ML20133A546
| ML20133A546 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 12/24/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20133A513 | List: |
| References | |
| 50-443-96-10, NUDOCS 9612310160 | |
| Download: ML20133A546 (21) | |
See also: IR 05000443/1996010
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
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Docket No.:
50-443
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. License No.:
Report No.:
50-443/96-10
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Licensee:
North Atlantic Energy Service Corporation
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Facility:
Seabrook Generating Station, Unit 1
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Location:
Post Office Box 300
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Seabrook, New Hampshire 03874
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Dates:
October 1,1996 November 29,1996
Inspectors:
John B. Macdonald, Senior Resident inspector
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David J. Mannai, Resident inspector
Accompanied by:
Javier Br'and, Resident inspector intern
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Approved by:
John Rogge, Chief, Projects Branch 8
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Division of Reactor Projects
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9612310160 961224
ADOCK 05000443
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EXECUTIVE SUMMARY
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Seabrook Generating Station, Unit 1
NRC Inspection Report 50-443/96-10
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 7-week period of resident inspection.
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Operations:
The licensee response to the NRC identification of the presence of temporary
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shipping caps in the spare conduit ports of several pressure transmitters has been
excellent. The caps have been in place since original transmitter installation and are
inconsistent with vendor manuals. However, due to the specific transmitter
applications and environmental qualification classifications, instrument operability
was not effected. The licensee decision to establish a task force to verify or
establish proper configuration for a significant sample population of currently
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installed transmitters reflected sound issue scope and initial cerractive action
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perspectives.
In sharp contrast to the corrective actions perspectives evidenced above, the
licensee failed to talo :.,rompt or comprehensive initial corrective actions to
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concerns initially raised by the Nuclear Safety Audit and Review Committee
(NSARC) in March 1994 regarding the lack of performance of a 10 CFR 50.59
safety evaluation for a procedure revision that established new operational and
configuration parameters for the emergency feedwater (EFW) system. Ultimately,
the licensee properly evaluated the et,ncern, determined the EFW system
configuration established by the procedure revision to be outside the design- and
licensing-bases of the station, and reported the occurrence to the NRC in
accordance with 10 CFR 50.72 and 50.73 reporting criteria. However, because
initial corrective actions were neither prompt nor adequate, the failure to perform an
adequate evaluation when the subject procedure was revised is cited as a violation
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of the requirements of 10 CFR 50.59.
Control room operators alertly identified initial indications of potential primary
reactor coolant system to secondary system leakage. Chemistry samples verified
the presence of a minor leak of approximately 1.0 gallons per day (gpd) in the "C"
steam generator (SG), which is a small fraction of the technical specification limits
of 500 gpd through any one SG and 1.0 gallons per minute (gpm) through all four
SGs. Throughout the report period, the leakage rate varied from less than
detectable levels to approximately 1.0 gpd. Station management developed a well-
coordinated response to the initial leakage, and established conservative
administrative response actions in the event of increased leakage.
Maintenance:
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System engineers effectively evaluated the potential adverse effects of oilintrusion
into the emergency diesel generator (EDG) barring device micro-switches.
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Executive Summary (Cont.)
Continuing evaluation identified a component upgrade to make the switches less
vulnerable to foreign materialintrusion.
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The work plan for the attempted leak sealant repair of a steam line instrument root
valve was effectively supported by engineering evaluation that considered
appropriate American Society of Mechanical Engineers (ASME) Code requirements
and valve design and application information. Good independent quality oversight
of the work effort was evidenced when a quality control (OC) inspector identified
that a drill stop had been improperly set. Field supervision properly terminated the
repair attempt when it was determined that physical interferences would prevent
successful completion of the intended repair. A subsequent repair plan was
developed and successfully implemented.
A Licensee Event Report (LER) and its supplement (LER 96-03 and 96-03-01)
regarding EFW pump mechanical seal failure properly addressed the reporting
criteria of 10 CFR 50.73.
Enaineerina:
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Diagnostic motor operated valve (MOV) testing of containment building spray (CBS)
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valve, CBS-V 43, was well controlled. The replacement of'the actuator gear set to
restore assumed operational performance and design-bases margin was well
controlled and effectively implemented.
Plant Sunoort:
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Radiological protection program controls were observed to have been properly
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implemented. Workers were noted to be complying with established procedures
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and controls. Chemistry personnel effectively supported the initial verification and
subsequent monitoring of the minor primary to secondary system leakage.
A previously issued safeguards violation (50-443/96-02 03) regarding the lack of a
continual behavior observation program for contractors with unescorted access who
are absent from the station for extended periods (greater than 30 days) was closed
following a review that determined appropriate corrective actions had been
implemented to the access authorization and control processes.
Assurance of Quality
Overall, station management demonstrated good oversight of issues important to
safety as well as to corrective action processes. Response to the initial indications
of primary to secondary leakage were prompt and well coordinated, increased
monitoring intervals and administrative limits were established that were
significantly more conservative than existing station procedural or regulatory
requirements.
