ML20056C972
| ML20056C972 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 07/21/1993 |
| From: | Eugene Kelly NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20056C970 | List: |
| References | |
| 50-271-93-13, NUDOCS 9307300170 | |
| Download: ML20056C972 (65) | |
See also: IR 05000271/1993013
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report No. 93-13 ,
Docket No. 50-271
Licensee No. DPR-28
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Licensee: Vermont Yankee Nuclear Power Corporation
RD 5, Box 169 )
Ferry Road
Brattleboro, VT 05301
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Facility: Vermont Yankee Nuclear Power Station i
Vernon, Vermont
Inspection Period: May 23 - June 26,1993
Inspectors: Harold Eichenholz, Senior Resident Inspector
Paul ' Harris, Resident Inspector
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Approved by: - - 7 3
Eugene M. Kelly, Chief Date
Reactor Projects Section 3A
Scope: Station activities inspected by the resident staff this period included: plant
operations; radiological controls; maintenance and _;urveillance; security-
engineering and technical support and safety assessment and quality l
verification. An initiative selected for this inspection was simulator training 1
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for control room operators. Backshift and " deep" backshift including weekend !
activities amounting to 21 hours were performed on May 25, 26, 27, June 6, I
8,9 and 14. Interviews and discussions were conducted with members of i
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 summarized in the
Executive Summary. A violation involving improper calibration of the core
spray sparger pressure differential instruments was identified (Section 4.2.1).
Enforcement discretion was exercised for the failure to properly leak rate test
the containment atmospheric sampling system (Section 6.1). An unresolved
item was opened (Section 3.2) regarding contaminated equipment control.
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EXECUTIVE SUMMARY
Vermont Yankee Inspection Report 93-13
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Plant Operations
Conservative actions were implemented to minimize fuel stress, in response to indications of
a minor fuel element failure. Simulator training for control room operators was effective.
Radiological Controls f
Several instances reflecting poor radiological work practices were observed. A lack of
sensitivity to the potential for internal system contamination was demonstrated during l
maintenance on a standby gas treatment filter. Surveys were not performed for potentially
changing radiological conditions during testing. Vermont Yankee identined ineffective
control of contaminated equipment at an offsite storage facility.
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Maintenance and Surveillance ;
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Effective planning and maintenance was performed on three safety-related systems.
Improved work package development and attention to detail were observed. Concern over
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Vermont Yankee's root cause evaluations for the residual heat removal service water 89A
valve failure involved limited documentation of "as-found" conditions.
Evaluation of industry experience and biennial technical review of procedural adequacy failed ,
to identify a long-standing setpoint problem for core spray sparger pressure instruments, I
resulting in a violation of Technical Specifications.
Engineering and Technical Support
Appropriate corrective actions were implemented to leak rate test the containment
hydrogen / oxygen monitoring system. Adequate Emergency Operating Procedure review and
operator training were conducted for potential reactor water level instrumentation errors
during and after reactor depressurization.
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TABLE OF CONTENTS .
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EXECUTIVE SUMMARY ......................................ii !
TABLE OF CONTENTS .......................................iii
1.0 SUMMARY OF FACILITY ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . I
2.0 PLANT OPERATIONS (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I
2.1 Operational Safety Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 l'
2.2 Rod Pattern Adjustment ............................... 2
2.3 Evaluation of Reactor Offgas Release Rates . . . . . . . . . . . . . . . . . . . 2 l
2.4 Control Room Operator Training . . . . . . . . . . . . . . . . . . . . . . . . . . 1 !
3.0 . RADIOLOGICAL CONTROLS (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . 3 ;
3.1 Radiation Surveys in Support of Plant Maintenance . . . . . . . . . . . . . . . 3 ,
3.2 (Open) URI 93-13-01: Contaminated Equipment Control . . . . . . . . . . . 4
3.3 Radiological Surveys During Changing Plant Conditions ........... 4
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4.0 MAINTENANCE AND SURVEILLANCE (62703, 61726) . . . . . . . . . . . . . . 5 i
4.1 Maintenance ..................................... 5 '
4.1.1 Failure of Service Water Valve Anti-Rotation Key . . . . . . . . . . . 5
4.1.2 Standby Gas Treatment - LCO Maintenance . . . . . . . . . . . . . . . 6
4.1.3 Circuit Breaker Maintenance . . . . . . . . . . . . . . . . . . . . . . . . 7 l
4.2 S urveillance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
4.3 (Open) VIO 93-13-02: Core Spray Sparger Break Detection -
Nonconservative Setpoints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
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5.0 SECURITY (71707, 92700, 93702) . . . . . . . . . . . . . . . . . . . . . . . . . . . . I1
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6.0 ENGINEERING AND TECHNICAL SUPPORT (71707,62703) ......... I1
6.1 Appendix J Testing: Drywell Hydrogen / Oxygen Monitoring System ... 11
6.2 Water Level Instrumentation Errors During and After Depressurization ;
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Transients (TI 2515/1 19) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
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7.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (90712. 90713,
92700) ............................................. 13
7.1 Periodic and Special Reports ........................... 13
7.2 Licensee Event Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 .
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8.0 MANAGEMENT MEETINGS (30702) ......................... 14
8.1 Preliminary Inspection Findings ......................... 14 . :'
8.2 En forcement Conference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Note: Procedures from NRC Inspection Manual Chapter 2515 " Operating Reactor
Inspection Program" which were used as inspection guidance are parenthetically listed for
each applicable report section.
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DETAILS 7
1.0 SUMMARY OF FACILITY ACTIVITIES ;
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Vermont Yankee Nuclear Power Station was operated at full power during this inspection
period. On June 6, the licensee (or VY) reduced power to 65 percent for a rod pattern
adjustment and single rod scram testing. Results of this testing were within Technical l
Specification (TS) requirements for both core average and 2 x 2 arrays, and did not indicate !
any abnormal trend. !
A delegation of representatives from Eastern European nuclear regulatory bodies, who were ,
in the United States as part of NRC-sponsored training, visited the site on June 14-15. The .
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delegation also observed the conduct ofinspections associated with the NRC Operational
Safety Team Inspection performed on site during this period. t
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During May 10 to June 11, the Operations Superintendent participated in the INPO
sponsored Senior Nuclear Plant Management Course.
2.0 PLANT OPERATIONS (71707)
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2.1 Operational Safety Verincation ,
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This inspection consisted of direct observation of facility activities, plant tours, and I
operability reviews of systems important to safety. The inspectors verifi ,' that the facility l
was operated in accordance with license requirements. Plant operations . ere observed i
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daring regular and backshift hours in the control room, reactor building, cable spreading
room, and emergency diesel generator rooms. Daily, the inspectors verified that emergency
core cooling systems (ECCS) were properly aligned for automatic initiation. Field ;
inspections confirmed that ECCS pumps and valves were configured as indicated on control i
room panels, material conditions were good, and housekeeping was commensurate with work
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in progress.
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The inspectors toured the perimeters of both the secondary and primary containments to
verify system integrity. Torus water level and temperature process connections, and a
sample of penetration welds for systems connected to the suppression chamber, were visually
inspected using OP 4115, Rev. 29, " Primary Containment Surveillance," as a pide. No l
, corrosion or porosity was observed on the inspected welds and no discrepancies were {
identified. The inspector also verified that the surveillance of the torus vent system was j
properly performed. During the walkdown of the secondary containment, the inspectors i
verified that truck door seals were properly inflated, reactor building ventilation ducts were . !
intact, and personnel access doors were properly sealed. Of the areas inspected, all air
leakage was in-leakage and no degraded containment material conditions were identified.
Control room and shift manning were in accordance with TS requirements. Control room
instruments correlated between channels and were verified to properly trend during l
surveillance and/or system operation. In addition, plant parameters displayed on the l
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Emergency Response Facility Information System (ERFIS) also correlated well with plant
instruments. Control room operators were observed to effectively use ERFIS in the
identification of trends, status of single rod scram testing, and turbine valve surveillances.
Alarms received in the control room were reviewed with respect to the alarm response
requirements, discussed with operators, and verified to be adequately documented in control
room logs. Control room operators were knowledgeable of ahrm conditions and single rod
scram testing.
