IR 05000528/1996009
Text
January 22, 1996
SUBJECT:
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE (SALP)
(NRC INSPECTION REPORT No. 50-335/95-99; 50-389/95-99)
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Dear Mr. Goldberg:
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The Systematic Assessment of Licensee Performance (SALP) for the period
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January 2.1994 through January 6,1996, has been completed for St. Lucia.
The results of the assessment are documented in the enclosed SALP report which will be discussed with you at a public meeting at the St. Lucie Site on
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l February 22,1996, at 1:00 pm. At the meeting, you should be prepared to discuss our assessment and any initiatives that address our concerns and challenges identified in the SALP report.
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Overall the performance of the St. Lucie Plant was assessed as good over the performance period.
The overall perfomance was mixed with the response to '
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transient events being very good but routine activities performed at a
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somewhat lower level of performance. The engineering and plant support functional areas sustained the previously assessed ratings of superior performance, but there is a disturbieg perfomance trend in the functional areas of operations and maintenance. Perfomance declined significantly in these areas from superior ratings that had been sustained over several past performance periods to a level of good performance.
There is a concern that the long period of superior perfomance may have led to a pervasive complacent environment that is tolerant of equipment issues and a lack of discipline in adhering to procedures. There is evidence that the decline in human performance may be aggravated by inadequacies in the quality of the procedures themselves. Another contributor appears to be acceptance of a lower standard of performance by a significant part of the organization.
A further concern is the degree to which the performance declined before it was detected by the organization's self-assessment programs.
There is a clear
indication that these programs were not effective in identifying the trends early.
It is too early to evaluate the effectiveness of the extensive corrective actions that were instituted in the very late part of the
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assessment period, but it is clear they must be aggressively pursued to terminate the negative trend in performance.
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In accordance with Section 2.790 of the.NRC's " Rules of Practice," a copy of this letter and its enclosure will be placed in the NRC Public Document Room.
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Should you have any questions or comments, I would be pleased to discuss thes
with you.
Sincerely,
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w/
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Stewart D. Ebneter
Ragional Administrator
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Enclosure: As stated
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cc w/ encl:
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D. A. Sager, Vice President
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St. Lucie Nuclear Plant
P. O. Box 128 Ft. Pierce, FL 34954-0128 H. N. Paduano, Manager Licensing and Special Programs Florida Power and Light Company P. O. Box 14000 Juno 8each, FL 33408-0420 J. Scarola, Plant General Manager St. Lucie Nuclear Plant
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P. O. Box 128 Ft. Pierce, FL 34954 0128 Robert E. Dawson, Plant Licensing Manager St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce, FL 34954-0218 J. R. Newman, Esq.
Morgan, Lewis & Bockius 1800 M Street, NW Washington, D. C.
20036 John T. Butler, Esq.
Steel, Hector and Davis 4000 Southeast Financial Center Miami, FL 33131-2398 cc w/enci: Continued see page 3
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cc w/ enc 1: Continued Bill Passetti Office of Radiation Control Dept of Health and Rehab. Serv.
1317 Winewood Boulevard
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Tallahassee, FL 32399-0700
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l Jack Shreve, Public Counsel
Office of the Public Counsel
c/o The Florida Legislature 111 West Madison Avenue, Room 812
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Tallahassee, FL 32399-1400 Joe Myers, Director Division of Emergency Preparedness Department of Community Affairs 2740 Centerview Drive Tallahassee, FL 32399-2100 Thomas R. L. Kind'ed, County Administrator
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r St. Lucie County
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2300 Virginia Avenue Ft. Pierce, FL 34982 l
Charles 8. Brinkman Washington Nuclear Operations A88 Combustion Engineering, Inc.
12300 Twinbrook Parkway, Suite 3300 Rockville, MD 20852
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50-335: 50-389
JANUARY 2. 1994 - JANUARY 6. 1996 j
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marraensam
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The SALP Board convened on January 18, 1996, to assess the nuclear i
safety perfomance of St. Lucie Units I and 2 for the period of January 2, 1994, through January 6, 1996.
The Board Meeting was
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j conducted pursuant to NRC Management Directive 8.6, " Systematic Assessment of Licensee Performance." Board members were Ellis W.
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Marschoff (Chairperson), Director, Division of Reactor Projects, Region II (RII); Johns P. Jaudon, Deputy Director, Division of Reac. tor Safety, RII; and David B. Matthews, Director, Project Directorate II-1,
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Office of Nuclear Reactor Regulation.
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The performance category ratings and the assessment functional areas jl
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" Systematic Assessment of Licensee Performance (SALP)."
used below are defined and described in NRC Management Directive 8.6,
l II.
PERFORMANCE ANALYSIS - PLANT OPERATIONS l
i This functional area assesses the control and execution of activities
directly related to operating the plant.
It includes activities such as plant startup, power operation, plant shutdown, and response to
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1 Overall performance in the operations area has declined from its previous superior level to an overall rating of good.
The plant has
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been operated safely, although there has been an increase in the number
of operational events. This increase is attributable to the following:
weaknesses in operator performance, the acceptance of long standing
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deficiencies in plant equipment, management expectations not effectively communicated to personnel and enforced, weaknesses in procedural
adequacy and adherence, and the impkmentation and adequacy of j
corrective actions.
Quality Assurance activities associated with
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Operations remained strong and effective in identifying areas for l
improvement.
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Operator performance during the period has, overall, been good, and
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continued to be strong during unusual plant events or evolutions.
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Operators showed alert and proper response to ten reactor trips, reflecting well upon the licensee's training program and individual
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capabilities.
Similarly, operator performance during twelve observed
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startups and seven monitored entries into reduced inventory conditions were typified by excellent command and control and thorough operator
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knowledge.
However, operator performance during less demanding or less i
focused evolutions showed weaknesses in procedural adherence, the i
identification and correction of deficiencies, and attention to detail.
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s Of particular concern, procedural adherence and adequacy issues resulted
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l in, or contributed to, an increase in the number and severity of
operational events. The lack of overall quality in plant procedures was
underscored by the shear velume of procedural changes required when a
policy of verbatim compliance was adopted.
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The ability of Operations to identify and correct problems in a meaner
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i sufficient to prevent recurrence was also of concern. This issue was
compounded by identified weaknesses in communications across i
organizational interfaces, in that failures in informal communications l
were not compensated for by prograssiatic methods.
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Finally, operator attention to detail has declined during this SALP i
period. Given that issues of procedural inadequacies existed, the importance of attention to detail by operators was amplified, in that it i
represents an important barrier to failures.
The decline in attention j
to details was indicative of an onset of complacency through the SALP
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period, a trend which operations management failed to identify and remedy in a timely manner.
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The Plant Operations area is rated Category 2.
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l III.
PERFORNANCE ANALYSIS - NAINTENANCE i
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i This functional area assesses licensee activities in the areas of testing and maintaining plant structures, systems, and components.
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Activities assessed include preventive, predictive, and corrective
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maintenance, as well as surveillance, post-modification, and post-i maintenance testing.
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j overall performance in the maintenance area declined from its previous superior level to an overall rating of good.
Maintenance provided
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generally effective support for plant operations on a day-to-day basis.
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However, there were problems with equipment that adversely affected l
overall plant performance and provided unnecessary challenges to
operations.
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l Significant problems related to maintenance were manifested by an I
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operability issue with pressurizer power-operated relief valves, reactor l
coolant pumps seal failures, and inadequate post-maintenance test; determinations. There were also procedural difficulties encountered,
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especially in surveillance and preventive maintenance procedures. These i
issues had been present but unrecognized previously, and the licensee's remedial actions included an attempt to utilize a " verbatim compliance" approach.
However, the older procedures were not written to a level of i
detail' that would support this methodology, and the plant rank and file
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were not well oriented in the concept of procedural adherence; a
j therefore, the use of verbatim compliance did not resolve the problems i
emanating from weak procedures.