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Executive Summary (Cont.)
The management decision to form a task force to verify or establish appropriate
instrument transmitter configurations reflected sound corrective action practices.
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Additionally, controls established to ensure proper conduct of an in-plant temporary
leak sealant repair effectively identified and ensured correction of improper tool
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settings prior to the initiation of the field work.
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However, station management did not aggressively ensure the timely technical
resolution of the NSARC concern initially raised in March 1994, regarding the
implementation of a revision to the startup feedwater pump (SUFP) operations
procedure without performance of a 10 CFR 50.59 safety evaluation it took
approximately two years of persistent effort on the part of the NSARC to heighten
the concern sufficiently before a detailed safety evaluation determined the
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procedure revision had authorized the establishment of an EFW configuration that
was outside the original design basis of the system.
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TABLE OF CONTENTS
EX ECUTIVE SUM M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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T AB LE O F CO NTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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1. Operations
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Cond uct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,
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01.1 General Comments (71707)
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Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . 1
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O 2.1 Transmitter Configuration Control (IFl 50-44 3/9 6-10-01 ) . . . . . . . . . . . . 1
O2.2 Turbine-Driven Emergency Feedwater Pump Exhaust Line Painting . . . . . 2
02.3 Indication of Primary to Secondary System Leakage . . . . . . . . . . . .
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Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
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07.1
(Closed) LER 96-04, " Emergency Feedwater System Valve Closure"
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(VIO 50-443/96-10-02)
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11. Maintenance
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Conduct of Maintenance
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M 1.1 EDG Barring Device Micro-switch
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M1.2 Leak Sealant repair
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Miscellaneous Maintenance issues
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M8.1 (Closed) LER 96-03 and LER 96-03-01, " Emergency Feed Water Pump
Mechanical Seal Replacement" . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
lll . En g in e e ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
E2
Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . 11
E2.1
MOV Diagnostic Testing . . . . .
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IV. Plant Support
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R1
Radiological Protection and Chemistry Controls
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R 1.1
General Comments
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S1
Conduct of Security and Safeguards Activities . . . . .
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S1.1 General Comment (71707, 71750) . . . . . . . . . . . . . . . . . . . . . .
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P7
Quality Assurance in ' Security and Safeguards Activities .
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Closure of Previously identified Violation . . . . . . . . . . . . . . . . . .
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V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . .
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Table of Contents (Cont.)
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Exit M eeting Sum m a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
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Other NRC Activities
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PARTI AL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
LIST OF ACRONYMS USED
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REPORT DETAILS
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Summarv of Plant Status
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The facility operated at approximately 100% of rated thermal power throughout the
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inspection period with routine minor power reductions performed to support instrument
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calibrations and turbine valve testing. On November 25,1996, initialindications of
primary to secondary leakage were identified.
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l. Operations
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Conduct of Operations
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01.1 General Comments (71707)
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Using inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. In general, routine operations were performed in
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accordance with station procedures and plant evolutions were completed in a
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deliberate manner with clear communications and effective oversight by shift
supervision. Control room logs accurately reflected plant activities and observed
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shift turnovers were comprehensive and thoroughly addressed questions posed by
the oncoming crew. Control room operators displayed good questioning
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perspectives prior to releasing work activities for field implementation. The
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inspectors found that operators were knowledgeable of plant and system status.
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Operational Status of Facilities and Equipment
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Insoection Scone (71707,62707)
The inspectors routinely conducted independent plant tours and walkdowns of
selected portions of safety-related systems during the inspection report period.
These activities consisted of the verification that system configurations, power
supplies, process parameters, support system availability, and current system
operational status were consistent TS requirements and UFSAR descriptions.
Additionally, system, component, and general area material conditions and
housekeeping status were noted.
02.1 Transmitter Configuration Control (IFl 50-443/96-10-01)
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Observations and Findinas
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On October 8,1996, during an independent tour of the service water (SW) pump
house, the inspectors noted that plastic foreign material exclusion (FME) shipping
caps were installed in the spare conduit ports on SW system pressure transmitters,
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1-SW-PT-8272 through 8274 and 1-SW-PT-8282 through 8284. This observation
was brought the attention of plant management who directed appropriate
engineering personnel to review this condition. Engineers subsequently verified that
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temporary shipping caps were installed in the subject transmitters and ACR 96-
1002 was generated.
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The SW pump house area where the subject transmitters are located, environmental
zone SW-1, is classified as a mild environment with respect to the station
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environmental qualification program required by 10 CFR 50.49. This classification
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does not specifically require that moisture accumulation at the terminal side of the
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transmitter housing be prevented by means such as a qualified environmental seal.
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Nonetheless, the vendor manual for the subject transmitter model, Rosemount 1153
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series-manual FP73280, directs that unused conduit ports be closed off with a
stainless steel pipe plug, with threads sealed by pipe thread sealant. Therefore,
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work request, WR 96 WOO 2012 was initiated to replace the plastic FME shipping
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plugs with stainless steel pipe plugs per the transmitter manufacturer specifications.
