate and
' identified no specific concerns regarding the numbar or types of engineering
j work items in backlog. VY management has adequato inechanisms currently in
,
place to routinely monitor and assess the progress of these activities to
assure timely resolution.
5.0 PLANT SUPPORT (71750, 71707)
. 5.1 Radiological Controls and Radiological Effluent Release Review ,
I Inspectors routinely observed and reviewed radiological controls and practices
j during plant tours. The inspectors observed that posting of contaminated,
'
high airborne radiation, radiation and high radiation areas were in accordance
1 with administrative controls (AP-0500 series procedures) and plant
'
instructions. High radiation doors were properly maintained and equipment and
l' personnel were properly surveyed prior to exit from the radiation control 1
area. Plant workers were observed to be cognizant of posting requirements and i
i maintained good housekeeping.
1
The inspector reviewed VY data to assess radiological effluent releases from
the main plant stack. Data reviewed included gaseous and particulate isotopic
i
concentrations and trends as illustrated in failed fuel status reports, off-
site dose calculations, and " raw" data from the main plant stack effluent
'
- charcoal.and filter samples. This inspection focused on. radiological data at
,
the end of the last operating cycle (March 17,1995) and the data and trend
information from May 2, 1995, to December 15, 1995.
!
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The inspector identified no abnormal sample or release values, or adverse
l
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trends. Trends for isotopic elements generated from reactor power operation
over the operating cycle were normal. Transuranic radio-isotope daughter
> products from previous fuel element failures continued,their downward trend.
This trend included krypton, xenon, and iodine release rates. The inspector
also verified that offsite dose releases at the site area boundary were within
i
TS limits. These included iodine, tritium, and particulates, and noble gas
'
beta and gamma. A sampling of the gaseous effluent filter analyses was
examined and the inspector verified that periodic samples and analyses were
conducted. Daily control room panel walkdowns and TS log reviews confirmed
i the operability status of the augmented offgas system and main plant stack
radiation monitors. Daily the inspectors assessed the offgas rate and slope
and reviewed the identified corrective maintenance list. No radiological
effluent release concerns involving these systems were identified.
5.2 Security
- The inspector verified that security conditions met regulatory requirements
i and the VY Physical Security Plan. Physical security was inspected during
regular and backshift hours to verify that controls were in accordance with
the security plan and approved procedures.
5.3 Fire Protection
,
5.3.1 Inadvertent Fire Alarm j
On November 30, at approximately 9:00 a.m., the turbine truck bay fire
detection system alarmed. The station fire brigade responded, accordingly.
i The cause of the fire detector system alarm was an open flame (propane torch)
"
being used to install shrink wrap material on a turbine part. This truck bay
,
maintenance evolution was planned, and the fire brigade was secured after the
cause of the fire detection alarm was identified.
Inspector follow-up with the shift engineer (fire brigade leader) determined
- that the fire detection alarm was not anticipated. The turbine truck bay is
protected from fire damage by an ultraviolet (VV) detection system (four
- sensors, one in each quadrant of the bay) and its associated automatic water
i deluge system. In preparation for the truck bay work, this system was taken
to bypass because an open flame was expected to trigger the UV detectors and
activate the system. However, the VY staff did not expect to receive the fire
- detection alarm with the system control switch in bypass.
Olscussions with the control room staff identified that no specific system
I
written guidance was available for fire protection detection or actuation
circuits with respect to disabling and re-enabling these systems from service.
The inspector determined that Operating Procedure (0P)-2186, " Fire Suppression
Systems", provides limited fire suppression system automatic and manual
actuation procedural guidance. Control room operator experience and on-the-
ojob. training currently serves to provide this type (how to bypass / abort a fire
,
system) of plant systems knowledge. With respect to this turbine truck bay
door issue, the control switch being placed in the abort / bypass position was
assumed to remove both the automatic deluge and detection (alarm) function
i
from service. As demonstrated, the alarm function was not bypassed via this
,
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18
control function.