2.2 Rod Pattern Adjustment
On June 6, the inspector conducted " deep" backshift (between 10:00 p.m. and 5:00 a.m.)
inspection to observe the conduct of operations during a planned rod pattern exchange. In
accordance with Operations Department night orders and Reactor and Computer Engineering
Department guidance, control room operators decreased power to 65 percent. During
scheduled hold points, surveillance testing was performed in accordance with procedures OP
4424 and OP 4160 to verify the operability of all control rods, main steam isolation valves,
and turbine bypass valves. Single rod scram testing on 45 of 89 control rod drive
mechanisms was performed, and the following average insertion times were achieved:
45 rod average - 0.320 secs Previous 89 rod average - 0.312 secs
89 rod average - 0.312 secs TS limit - 0.375 secs.
All testing performed met TS requirements. Control room operators demonstrated
knowledge of the surveillances performed, and test results were promptly evaluated.
Approved procedures were in use and appropriate shift augmentation was provided to
facilitate safe plant operation. Surveillance testing was performed sequentially and
subsequent testing was not commenced until previous test results were evaluated. Operators
were attentive to duty and focused on the task at hand. The shift turnover was accomplished :
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such that current plant conditions were understood by the on-coming shift. I
2.3 Evaluation of Reactor Offgas Release Rates
Following the rod pattern adjustment on June 6, reactor power was increased to 100 percent
whereupon subsequent offgas analyses indicated a small fuel rod failure. This determination
was based on an analysis of the isotopic concentration of the offgas sample and confirmed by
both Yankee Nuclear Services Division and General Electric. Vermont Yankee has
preliminarily concluded that a very small pinhole or crack exists within one fuel rod.
Significant changes in the offgas radioactive concentrations have not been observed, as
instantaneous offgas values continue to be in the 19,000 to 21,000 pCi/sec range. Licensee
management implemented conservative power ascension rates to minimize fuel element
stress, and implemented a plan to reduce the number of future rod pattern adjustments to
further minimize the number of power-cycles on the fuel. These actions were more
conservative than those required by the existing Failed Fuel Action Plan. j
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2.4 Control Room Operator Training
On June 4, the inspector observed simulator training for control room operators. Operators
responded to two sequential and challenging plant transients: one involving a recirculation
line break that required reactor pressure vessel emergency depressurization and flooding, and
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the other, an anticipated transient without scram with an electrical bus failure. Both
scenarios were evaluated and graded by the VY training staff using NRC examiner standards.
The operators correctly diagnosed plant conditions and responded in accordance with
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Emergency Operating Procedures (EOPs). Actions were timely, EOP entry conditions were
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recognized and properly evaluated, and operators demonstrated proficiency at the controls.
Communications were accurate and succinct. Event notifications met regulatory
requirements. The simulator critique performed by the VY training staff was also effective.
Crew performance strengths and weaknesses were itemized and the post 4 rill brief was
candid and focused on each observation. The critical tasks / steps accurately paralleled the
scenarios and were individually assessed. The training staff did not interject or direct crew
actions, and the Operations Training Supervisor independently evaluated the operating crew
and training staff.
3.0 RADIOLOGICAL CONTROLS (71707)
Inspectors routinely observed and reviewed radiological controls and practices during plant
tours. The inspectors observed that posting of contaminated, high airborne radiation,
radiation and high radiation areas were in accordance with administrative controls (AP-0500
series procedures) and plant instructions. High radiation doors were properly maintained and
equipment and personnel were properly surveyed prior to exit from the radiation control area
(RCA). Plant workers were observed to be cognizant of posting requirements and
maintained good housekeeping. Several exceptions to these routine observations occurred, as
discussed below.
3.1 Radiation Surveys in Support of Plant Maintenance
During this period, the inspector selected two work activities to verify the proper
performance of radiation surveys: (1) insulation replacement for the residual heat removal
service water (RHRSW) system; and (2) maintenance / surveillance for the standby gas ;
treatment (SBGT) system (Section 4.1.2). Radiation and contamination survey maps were
reviewed, field inspections were conducted, and workers were interviewed at the work site to
assess their knowledge of existing radiological conditions. In both activities, workers were
knowledgeable; radiation and contamination levels were minimal, and radiation surveys were
necessary prior to start of work and work scope increases. Appropriate airborne monitoring .
for iodine and radiological boundaries / postings were implemented. l
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During the maintenance on the SBGT system, personnel associated with the jobs
demonstrated a lack of sensitivity to the potential for internal contamination during the
removal and handling of the carbon trays without the use of anti-contamination clothing. The
radiation protection (RP) technician who observed this activity stated that the probability of
contamination was low based on past RP surveys, because an upstream high efficiency
particulate air (HEPA) filter would prevent contamination of the trays. Both the RP
technician and RP Manager later acknowledged the inspector's concern that the internal
components of a potentially contaminated system should be treated as such, until proven
otherwise, and that reliance on the integrity of the upstream HEPA filter is inappropriate.
The mdiation work permit for this job did not specifically require contamination clothing,
although subsequent surveys indicated contamination levels less than 1000 dpm per square
centimeter, and no actual contamination events occurred.
3.2 (Open) URI 93-13-01: Contaminated Equipment Control
On May 25, during a quarterly RP surveillance, VY identified radioactive material outside
the radiation control area (RCA) in a Mercury Company offsite equipment storage facility.
Mercury Company performs maintenance and modification support activities at VY. Four
items were identified (a grinder, welder power supply cord, extension cord, and air hose)
that had contamination levels above that required for free release; all items exceeded fixed
contamination administrative limits. These items were transported back to the RCA and
analyses performed to determine the isotopic makeup of the contamination. Subsequently, a
second survey team was sent to the facility to perform a spot check and identified three
additional items (air hose, tape, and scaffolding) which also exceeded the release limits
specified in plant procedure AP 0516, Rev 3, " Survey and Release of Materials, Vehicles,
and Trash from the Radiation Control Area." Previous occurrences involving VY's failure to-
adequately survey equipment prior to release from the RCA were documented in NRC
Inspection Report 92-09. The inspector also questioned whether the surveillance sample size
was sufficiently large enough to provide reasonable assurance that no additional contaminated
items were stored offsite. Vermont Yankee representatives indicated that the question of
thoroughness of surveys in the offsite facility would be addressed as part of their corrective
action. The corrective actions implemented by VY were discussed with an NRC Region I
radiation protection specialist and will be reviewed during a subsequent inspection (URI 93-
13-01).
3.3 Radiological Smveys During Changing Plant Conditions
During the performance of quarterly surveillances for the high pressure coolant injection
(HPCI) and reactor core isolation cooling (RCIC) systems, the inspector observed that
radiation surveys were not performed to monitor the changing radiation fields due to the use
of reactor steam for HPCI and RCIC pump turbine operation. An RP technician dispatched
to the surveillance areas was observed performing contamination surveys for valve packing
leakage. The inspector reviewed the RP log and survey file, and found no documentation
that substantiated the performance of a survey.
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A contributing cause was that the inter-departmental communications, prior to the
performance of the surveillances, were not effective. This was based on the lack of
documented surveys and log entries regarding the surveillances in both the Operations and
RP logs. In addition, unlike other plant procedures which require inter-departmental
coordination, the HPCI and RCIC surveillance procedures do not specifically require RP
Department notification for the assessment of changing radiation fields.
The inspector concluded that the lack of a radiation survey during turbine operation
represented a missed opportunity and poor work practice with respect to ALAPA (As Low
As Reasonably Achievable) considerations. Actual radiological conditions did not change in
this instance. The RP Manager acknowledged the inspector's conclusions and planned to _
emphasize this concern with RP personnel.
4.0 MAINTENANCE AND SURVEILLANCE (62703,61726)
4.1 Maintenance
The inspectors observed selected maintenance on safety-related equipment to determine
whether these activities were effectively conducted in accordance with VY TS, and
administrative controls (Procedure AP-0021) using approved procedures, safe tagout practices
and appropriate industry codes and standards.
4.1.1 Failure of Service Water Valve Anti-Rotation Key
On June 15, the inspector observed control room operator response to a stuck open residual
heat removal service water (RHRSW) valve 89A being used during containment cooling.
The valve failed at 35 percent open and did not respond to operator control. The valve is
used to throttle service water flow from the RHR heat exchanger. The operators promptly
declared the containment cooling subsystem inoperable, entered the applicable TS action -
statement, and notified the Maintenance Department.