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The ACR evaluation was expanded by the licensee to inspect and verify or establish
as necessary the proper configuration of a population of 523 currently installed
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process transmitters. The licensee concluded this action was appropriate due to the
diversity of transmitter models and designs that could be installed in various service
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applications. A dedicated task force was established, with projected milestones of
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December 15,1996 for the completion of in-plant inspections and January 13,
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1997 for project completion and task force report issuance.
The inspectors have met w.i.1 the task force leader several times to verify project
scope, assurance of quality, incorporation of potential lessons learned into proper
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program processes, and to maintain status of observations. At the conclusion of
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the inspection report period, the task force had not identified any transmitter
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discrepancy that effected instrument operability or environmental qualification.
However, several minor deficiencies such as loose junction box door clamps,
missing qualification tags, and missing end caps for instrument drain line tubes had
been identified,
c.
Conclusions
The shipping caps that the inspector identified installed in the spare conduit ports of
the SW pressure transmitters have been in place since original installation.
Although these caps do not conform with vendor specifications, their installation in
this specific application does not effect instrument operability or qualification.
The licensee demonstrated excellent causal and corrective action analysis by
establishing a dedicated task force to provide positive verification of the design-
bases configuration requirements for a significant sample population of transmitters
currently installed in the station. Review of the final task force report and any
subsequent corrective actions will be tracked by an inspector follow-up item (IFl 50-
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443/96-10-01).
02.2 Turbine-Driven Emergency Feedwater Pump Exhaust Line Painting
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b.
Observations and Findinas
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On October 11,1996, during a system walkdown with the system engineer, the
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inspector identified that the turbine-driven EFW (TDEFW) pump steam exhaust
piping had been painted blue. The color code procedure, SM 7.2, " Station Labeling
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Program," indicates that this piping should be painted white. More significantly, the
inspector questioned if the paint was qualified to the temperatures expected to be
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experienced in the exhaust line during design-bases operation of the TDEFW pump.
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ACR 96-1040 was initiated.
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The licensee provided a turbine specification sheet that indicated fullload exhaust
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temperature would be 235* Fahrenheit (F). Vendor specifications for the paint
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indicated the primer coat was temperature resistance rated to 350* F and the finish
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coat of colored paints are rated to 250
F.
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Conclusions
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The incorrect paint color coating for the TDEFW pump turbine exhaust line was of
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negligible significance. Additionally, the inspector verified that the labeling program
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had properly considered process piping temperatures in determining the chemical
qualities for the paint products. The inspector had no further questions regarding
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this issue.
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02.3 Indication of Primary to Secondary System Leakage
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a.
Insoection Scoce (71707)
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On November 25,1996, control room operators noted indications of potential
primary or reactor coolant system to secondary system leakage. At approximately
3:00 a.m., operators were preparing to regenerate a blowdown system cation filter
bed when the "C" SG blowdown radiation monitor alarm briefly went into the alert
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range. The alarm quickly cleared, however at approximately 8:00 a.m., the alarm
again went into alert and remained at slightly above normal readings. The operators
promptly notified chemistry and entered the off-normal procedure OS 1227.02,
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" Steam Generator Tube Leak." Chemistry initiated secondary system sampling with
increased frequency in accordance with procedure, CS 0905.08A. The inspector
reviewed Technical Specification (TS) 3.4.6.2, associated with reactor coolant
system leakage, procedure OS 1227.02, NUREG/CR-6365 " Steam Generator Tube
Failures," and held discussions with Chemistry Department personnel and senior
station management.
b.
Observations and Findinas
Chemistry confirmed the presence of a primary to secondary leak in the "C" SG by
use of gaseous isotopic analysis and determined the leak rate was very small
(approximately 1.0 gpd). TS 3.4.6.2 limits reactor coolant system leakage to 1.0
gpm total reactor-to-secorJary leakage through all Sgs and 500 gpd through any
one SG. The licensee prcmptly and aggressively began a thorough evaluation of the
indications of SG tube leakage. Senior station management provided strong
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oversight of and involvemei.t :T. :"aluation of the tube leak and development of
corresponding response strategies and contingencies. The station sought the most
current industry experience on SG tube leaks and contacted SG experts at
Westinghouse. The licensee established sampling and operational controls that
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were significantly more conservative than both general industry standards that had
been established by the Electric Power Research Institute (EPRI) guidance (150 gpd
totalleakage, rate of change of greater than 60 gpd in one hour shutdown criteria)
and TS requirements (500 gpd). An administrative limit of 60 gpd for initiating a
plant shutdown was imposed. Additionally, contingency repair plans were under
development to repair the source of the leakage during the next refueling outage or
sooner if conditions should sooner necessitate a forced shutdown. Frequent
briefings were conducted to inform station management of the status. At the
conclusion of the inspection report period, the SG tube leak had stabilized at
approximately 0.2 gpd.