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50-335; 50-389
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JANUARY 2. 1994 - JANUARY 6. 1996
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BACK8ROUND c
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The SALP Board convened on January 18, 1996, to assess the nuclear
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safety performance of St. Lucie Units 1 and 2 for the period of
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January 2, 1994, through January 6, 1996. The Board Meeting was I
conducted pursuant to NRC Management Directive 8.6, " Systematic j
Assessment of Licensee Performance." Board members were Ellis W.
Marschoff (Chairperson), Director, Division of Reactor Projects,
i Region II (RII); Johns P. Jaudon, Deputy Director. Division of Reactor l
Safety, RII; and David B. Matthews, Director, Project Directorate II-1, Office of Nuclear Reactor Regulation.
!
The performance category ratings and the assessment functional areas l
used below are defined and described in NRC Management Directive 8.6,
'
j
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" Systematic Assessment of Licensee Performance (SALP)."
l II.
PERFORNANCE ANALYSIS'- PLANT OPERATIONS This functional area assesses the control and execution of activities directly related to operating the plant.
It includes activities such as
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plant startup, power operation, plant shutdown, and response to transients.
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overall performance in the operations area has declined from its j
previous superior level to an overall rating of good. The plant has been operated safely, although there has been an increase in the number i
of operational events. This increase is attributable to the following:
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weaknesses in operator performance, the acceptance of long standing
deficiencies in plant equipment, management expectations not effectively l
communicated to personnel and enforced, weaknesses in procedural j
adequacy and adherence, and the implementation and adequacy of
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corrective actions.
Quality Assurance activities associated with Operations remained strong and effective in identifying areas for
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l improvement.
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Operator performance during the period has, overall, been good, and
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continued to be strong during unusual plant events or evolutions.
)
Operators showed alert and proper response to ten reactor trips,
reflecting well upon the licensee's training program and individual s
j capabilities.
Similarly, operator performance during twelve observed startups and seven monitored entries into reduced inventory conditions
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were typified by excellent command and control and thorough operator knowledge.
However, operator performance during less demanding or less focused evolutions showed weaknesses in procedural adherence, the identification and correction of deficiencies, and attention to detail.
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l Of particular concern, procedural adherence and adequacy issues resulted
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in, or contributed to, an increase in the number and severity of
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operational events. The lack of overall quality in plant procedures was
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underscored by the shear volume of procedural changes required when a policy of verbatim compliance was adopted.
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I The ability of Operations to identify and correct problems in a manner
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sufficient to prevent recurrence was also of concern. This issue was
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compounded by identified weaknesses in communications across organizational interfaces, in that failures in informi consnunications were not compensated for by progransnatic methods.
Finally, operator attention to detail has declined during this SALP period. Given that issues of procedural inadequacies existed, the importance of. attention to detail by operators was amplified, in that it represents an important barrier to failures. The decline in attention to details was indicative of an onset of complacency through the SALP period, a trend which operations management failed to identify and remedy in a timely manner.
The Plant Operations area is rated Category 2.
III.
PERFORNANCE ANALYSIS - NAINTENANCE This functional area assesses licensee activities in the areas of
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testing and maintaining plant structures, systems, and components.
Activities assessed include preventive, predictive, and corrective maintenance, as well as surveillance, post-modification, and post-maintenance testing.
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Overall performance in the maintenance area declined from its previous superior level to an overall rating of good. Maintenance provided generally effective support for plant operations on a day-to-day basis.
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However, there were problems with equipment that adversely affected
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overall plant performance and provided unnecessary challenges to operations.
Significant problems related to maintenance were manifested by an operability issue with pressurizer power-operated relief valves, reactor
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coolant pumps seal failures, and inadequate post-maintenance test determinations. There were also procedural difficulties encountered, especially in surveillance and preventive maintenance procedures.
These l
issues had been present but unrecognized previously, and the licensee's remedial actions included an attempt to utilize a " verbatim compliance" approach.
However, the older procedures were not written to a level of detail that would support this methodology, and the plant rank and file were not well oriented in the concept of procedural adherence; therefore, the use of verbatim compliance did not resolve the problems emanating from weak procedures.
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Management of the maintenance area changed during this assessment period, and by the end of the assessment period, the new management
appeared to be providing the leadership necessary to reverse the observed negative trends.
In the area of pr6cedures, the new management
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team instituted a dual approach of correcting the procedures and i
training the personnel to use them which has seen some preliminary
successes.
i The'surve111ance program was implemented satisfactorily, but the procedural problems discussed above kept it from rising to the superior i
j level. Corrective maintenance was performed acceptably and generally had strong management involvement.
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In addition to the apparent strength of the new management team, the predictive maintenance group was considered a strength. The group was
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adept at vibration analysis, thermography, and lubrication analysis.
The predictive maintenance group had strong and positive interactions with the operations and maintenance programs and, furnishing early
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warning of incipient equipment failures, and long-term degradation of important components.
Licensee preparations to implement the new maintenance rule were successful in identifying equipment such as the radiation monitoring system and the emergency diesel generators which were not performing to the licensee's expectations.
The Maintenance area is rated Category 2.
IV.
PERFORNANCE ANALYSIS - ENGINEERING This functional area assesses activities associated with the design of plant modifications and engineering support for operations, maintenance, surveillance, and licensing activities.
The overall performance in the Engineering area remained superior.
The strength of the engineering group was shown in the area of design and installation support. This was manifested by a number of well engineered and implemented plant modifications.
In the area of design control and maintenance of the current licensing' basis, the engineering
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organization typically performed well with occasional weaknesses.
The plant's operations were supported successfully throughout the assessment period. Of particular note was the design and installation on Unit 2 of the condenser tube cleaning system.
In addition, the licensee has undertaken several initiatives to reduce the number of jumper / lifted leads, eliminate operator work-arounds, reduce the number of old work orders, and to improve the performance of contractors. The fuel vendor independence program will result in better control of core i
design, improved support for the plant and enhanced fuel utilization.
The support of maintenance activities remain 4d strong. The 45th Street Laboratory provided good support with componAnt specialists'along with
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effective nondestructive examination services.
A comprehensive program i
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of monitoring Alloy 600/690 applications focused on the pressurizer, j
i reactor vessel and loop piping penetrations. The recently implemented
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maintenance specification program should result in effective maintenance I
support, efficient engineering, and enhanced plant safety.
In light of
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I the weaknesses discussed in the Maintenance section, the support of
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maintenance activities by engineering is an area where improvements
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could be achieved.
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l Throughout the assessment period, licensing submittals have been
consistently of high quality, reflecting sound engineering judgment and
appropriate attention to detail.
Safety evaluations demonstrated the
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licensee's commitment to safety and compliance with regulations.
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l The Engineering area is rated Category 1.
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l V.
PERFORMANCE ANALYSIS - PLANT SUPPORT i
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This functional area addresses radiological controls, radioactive
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effluents, chemistry, emergency preparedness, security, fire protection, i
and housekeeping controls.
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l The overall performance in the Plant Support area has remained superior.
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i The radiation protection program received strong management support.
j The accumulated dose goal was met for the first year of the assessment I
period but not for the second year. This was the result of the j
maintenance problems and the resulting increased outage time. The
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radiation protection organization continued to implement strong
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i initiatives in the "as low as reasonably achievable" (ALARA) program l
through the use of remote monitoring of potentially high radiological i
dose work and the introduction of electronic dosimetry. Management involvement and support was evidenced by the small amount of surface
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area contamination, a significant reduction in the volume of solid l
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waste, and the readiness of the post accident sampling system. Training and self-assessments were found to be effective.
Thus, the combination of management support and an innovative health physics organization
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Security maintained an excellent level of performance during a staff
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reduction of the guard force and the introduction of biometrics.
l Measures used included effective training, which included the use of a
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combat firing range and good self-assessments.
Changes to the security l
plan were both appropriate and made in a timely manner.
However, there i
were some performance problems such as a repeat instance of failure to compensate in a timely manner for a computer failure; this suggested a
j problem with the effectiveness of corrective action from a previous event.
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In the fire protection area, combustible control was effective and the fire brigade performed well during drills and during an actual event.