Maintenance Department personnel commenced troubleshooting and repair in accordance
with emergency work order no. 93-4041 and identified that the motor pinion gear key,
located in the motor operator portion of the valve, was missing. This key splines the drive
motor shaft to the motor pinion gear to prevent rotation. In addition, a set screw (which pins
the motor shaft to the pinion gear preventing axial motion) was found to be excessively worn
and unable to perform its function. Both retaining devices were replaced, the motor shaft
and gear inspected, post-maintenance testing conducted, and the valve returned to service that
day. The key was found in the motor grease and was observed to have rounded edges (an
indication of excessive wear). Vermont Yankee attributed the root cause of the failure to
cyclic stress induced on the key by the motor cycling and by system vibration.
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On June 18, the inspector discussed the key failure with the Maintenance Manager and
cognizant engineers and concluded that VY's efforts to correct the failure were timely.
However, limited documentation existed regarding the "as found" condition of the key, key
way, set screw, motor shaft and gear. The inspector considered the measurement and
documentation of these critical attributes important to a comprehensive determination of root
cause. These attributes would also enable an assessment of common cause failure on
similarly configured motor operators should failures occur in the future.
Vermont Yankee concluded that no immediate corrective action was necessary to improve the
installed key configuration based on the lack of similar past failures and because such a key
failure was dependent on time in service (valve 89A had approximately twice the service life
of 89B). The licensee inspects each of these valves once every three years on a rotating
basis, and intends to inspect RHRSW-89B during the week of July 12. Modifications to both
RHRSW subsystems will be implemented during Refueling Outage XVII (August 1993) to, in
part, reduce system vibration and cyclic stress on the motor key. Notwithstanding
inspector's concern for root causal analysis, the licensee's actions were concluded to be
appropriate and the replacement of these valves in the upcoming outage will be followed in
future NRC inspections (IFI 93-13-02).
4.1.2 Standby Gas Treatment - LCO Maintenance
During this inspection period, VY voluntarily entered the TS limiting condition for opei Ttion
(LCO) action statements for the "A" and "B" standby gas treatment (SBGT) systems to
perform maintenance and surveillance. The inspectors conducted direct field inspection to
assess this LCO maintenance. Interviews were conducted with the cognizant engineer,
mechanics, and Instrument & Control Department technicians. Internal VY commitment
items, the Final Safety Analysis Report, TSs, and Regulation Guide 1.52, " Design, Testing,
and Maintenance Criteria for Post-Accident Engineered-Safety-Feature Atmosphere Cleanup
System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants,"
were reviewed. In addition, applicable plant procedures and the SBGT pre-operational
testing, performed prior to initial reactor startup, were also reviewed to support this
inspection.
Each SBGT train was sequentially taken out of service for approximately two days of the 7-
day LCO period. The surveillances verified the efficiency of the HEPA and charcoal
filtering elements, calibrated system instruments, and identified a wiring discrepancy
associated with the "B" SBGT system airstream thermocouple. The maintenance focused on
the field verification and correction of system configuration discrepancies associated with
sealing gaskets, bolts, and charcoal tray thermocouples. In addition, preventive maintenance
and inspections were performed on the SBGT fan, moisture separator, and sight level gage.
Management controls and the disposition of identified deficiencies were good. For example,
following maintenance on the "B" SBGT system in November 1992, VY identified and
evaluated several minor problems with the "as-found" configuration of the carbon tray
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thermocouple (TE-1-124-4B) and the location of the tray itself. Corrective actions were l
implemented to assure that these configuration control issues were properly corrected during l
current maintenance. A second example involved the identification of concerns regarding the '
qualification of gasket materials. Vermont Yankee was concerned that the installed gaskets
would not maintain seal integrity during post-accident radiation exposure. Vermont Yankee
management delayed entry into this current maintenance to complete an engineering I
evaluation of the as-found configurations; the licensee concluded that no system operability
concerns existed. The inspectors reviewed these assessments and found them to be !
appropriate.
. Pre-planning effectively supported the maintenance and surveillance performed. The work
package was comprehensive based on the incorporation of technical literature, one-for-one ,
evaluations, and inter-department memorandums that described the gasket and thermocouple ;
issues. The cognizant engineer demonstrated detailed knowledge of the issues and provided
effective oversight of the maintenance performed. Maintenance and I&C Department
personnel were experienced and followed work instructions. A problem involving the
segregation of safety and non-safety related bolting was identified by the inspector, but l
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promptly corrected by VY. Overall, the LCO maintenance was well managed, and
consistent with NRC guidance for this work. ;
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4.1.3 Circuit Breaker Maintenance
3 During this period, maintenance was performed on the 4KV AC breaker for the "A" service
water pump (P7-1-A). The inspector performed a field inspection of this activity, .
interviewed the electrician, and reviewed the work package. Plant procedure OP 5222, Rev. {
11, "4KV AC Circuit Breaker Inspection, Calibration and Testing," NRC Information Notice !
90-41, " Potential Failures of GE Magne-blast Circuit Breakers and AK Circuit Breakers," I
and General Electric (GE) Service Advice Letter 073/348.1, dated December 7,1990, were
reviewed by the inspector.
The inspector concluded that the work package and documentation of identified deficiencies
were comprehensive. The work package contained the GE service information and the one-
for-one evaluation regarding this industry information, the applicable circuit breaker technical
manual, and appropriate work release documents. Manufacturer-recommended lubricants
were in use and correctly illustrated in OP 5222. The field notes were documented directly
on the breaker inspection report, and clearly described identified deficiencies. Attention to l
detail was demonstrated by the electrician in the identification of an out-of-position trip
spring and commutator wear indications. Engineering evaluation of the deficiencies was also
timely.
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4.2 Surveillance !
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The inspector reviewed procedures, witnessed testing in-progress, and reviewed completed ]
surveillance record packages. The surveillances which follow were reviewed and were found
effective with respect to meeting the safety objectives of the surveillance program. The i
inspector observed that all tests were performed by qualified and knowledgeable personnel, i
and in accordance with VY Technical Specifications, and administrative controls (Procedure
AP-4000), using TS approved procedures.
* OP 4111, Rev. 24, " Control Rod Drive System Surveillance"
* OP 4115, Rev. 29, " Primary Containment Surveillance" ,
* OP 4116, Rev.14, " Secondary Containment Surveillance"
* OP 4117, Rev.17, " Standby Gas Treatment System Surveillance" -
* OP 4120, Rev. 26, "High Pressure Coolant Injection System Surveillance" ,
* OP 4121, Rev. 24, " Reactor Core isolation Cooling System Surveillance"
* OP 4160, Rev. 23, " Turbine Generator Surveillance"
* OP 4424, Rev.17, " Control Rod Scram Testing and Data Reduction"
* OP 4501, Rev. 7, "Fiker Testing"
4.3 (Open) VIO 93-13-02: Core Spray Sparger Break Detection - Nonconservative
Setpoints !
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On May 25 an auxiliary operator (AO) conducting routine rounds in the reactor building
identified that core spray differential pressure instrument DPIS-14-43A was indicating below
zero pressure. Instrument DPIS-14-43B, which is mounted directly below the "A"
instrument, was indicating at (but not below) zero pressure. The AO assessed that the
condition potentially reflected anomalous equipment performance and reported it to the Shift :
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Supervisor (SS). A work order to address the downscale indication on DPIS-14-43A was
initiated and I&C Department personnel were assigned to investigate.
At 8:50 a.m., May 25, the SS declared the "A" core spray subsystem inoperable and entered l
the action statement for TS 3.5.A.2 which allows seven days of continued plant operations. 1
Plant Procedure OP 4347, Rev.14, " Core Spray Header Differential Prcssure
Functional / Calibration," was used to facilitate the investigation. Initial corrective actions
identified the need to repair the internals of the instrument. However, the instrument's !
maintenance history file and procedure OP 4347 stated that a 0.75 pounds per square inch
differential (psid) head correction needed to be applied to "zero" the instrument, but the
technical investigation determined that a 1.9 psid value was necessary for full power )
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Background
Each core spray (CS) subsystem has a detection system to confirm the integrity of the piping
between the inside of the reactor vessel and the core shroud. A differential pressure
indicating switch (DPIS) measures the pressure difference between the bottom of the core and
the inside of the CS sparger pipe just outside the reactor vessel (high and low pressure sides,
respectively). With the instrumentation connected across the core shroud in this fashion, it i
provides a negative pressure indication during normal operation but a positive pressure if a
core spray line break were to occur at power. The setpoint value used to calibrate the
instrument to read 0 psid at full power is designated as the " head correction." The switches ;
used at VY are Barton Model No. 288, designated as DPIS-14-43 A/B, do not have a
negative valued scale (i.e., they cannot indicate negative pressures).