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Conclusions
The inspectors determined the licensee response to the tube leak was prompt,
thorough, and conservative which demonstrated sound safety perspectives. The
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licensee used recent industry information when developing response strategies,
which was considered very prudent given the industry experience with SG tube
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leaks and the sometimes rapid leak rate increase from a few gpd to several hundred
in a short period of time. The operators alertly responded to the radiation data
management system (RDMS) alarms. The inspectors observed good coordination
between the chemistry, health physics, and operations departments. Senior station
management involvement was strong and ensured appropriate station response.
The inspectors had no further questions.
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Quality Assurance in Operations
07.1 (Closed) LER 96-04, " Emergency Feedwater System Valve Closure"
(VIO 50-443/96-10-02)
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Inspection Scope (71707.40500)
On July 24,1996, the licensee submitted LER 96-04 which documented that
evaluations, completed on June 27,1996, had concluded that the alignment of the
startup feedwater pump (SUFP) to the steam generators (Sgs) via the emergency
feedwater (EFW) flow control valves for non-emergency operation was an
unanalyzed condition that significantly compromised safety. On June 27,1996,a
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one-hour non-emergency notification was made to the NRC operations Center in
accordance with the requirements of 10 CFR 50.72.
The inspector reviewed numerous documents that recorded the development of this
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issue from the initial identification of a concern in 1991 through issuance of LER 96-
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04. Documents of significant import included:
Station Information Report (SIR)91-036, dated December 6,1991
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Root Cause Analysis for SIR 91-036, No.91-013, dated January 31,1992
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UFSAR Section 6.8, " Emergency Feedwater System"
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TS Section 3.7.1.2, " Auxiliary Feedwater System"
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ON 1034.03, " Condensate System Operation" Rev 3, change 13
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OS1035.02, "Startup Feed Pump Operation," Rev 7, change 01-04
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TS Clarification, TS-148, " Emergency Feedwater System Operation"
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ACR 95-511, dated December 13,1995
Yankee Atomic Memo, " Review of ACR 95-511," dated May 24,1996.
Additionally, several Nuclear Safety Audit and Review Committee (NSARC) meeting
minute reports and correspondence to and from the NSARC and plant staff were
reviewed.
b.
Observations and Findinas
On April 2,1991, feedwater check valve, FW-V-330, did not stroke freely with the
plant maneuvering in Mode 3 (HOT STANDBY). The normal condensate and
feedwater flow path was required to be isolated in order to f acilitate repairs to the
valve. Rather than placing the reactor in a shutdown condition, the licensee
established a configuration in which the SUFP was isolated and the steam
generators were fed by the condensate pumps via the EFW system, with level being
maintained by the EFW flow control and isolation valves. The configuration was
established by a revision (Change 13 to Revision 3) to station procedure ON
1034.03, " Condensate System Operation." The plant remained in this configuration
for approximately three days until repairs to the feedwater check valve were
completed and the normal feedwater flow path was restored. During this period of
time, the plant was in the action statement of TS 3.7.1.2, applicable in Modes
1,2,and 3, which limits continued operation in this configuration to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
On December 6,1991, SIR 91-036 was ganerated due to questions regarding the
potential for the off-normal feedwater aligament to be in conflict with high energy
line break evaluations. A root cause analysn evaluation for SIR 91 036 (91-013,
dated January 31,1992) concluded that the orocedure revision that authorized the
off-normal feedwater alignment lacked an adequate 10 CFR 50.59 evaluation and
that inconsistencies existed between various station manuals and procedures that
govern the performance of 10 CFR 50.59 evaluations and procedure revisions. In
part due to SIR 91-036, Technical Clarification (TC), TS-148, was issued May 28,
1992 and revised August 21,1992, that further supported operation of the EFW
system non-emergency SG level control in the off normal feedwater alignment.
On January 27,1994, station procedure, OS 1035.02, "Startup Feed Pump
Operation," was revised (Change 01 to Revision 07) to authorize operation of the
SUFP and EFW flow control and isolation valves to maintain SG water level during
normal plant operations. TS-148 was referenced as technical support for the
procedure revision. Shortly after, on March 30,1994, the NSARC Operations
Subcommittee (NSARC OC) questioned the adequacy of the procedure revision
evaluation at NSARC OC meeting No. 94-01, as documented in NSARC OC meeting
minutes memorandum dated April 8,1994. Specifically, the NSARC OC expressed
concern that the procedure revision was implemented without the performance of a
10 CFR 50.59 evaluation. Further, the NSARC OC expressed concern that the
revision used a TC to support the revision. Licensing management subsequently
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issued memorandum, LIC 94-0396, dated June 16,1994, that clearly defined the
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controls, instruction, and limitations of a given TC.
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As a result of continued apparent differing opinions between the NSARC OC and
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plant staff regarding the need for a 10 CFR 50.59 evaluation for the newly
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developed EFW system operation, the NSARC elevated the issue to the attention of
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the Station Manager for SORC resolution in the August 23,1994 NSARC meeting
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(94-11), as documented in the meeting minutes report dated August 23,1994.