L However, observation of surveillance testing of the fire protection
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systems revealed weak procedures, poor attention to detail, as well as
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minor past errors that had gone uncorrected. On br. lance, procedural and
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surveillance problems detracted from the otherwise excellent level of performance in the fire protection area.
In the emergency preparedness area, the full participation exercise conducted in 1994 was successful, and appropriate emergency classifications were made. Overall exercise performance was rated as good. The status of equipment and supplies needed to support emergency preparedness was found to be adequate. The emergency preparedness program maintained a good state of readiness for event response.
The Plant Support area is rated Category 1.
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SITE INTEGRATION MATRIX BY DATE St. Lucie SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSE ICOMMENTS
\\ 8!9/96 EMERG IR 96-14 L
O M
NOUE declared due to RCS leakage in excess Charging pump packing leakage (pending)
of I gpm unidentified.
identified as source of leak.
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N /3/96 VIO IR 96-11 N
E M
Prelubrication of valves prior to surveillance Procedure which required prelube
(pending)
asting in 1995 resolved as being a violation of had not been considered for
.0CFR50 Appendix B caiterion XI potential effects on stroke time.
8/3/96 NCV IR 96-11 N
M Review of outage freeze seals indicated that one Stop work order by management (pending)
freeze seal had been left unattended for for cleanup of the Unit 1 pipe tunnel approximately one hour.
resulted in directing freeze seal watch to another area to make 8/3/96 OTHER IR 96-11 N
M E
Licensee's activities regarding maintenance of (pending)
tod control system were adequate.
'% 8/3/96 NCV IR 96-11 L
O QA audit discovered that coneclive action Rush to close out STARS (old (pending)
documents had been closed will out being corrective action document) when forwarded to onginator for appro tal (as required CRs (new corrective action by procedure). NRC identified that personnel document) were instituted.
without signatute authority were closing documents
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/30/96 OTHER 1R 96-11 L
O M
3 of 4 Unit I linear Ni channels found miswired.
Drawing errors - discrepancy (pending)
with the detectors' upper chambers feeding the between vendor technical manuals lower Ni drawer inputs and vice-versa. Result and controlwiring diagrams was 3 channels for which axial shape index was generated for the installation of the in error.
new Unit 1 Ni drawers.
FROM: 8/1/95 TO: 8/23/96 Page 1 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRrM sEc ITEM APPARENT CAUSE I COMMENTS 7/20/96 NEG IR 96-11 L
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2 opearting charging pumps tripped when I&C failed to recognize that reactor (pending)
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maintenance induced an erroneous level signal regulating system would be into reactor regulating system. Letdown isolated affected by their activities.
by operators. Upon reinitiating letdown, minor waterhammer event occurred
/20/96 POS IR 96-11 N
M O
Post-outage walkdown of Unit 1 containment
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(pending)
indicated excellent cleanliness 7/18/96 OTHER 1R 96-11 L
E M
Unit 1 AFAS setpoints found nonconservative Failure to emp;oy as-buHt during review of recalibratiori activities.
elevations of condensate pots in the development of calibration criterla.
7/16/96 NEG IR 96-11 L
o 2C auxilliary feedwater ptunp tiipped on Operator error in not properly (pending)
overspeed during post-maintenance testing.
implementing cautions in a procedure
\\ 7/13/96 EMERG IR 96-11 L
O M
NOUE declared when 2C clear 0 ng pump check Check valve stuck open due to i
(pending)
valve stuck open, creating bypass flowpath from possibly generic effects of pulsating charging pumps to VCT. Operators timely in low tiow in a continuous service declaring event.
valve.
E Five examples of a possible ineakdov n in Lack of appropriate pre and post-96-236 configuration management controlidentified, installation review.
involving inaccuracies in procedures sind drawings dire to design changes M 7/12/96 WEAK IR 96-12 L
E Licensee veritcal slice inspection of EDG, HPSI.
Lack of proper configuration control and CCW systems revealed numeroits over time.
deficiencies in procedure, design dor ument and FSAR accuracy.
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FROM: 8/1/95 TO: 8/23/96 Page 2 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM sEc ITEP1 APPARENT CAUSEI COMMENTS M 7/9/96 STREN IR 96-11 N
O Two entries into reduced inventory made during (pending)
inspection period. Strong management involvement in scheduling around Hurricane Bertf a. Reduced inventory operations continues to brt a strength.
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M 7/8/96 POS IR 96-11 N
O M
Licensee preparations for Hurricane Bertha Hurricane forcasts showed storm (pending)
proactive and responsible.
missing area, but licensee prepared as though it would change course.
/6/96 VIO IR 96-09 N
M E
Review of testing activities foi continment blast Failure to property implement App.
darapers indicated that violations of 10 CFR 50 B and QA plan as they related to App. B and site procedures existed Two documenting as-found and as-left violations cited data. Additionally, multiple examples of failures to properly 7/6/96 POS IR 96-09 N
PS Review of RCP oil collection system.
System met description in FSAR and was in accordance with App R.
except as allowed by approved exemption.
7/5/96 POS IR 96-09 N
O Unit I reduced inventory preparations and Mid-Loop controls effective.
execution.
Licensee attention and management oversight excellent.
M 6/27/96 OTHER IR 96-09 L
O E
Site reorganization announced which would place almost all engineering functions (system engineering. STAS, test engineers) under Engineering. Also. Outage Management folded into a global work planning group under the Plant General Manager.
\\ 6/20/96 POS IR 96-09 L
M O
Loss of 3 Wide Range Nuclear Instrument Operators prompt and accurate in Channels on Unit 1 resulted in entering TS AS verifying shutdown margin for Nis.
requirements.
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FROM: 8/1/95 TO: 8/23/96 Page 3 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSE / COMMENTS
4 6/19/96 POS IR 96-09 N
O Unit i reduced inventory preparations and Controls were appropriate.
execution.
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N 6/13/96 POS IR 96-09 N
M Maintenance activities associated with Unit 1 Work conducted satisfactorily.
reactor head lift and Unit 2 feed reg valve work.
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\\ 6/13/96 VIO IR 96-09 N
M A review of overtime foi a one month period Failure of management to track the indicated that overtime guidelines were routinely use of overtime as specified in site exceeded without prior (or subsequent)
procedure. Procedure poorfy approval 56 examples cited for 5 individuals.
defined requirements. Personnel had varying understandings of M /8/96 POS iR 96-08 N
O 3 QA audits reviewed Broad in scope, appropriately focused, indicated an aggressive application of quality standards.
\\6/8/96 NEG IR 96-08 N
M Application of ladder and scattolding programs appears to be minimally compliant with licensee's self-imposed sequirements. Many scaffolds and ladders required caution tags or had not been removed promptly after use.
6/8/96 OTHER IR 96-08 N
M Review of maintenance backlog indicated that licensee had a plan for backlog reduction in place but has yet to meel goals
\\ 6/8/96 VIO IR 96-08 N
O M
Testing of 1 A and 1B EDGs following radiator l_ack of attention 10 detail by test replacement in each case included observations personnel.
of inoperable temperature indicators and a lack of cognizance of the conditions by test personnel. Violation cited for failing to comply
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with procedure.
FROM: 8/1/95 TO: 8/23/96 Page 4 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM sEC ITEM APPARENT CAUSEI COMMENTS
/8/96 POS IR 96-08 N
M Repair work for Unit 1 fuel transfer tube isolation Conducted satisfactorily valve.
h6/8/96 POS IR 96-08 N
E M
Unit 1 RWT tiner inspection.
Licensee satisfied committments to inspect fiberglass liner in RWT.
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Results sat 6/8/96 OTHER 1R 96-08 L
E Ongoing review by licensee nf UFSAR accuracy Failure to update FSAR over time identified approximately 150 items, ranging from and failure to review FSAR properly typographical errors 10 more sutestantive issues.
when preparing procedures.