An increase in the normal pressure drop at power (from a negative to a positive differential)
initiates an alarm in the control room. The corresponding alarm response procedure requires
operator actions to verify that the differential pressure is legitimately high, and to consult the
applicable TSs. Regarding the alarm setpoint and instrument operability requirements, TS
Table 3.2.1 specifies that the alarm trip level setting shall be less than or equal to 5 psid; if ,
the alarm channel is not available (or operable), then the respective CS subsystem is to be ;
considered inoperable and the requirements of TS 3.5 apply.
Detailed Investigation
The established head correction for the DPIS-14-43B instrument was 1.9 psid and, because ;
the monitoring systems for both CS subsystems have identical instrument piping
arrangements, it was unclear as to why the "A" side would have a different value (0.75 psid)
for the established head correction. Further investigation by both I&C Department and ,
Engineering Department personnel determined that both correction values should be the !
same.
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In September 1979, the General Electric Co. (GE) issued Service Information Letter (SIL) l
No. 300 that addressed a situation where the subject DPIS instruments were routinely
indicating downscale during plant operation, an operational nuisance and potentially bad i
practice. The SIL also provided information for BWR operators to review the calibration of !
this instrumentation. For VY, a maximum expected change in differential pressure across :
the core shroud following a sparger break was calculated by GE to be 4 psid; however, a
question as to appropriateness of the TS stated 5 psid instrument alarm setpoint value was not l
recognized during the 1979 review of the SIL.
The VY investigation identified inadequacies in procedure OP 4347 involving an incorrect
and inconsistent methodology in applying the head correction factor. Specifically, a 4.0 f.
0.3 psid alarm trip value, as indicated on measuring and test equipment, was used to set the
instrument's alarm switch; however, the actual head correction sensed by the system (i.e.,
the -1.9 psid measured value across each instrument) was not considered in arriving at the
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instrument alarm setpoint. This resulted in the actual alarm switch being set at
approximately 5.9 psid and, therefore, nonconservative with respect to the TS. The actual l
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" zeroing" of the indicator pointer to preclude downscale indication has no actual affect on the
alarm setpoint due to the nature of the switches' internal mechanism.
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Corrective Actions t
At 8:30 p.m. on May 27, following VY's identification that the OP 4347 calibration ,
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procedure incorrectly set the alarm points nonconservatively with respect to the TS value,
both the "A" and "B" CS subsystems were declared inoperable in accordance with TS Table .
3.2.1. The procedure was revised to correct the nonconservative conditions and DPIS 14-
43B was recalibrated and returned to operable status three hours later. The DPIS 14-43A
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instrument was made operable on May 28 at 1:25 p.m. Vermont Yankee held discussions
with General Electric Co. technical representatives to ensure that their corrective actions ,
were consistent with the plant's design.
Regarding past missed opportunities for VY to have identified the setpoint deficiencies, the
inspector noted the applicability of two relevant activities: (1) the disposition of NRC
Information Notice 91-75; and (2) the biennial procedure review process. NRC Information
Notice 91-75, " Static Head Corrections Mistakenly Not Included in Pressure Transmitter !
Calibration Procedure," was intended to alert licensees to situations where errors were found !
in the calibration of pressure transmitters that occurred because the effects of static pressure
had not been considered, or had been considered inappropriately. Vermont Yankee's action l
to address the " lessons-learned" from this document was to create a procedure comment file
to have the I&C Department add references to head corrections in the discussion section of
all applicable calibration procedures during the next biennial review for the subject I
procedures. When Revision 14 of procedure OP 4347 was issued on December 7,1992 (its i
next biennial revision), the head corrections of 0.75 and 1.9 psid for the respective switches
were added from the equipment history file. There were no evaluations performed to ensure
the accuracy of the existing setpoints.
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The biennial review process at VY is intended, according to procedure AP 0037, " Plant
Procedures," to be a comprehensive review of the entire procedure. Specifically, the
cognizant department head has the responsibility to ensure that the procedure is reviewed for
technical adequacy, including compliance with the TSs. Vermont Yankee's actions to
strengthen the biennial review process had become the cornerstone of their corrective action
to address a number of past missed smveillances that were related to poor or inadequate
procedures.
Safety Significance and Conclusions !
The switches were nonconservatively set, above 5.0 psig, since 1979. However, the
switches only feed an alarm and do not result in a loss of function of the core spray system.
The lack of an alarm which would annunciate upon a sparger piping break inside of the
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reactor vessel does not affect the ability of an engineered safeguards feature to mitigate
accident consequences; rather, what was lost was the ability to detect a relatively low ]
likelihood passive piping failure. Other programs such as inservice inspection (ISI) exist to ;
detect and prevent such failure mechanisms as intergranular stress corrosion cracking.
Nonetheless, both channels were inoperabic for a period in excess of ten years, and several
opportunities were missed to identify and correct this condition.
A good questioning attitude was demonstrated by the equipment operator in identifying
anomalous instrumentation performance. Previous biennial procedure reviews and industry
experience evaluations which missed this problem, however, indicate weaknesses in those
processes. Vermont Yankee failed, as far back as 1979, to provide proper technical
guidance in the form of a surveillance procedure to ensure the correct implementation of a
TS required setpoint for the core spray sparger high pressure alarm. This failure to ensure
that TS Table 3.2.1 requirements for this alarm function were met was determined to be a
violation of NRC requirements (VIO 93-13-03).
5.0 SECURITY (71707, 92700, 93702)
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The inspector verified that security conditions met regulatory requirements 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.
During this period, the inspector walked down portions of the Protected Area fence and
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observed that security personnel properly responded to perimeter alarms. During a night
tour, the inspector found the security lighting acceptable. On June 25, the inspector .
observed security personnel appropriately search and escort a vehicle onsite, inside the
protected area.
6.0 ENGINEERING AND TECIINICAL SUPPORT (71707,62703)
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6.1 Appendix J Testing: Drywell IIydrogen/ Oxygen Monitoring System
On February 5, VY identified that portions of both drywell hydrogen / oxygen (H2/02)
monitoring systems were not leak rate tested in accordance 10 CFR Part 50 Appendix J, ,
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" Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." Both
systems were declared inoperable, leak rate tested, and restored to service. The H2/02
system provides continuous sampling of oxygen and hydrogen concentrations within ;
containment, and provides alarm and indication in the control room. Potential Reportable ]
Occurrence Report No. 93-09 and Licensee Event Report (LER) 93-03 documented VY's
engineering evaluation and corrective actions implemented for this issue. I
Vermont Yankee identified this discrepancy following preventive maintenance of the H2/02
monitoring systems in January 1993 (NRC Inspection Repon 93-02). During this
maintenance, system components that form part of the primary containment pressure
boundary were removed and reinstalled. local leak rate testing (LLRT) was part of the post-
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maintenance testing and performed in accordance with procedure OP 4029, Rev 6, " Type A - )
Primary Containment Integrated Leak Rate Testing." However, the procedure was )
inadequate in that tubing downstream of a safety class check valve was not vented to
atmosphere, and tubing within both monitor cabinets was not subject to test pressure.
The inspector reviewed procedure OP 4029, the root cause determination, and LER 93-03
and concluded that VY's assessment of this issue was adequate. The inspector concurred
with the licensee's root cause determination in that VY failed to adequately perform leak rate
testing due to an inadequate procedure. However, the inspector also considered the biennial l
review of the procedure ineffective because the testing inadequacy was not previously
identified.
The immediate and proposed long-term corrective actions were appropriate. The results of
the LLRT performed in response to the identified discrepancy were satisfactory and identified
no system integrity concerns. Similarly, the overall integrated leakage rate was re-calculated
using the new LLRT value and found within acceptable limits. The proposed independent
assessment and rewrite of the Appendix J testing program was appropriate and intended to
improve the overall quality of the program and prevent recurrence of similar deficiencies.