Based upon the above, the control room operators initiated an ER (#95-655) to
capture this event and information concerning the turbine truck bay automatic
deluge system. Further review by the inspector determined that other than as-
built electrical prints, none of the fire protection detection and suppression
systems have written guidance to aid the operators in understanding and
assuring the proper bypassing of their respective automatic detection and
actuation circuits. The lack of a readily available reference material for
this type of evolution was considered a procedural weakness.
5.3.2 Fire Loading Assessment
During a reactor building tour, the inspector observed workers replacing the
insulation on the HPCI turbine exhaust pipe. The workers were properly
following pre-planned work instructions, however, the activity resulted in a
temporary accumulation of combustible materials in the immediate vicinity of
the HPCI system. After discussing this observation with the control room
-operators, the on-shift Shift Engineer (SE) assessed this increased loading as
acceptable and work continued.
The inspector noted that the HPCI system is inspected every two hours by
firewatches established to compensate for licensee-identified problems with
their implementation of 10CFR50, Appendix R, safe shutdown requirements. In
addition, other SEs and fire protection engineers have routinely toured the
area to assess fire conditions in an on-going strategy to prevent fires and
enhance fire safety. Nonetheless, the inspector determined that little
information exists in VY procedures as to what constitutes unacceptable
transient combustible material fire loading. When the SE assessed the
condition in the HPCI room, the fire loading was assessed based on experience
and training. This type of subjective assessment applies to other SEs and the
onsite fire protection engineers. Guidance on acceptable fire loading is not
described in VY procedures or Fire Hazards Analysis. Although it would be
- difficult to specify explicit requirements for all conceivable combinations of
- ~ fire. loading throughout the plant, general guidance based on known in-situ
combustibles and margins to fire suppression capability can be qualitatively
evaluated to provide some guidance to personnel responsible for making fire
safety assessments.
The Fire Protection Manager acknowledged the inspectors observations and
- concerns and stated that a VY internal commitment already exists to enhance
the instruction and guidance provided in plant procedure AP 0042, Plant Fire
'
- Prevention and Fire Protection. The manager stated that this initiative would
i be expanded to include an assessment whether explicit guidance can be
'
furnished to provide confidence that fire loading assessments are consistent
and based on objective standards. The inspector had no further questions and
- considered the lack of explicit written guidance on specifying and assessing
- ~ transient. combustible. material fire loading as a procedural weakness.
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6.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (71707, 40500)
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- 6.1 (Update) VIO 94-13-01
- Plant Operations Review Committee ;
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The inspectors observed a number of PORC meetings and determined that they
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fulfilled TS requirements regarding the review of procedures and abnormal
- operating conditions. PORC meeting 95-121, focused on the immediate and long-
i term safety assessment of a very small pinhole leak in the service water
system. The leak was of particular importance because its isolation adversely
affected the operability of the fire water system. A meeting held on November
j 9, was a special PORC that convened to review the slow control rod scram times
- (reference Section 3.2.1). Although the scram times were still acceptable,
j the PORC reviewed the safety consequences of slow scram times and extrapolated
i current scram times into the future to ascertain when the margin-to-safety as
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defined in the TS could potentially become compromised. PORC members also
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discussed plans to conduct additional scram time testing, the status of
I replacement parts, and actions to obtain information from GE regarding
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potential problems with ASCO solenoid valve end-cap tolerances and the VIT0N
j . diaphragm " stickiness" issue. The PORC prompted a review to ascertain whether
A followup.PORC on November 20 reviewed plans to conduct additional single rod
' scrams and questioned the adequacy of procedural controls and status of
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shutdown margin evaluations to support this testing.