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Two more NSARC meetings passed without resolution of the concern. It was not
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until April 13,1995, that the licensee confirmed the intention to perform a 10 CFR
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50.59 evaluation. The evaluation was performed in June 1995, however the
NSARC assessed the evaluation as weak, lacking in technical as well as design- and
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licensing-bases information. Due to the apparent lack of a success path on this
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issue, NSARC issued ACR 95-511 on December 13,1995.
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Ultimately on May 1,1996, at the direction of the Senior Site Officer acting as the
NSARC Chairman, Yankee Atomic conducted a comprehensive evaluation of ACR
95-511 as well as the historical documents on the procedure change. The
evaluation, " Review of ACR 95-511," dated May 24,1996, concluded that the
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procedure revision placed the EFW system in a configuration that was outside the
design- and current licensing basis for the plant. The evaluation determined that;
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operation of the EFW system in non-emergency modes contradicted past licensee
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statements and supporting licensing documents; operation with the EFW flow
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control and isolation valves throttled for non-emergency SG level control was not
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evaluated with respect to the UFSAR; and, TS 4.7.1.2.1.a.1 requires that the EFW
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flow control and isolation valves be open at all times during non-emergency plant
operations. The specific vulnerability involved a scenario in which the EFW flow
control and isolation valves would be shut to support the starting sequence of the
SUFP coincident with the receipt of a station blackout.
Licensee evaluation concurred with the Yankee Atomic review of ACR 95-511, and
on June 27,1996, the licensee notified the NRC in accordance with 10 CFR 50.72
of the unanalyzed EFW alignment. Immediate corrective actions included deleting
use of the EFW system for non-emergency SG level control. Other corrective
actions were directed at clarifying 10 CFR 50.59 requirements, issuing standing
orders that would reinforce that EFW flow control and isolation valves should not be
throttled, and revision to TS-148.
c.
Conclusions
UFSAR Section 6.8.1 states that the design basis for the EFW system is to provide
the capability to remove heat from the reactor coolant system during emeraency
conditions when the main feedwater system is not available, including small LOCA
cases. Additionally, for station blackout, the turbine-driven EFW pump will operate
during the four-hour coping period to cool down and maintain the secondary side
pressure at about 250 psig. This section further states that for all other modes of
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plant operation, including startup, hot standby, and normal operation up to full
power load, the EFW system is depressurized and has zero flow.
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Additionally, the UFSAR Section 6.8.2 description of the EFW system states that
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the open position of the flow control valves for system limiting conditions will be
I
set to insure the minimum flow of 470 gpm to three Sgs and a minimum total flow
j
of 650 gpm to four Sgs with one EFW pump operable. Further, the UFSAR Section
i
6.8.3 safety evaluation states that the flow regulating valves in each EFW line are
l
normally open, and are sized to pass the required flow under accident conditions.
The only action necessary to establish EFW flow is to start the pumps.
,
I
TS 3.7.1.2 states that in Modes 1,2, and 3 at least three independent steam
!
generator auxiliary feedwater pumps and associated flow oaths shall be operable.
I
i
The licenser
"isions to station procedures, ON 1034.03, " Condensate System
i
Operation," e Mril 1991 and OS 1035.02, "Startup Feed Pump Operation," in
January 19M. established procedural guidance authorizing non-emergency
feedwater flow paths to the Sgs through the EFW system, with SG level being
controlled by throttling the EFW flow control and isolation valves. The procedures
l
were revised without performance of safety evaluations consistent with the
!
requirements of 10 CFR 50.59 to determine if the changes involved an unreviewed
i
safety question as defined in 10 CFR 50.59. It is recognized that the plant has
l
actually been operated in the off-normal configuration authorized by ON 1034.03
'
one time from April 2-5,1991 and that the off-normal alignment authorized by OS
'1035.02 has never been established. Notwithstanding, the failure to perform safety
[
evaluations to determine if revision of procedures ON 1034.03 and OS 1035.02
i
involved an unresolved safety question as defined by 10 CFR 50.59 is a violation.
j
(VIO 50-443/96-10-02)
l
!
Several related aspects of this issue are of concern to the inspectors. Initially, the
!
NSARC and NSARC OS expressed obvious concern for the lack of a 10 CFR 50.59
l
evaluation with respect to the OS 1035.02 revision at meetings for approximately
[
two years beginning in March 1994, without satisfactory resolution. Ultimately, the
!
Senior Site Officer and NSARC chairman, on May 1,1996, directed that an
l
immediate resolution to the concern be achieved. Secondly, the licensee originally
justified the revision on the basis of a technical clarification, TS-148. When a
!
subsequent 10 CFR 50.59 safety evaluation was performed it was qualitative in
nature, lacking technical rigor supported by design and licensing basis information.
!
Finally, the corrective action processes, including resolution to NSARC issues
through initiation and resolution of associated ACRs, similarly lacked technical rigor
j
and were not prompt or timely. These issues were discussed in detail with licensee
management and will be addressed in the licensee response to the attached Notice
l'
of Violation.