N /8/96
STREN IR 96-08 N
E M
ISI activities for SG and reactor vessel eddy Examinations well-planned, current examinations reviewed performed and managed by very latented and knowledgable personnel
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6/8/96 POS IR 96-08 y
O 3 QA Audits reviewed Broad in scope, focused on weak areas. Agressive application of standa:ds evident in the number of findings cited 6/8/96 POS IR 96-08 n
PS Fire barrier inspections performed by the licensee were found to employ conservative criteria nad be detailed 6/6/96 VIO IR 96-12 N
E Four 10 CFR 50.59 issues identified One USQ, One case of interpretation error, EA-96-249 two failures to perform safety evals due to two of failing to employ system, failure to screen issues, and or:e licensee-one personnel error while identified failure in the screening process that performing screening.
was later caught in FRG review.
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FROM: 8/1/95 TO: 8/23/96 Page 5 of 26 23-Aug-96
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I SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSE ICOMMENTS Nr6/6/96 POS IR 96-08 s
O Unit 2 manually tripped due to high main Operators acted promptly and generator gas temperature due to failed correctly in tripping the unit. Post temperature control valve trip response of both plant and operators was good.
6/3/96 NEG IR 96-08 N
O Poor practice observed in spent fuel pool
"On deck" status was an effort to
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operations. Fuel assembhes were left hanging expedite reload. Operatorleaving
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in an "on deck" status while awaiting upender machine was due to inadequate availability. Also, operator left machine manpower-operator had to unattended with fuel hanging at least once per operate upender controls, which movement.
were mounted on wall.
M E
High temperature condition in Unit 2 :od control Failure of an air conditioner.96-236 cabinet room due to failure of an air conditioner Further review by licensee /NRC led to indications of rod control pioblems.
showed air conditioner was Indications later shown to be false. Also, high temporary equipment installed temp condition led to failure of a diverse turbine without design controls and room trip relay.
itself may have been constructed without seismic or appendix R reviews.
6/3/96 OTHER 1R 96-08 N
M EDG reliability calctitations indicate that EDG reliability is in keeping with SBO assumptions
\\ 6/3/96 OTHER 1R 96-08 L
O E
Unit 1 outage extended to July 19 due to New plugging criteria resulting from expansion of SG MRPC tube inspections.10 discussions with NRR on defect face-span indications identified to date.
characterization methodologies.
Projected tube plugging will exceed 25% limit.
PLAs submitted to NRR to allow plugging up to 30%.
6/2/96 LER L
O M
Non-safety related breaker alignments to Operators not aware that support Unit 1 outage resulted in loss of audible containment amplifier was going to count rate amplifier for containment. Audible be affected by lineup. Control counts lost in containment for approximately 5 room amplifier not affected.
minutes durin2 fuel movements.
FROM: 8/1/95 TO: 8/23/96 Page 6 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PmM sEc ITEM APPARENT CAUSEl COMMENTS
/ 6)i/96 POS IR 96-08 N
E CNRB activities surrounding PLA reviews in support of SG tube plugging issues were probing and competeni.
\\5/31/96 OTHER IR 96-08 S
O M
Blown fuse resulted in closure of att Unit 2 MSR Moisture found in a junction box temperature control valves, resulting in a 5%
following heavy rain.
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load rejection.
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5/29/96 LER
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L
M Suspected loss of approximately 1200 condenser tube cleaning balls reported to
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state /NRC. Balls were found unaccounted for during an inventory balance. Suspected that balls were released to Atlantic Ocean.
5/24/96 POS IR 96-08 S
G M
Rod control system failure sesulted in inability to Operators conservative in move (electrically) 4 CEAs. Operators interpreting TS, plant organizations conservatively interpreted TS to require provided timely support with lists of shutdown in this instance. Situation complicated equipment which would be l
by an out of service Startup Transformer.
inoperable when the main generator was tripped.
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\\ 5/22/96
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L M
V 2483 (SDC Suction Reliel) selpoint found out-Root cause is yet to be established.
OTHER of-spec high, rendering valve incapable of pertorming its intended function.
l 5/t 7/96 NCV IR 96-08 N
M Failure to verify the currency of procedure in use Cognitive persennel error at jobsite
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5/17/96 NCV IR 96-08 N
M Failure to satisfy requirements for Cognitive error.
" independence' on the part of independent verifier.
FROM: 8/1/95 TO: 8/23/96 Page 7 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM SEc ITEM APPARENT CAUSEI COMMENTS 5115/96 NEG IR 96-08 N
PS Observations of radiation worker practices revealed inconsistencies in the application of site practices (e g. wearing of dosimetry, donning / doffing PCs).
s 5/14/96 POS IR 96-08 N
O Fuel movements during Unit 1 core offload and
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reload performed well.
N 5/14/96 NCV IR 96-08 L
o Fuel movement begun willi only one of two Poor communication between required wide range Ni channels operable.
control room operatcrs performing Condition identified and fuel movement secured surveillance testing on the subject after approximately 1 It of travel.
channel and the refueling center.
Compounded by operators not 5/12/96 VIO IR 96-12. EA L
O E
Initial temperature (and othes) conditions Programmatic weakness in Plant 96-236 specified in Unit 1 spent fuel pool heat load Change / Modification process.
calculation (to support total core ollload) was not factored into procedures Additional examples of design control failures cited 5/11/96 POS IR 96-06 N
M Observations of Pressurizer Code Safety Valve No deficiencies noted testing and repair 5/11/96 POS IR 96-06 N
O 2 clearances audited, both conect M 5/11/96 POS IR 96-06 N
M E
Polar crane load rating calc and Unit 1 head lift.
No deficiencies identified.
.
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SFA DATE TYPE SOURCE ID PRIM SEc ITEM APPARENT CAUSEI COMMENTS 5/11/96 POS IR 96-06 N
M MSSV testing - Unit 1 Outage Review of test data and methodology sat.
MS/11/96 POS IR 96-06 N
M Observations of maintenance activities in No deficencies noted.
containment (Unit 1 outage) involving valve
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packing replacement and modification.
5/t 1/96 POS IR 96-06 N
M Pieparations for Unit t reactor vesselISI.
In accordance with requirements and showed good outage planning.
N 5/8/96 NCV IR 96-06 N
M t_ack of verified (controlled) copy of procedure Failure of Maintenance workers to identified at CCW heat exchanger jobsite.
property verify procedures prior to beginning work.
5/7/96 VIO IR 96-06 N
PS Programmatic weaknesses identified in Fire 11/62 members had expired Protection Program for medical qualification of medicals. 9/65 with expired fire brigade members.
medicals worked 60 shifts in April.
2 Fire Team leaders not listed on roster worked 31 shifts in April.1 Fire Team member with expired medical and not on roster worked 1 shift.
.
$ 5/5/96 POS IR 96-06 N
O Reduced inventoiy operations conducted well by operators.
5/3/96 WEAK IR 96-05 N
PS Response letters prepared by Speakout to concemed employees did not contain adeos: ate feedback to concemed employees.
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SFA DATE TYPE SOURCE ID PRIM SEc ITEM APPARENT CAUSE / COMMENTS k5/3/96 WEAK IR 96-05 N
PS Investigative techniques of Speakout program No requirement to develop plans to have the potential to reveal, inadvertently, of ensure identity is protected.
concerned employees.
5/3/96 POS IR 96 05 N
PS Inspection of FPL Speakout program.
Program etlective in handling and resolving employee safety concems.
5/3/96 WEAK IR 96-05 N
PS Speakout program corrective actions were not Lack of procedural specificity.
tracked through implementation as required.
\\ 5/2/96 POS IR 96-06 N
O Good performance by operators and test personnel during integrated safeguards testing on Unit 1.1B EDG output t>reaker failed to close during first test. Operators handled
,
situation well.
4/29/96 NCV IR 96-06 N
E Failure to promptly stocument a nonconformance. Engineering f ailed to initiate CR upon discovery that approx. 35 S-R instruments on each unit might have been calibrated at temperatures lower than those assumed in setpoint cales.
.
4/28/96 POS IR 96-06 y
O Operators' performed well dunng Unit 1 RFO Communicaticas formal, excellent shutdown.
use of annimciator response procedure. Performance of rod drop time testing a noteworthy initiative.