This effort is scheduled for completion by the third quarter of 1994, prior to the next ;
scheduled Appendix J test in Refueling Outage XVIII. This violation involving the failure to ,
properly leak rate test the H2/02 monitors meets the criteria for enforcement discretion in
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Section VII of the NRC's Enforcement Policy, and will therefore not be cited.
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6.2 Water Ixvel Instrumentation Errors During and After Depressurization ,
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Transients (TI 2515/119)
The inspector verified that VY implemented operator training and guidance regarding reactor
water level instrumentation errors during and after rapid depressurization events and that this
material was consistent with current plant Emergency Operating Procedures (EOPs). As part i
of this assessment, the inspector interviewed the VY training staff and a number of control -
room operators (CROs), and reviewed training matenals. Previous review of this issue and
recent water level instrumentation anomalous performance at VY are documented in NRC
Inspection Reports 92-21 and 93-08.
Two simulator scenarios were observed to verify that CROs were trained to respond to the
failure of reactor vessel water level instrumentation caused by a rapid depressurization
transient (Section 2.4). The EOPs appropriately led operators into reactor vessel flooding
and depressurization actions and provided clear information when such activities were
required. Even though the EOPs do not clearly define all situations involving "when reactor
water level is undetermined," the operators interviewed demonstrated adequate knowledge of -
explicit plant indications which necessitate this EOP entry condition. Simulation of
undetermined reactor water level is based on reference leg flashing due to saturation
conditions; the computer algorithm does not simulate level anomalies due to degassing of {
noncondensables.
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The safety parameter display system (SPDS) models reactor vessel water level failures and
level indication identical to that available in the control room. In addition, SPDS color will
change when data exceeds acceptable tolerances. This modeling assesses the validity of
discrete level values and the statistical variations between channels to determine the
acceptability of processed information. Because level divergence between channels is not
specifically assessed nor displayed by the computer algorithm, CROs perform log keeping to
document level divergence.
The inspector reviewed the VY training lesson plans for reactor water level instrumentation
and determined that the plan adequately describes the effects of noncondensable gases in
reference legs. The training references Generic Letter 92-04 and VY's response, and ~
incorporates discussion regarding water level anomalies experienced at another boiling water
reactor (BWR) facility. Further, Operation's Department Night Orders were issued to
enhance CRO knowledge of level anomalies that have occurred in the industry. Based on a
sampling of CROs interviewed, operators indicated an adequate level of knowledge in
regards to industry issues; however, operators had some difficulty in articulating the
differences between the level anomalies observed at VY in April 1993 (NRC Inspection
Report 93-08) and recent industry experiences. Industry information has also been
incorporated into the training program, however, the 8-step level determination test
(BWROG-92096, dated October 16,1992) will uot be implemented. Augmented training, as
required by NRC Bulletin 93-03, " Resolution of Issues Related to Reactor Vessel Water
Level Instrumentation in BWRs," will be completed on August 13,1993 (VY letter dated
June 9,1993 to the NRC).
7.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (90712,90713,
92700)
7.1 Periodic and Special Reports
The plant submitted the following periodic and special reports which were reviewed for
accuracy and found to be adequate:
* Monthly Statistical Report for May 1993
* Monthly Status of Feedwater Nozzle Temperature Monitoring
* Report of Fuel Failure Status and Parameter Trends for May and June 1993
7.2 Licensee Event Reports
The inspector reviewed the following Licensee Event Reports (LERs) and concluded that:
(1) the reports were submitted in a timely manner, (2) the description of the event was
accurate, (3) a root cause analysis was performed, (4) safety implications were considered,
and (5) corrective actions implemented or planned were sufficient to preclude recurrence.
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* 93-01, Supplement 1: " Degraded Vital Fire Barriers Due to inadequate
Documentation of Assumptions and Inadequate Procedures." NRC evaluation of
degraded fire barriers is documented in NRC Inspection Report 93-05.
* 93-03: " Failure to Properly Leakage Rate Test Portions of the Primary Containment
Hydrogen / Oxygen Monitoring System" (refer to Section 6.1).
* 93-06: " Core Spray Systems A&B Declared Inoperable Due to Calibration Procedure
Error" (refer to Section 4.3).
8.0 MANAGEMENT MEETINGS (30702)
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8.1 Preliminary Inspection Findings Meetings were periodically held with plant management during this inspection to discuss inspection findings. A summary of preliminary findings was also discussed at the conclusion of the inspection in an exit meeting held on June 30. No proprietary information was identified as being included in the report. 8.2 Enforcement Conference
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On June 15, an enforcement conference was held at the NRC Region I office with VY representatives to discuss control rod performance involving inadequate scram insertion times. A list of meeting attendees and copies of overhead slides used in the VY presentatian are contained in Attachments A and B to this report.
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ATTACHMENT A
LIST OF ATTENDEES ,
ENFORCEMENT CONFERENCE l
JUNE 15,1993
NRC Attendees
E. Imbro, Acting Deputy Director, Division of Reactor Safety (DRS)
C. Hehl, Division Director, Division of Reactor Projects (DRP) '
P. Eapen, Chief, Systems Section, DRS
W. Butler, Project Director, Project Directorate I-3, Office of Nuclear Reactor Regulation l
(NRR) l
L. Prividy, Team leader, DRS
M. Banerjee, Sr. Enforcement Specialist, Office of Regional Administrator
T. Shedlosky, Project Engineer, DRP ,
E. Kelly, Chief, Reactor Projects Section 3A, PB3, DRP i
H. Eichenholz, Sr. Resident Inspector J
R. Matakas, Investigator, Office of Investigation
B. Whitacre, Reactor Engineer, DRP
R. DePriest, Reactor Engineer, DRS
J. Petrosino, Vendor Inspection Branch, NRR
P. Drysdale, Sr. Reactor Engineer, DRS
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Licensee Attendees l
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D. Reid, Vice President, Operations
R. Wanczyk, Plant Manager
J. Herron, Technical Services Superintendent {
M. Watson, Manager, Instrumentation and Controls
M. Benoit, Manager, Reactor and Computer Engineering
P. Corbett, Sr. Electrical Engineer, Engineering
P. Bergeron, Manager, Transient Analysis, Yankee Atomic Electric Company
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ATTACHMENT B
SLIDES FROM JUNE 15,1993 ,
ENFORCEMENT CONFERENCE
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JUNE 15,1993
ENFORCEMENT CONFERENCE
CONTROL ROD DRIVE INSERTION TIMES
I. INTRODUCTIONS
II. REVIEW OF OCTOBER,1992 SCRAM TIMING
SURVEILLANCE / TECH SPEC REVIEW
III. ASSESSMENT OF OCTOBER,1992 RESULTS
AND CORRECTIVE ACTIONS
IV. DESIGN CONTROL PROGRAM
V. SHELF LIFE CONTROL PROGRAM
VI. SCRAM TIMING SURVEILLANCE TASK FORCE
EFFORTS AND CORRECTIVE ACTIONS
VII. SAFETY SIGNIFICANCE
VIII. SUMMARY
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REVIEW OF OCTOBER,1992 SCRAM TIMING ;
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SURVEILLANCE AND TECH SPEC REVIEW
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o SINGLE ROD SCRAM TIME TESTING / RETESTS !
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o EVALUATION
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o MANAGEMENT REVIEW ;
- ENGINEERING INPUT
- STANDARD TECH SPECS
- TECH SPEC INTERPRETATION
- REVIEW OF PRIOR TRENDS )
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o PRO DOCUMENTATION j
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BASES
C. Scram Insertion Times
The Control Rod System is designed to bring the
reactor subcritical at a rate fast enough to prevent fuel
damage. The limiting power transient is that resulting
from a turbine stop valve closure with a failure of the
Turbine Bypass System. Analysis of this transient
shows that the negative reactivity rates resulting from
the scram with the average response of all the drives
as given in the above specification, provide the
required protection, and MCPR remains greater than
the fuel cladding integrity limit.
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4.3 SURVEILLANCE REQUIRDfENTS
3.3 L1 HIT 1HC CONDITIONS FOR OPERATION
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Scram insertion Times _ C. Screes Insertien Times .
C.