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11. Maintenance
M1
Conduct of Maintenance
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M1,1 EDG Barring Device Micro-switch
,
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a.
Inspection Scoce (62707)
On October 7,1996, the inspector observed portions of the "A" EDG load test
being performed per station procedure EX 1804.001.
b.
Observations and Findinas
During a walkdown of the EDGs, the inspector noted that engine lube oil was
dripping directly onto the barring device lower micro-switches that are designed to
,
prevent a start of the EDG with the barring device engaged. There is an upper
l
(DGA/B-ZS BD1) and lower micro-switch (DGA/B-ZS BD2) for the barring device on
each engine; only the lower micro-switch would be vulnerable to the oil leakage
i
from the barring device. This observation was brought to the attention control room
)
personnel who directed appropriate system engineering personnel to evaluate this
observation.
)
1
5
System engineers verified the inspector observation and initiated ACR 96-1067,
'
- The licensee evaluation concluded that oil could enter the micro-switch casing and
potentially prevent the switch from functioning. The oilis non-conductive and does
not present an electrical short circuit potential. The primary micro-switch reliability
concern would be that the switch may remain in its current state position and not
respond to a change in barring device status. This concern presents minimal safety
concern because the upper micro-switch would be capable of actuating the
protective parallel circuit and prior to use of the barring device, the associated EDG
would be removed from service and other administrative and physical controls
would prevent automatic engine startup. Also should micro-switch remain in the
engaged position after the barring device is removed from the EDG, a common EDG
local annunciator and control room computer digital alarm point (Drawings 31087,
SH-E93/8a,b,f 1-NHY-503490, 506393, and 9763-M-510000) would provide
indication of the switch failure prior to returning the EDG to service.
System engineers contacted the micro-switch vendor, who indicated an optional
rubber boot was available to minimize the potential of foreign materials entering the
switch. An engineering work request was initiated for design engineering personnel
to evaluate installing the rubber boot seals. Additionally, WRs 96 WOO 2024 through
96 WOO 2027 were generated to correct the source of the oilleakage and to inspect
the micro-switches.
r
c.
Conclusions
!
!
It appeared that the minor oil leakage from the barring device had been present for
i
some time prior to being brought to the attention of the licensee by the inspector.
,
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9
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The inspector reviewed micro-switch logic diagrams and concurred in the licensee
conclusion that failure of a micro-switch would be of minimal personnel or
equipment safety significance. Subsequent engineering evaluation of the condition
!
was thorough and identified a potential component enhancement involving the
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rubber boot seal for the micro-switches.
'
M1.2 Leak Sealant repair
a.
Inspection Scoce (62707.37551)
Previously during the second refueling outage (ORO2) main steam instrument root
valve, MS-V-56 was repacked with undersized packing. MS-V-56 is the root valve
for steam pressure transmitter FW-PT-544, which inputs to the safety injection and
steam line isolation two-out-of-three low steam line pressure logic. The transmitter
also provides post accident monitoring capability. The licensee controlled the root
valve on its backseat to limit packing leakage, however over the course of the
current operating cycle the packing performance had degraded. WR 96WOOO845
was generated to perform a temporary leak sealant injection repair of the packing
gland. The inspector reviewed the work request, applicable sections of Section XI
q
of the ASME Code governing repair of ASME class components, station procedure,
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MS 0526.09, "On Stream Leak Repairs," discussed specific work-related controls
with cognizant engineers, and directly observed portions of the field work.
u.
Observations and Findinas
On October 29,1996, the licensee held a pre-evolution briefing, placed transmitter,
FW-PT-544, in bypass, and initiated the work activity. The actual physical work
was performed by contractor technicians with direct licensee supervision and
quality oversight. The injection preparation was a two step process involving an
initial drill of 0.312 inches to a depth of approximately 0.360 inches for the
installation of an injection valve followed by a center drill into the packing gland.
The depth of the initial drill was controlled by setting a drill stop. At a pre-
determined procedure hold point, license OC personnel alertly identified that the
contractor technician had improperly set the drill stop. The stop was properly set
and the initial drill was performed. However, due to physical interferences, the drill
was not perpendicular to the packing gland and the minimum specified injection
valve thread engagement of 3 turns could not be obtained.
The licensee supervisor suspended the work effort, engineering personnel evaluated
further repair options, and ACR 96-1114 was initiated. An initial operability
determination (OD) that was largely qualitative was rejected by operations
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management. A subsequent OD, ODF No.96-015, dated October 30,1996, that
was supported by design-basis assumptions and calculations was approved. The
OD concluded that with the drilled hole the valve maintains its original design
requirements and remains operable.
On November 13,1996, the licensee implemented WR 96 WOO 2299, that
performed an ASME Section XI code repair of the drilled hole. Following completion
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10
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of the code repair, the WR directed closure of the root valve and sequential removal
of the packing gland follower nuts and cleaning of the follower stud threads and
attempting to make up all the free travel on the follower. This effort proved
successful and leakage from the packing gland was stopped.
c.
Conclusions
!