The inspector observed the PORC's review of the proposed RHR suction strainer
test, STP 95-02 (reference Section 3.2.2). During this meeting. PORC members
evaluated the effect of the temporary pressure gauges on system seismic '
calculations, RHR pump operability with respect to suction pressures, and the
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i actual test configuration of the RHR subsystems during the test. A discussion
also focused on potential water hammer problems and system response should a
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loss of coolant accident and loss of offsite power occur during the special
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test. An appropriate safety perspective was demonstrated when a VY engineer
recommended (and PORC approved) that inanual operator actions should not be
credited nor relied upon to take-chamistry water samples from the SC during
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testing.
The reactive and routine PORCs observed this period appropriately focused on
plant and equipment problems that had an impact on plant safety. The PORC
4
members demonstrated a good questioning attitude during their evaluation of
i technical issues and provided a proper safety perspective in their decision
not to rely on manual operator actions during ECCS suction strainer testing.
1 No safety concerns or unreviewed safety questions were identified.
6.2 Review of Written Reports
{ The inspectors reviewed Licensee Event Reports (LERs) submitted to the NRC to
, verify accuracy, description of cause, and adequacy of corrective action. The
inspectors considered the need for further information, possible generic
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implications, and whether the event warranted further onsite followup. The
-LERs'were also reviewed with respect to the requirements of 10CFR50.73 and the
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guidance provided in NUREG 1022.
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e LER 94-09-01, Inadvertent primary containment isolation system
i activation due to an unexpected transfer of the 120/240 VAC vital bus
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to its alternate power source during a lightning storm, dated July 20,
1995,
e LER 94-10, Non-Nuclear Safety (NNS) components acting as a primary
containment boundary, dated September 9, 1994, (reference Section
4.4).
e LER 94-18 & 94-18-01, Two vital fire barriers inoperable due to
degraded fire penetration seals, dated January 13, 1995 and June 7,
1995, respectively.
e LER 95-01 & 95-01-01, Failure to perform surveillances to assure
primary containment integrity before releasing equipment for ,
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maintenance due to inadequate procedures, dated January 20, 1995 and
June 16, 1995, respectively. The failure to perform surveillance to
assure primary containment integrity were licensee identified, of
minor safety significance, and corrective actions were prompt and
comprehensive. This violation as described above was not cited
consistent with the NRC Enforcement Policy,Section IV.
e LER 95-02 & 95-02-01, Inadequate Final Safety Analysis Report
statement regarding ventilation airflow in the radwaste building
during resin cask transfer, dated February 17, 1995 and July 13, 1995,
respectively. The failure to perform surveillance to assure primary
containment integrity were licensee identified, of minor safety
significance, and corrective actions were prompt and comprehensive.
This violation as described above was not cited consistent with the
NRC Enforcement Policy,Section IV.
e LER 95-03, Failure to provide required emergency lighting in an area
in accordance with 10CFR50 Appendix R, Section III.J, due to a failure-
in the management system, dated March 3, 1995.
LER 55-03 documents the licensee's identification of inadequate
emergency lighting in the intake structure for operators to locally I
control the service water system for alternate plant shutdown l
purposes. A similar event was discovered by the VY staff and reported
in LER 94-11. Identification of this event was, in part, the result
of corrective actions associated with LER 94-11. Additional
inspection observations pertaining to emergency lighting were
documented in inspection report 95-26, and are being tracked via
unresolved item 94-31-02.
e LER 95-04, Incomplete repair of inoperable vital fire barrier
penetration fire seal, dated April 27, 1995,
e LER 95-06, RCIC system inoperable with isolation valve in closed
position due to a tripped supply breaker as a result of.a low
instantaneous trip setting, dated June 1, 1995.
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e LER 95-14 Supplement 2, Incomplete implementation of 10CFR50 Appendix
R based on identified deficiencies in the safe shutdown capability
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l analysis, dated November 20, 1995.
Supplement 2 documents the root and contributing causes for these
Appendix R deficiencies, as determined by the VY independent multi-
disciplined team. A detailed NRC staff review of the identi','ied
deficiencies was documented in NRC Inspection Report 95-26. Based
upon this review, additional inspection followup of the VY root cause
evaluation and corrective action was anticipated and will be tracked
independent of LER 95-14 and its two supplements.