1.1 The average scram time, based on the 1. Af te'r refuelitig outage and" priot to* operation ,
' de-energitation of the scram pilot above 30% power with reactor pressure abovu
800 peig all control rode shall be dubject to
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valve notenoids of all operable control *
rode l'n the reactor power operation .
scram 41me measurements f rom the fully
condition shall be ho greater thant withdrawn position. The scram times for single
- tod scram testing shall be measured without
Drop-Out of 11neerted From Avg. Scram Insertion , reliance on the control rod drive pumpe.
Position Fully Withdrawn Time (sec)
2. During or following a controlled shutdown of the
reactor, but not more frequently than 16 weeks
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46 4.51 0. 358 ' .
36 25.34 0.912 nor less frequently than 32 weeks intervate,
1.468 50% control red drives in each quadrant of
26 46.18 .
06 87.84 2.686 the reactor core shall be measured for scram !
* times specified in Specification 3.3.C. All
The average of the scram insertiorl times control rod drives shall have esperienced
scram-time measuremente each year. Whenever
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for the three fastest control rods of all 50% of .the control rod drives scram times have e
groups of four control rods in a two by .
been measured, an evalus' tion shall be made
two stray shall be no greater than:
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to provide reasonable assurance that proper
Drop-Out of IInserted From Avg. Scram Insertion control rod drives performance is being
maintained. The results of measuremente per-
position _ Fully Withdrawn Time (sec)
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formed on the control rod drives shall be ,
4.51 0.379 submitted in the start up test report.
46- *
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36 * 25.34 0.967
26- 46.18 . 1.556
06 87.84 2.848 .
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3.3 L1 HIT 1HG CONDITIONS FUR OFERATION *
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4.3 SURVEILIANCE REQUIREMENTS * '
I,3. If Specification 3.3.C.1.2'cannot he met, 9..:. '
the reactor shall not be made super- * .
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criticalg if operating, the reactor * * ,
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ehall be shut down leanediately upon
determinetton that average scene time '
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111 ASSESSMENT- OF OCTOBER,1992 RESULTS AND 1
CORRECTIVE ~ ACTIONS-
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A) PRO 92-083 Evaluation j
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B) Trend Evaluation :
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C) Trending Methods i
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D) Scram Time Testing Methods j
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E) Scram Testing Procedure Requirements !
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F) Scram Time Projection l
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G) Sensitivity Study ,
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VermontYankee ; ,
fttch 46 Scram Time - All Ehta
0.4
0.38
+
0.36 - 4+
m + 4+ + + +
io0.34 +- +-+-+ + --+
+ + + + + +
8 0.32 +-++-
*
+ +
ai 0.3 +- + 4+-
. E ++ <<+ + + + + + +
F- 0.28 +-+ -+ <<+-+ - 4+ + +
$ +++ + + + '+ + 4+
0.26 + + +
0
a + + + +
0.24 + + +
0.22
0.2
80 90 100 110 120 130 140 150 160
Scram ihmber
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tbtch 46 Scram Time - Automatic Scrams
O.4
0.38
0.36
f 0.34
O g 0.32 + e + ar 0.3 + + <+ E ++ <<+ + + + + + +
F 0.28 +-+ -+ <<+-+ - 4+ + + e +++ + + + '+ + (+ 8 0.26 + + -+ o + + + + .
0.24 + + +
0.22
0.2 ,
80 90 100 110 120 130 140 150 160
Scram Number
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Vermont Yankee .
tbtch 46 Scram Time -Pbwer Testing
0.4
0.38
+
0.36 <+
+
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m +
j 0.M +-+ +
o +
g 0.32 -
+ .
a +
ar 0.3
E
F 0.28
m
8 0.26
i O
0.24
0.22
0.2
80 90 100 110 120 130 140 150 160
Scram MJmber
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+ 0 -
5
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0
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a 3
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o e
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YaH m -
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om m
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Ve m a
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r 0
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S 1
6 + .
-
4 -
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c + .
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f
0
0
1 -
-
+
0
9
+
-
+ 0
8
4 8 6 4 2 3 8 6 4 2 2
-
0 3 3 3 3 0 2 2 2 2 0
0 0 0 0 0 0 0 0
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3REJ::CTIOsl FOR APR::_ 6, :.993
SING _E RO] SCRAv TEST:: NG
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CYCLE 16
HYDRO
DO 46 AVG. 0.344 SECONDS
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BOC BOC
O.348 0.340
DELTA =
0.008 DELTA =
0.016
Y b
OCT 92 APR 93
AS-LEFT =
0.356 PREDICTION =
0.356
AS-FOUND =
0.366 ACTUAL =
0.384
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VY DESIGN CONTROL PROCESSES
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Process Senp_e
Maintenance Request = Plant or Security Equip.
= PM or CM
= No changes to essential criteria
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= Non identical components with One
for One or Equivalency Evaluation
Work Request = Non-Plant / Non-Security
Temporary Modification = Renders Plant equipment unlike I
current design
= Temporary in Nature
Eng. Design Change = Change in Plant Design
= YNSD initiated
Plant Design Change = Change in Plant Design
= Plant initiated
One for One Evaluation = Non identical part or comp.
= Equal or better
= Compare critical characteristics
Equivalency Evaluation = Alternate Replacement Items
= During Procurement Process
= Compare critical characteristics
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COMPONENT REPLACEMENT PROCESSES
Process Preparation Approval ,
One for One Eval. Engineer Eng. Supervisor
(AP 0008)
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Equivalency Eval. Procurement Eng. Supervisor
(VYP:329) Engineer
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* Future- Combination of two processes for consistency
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SCRAM SOLENOID O-RING
REPLACEMENT
= 9/91 I&C initiated efforts to replace O-rings .with
Viton
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= 9/91 Verbal contact to YNSD I&C Eng., approval &
EQ doc.
= 9/9/91 Requisition for Viton 0-Rings initiated
= 9/10/91 Procurement Eng. review of requisition
assessed critical characteristics
= 9/11/91 One for One Evaluation by Engineering
* Emphasis was EQ/ aging aspects
* Ref. YNSD eval. & documentation
= 9/11/91 EQ Documentation Issuance
= 9/13/91 0-Rings changed to viton in two leaking 117
,
valves
= 4/92 1992 Refueling Outage, Installed Viton 0-rings
in 117 valves
= 4/93 1993 SCRAM Timing Event, Refurbished 117
& 118 valves, Buna-N 0-Rings used
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J
SCRAM SOLENOID O-RING REPLACEMENT
l
Conclusions
= Significant review and approval
-
I&C Engineering
-
I&C Supervisor
-
YNSD I&C Engineering
-
Procurement Engineering
-
Plant Engineering
-
Plant Engineering Supenrisor i
= Dimensions identical, key attribute EQ/ aging. Viton
superior properties to Buna-N and concluded to be an i
acceptable replacement
= Since performance of other valve elastomers was
monitored by factors other than SCRAM air header
leakage, air leakage was not considered as an indication
of degradation
= No consideration given to coordinating with ASCO or GE
as Environmental Qualification was not based on
ASCO/GE Reports but on a VY specific DOR Qual.
Report. Key attribute affecting SCRAM Timing was not
being changed
Euture Actions
=
Review for enhancements from lessons learned (broader
implications of premature components failures and
consideration for vendor contacts)
-
,. .
.
. ..
,
SERVICE LIFE OF SCRAM
l SOLENOID PILOT VALVES (SSPVs) i
References:
= GE SIL 128
= GE Letter, HPW87.018 to S. Moriarty (VY),
dated June 6,1987
= VY Procedure DP 0313, " Equipment Service
Life Tracking"
=
VY I/C EQ File 3-6
.. _ . .
.
,. ..
. ..
.
= Service Life is 7 years maximum (with no '
shelf life correction; any shelf life must be
deducted from service life). l
= 90% degradation is considered end of life,
thus a service life of 6.3 years (again with no 4
shelf life correction applied) maximum is l
applied on the SSPVs. ]
:
= A 5% service life degradation occurs with 6
year shelf life, a 10% service life degradation :
occurs with a 12 year shelf life.
=
EQ File 3-6 states: "I/C engineering
concurrence is required if valve kits or pilot .
head kits have an assemble date greater than ;
two years from the installation date." Thus, -
without I/C engineering involvement a two- 1
year span from assembly date to installation
date is possible (worst case).
!
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DESCRIPTION OF EVENT - 4/6/93
I
:
1
= Performed single Rod Scram Testing IAW
Technical Specifications 4.3.C.2 during
scheduled R.P.E.