The initial packing gland leak repair plan was well developed, however it was of a
high degree of difficulty due to physical interferences. The repair plan was
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discussed in detail with NRC Region i ASME Code and temporary leak sealant repair
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specialists during a conference call on November 1,1996. Licensee QC personnel
provided excellent independent oversight as evidenced by the identification of the
improperly set drill stop.
Operations section management demonstrated good standards by rejecting the
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initial OD that lacked design- and operational-bases technical evaluation. The
subsequent OD was properly supported and approved.
The repair plan for the unsuccessful leak sealant attempt was well developed.
Notwithstanding, it appears that the work planning process initially overlooked the
,
less intrusive and technically challenging repair option of gland follower stud thread
cleaning which ultimately proved successful, in favor of the leak sealant repair
option. The inspector had no additional questions regarding this activity.
>
M8
Miscellaneous Maintenance issues
M8.1 (Closed) LER 96-03 and LER 96-03-01, " Emergency Feed Water Pump Mechanical
f
Seal Replacement"
On May 21,1996, with the plant operating at 100% of rated thermal power the
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TDEFW pump was rendered inoperable when sparks were observed emanating from
the outboard mechanical seal area during quarterly flow surveillance testing. The
seal was disassembled and determined to have been improperly installed during the
last refueling outage in November-December 1995. The licensee performed a
formal root cause analysis which concluded a mechanical seal design deficiency and
inadequate corrective actions for a previously identified event as the primary causes
for the event. A contributing cause was inadequate predictive maintenance
techniques. NRC Inspection Report 50-443/96-04 documented the event including
a Notice of Violation for the improper seal assembly.
The LER properly documented the event and contained the appropriate reporting
requirements of 10 CFR 50.72. Any further NRC inspection of this event will be
documented in follow-up of the violation and violation corrective actions response
documents. The inspector had no further questions regarding closecut of the LER.
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lil. Enaineerina
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E2
Engineering Support of Facilities and Equipment
E2.1
MOV Diagnostic Testing
a.
Insoection Scoce (62707,37551)
,
1
On October 22,1996, the licensee removed motor operated valve, CBS-V-43, from
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service to perform diagnostic testing. The MOV actuator is a Limitorque SMB-000
model. The design-bases functions of the valve are to automatically open on a "P"
i
signal to allow sodium hydroxide to gravity feed to the refueling water storage tank
(RWST) and to close to terminate transfer of the spray additive to the RWST. The
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inspector reviewed TS 3.6.2.2.b, RTS 96RM19204001, WR 96 WOO 2181, and
discussed various aspects of the work activity with involved personnel.
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b.
Observations and Findinas
1
Initially, the valve was removed from service and the appropriate actions per TS 3.6.2.2.b. thu limit continued operation with CBS-V-43 inoperable to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />,
were initiawd. Performing technicians identified minor discrepancies for limit switch
settings for valve position indicating lights. Additionally, technicians identified that
the Bellville washer stack for the spring pack was not properly configured. Each of
these discrepancies were corrected prior to completion of diagnostic testing,
l
However, subsequent diagnostic testing identified that peak unseating force
exceeded predicted values, in order to restora design-bases margins to the
actuator, the motor pinion and worm shaft gear sets were replaced. Post-
maintenance diagnostic testing indicated that with the new gear sets installed that
approximately 114% of predicted design margins were restored to the actuator.
'
c.
Conclusions
The licensee appropriately and conservatively addressed each discrepancy and test
deficiency encountered. Replacement of the valve actuator gear set reflected sound
understanding and respect for reliability and design margin goals of the MOV
program established in response to NRC Generic Letter 89-10. The testing results
and corrective actions were discussed with the NRC Region 1 MOV specialist during
an October 24,1996 conference call.
Notwithstanding the above noteworthy technical performance, the inspectors
concluded that the licensee could have better planned for a contingency to replace
the actuator gear set based on other recent plant experience. Specifically,
diagnostic testing of the redundant flow path spray additive valve, CBS-V-38, had
recently been conducted with similar as-found reductions in design margins. In the
case of the CBS-V-38 valve adequate margins were restored by torque switch and
limit switch adjustments. Based on the similarity of valve design, operational
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application, and test experience, the licensee should have anticipated similar as-
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found test data for the CBS-V-43 valve. However, the on-line maintenance planning
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was largely focused on diagnostic test performance with an absence of meaningful
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initial engineering assessment for the potential for design margin reductions that
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would necessitate detailed reactive engineering support. The net effect of the lack
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of contingency planning.was a probable increase in the time that CBS-V-43
remained out of service. It should be noted that CBS-V-43 was returned to service
within the TS 3.6.2.2.b allowed outage time. The inspector had no additional
.
questions regarding this maintenance activity.
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IV. Plant Suonort
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R1
Radiological Protection and Chemistry Controls
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R1.1 General Comments
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a.
Inspection Scope
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During the inspection period the inspector toured the radiologically controlled area
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(RCA) on several occasions to observe radiological controls practices,
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b.