FROM: 8/1/95 TO: 8/23/96 Page 10 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSEI COMMENTS yM22/96 NCV IR 96-06 L
O E
Unauthorized breech in RAB fire barrier during Operators showed good attention to installation of CCW piping modification.
detail in identifying two holes bored in wall. Engineering failed to account for the effects of modification installation in fire rated assembly, as required by procedure for engineering packages.
.
\\ 4/20/96 OTHER IR 96-06
O Unit 2 downpowered and taken off-line due to Blockage in auto-stop oil line orifice low pressure condition in auto-stop oil.
which prevented buildup of auto-Operators observed to contiol evolution well.
stop oil pressure. Only negative
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aspect was crowding of control panels by control room SROs during portions of evolution.
\\ 4/18/96 NCV IR 96-06 I.
E M
Missing orif ce plate identified in Unit 1 ICW Either f ailure to install orifice during system during licensee field walkdowns.
plant modification, ar failure to reinstall orifice fo!!owing maintenance.
4/14/96 WEAK IR 96-06 N
O E
ICW system walkdown Results indicate weaknesses in procedure-to-procedure agreement, labeling, and surveillance i
.
requirements, in addition to configuration controlissues disussed separately.
\\ 4/t 4/96 WEAK IR 96-06 N
O E
Configuration Control issues resulted from ESF Walksdowns of both units' CS, ICW system walkdowns and IA systems indicate programmatic failures in incorporating design changes into drawings, the FSAR and operating procedures. Unresolved item tracking expansion ofinspection scope to include instrumentation setpoints.
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SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSEI COMMENTS M 4/13/06 POS IR 96-06 N
E Engineering response to failure of HVS-4A Procurement engineering effective motor considered good.
In locating and dedicating replacement motor and in identifying and resolving incorrect bearing rating calc for new motor.
Minor problem existed in that new starting current profile was not adequately treated.
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4/10/96 OTHER IR 96-300 N
O 4 of 4 SRO candidates passed SRO
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examination. In 3 of the cases, perfo mance was mar 0inally satisfactory No generic candidate weaknesses i 9 niified.
4/10/96 POS IR 96-300 N
O Simulator perfotmed welllinoughout SRO qualification testing 4/9/96 NEG S
E CIRC water piping through. wall leaks observed Galvanic corrosion due to in two water boxes' outlets inadequale cathodic protection following installation of stainless steel Tapparogge components.
4/4/96 OTHER tR 96-06 L
O Interim Operations Manager (11 Johnson)
named
\\3/31/06 EMERG IR 96-06 N
O PS Operator response to RCS leakage through Operators effective at CVCS system.
identifying / isolating leak; however, Unusual Event call was non-conservative in that the callwas
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delayed to allow a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> RCS inventory balance to be calc'd when otherinformation indicated that excessive leakage existed.
FROM: 8/1/95 TO: 8/23/96 Page 12 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSEI COMMENTS M 3/30/96 NEG IR 96-04 N
M Control of maintenance procedures was such Programmatic vunerability.
that an outdated procedures could, programmatically, wind up in the field da to their inclusion in previously prepared packages.
l.icensee corrective action adequate.
\\ 3/30/96 POS IR 96-04 N
M 10 mairenance activities obsesved durir.g
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inspection period. No significant deficiencies noted, j 3/30/96 OTHER IR 96-04 S
M Maintenance underwent major departmental reorganization. Selected supervisors'
qualifications found satisf actory per TS requirements.
3/30/96 POS IR 96-04 y
O Review of 5 clearances indicates better attention
/
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to detail than had been observed in past.
3/29/96 POS IR 96-04 N
O Operator requalification program found to be supporting management expectations for operations and covering timely and impottant topics.
,
\\ 3/27/96 VIO IR 96-04 N
O Operators failed to propeily tog boron dilution Management direction to operators evolutions. Globallog entry was made at the allowing globallog entries for beginning of the shift stating dilutions would be reactivity manipulations during made; however, procedure required each transient conditions (e g. uppower)
dilution to be logged.
which was not in accordance with Conduct of Operations procedure.
M 3/14/96 OTHER L
PS Management change. A. Desoiza (human resources manager) replaced by 1 ynn Morgan (from TP)
,
FROM: 8/1/95 TO: 8/23/96 Page 13 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM sEC ITEM APPARENT CAUSE1 COMMENTS 3/12/96 POS IR 96-04 S
O Licensee disposition for deficiency noted in 1 borollex panel (1op 15" missing) found satisfactory. FRG treatment of issue found appropriate.
[ 3/10/96 OTHER 1R 96-04 L
O Unit I downpowered to 97.5% due to hot leg Hot leg stratification.
stratification and flow swirl which resulted in
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higher than actual indicated reactor power.
3/7/96 NEG IR 96-04 N
O During MTC testing, inspector noted that boron Poor attention to detail.
,
concentration had been verified at 30 minute intervals, vice 15 minute intervals as called for in procedure.
k3/7/96 NEG IR 96-04 N
O Licensee failed to place a CEA which had been Operator oversight.
/
declared administratively inoperable in the equipment out-of-service log. CEA was operable per TS.
k 3/1/96 OTHER 1R 96-04 N
PS Licensee found to be utilizing ALARA tecimiques and making progress at reducing collective doses for staff.
3/1/96 OTHER L
O Management Changes - T. Plunkett succeeds G.
Goldberg, C. Wood replaces L. Rogers as manager of SCE, C. Marple seplaces C. Wood as Ops Supervisor.
3/1/96 OTHER 1R 96-04 y
ps Licensee found to be implementing adequate RP controls and monitoring individual exposures per code requirements.
FROM: 8/1/95 TO: 8/23/96 Page 14 of 26 23.Aug-96
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SFA DAtE TYPE SOURCE ID PRIM sEc ITEM APPMENT CAUSE I COMMENTS 3d/NI OTHER IR 96-04 N
PS Housekeeping in RABs generally good; however, equipment storage areas rund
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cluttered and untidy.
3/1/96 POS IR 96-04 N
PS Ongoing HP efforts to obtain accreditation of g,A FPL electronic dosimc ry program identified as a
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good example of department's technical capabilities.
3/ t/96 NCV IR 96-04 N
PS Inspection of Hot Tool Room identified several Attention to detailin foot storage tools which were either not painted purple (as and surveying.
required) or which slightly exceeded limits for contamination _
V 2/24/96 WEAK IR 96-04 s
O Procedura! weakness results in attempting to Procedure review weakness - lack
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synchronize main generator with grid with of verification that disconnect links generator disconnect links open.
were closed.
2/24/96 VIO IR 96-04 N
M Acceptance criteria specified for CEDM coil Failure of l&C System Supervisor resistances in PC/M package found varied and to adhere to test criteria unclear. Criteria were not properly applied and compounded by failure of l&C values outside of specifications were not management to identify obvious documented and resolved errors during post-work review.
2/24/96 VIO IR 96-04 L
PC O
Unit I containment radiation monitor found out-Failure to follow procedure on the of-service due to isolation valve which was part of HP personnel, compounded closed to support a grab sample prior to a by failure to identify condition by containment entry and not returned to the open operators during rounds.
position. Condition existed for 2 days, unknown Io licensee.
\\
N2/24/96 WEAK IR 96-04 N
M Maintenance practices for Steam Bypass and Poor preventive maintenance on Control System and Feedwater Regulating SCBC valve air lines and FRVs.
valves found weak in inspection following 2/22/96 Unit 1 trip.
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SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSEICOMMENTS EMERG IR 96-04 s
O Dropped CEA (due to S'CR failure) leads to TS-Equipment Failure
\\ 2/22/96 required shutdown and declaration of NOUE, Failure of air supply to FRV leads to operators tripping reactor from 26%. Good operator performance throughout.
M 2/22/96 VIO IR 96-04 N
O O
Operators found adding boric acid to VCT Procedures were put away to tidy without procedine in hand, as required by up control room prior to NRC senior conduct of operations piocedute Additional managers' tour prior to SALP example of EEA 96-040.
meeting.