= Results were as follows:
l
o Core Wide average notch 46 = .359
o Seven (7) 2 x 2 arrays ranging from .380
to .418
= Task team developed to determine the cause of
'
the slow scram times to notch 46
1 l ! l-
- . - - -
.-
- - - - - .-
~
.. ..
.. .
.
e
1
TASK TEAM ,
p
7
O l
;
A multi-disciplinary task force was formed of
plant individuals from: ;
1. Reactor and Computer Engineering f
2. I&C l
3. Mechanical Maintenance )
4. Operations j
.
1
The General Electric -Company lead system
engineer for the Control Rod Drive (CRD)
system and a design engineer from Automatic
Switch Company (ASCO) were added to the
team.
MISSION
Investigate the slow, changing and inconsistent
'
scram times, determine the root cause and
recommend any necessary repairs.
:
I
i
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*
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,
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j
. ;
.
.
!
a
TASK TEAM
i
:
l
#2 ;
A sub-task team was added that was headed !
up by Vermont Yankee's Engineering
Director. This team was formed of- plant i
engineering experts in the EQ, materials and q
procurement areas. !
MISSION
!
To acquire physical data from scram solenoid l
pilot valves (SSPV's) to identify a root cause
within the values. i
l
..
,
-
.
.
..
. .
,
.
TASK TEAM ;
D
An independent fact-finding team was assembled from the Yankee
Nuclear Services Division. The team consisted of the following:
1. Technical Director, Yankee Nuclear Rowe Station (Rowe)
2. Engineer, Vermont Yankee Project
3. Director, Nuclear Engineering Department
4. Lead Engineer, Reactor Physics Group
Two of the members of this team are members of our Nuclear
Safety Audit and Review Committee (NSARC).
MISSION
Charged with evaluating scram time testing methods used at :
Vermont Yankee in addressing Technical Specifications
= Review Technical Specification scram time testing requirements
= Evaluate past data gathering and use in determination of control
rod scram insertion time, including the use of "As-Found" and l
"As-Left" data I
= Review of industry practice with respect to scram time testing
= An evaluation of the use of scram time data to show compliance
with VY Tech Specs
= An examination of plant management expectations with respect to
the use of scram time data
= Recommendations to improve scram time testing practices in the
future .
1
1
.
. ..
'
. .- _
SIGNIFICANT CORRECTIVE ACTION REPORT
TASK TEAM #1 - ROOT CAUSE
= Root Cause
o The refurbishment kits installed in the SSPVs
during the 1989 refueling outage (#14) have
component (s) that have an unknown reduced
capability compared to the present ones installed
and components that have deteriorated over time.
The combination of the two deficiencies have led
to the slow Start of Motion times.
= Contributing Root Cause(s)
o The contributing root causes deal with a number
of programmatic issues that contributed to the
lack of attention paid to deteriorating scram
times
._ _ _ .
-
.- ... .
,
. . .
.
TASK TEAM SUMMARY ON SSPV
:
= CEP techniques used for the determination of slow scram :
times l
:
= The Scram Solenoid Pilot Valves were the cause of the- !
slow scram times -
= The Start of Motion (SOM) was the specific definition of i
the area of concern !
:
= All 89 Control Rod Drive SSPV's were replaced - total of ;
178 kits 1
= April 14,1993 - Cold Hydro Test results I
:
o Core wide average time to notch 46 = .320 see
o No 2 x 2 array issues
= April'17,1993 " HOT" At Power Test results ;
!
o Core wide average time to notch 46 = .312 sec l
o No 2 x 2 array issues ;
I
= Both Hot and Cold Test data are Vermont Yankee's best
times ,
!
= June 6,1993 " HOT" At Power additional testing results. ;
1
;
o Core wide average time to notch 46 = .316 !
o No 2 x 2 array issues
i
a
$
;
', . .,.
. .. . .
.
SIGNIFICANT CORRECTIVE ACTION l
REPORT RECOMMENDATIONS l
!
TASK TEAM #1 :
!
Summary of Recommendations ;
;
= Refurbish all SSPV's
= GE and ASCO to perform material testing l
!
= Establish Administrative Limits l
t
;
= Evaluate CRD HCU preventive maintenance j
i
= Improve procedural controls
= Evaluate Tech Spec Section 3.3.C/4.3.C
= Issue Part 21 Evaluation
= Evaluate the Single Rod Scram Test Panel
= Engineering evaluation of RPS voltage
= Evaluate Scram Air Header Pressure
= Self-assessment of other Tech Spec areas
= Re-Evaluate SIL-128
=
Determine the need for additional QA audits GE/ASCO
= Determine assumptions used for 7-year service life
= YAEC to evaluate past audits of GE/ASCO
= Reconvene task team to assess CA effectiveness
- - - - - - - - - - - - _ -
'. . .
..
.
..
SUMMARY OF PROGRAMMATIC ISSUES
TASK TEAM #3
Final Report Summary
= Technical Specification Review
= Review of Test Records
= Review of As-Found Data Records
= Evaluation of Corrected Full Scram Data
= Review of Technical Specification Compliance
a Review of Industry Practice
.
= Management Expectations
.
. ..
.
..
.
d
TECHNICAL SPECIFICATION REVIEW '
.
= Apparent contradiction within Tech Spec Section 4.3.C.1
vs 3.3.C.3
= Tech Specs do not differentiate between As-Found and
As-Left
= Must use As-Found to meet the requirements of the
surveillances section of Tech Specs
= Re-testing should be allowed only for the following
reasons:
i
o Test recorder failure
o Data not retrieved or illegible
o Part of a maintenance /PMT activity
o Following a refueling / maintenance outage for the
purpose of insuring operability
= Separate the procedures for specific Tech Spec section
implementation
= " Average Scram Time" does not differentiate between
core wide average and 2 x 2 array
= Tech Spec 3.3.C.3 requires an immediate shutdmvn if
section 3.3.C.I.2 (scram times) is not met
,
. _ _ . --
.,
-
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; . .. ,
. . .
l
,
:
SCRAM TIME DATA GATHERING
AND DATA ANALYSIS
:
;
I
;
:
= 30 pen full scram recorders have ~
a 30
millisecond non-conservative error
= No recorder error on single rod scram testing ;
= Review of the BADTIME program was found I
'
to be in full compliance with Tech Specs
;
= Conservative errors were verified with the .
Single Rod Scram Test Panel (up to .070 sec)
.
1
--
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. ' _ :. ;
I
REVIEW OF TEST RECORDS li
.
l
= Long standing practice to perform re-testing !
!
-
= No distinction between Cold Hydro testing and
At Power Single Rod Surveillance Testmg !
!
= Re-testing was conducted for slow scram times
along with poor test equipment performance
= Testing of control rods was forward-looking
assessment of operability vs past compliance i
. :
= No attempt was made to disguise the testing
practice
= Final Scram test data was the time used to
verify compliance even if the control rod got
slower
= A change in philosophy with respect to using
As-Found data was evident
1
= The change in testing philosophy is what led to
the 10/15/92 PRO
l
l
l
. _ .___ ___ . _ - . _.
;
,. . . . _ . ..
'
'. .
...
.. .- .
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!
REVIEW OF AS-FOUND DATA RECORDS
:
!
,
&
= Single rod scram testing was reviewed with no l
violation to the Technical Specifications noted :
= Using As-Left data vs As-found data had a
relatively minor impact on the scram times
,
= A review- of some of the 2 x 2 arrays was
conducted - no other discrepancies noted
= Full scram data have consistently shown faster
times ;
= Full scram data questioned due to recorder- ;
delay in the start-up time '
= Correcting for the recorder start-up delay
time to previous full scram data - no violations '
of the Technical Specifications was noted
!
,
'..;..
.
-
'
.
t
REVIEW OF THE TECHNICAL <
SPECIFICATION COMPLIANCE
.
i
= PRO dated 10/15/92 needs to be re-evaluated;
team conclusion was that the plant should l
have been shut down
= Review of a 1984 memorandum appears to
have violated Technical Specifications Section
3.3.C.3
= Apparent contradiction between 3.3.C.3 and
4.3.C.1
= The apparent contradiction appears to have
contributed to the failure to meet Technical
Specifications during the 1984 refuel outage
.. . -. .- . .
!
.