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- LER 95-16, Stack particular filter used in composite sample to detect
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alpha and strontium 89 and 90 was misplaced due to inadequate tracking
methods, dated August 28, 1995.
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- LER 95-17 and Supplement 1, Technical Specification 4.6.E not met due
to components not included in the Inservice Test Program, dated
October 27, 1995 and November 30, 1995, respectively.
The subject of this LER was identified by NRC inspectors, as
documented in NRC Inspection Report 95-22. Enforcement action was
- taken and issued by letter dated October 20, 1995. Inspector followup
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and review of licensee corrective actions will be tracked via
- violations 95-22-01, 02, and 03. This LER is closed.
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! * LER 95-18 and Supplement 1, Inadequate IST surveillance and Regulatory
- Guide 1.97 submittal information on the recirculation loop sample line
isolation valves due to misinterpretation of the existing design
- configuration during program development, dated October 26, 1995 and
a November 30, 1995, respectively. l
Based upon an inquiry by another nuclear facility, the VY staff
4 identified that control power and indication circuit for valves FCV 2-
l 39 and FCV 2-40 (inside and outside containment recirculation loop
. sample isolation valves) did not satisfy Reg Guide 1.97 non-redundant l
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power source requirements, did not provide direct valve position
indication, and as a result, neither valve had been appropriately
tested per the Inservice Testing Program. The subject valves are air-
operated, 3/4-inch globe valves which: are normally closed; receive a
close signal from the primary containment isolation system Group 1
logic; and fail closed on a loss of air or control power. These
valves provide an alternate means of obtaining a reactor coolant
chemistry sample in the event the normal sample path, via the reactor
[ water cleanup system, is unavailable.
Upon identification of these deficiencies, the VY staff initiated
- prompt action to remove electrical power and protective tag the valve
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control switches on the control room panel per TS 3.7.D.2. The FCV 2-
40 valve has subsequently been verified closed daily per TS 4.7.0.2.
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Inspector review of the short and long term corrective actions for
this licensee identified problem determined that the VY staff has
- developed a comprehensive plan which includes
- the review of the
adequacy of earlier Reg Guide 1.97 commitments and submittals; a
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review of all power operated valve position indicator circuits for
similar design deficiencies; and a commitment to implement a design
change to facilitate proper inservice testing of FCV 2-39 and 40 prior
to startup from the 1998 Refueling Outage. VY determined the root
cause to be a misinterpretation of-the existing design configuration,
4 in that, it was not recognized that FCV-2-39/40 should have met Reg
Guide 1.97 power source requirements.
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These sample valve design and resultant testing deficiencies were
licensee identified, of minor safety consequence, and corrective
actions were prompt and comprehensive. This violation as described
above was not cited, consistent with Section IV of the NRC's
e LER 95-19, Vital fire door declared inoperable due to inability to
satisfy surveillance acceptance criteria, dated November 6,1995.
The reactor building (North) secondary containment airlock entrance
outer door was identified not to have an approved latch mechanism
installed. The VY staff identified this discrepancy as part of the
plant-wide baseline fire door inspection and evaluation. The
inspector verified appropriate compensatory measures were initiated
until an approved latch mechanism was procured and installed. VY
plans to submit a supplement to the LER to document the detailed root
cause analysis results for this event.
Periodic and Soecial Reoorts
Vermont Yankee submitted the following periodic and special reports which were
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reviewed for accuracy and found to be acceptable:
e Monthly Statistical Report for October and November,1995
7.0 MANAGEMENT MEETINGS
Heetings were held periodically with VY management during this inspection to
discuss inspection findings. A summary of preliminary findings was also
discussed at the conclusion of the inspection and prior to report issuance.
No proprietary information was identified as being included in this report.
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