Observations and Findinas
The Seabrook Station radiological controls technicians at the RCA checkpoint were
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attentive and provided assistance to radiation workers to assure proper work
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practices were used when radiation workers signed in and out of the RCA. The
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inspector determined that radiation area postings were proper and well marked and
survey recults were current and posted properly. All personnel observed were
properly wearing dosimetry while in the RCA. A sampling of high radiation area
doors identified no discrepancies with locking or posting requirements.
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c.
Conclusions
The inspector determined that Seabrook Station was properly implementing the
station radiological controls program requirements in the areas inspected.
Radiological controls personnel were knowledgeable of station procedures and
provided good oversight of radiation workers. Department managers were observed
in the field observing and supervising department personnel.
$1
Conduct of Security and Safeguards Activities
S 1.1 General Comment (71707, 71750)-
The inspectors observed security force performance during inspection activities.
Protected area access controls were found to be properly implemented during
random observations. Proper escort control of visitors was observed. Security
3
officers were alert and attentivo to their duties. Of particular note, the inspectors
!
consistently found that security force members performing compensatory post
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duties during security computer power supply upgrades to be fully aware of watch
requirements.
P7
Quality Assurance in Security and Safeguards Activities
.
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P7,1
Closure of Previously identified Violation
(Closed) VIO 50-443/96-02-03: The licensee failed to effectively implement a
developed procedure which addressed contractors with unescorted access into the
protected area that are away from Seabrook Station for more than 30 days and
have not been under a continual behavioral program.
With respect to the above violation, the inspectors determined that the corrective
actions described in the licensee's May 24,1996 letter, in response to the NRC's
Notice of Violation, were reasonable, complete, and appeared to be effective.
V. Manaaement Meetinas
X1
Exit Meeting Summary
,
The inspectors presented the inspection results to members of licensee
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management, following the conclusion of the inspection period, on December 23,
1996. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was
identified.
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X3
Other NRC Activities
'
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Conference calls between NRC managers and technical staff specialists and licensee
j
managers and technical staff leads we,re performed on the following dates.
!
e
October 24,1996-To discuss technical aspects of the MOV diagnostic test
results and subsequent repairs to CBS-V-43. (Section E2.1)
November 1,1996-To discuss technical aspects of the temporary leak
sealant repair of main steam instrument root valve, MS-V-56. (Section
M1.2)
November 15,1996-To perform a final exit for an MOV inspection. The
results of the inspection will be documented in a combined NRC Inspection
Report.
.
November 27,1996 To discuss technical aspects of the indication of primary
to secondary leakage. (Section 04.1)
)
_.
6
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
W. Diprofio, Unit Director
G. Kline, Technical Support Manager
R. White, Design Engineering Manager
J. Peterson, Maintenance Manager
J. Gnllo, Operations Manager
B. Seymour, Security Manager
W. Leland, Chemistry and Health Physics Manager
NRC
Albert W. DeAgazio, Project Manager
4
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INSPECTION PROCEDURES USED
!
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IP 37551:
Onsite Engineering
,
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing
Problems
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IP 61726:
Surveillance Observation
{
IP 62707:
Maintenance Observation
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IP 64704:
IP 71707:
Plant Operations
)
IP 71750:
Plant Support Activities
IP 73051:
Inservice Inspection - Review of Program
IP 73753:
Inservice Inspection
I
IP 83729:
Occupational Exposure During Extended Outages
IP 83750:
Occupational Exposure
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
,
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Facilities
!
IP 92902:
Followup - Engineering
IP 92903:
Followup - Maintenance
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IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
ITEMS OPENED, CLOSED, AND DISCUSSED
!
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Ooened
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Inspector Follow-up Item 50-443/96-10-01, " Review of Transmitter Configuration Task
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Force Report"
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Violation 50-443/96-08-01, " Failure To Perform 10 CFR 50.59 Safety Evaluation"
)
.
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Closed
.
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LER 96-04, " Emergency Feedwater System Valve Closure," dated July 24,1996
LER 96-03, " Emergency Feedwater Pump Mechanical Seal Replacement," as supplemented
September 12,1996
,
Violation 50-443/96-02-03, " Failure to establish access controls for contractors with
unescorted access who would be absent from the site for more than 30 days
Discussed
None
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LIST OF ACRONYMS USED
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ACR
Adverse Condition Report
American Society of Mechanical Engineers
Central Alarm Station
'
CBS'
Containment Building Spray
[
Emergency Feedwater
!
gpd
gallons per day
.
gpm
gallons per minute
!
LCO
Limiting Condition for Operation
!
motor operated valve
l
MPCS
Main Plant Computer System
'NSARC
' Nuclear Safety and Audit Review Committee
!
NSARC OS
NSARC Operations Subcommittee
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psig
pounds per square inch gauge
!
Quality Control
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Station Information Report
i
SORC
Station Operations Review Committee
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SUFP
Startup Feedwater Pump
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Turbine Driven Emergency Feedwater Pump
i
TS
Technical Specifications
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Updated Final Safety Analysis Report
Work Request
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