'
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i
;
REVIEW OF-
MANAGEMENT EXPECTATIONS
i
= Plant management was aware of As-Left
'
method for determining Control Rod
Operability
= Focus was on core wide average, not 2 x 2
= Plant management was aware of the change in
As-Left vs As-Found philosophy
'
l
= Plant management was briefed by R/CE and l
expectations were that 4/6/93 scram time j
would meet Tech Spec limits )
-
!
= YNSD Nuclear Department was- asked to
evaluate slow scram times to the Safety
Analysis
. _ - _
.
-
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.
. c;
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:
,
SIGNIFICANT CORRECTIVFs ACTION REPORT
TASK TEAM #3
= Root Cause
o The cause of both the PRO issue and the As-
Left vs As-Found interpretation is one of ;
personnel error, misinterpretation of I
information l
= Contributing Causes, Similar Events and Other
Problems
o The failure to identify, nor implement
correction to the full scram time data based on
the non-conservative start-up delay time of the ;
test recorders was found to be attributed to l
inadequate QC
o Multiple retest of individual control rods prior ;
to data analysis has been an accepted practice
at Vermont Yankee. This approach to Control
Rod Surveillance testing is not described in
testing procedure OP 4424. This contributing
cause is attributed to an incomplete procedure.
- !
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. . .
.**O
.
SIGNIFICANT CORRECTIVE ACTION
REPORT RECOMMENDATIONS
,
= Prohibit the use of the 30-pen recorders for full scram data
collection ;
= Tech Spec LCO 3.3.C.3 applies to core wide average and 2 x
2 array scram time
'
= Procedure OP 4424 should require explicit review of LCO
3.3.C.3 and 3.3.F
= Specific criteria shall be established for the use of As-Found
vs As-Left testing criteria
= Establish specific procedures for surveillance testing and
operability testing post refueling outage
= Establish specific guidelines and expectations for performance
trending
= Improve scram time data record keeping
= Re-Evaluate Technical Specifications Section 3.3.C and 4.3.C
= Train Vermont Yankee personnel on the various issues
identified in the CAR
= All departments to evaluate their surveillance philosophy (As-
Found vs As-Left)
= Multiple follow-up recommendations were also made to revisit
the correction actions for effectiveness
'..;*..
, , , _
!
.
PERFORMANCE REVIEW COMMITTEE
O PURPOSE
O METHODS l
l
= SECURITY
LOR
'
= i
= EDG i
= FIRE SEALS !
= SCRAM TIMING :
=
QA REPORTS
= NRC REPORTS
= CONSULTANT REPORTS
.
O FINDINGS
O ACTIONS
:
!
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. .. . . ,
-
l
SUMMARY
,
i
SIGNIFICANT REGULATORY SIGNIFICANCE l
l
\
MINIMAL SAFETY SIGNIFICANCE ;
I
SELF IDENTIFIED
IMMEDIATE NOTIFICATION :
'
THOROUGH, AGGRESSIVE CORRECTIVE ACTIONS !
i
'
EVENT SPECIFIC
COMPANY GENERIC
.]
l
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-
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.
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SAFETY SIGNIFICANCE ;
;
i
,
i
OF l
i
!
-i
(
,
:
P
~
VERMONT YANKEE
~
i
i
i,
SCRAM PERFORMANCE
1
:
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_ _ _ _ .
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-
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.
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.
1 1
.
PRESENTATION OUTLINE
- Review of Tech. Spec. requirements
:
:
- Basis for Tech. Spec. requirements
i
Recap of scram performance
-
-
:
I
- Significance of scram performance on i
'
MCPR limits
1
.
j
-
Conclusions ,
e
.
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.
.-
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!
. !
-
)
,
.
TECH. SPEC. REQUIREMENTS i
1
.
f
- Average scram times !
(single rod testing) ;
i
l
,
- MST !
?
i
!
!
;
Drop-Out of % Inserted From Avg. Scram insertion l
Position Fully Withdrawn Time (sec) :
.. i
46 4.51 0.358 *
36 25.34 0.91 2 ;
26 46.18 1.468 i
06 87.84 2.686 - !
,
!
.!
- 67B :
,
i
!
Drop-Out of % Inserted From Avg. Scram insertion j
Position Fully Withdrawn Time (sec)
46 4.51 0.358 j
36 25.34 1.096
26 46.18 1.860 ;
06 87.84 3.419 .
l
i
)
!
;
1
.
l
l
. . . - - - . _ . . ., - .
'
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,
1
- :
i
TECH. SPEC. REQUIREMENTS (Continued)
:
f
:
- Average of three' fastest of all groups of l
four in 2 x 2 array l
1
l
l
l
- MST l
:
Drop-Out of % Inserted From Avg. Scram insertion
Position Fully Withdrawn Time (sec)
46 4.51 0.379
36 25.34 0.967
26 46.18 1.556
06 87.84 2.848 -
-
67B
Drop-Out of % inserted From Avg. Scram insertion
Position Fully Withdrawn _ Time (sec)
46 4.51 0.379
36 25.34 1.164
26 46.18 1.971
06 87.84 3.624
!
.
.
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-
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.
'
BASIS FOR TECH. SPEC. REQUIREMENT i
-
>
- For most transient scenarios ,
important for rods to insert
:
- Time response important only for " fast"
transients (20% - 70% insertion) l
,
!
- Turbine trip w/o bypass ;
l
:
'
- Generator load rejection -
, l
!
.
.
- Rapid MSIV closure
.
a
- Results from " fast" transients establish 1
MCPR limits for cycle exposures > EOFPL .
4 - 1000' MWD /ST (all rods out)-
:
;
- Scram times associated with fast
transients are not a concern at earlier
exposures (some rod insertion)
'
'
.- ..
'
'
4
l.
-
i
!
i
1
BASIS FOR TECH. SPEC. !
REQUIREMENT (Continued) l
l
,
- Average scram time
- Assumed in MCPR limit 4 determination for
fast transients i
1
- 2 x 2 Scram Time l
I
- Assures local scram performance does
not deviate significantly from average i
!
- Assures assumption on core average ,
scram reactivity is maintained l
l
.- .. - . . .. .-
.,
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., -
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.
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:
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:
i
i.
RECAP OF SCRAM PERFORMANCE l
l
.
q
t
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i
- Notch 46 (4.51%) only position 1
Tech. Spec. exceeded ;
!
'
!
!
Average
'
-
;
;
-
~
. -i,
-
Max deviation i
.011 sec at notch 46 (.369 vs. 358) ]
l
!
!
l
- 2 x 2 Array l
!
!
!
!
- - Max single deviation
.039 sec at notch 46 (.418 vs. 379)
.
5
I
f
i
- -
- - . . _ . . __ _ . _ . . . - - - . . . . _ _ . . , _ _ , . .
!
_ . . . . _ _
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-
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:
SIGNIFICANCE OF SCRAM PERFORMANCE
ON MCPR LIMITS-
-
i
)
- Evaluation used NRC approved analytical
methods for fast transients j
:
;
- Turbine trip w/o bypass was evaluated by !
modifying scram curve at 46 notch j
position l
'
MCPR performance was quantified for
'
.
insertion time delays at notch 46 up to .50
seconds
.4
l
4 !
!
.
I
. . .
. . .- _ -_ . - _ . . - . - - . .J
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SCRAM RESPONSE
67B SCRAM SPEED
25
%
$
-
00 q .
D O.5 NDs *
..
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MCPR RESULTS FOR TURBINE TRIP l
-
i
I
-
t
MCPR
:
I
Insertion To j
Notch 46 MST 67B
l
I
t
Tech. Spec. .358 1.21 1.24 l
l
Modified Curve 0.40 1.21 1.24
"
(46 Notch) .
.
0.50 1.22 1.26
.,
Max difference of .02 for 0.50 sec is offset.by
'
initial power.
. Analysis performed at 104.5% of rated
.
. 2.5% power is worth .02 ACPR ;
.
e
. . - - - . .
_
:; .. -
- a. .
t
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!
CONCLUSION .
l
l
i
!
!
- Delay in rod insertion to notch '46 from ;
.358 sec >.500 insignificant impact on
'
MCPR or peak system pressure
i
i
- Insertion time limits for positions between )
20% -
70% are important for fast i
transients near EOFPL exposures i
!
i
4
- Consistent with fact that some plants do >
not have T.S. at notch 46 position (4.5%)
,
!
- -
?
}}