2/17/96 POS IR 96-01 N
M Noted improvements in housekeeping and malcrial conditions.
M2/17/96 NEG IR96-01 N
M Freeze seal procedure lacked objective criteria Procedura' Weakness
/
defining when a freeze seal existed
.\\ 2/17/96 NCV IR 96-01, IR N
M PS Work on 1 A ECCS suction header through-wall Personnel work practices (workers 96-04 leak revealed streng FME, but poor HP work ignored RWP requirements)
practices observed regarding contamination control resulted in NCV.
2/17/96 WEAK IR 96-01 N
O E
Numerous deficiencies identified in instrument ProceduralInadequacy air system walkdowns, including drawings accuracy, ONOP adequacy, and annunciator response procedure accuracy.
b /17/96 NEG IR 96-01 L
M Weakness identified in l&C calibration ProceduralInadequacy
procedure -lack of detail provided for safety related calibrations.
FROM: 8/1/95 TO: 8/23/96 Page 16 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM sEC ITEM APPARENT CAUSE / COMMENTS N2/15/96 NEG IR 96-01 N
O M
Tours of ECCS rooms revealed several active Material Condition leaks. Licensee could not explain how (if) FSAR assumptions on ECCS leakage were satisfied.
Later review of FSAR indicated leakage within assumptions.
IR 96-02 N
PS Licensee made significant observation of E-Plan Licensee objectively questioning 2/7/96 POS
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execution - 2 practice drills were required prior overall state of readiness.
to graded exercise for management to be satisfied with performance Management determined that more frequent drills were required to ensure readiness.
.
2/7/96 NEG IR 96-02 N
PS Two areas for improvement identified in graded inconsistencies in the use of EP exercise - Need for management to become Florida Notification Message Form.
more involved in assuiing correctness of info Confusion existed between NLOs being provided in offsite notification forms and dispatched from OSC and Control need to refine C&C for damage control teams.
room for similar repair missions.
2/7/96 POS IR 96-02 N
PS Licensee's onsite emergency organization was found to be well-defined and generally effective at dealing with simulated emeigency during graded exercise.
2/7/96 POS IR 96-02 N
PS Communication among the licensee's emergency response facilities and emergency organization and emergency response organization and offsite authorities were good during graded exercise.
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'>t>ee
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emergency plans were adequate and that licensee was capable of implementing them.
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SFA DATE TYPE SOURCE ID PRIM sEC ITEM APPARENT CAUSE I COMMENTS 2/7/96 POS IR 96-02 N
PS Observations of licensee performance in CR, TSC, OSC, and EOF indicated good command and control, staff utilization and staff demeanor during graded exercise.
K 1/26/96 OTHER 1R 96-01 N
O Inspection of corrective actiori program revealed Corrective Actions timely action on the part of management, but
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weaknesses in plans for tracking progress on personnel performance and procedure quality improvement.
1/26/96 VIO IR 96-01 -
N O
Violation identified regarding temporary changes Procedure Control VIO 96-01-01 to procedure which changed intent and which were approved for use without prior FRG review.
1/22/96 VIO IR 96-03 -
L O
E Baron dilution event due to operator leaving Operator error, poor short term EA 96-040 control panel while dilution was in progress.
tumover, poor command and control Weak command and control, procedural adherence, and short-term tumover.
Additionally, OP for boration/ dilution not consistent with FSAR and no 50 59 performed.
1/7/96 N
O SALP CYCLE 12 BEGINS 1/5/96 NCV IR 95-22 -
N O
PS Several deficiencies in prodecure change Failure to Propenly implement
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NCV 95-22-process implementation identified. Expired or Procedures
cancelled TCs found in control rooms and hot shutdown panel.
FROM: 8/1/95 TO: 8/23/96 Page 18 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSE t COMMENTS 15/96 NEG IR 95-22 N
O Several procedural deficiencies and inadequate Procedure Review and calculational errors identified in reload physics Execution test procedure.
1/5/96 WEAK IR 95-22 L
O M
U2 manual RX trip on high generator H2 temp Temp Control Valve Failure due to failure of temp control valve. Operator
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awareness of RPS status post-trip poor.
Inspection of post-trip review (for current trip as well as past trips) indicated weaknesses in the rigor of post-trip reviews 1/5/96 VIO IR 96-04 L
O NLO failed to employ procedure when placing Failure to use procedure, failure to EDG fuel oil tank on recirculation for chemistry.
notify control room of evolution.
As a result, he improperly perinrmed the evolution by isolating the discharge of the EDGFO transfer pump, which resulted in an inoperable EDG.
12/27/95.NEG IR 95-22 S
O E
FRG meeting suffered / items deferred due to Lack of Attendance at FRG lack of OPS /Eng'g attendance at meeting.
Major issues at meeting affected OPS /Eng*g.
12/20/95 OTHER IR 95-22 S
M RX vessel flange inner 0-ring groove pitting Pitting - Localized Corrosion resulted in cooldown and head removal for repair.
12/9/95 OTHER IR 95-22 L
M 2A2 RCP seal pkg lower seal destaged due to Filling RCS Before Coupling RCP reverse pressure across seal.
12/5/95 WEAK IR 95-22 N
O M
' ESFAS cabinet doors found unlocked fol lowing Poor Logkeeping/ Attn to Detail maintenance work - l&C error. Log entries associated with work were not complete.
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DATE TYPE SOURCE ID PRIM SEC ITEM APPARENT CAUSE ICOMMENTS k 12/1/95 NEG IR 95-21 N
PS Rad siaey results unavailable for B hot leg Failure to Document RAD Survey work. Surveys performed but not documented.
12/1/95 NEC 1R 95-21 N
O Operators unable to effectively obtain l&C Inadequate Operator Training setpoints from computer after hard copies were
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removed from control room.
12/1/95 NEG IR 95-21 N
O
- Unit 2 procedures and valve deviation log used Valve Position Administrative to cycle Unit 1 cross connect valves.
Controls h 12/1/95 WEAK IR 95-21 N
O SDC procedure contained coniticting values for Procedural Weakness / Inadequate RX cavity level requirements. Procedure had Review been approved since emphasis on accuracy stressed.
,
12/1/95 WEAK IR 95-21 N
O CCW sample valve showed dualindication FTF Procedure without corrective action documentation initiated.
12/1/95 WEAK IR 95-21 N
O Clearance in place to isolate N2 from CST to Poor Corrective Actions facilitale pressure switch replacement for nine days without work order being written.
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12/1/95 NEG IR 95-21 N
O Recurrent non-valid alarms when starting fire FTF Procedure
A pumps were not documented as operator k
workarounds. Voltage dips associated with such
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starts were contributors to a trip previously.
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SFA DATE TYPE SOURCE ID PRIM SEc ITEM APPARENT CAUSE I COMMENTS N12/1/95 WEAK IR 95-21 N
O Followup to previous inspection findings Corrective Actions indicated a weakness in followthrough in addressing deficiencies.
12/1/95 NEG IR 95-21 N
O SDC Procedure required natural circ-related ProceduralInadequacy surveillance prior to establishing RCS pressure
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boundary. Natural circ not possible without pressurization.
11/27/95 VIO IR 95-21 -
L O
Missed RCS Boron sample surveillance -
Personnel Error VIO 95-21-03 Repeat from IR 95-18.
p M11/21/95 NCV IR 95-21 -
t O
Faihne to maintain Penetration Log.
FTF Procedure
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NCV 95-21-
.
N 11/21/95 OTHER 1R 95-21 S
O Light socket failure during lamp replacement Equipment Failure results in loss cooling to 1 A Main Transformer.
Unil downpower to -60%.
11/20/95 VIO IR 95-21 -
N O
Valve discovered Closed vice Locked Closed as FTF Procedure VIO 95-21-01 specified on Equipment Clearance Order.
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I 11/16/95 OTHER IR 95-21 S
O M
Unit 1 manually tripped when 18 MFRV locked Long-Standing Equipment Problem in 50% position. Root cause - degraded power supply, compounded by voltage dip on starting both station fire pumps.
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SFA DATE TYPE SOURCE ID PRIM sEC ITEM APPARENT CAUSE / COMMENTS 1i/11/95 VIO IR 95-21 -
N O
Tech. Spec. equipment not specified for IV on FTF Procedure VIO 95-21-02 Equiprnent Clearance Order.
N 11/6/95OTHER 1R 95-21 S
M Failure of EDG 2A relay sockets Potential Equipment Failure common mode failure.
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h 11/1/95 NCV IR 95-18 -
S M
ICI wiring error during RX head installation last Personnel Enor o
NCV 95-18-RFO.
10/19/95 NCV lR 95-18 -
O Missed shift CEA position indication surveillance. Personnel Error NCV 95-18-
10/18/95 NCV IR 95-18 -
L O
Missed RCS Boron sample sinveillance.
Personnel Error NCV 95-18-
0/17/95 WEAK IR 95-18 S
O Lack of attention to task resulted in overfilling Personnel Error RCB lower cavity during flood up.
10/12/95 VIO IR 95-18 -
S E
Inserting CIAS signal during safeguards test Design Error VIO 95-18-04 shifted EDG 2A to isochronous mode while EDG paralleled with offsite power.
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's SFA DATE TYPE SOURCE ID PRIM sEc ITEM APPARENT CAUSEI COMMENTS 15/9/95 LER LER 95-S02 L
PS Potential route for unauthorized access to Personnel Error protected area, CW water piping 10/7/95 VIO IR 95-18 -
N O
Did not enter bypass key position in deviation Failure to Follow Procedures VIO 95-18-01 log.
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N10/5/95OTHER IR 95-18 S
M DG 18 developed FO leak at threaded Equipment Failure connection during surveillance run.
9/30/95 VIO IR 95-18 -
N O
Did not enter bypass key position in deviation Failure to Follow Procedures VIO 95-18-02 109 N 9/28/95 OTHER 1R 95-18 S
E Leaking PZR SVs extended forced outage -
Equipment Failure problems with tailpipe alignment.
\\ 9/20/95 OTHER 1R 95-18 S
M EDG 1 A/1B govemor control problems resulted Equipment Failure in load oscillations.
\\ 9/15/95 VIO IR 95-18 -
s O
M Main / Ops did not provide clearance for work on Failure to Follow Procedures VIO 95-18-03 condenser waterbox cover. When cover pulled closed, severed :vorker's finger.
9/10/95 AnIAK LER U1/U2 L
PS Security failed to take correct compensatory Failure to Follow Procedure 95-S01 action on computer failure.
FROM: c..- 3 TO: 8/23/96 Page 23 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM SEC ITEM APPARENT CAUSEICOMMENTS 9/10/95 WEAK IR 95-18 S
O SG blowdown sent to incorrect system on RAB Failure to Use Correct Procedrue roof. Operator used wrong procedure. When
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identified did not back out of procedure correctly.
9/9/95 WEAK IR 95-15 S
M Leak on SV 1201 flange extended outage.
Weakness in Work Screening and
identified one month earlier but not worked.
Planning
,
9/7/95 WEAK IR 95-15 L
O Unit 2 Main Generator overpressurized while Personnel Error / Inoperable filling with H2. Inallention by operators.
Equipment /OWA y 9/2/95 VIO IR 95-15 -
N O
Weaknesses identified in logs relating to Personnel Error VIO 95-15-03 abnormal equipment conditions and out of service equipment not logged (mulitple examples).
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8/31/95 OTHER IR 95-15 S
M Damaged cylinder and head on 18 EDG due to Personnel Error loose lash adjustment.
8/30/95 WEAK IR 95-15 N
PS Containment closure walkdowns by Management and OC Weaknesses management were inadequate and depended heavily on QC involvement to identify deficiencies.
[ 8/30/95 WEAK IR 95-15 N
M Maintenance personnel not using procedures for Supervisory Oversight and Worker
/
work in progress.
Attitude FROM: 8/1/95 TO: 8/23/96 Page 24 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM SEc ITEM APPARENT CAUSE / COMMENTS 8/29/95 VIO IR 95-15 -
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Started 1B LPSI pump with suction valve Personnel Error VIO 95-15-04 c osed. (No damage to pump)
8/29/95 VIO IR 95-15 -
N M
Maintenance joumeyman not signing off Procedure Use VIO 95-15-06 procedure steps as work completed (previously identified as a weakness in May 1995).
'
8/23/95 WEAK IR 95-15 S
M 2A HDP trip due to relay failure. Eight HDP trips Equipment Failurelinadequate in past year. Engineering solution available but Corrective Action not implemented.
8/22/95 VIO IR 95-15 N
PS QA failed to document a deficiency on Personnel Error containment spray valve surveillar:ce identified in an audit.
8/19/95 WEAK IR 95-15
O Overfill of PWT. Spilled approx.10K gallons on Operator Error / Operator ground inside RCA. Operator work around on Workaround level control system and inattention to filling process by operator caused error.
8/18/95 WEAK IR 95-15 N
M P;ocedural weakness involving supervisory Procedural Weaknuss wersight and journeyman quahfication.
8/17/95 VIO LER U195-S O
Spraydown of Unit 1 containment. STAR Proceduralinadequacy and 007 - VIO 95-process did not assign accountability for Weakness / Operator-Work-Around
corrective action. Valve surveillance prelube net documented on STAR.
FROM: 8/1/95 TO: 8/23/96 Page 25 of 26 23-Aug-96
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SFA DATE TYPE SOURCE ID PRIM SEc ITEM APPARENT CAUSEICOMMENTS
\\ 8/9/95 VIO IR 95-16 -
L M
Inoperable Unit 1 PORVs due 10 maintenance Maintenance / Testing ErTors LER U195-error / testing inadequacies. (Valves assembled 005 - EA 95-incorredly) (Used acoustic data only)
180
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8/6/95 VIO LER U195-S E
Lifting of Unit 1 SDC thermal relief due to Corrective Action / Procedural 006 - VIO 95-procedural revision from previous corrective Weakness 20-01 action. Inoperable equipment not logged.
8/2/95 VIO LER U195-L O
1 A2 RCP seal failure due to " restaging" at high Proc-dural Weakness / Failure to 004 - VIO 95-temperature.
Folf nProcedures 15-02 8/2/95 VIO LER UI 95-S O
Operator failed to block MSIS actuation during Operator Error 04 - VIO 95-cooldown, 15-01 SALP Functional Areas:
ID Code:
E ENGINEERING L
LICENSEE M
MAINTENANCE N
NRC O
OPERATIONS S
SELF-REVEALED
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PS PLANT SUPPORT SA SAFETY ASSESSMENT & OV FROM: 8/1/95 TO: 8/23/96 Page 26 of 26 23-Aug-96
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ST.
LUC UNIT
Operational Period Se p te rn b e r 1995 1. h r o u g h Augus t 23,
!996
2
4.
-
-
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3.
On Feb ruary 24,1996, 8O-a mannal trip was initiated
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a rnanual rn cloi trip was
April 29,1996, 20 -
initialed to eiloim MFRV shutdown for r Iaintenanv refue ing O
,umm"n ii n n o mi"m o n u n n i n n i i n n o i i n i
- n n i n a rm o n n i i i n.................. u r,
ininini S
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A PERIOD OF OPERATION Graph does not include power reductions for rou ti n e repairs, waterbox cleaning, or required repairs.
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ST.
LUC UNIT
O pe ra ti o n a l P e ri o d Sep te m ber 1995 tbrough August 23, 1996
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1. Or ! October 9,1995, the LJ
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4. On Apr 120,1996 i
N scheduled refueling' oulacle.
the uni was removed
-
p fror 1 s'arvice during
!
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3. On April 2.1996. povre r lurt,ine testing F
was rei1uced to allow
- 2
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circ water system pip e l
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repairs N
2.
On January 5,1996. the 5. On < une 6,1996, the l
20-unit was manually Iripped unit was manually tripped I
due to high generator
due to h gli generator hyd ogen gas temperatut e hydrogelgas temperature.
O mnr m"nmnnmnnnnnmnn". o o o o n o n u i n rn 5. o n: :. o o i n n o ne n. n. n n u o n. n n.
S O
N D
J F
M A
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J A
PERIOD. OF OPERATION Graph does not include power reductions for routine repairs, waterbox cleaning, or required repairs.
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j TAB E
MAINTENANCE RULE BASELINE INSPECTION REPORT OUTLINE
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t Cover Letter Cover Page Executive Summary Report Details:
' Summary of Plant Status Introduction I. OPERATIONS
Operator Knowledge and Performance 04.1 Ooerator Knowledae of Maintenance Rule (62706)
a.
Insoection Scoce
'b.
Observations and Findinos c.
Conclusions II. MAINTENANCE M1 Conduct of Maintenance M1.1 Scone of Structures. Systems. & Comoonents Included Within the Rule (62706)
a.
Insoection Scoce b.
Observations and Findines c.
Conclusions
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M1.2 Safety (or Risk) Determination (62706)
a.
Insoection Scone
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b.
Observations and Fin 6'qqg c.
Conclusions M1.3 perdodic Evaluation (62706)
a.
Insoection Scone b.
Observations and Findinas c.
Conclusions M1.4 Balancina Reliability and Unavailability (62706)
a.
Insoection Scone b.
Observations and Findinas c.
Conclusions M1.5 Plant Safety Assessments Before Takino Eauioment Out-of,
-Service (62706)
a.
Insoection Scone I
b.
Observations and Findinas
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Conclusions p
a i
j M1.6 Goal Settina and Monitorina for (a) (1) SSCs (62706)
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a.
Insoection' Scone b.
Observations and Findinos c.
Conclusions i
M1.7 Preventative Maintenance and Trendina for (a) (2) SSCs (62706)
a.
Insoection Scone
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b.
Observations and Findinas c.
Conclusions
)
M2 Maintenance and Material Condition of Facilities and Equipment l
M2.1 Material Condition %alkdowns (62706)
a.
Insoection Scone b.
Observations and Findings c.
Conclusions M7 Quality Assurance in Maintenance Activities M7.1 Licensee Self Assessment (62706)
l a.
Insoection Scone l
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b.
Observations and Findinas
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c.
Conclusions
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III. ENGINEERING E2 Engineering Support of Facilities and Equipment E2.1 Review of Undated Final Safety Analysis Renort (UFSAR)
j Commitments (62706)
A recent discovery of a licensee operating their facility in a manner contrary to the. UFSAR description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR descriptions.
While performing the inspections discussed in this report, the inspectors reviewed the applicable portions
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of the UFSAR that related to the areas inspected.
The
inspectors verified that the UFSAR wording was consistent with
the observed plant practices, procedures and/or parameters.
l l
???????????????? NEED TO MAKE SURE THIS IS DONEl!!!!IIIIIIII i
E4
, Engineering Staff Knowledge and Performance
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E4.1 Engineer Knowledae of the Maintenance Rule (62706)
a.
Insoection Scoce
b.
Observations and Findinos c.
Conclusions
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V, MANAGEMENT MEETINGS X1 Exit Meeting Summary
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i ATTACEMENT 1
PARTIAL LIST OF PERSONS CONTACTED
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LICENSEE:
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LIST OF INSPECTION PROCEDURES USED
IP 62706 Maintenance Rule
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LIST OF ITEMS OPENED. CLOSED, DISCUSSED
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o ATTACIDGlNT_2 LIST OF PROCEDURES REVIEWED
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s TAB G INSPECTION FINDING FORM NUMBER:
REV:
DATE:
INSPECTION FINDING INSPECTION AREA:
INSPECTOR:
EFFECTED ITEM OR EQUIPMENT:
REQUIREMENTS:
(site full references)
DISCUSSION OF FINDING (S) :
(characterize as strength or weakness)
PROBABLE CAUSE OF FINDING:
LICENSEE RESPONSE TO FINDING:
CONCLUSION:
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UNITED STATES j
j NUCLEAR REGULATORY COMMISSION o
WASHINGTON, D.C. snanam 4, ******,@
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August 21. 1996
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EGM 96-002 MEMORANDUM TO:
Hubert J. Miller, Regional Administrator Region I Stewart D. Ebneter, Regional Administrator Region II A. Bill Beach, Regional Administrator Region III L. Joe Callan, Regional Administrator i
Region IV
Roy Zinnerman, Associate Director for Projects, NRR Ashok C. Thadani, Associate Director for
'
Inspection and Technical Assessment, NRR
'
Elizabeth 0. Ten Eyck, Director, Division of Fuel Cycle Safety and Safeguards, NMSS Donald A. Cool, Director, Division of Industrial and Medical Nuclear Safety, NMSS
John T. Greeves, Director, Division of Waste
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nagement yS j
hah'A n'g trector FROM:
Jo h
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0 it of Enfo nt SUBJECT:
ENFORCEMENT GUIDANCE MEMORANDUM INTERIM GUIDAN 10 CFR 50.65 - THE MAINTENANCE RULE This Enforcement Guidance Memorandum (EGM) is being issued to provide i maintenance rule inspections of licensee facilities. enforceme have been devel.oped in close coordination with the Division of ReactorThe enclos Controls and Human Factors of NRR.
,
The guidelines in the attachment are intended to provide guidance to the NRC to comply with the requirements of the maintenance rule. staff It is important to note that these guidelines are not currently contained in the Enforcement Policy and are, therefore, not controlling.
applying the definition in Section IV of the Policy for:They should be used to assist i (I) instances of very significant regulatory concerns for Severity Level II violations), (2 significant regulatory concerns ((for Severity Level III violations), o more than of minor concern (for Severity Level IV violations).
It is recognized that maintenance issues can overlap with other issues such as quality assurance and operability.
For some enforcement considerations, other issues relative to the case may result in another enforcement approach being taken.
In some cases, the issues can be categorized by either result or the root cause.
For example, in some instances, the root cause may be more
- %10210015 90pp.
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Multiple Addressees
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significant than the result, whereas in other circumstances, the o i
hold true.
Supplement I to the Policy, the selection should normally
provides the higher severity level and the clearer message.e whichever The form and philosophy of the rule encourages
,
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of the rule.
Within these broad requirements, enforcement action would be
appropriate for licensees who have inadequately implemented aspects of t
rule or whose performance demonstrates a continuing ineffectiveness of maintenance activities.
Escalated enforcement would be appropriate where there was a failure reasonable efforts to implement the requirements of the rule or where significant degradation of SSCs could have been prevented through effec implementation of the maintenance rule.
guidance that is more fully expanded in the examples in the attachme A single violation would be a Severity Level IV violation
NOTE: In considering whether to make a citation for a violation involving a relatively isolated, low safety significant SSC SSC; the reasonableness of the licensee's effort rule, including consideration of its and industry's prior operating experience; and the licensee's corrective action.
the licensee has acted reasonably, a citation might nr:t be If warranted.
A single violation involving a high safety significant SSC that
causes a plant transient that would have beer, prevented by effective implementation of the maintenance rule would be a Severity Level III violation.
i Supplement I, Example C.9 that equipment failures caused by inadequate or improper, provides maintenance that substantially complicates recovery from a plant transient is considered a Severity Level'III violation or problem.
'
Multiple examples of maintenance failures that demonstrate a
Level III violation." programmatic breakdown," would normally be c This is consistent with Supplement I, Example C.7, which provides that a breakdown in the control of licensed activities involving a number of violations that are related that collectively represent a potential carelessness toward licensed responsibilities is considered a Severity Level III violation or problem.
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Mu'ltiple examples of maintenance failures of high safety
significant SSCs that cause a plant transient or complicate the recovery from a plant transient, indicate a programmatic breakdown in implementation of the requirements of the rule and would be considered a very significant regulatory concern and should be
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considered for issuance as a Severity Level II violation or
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problem.
The maintenknce rule does not supersede any existing requirements, such as
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i those contained in 10 CFR Part 50 (including Appendix B and other sections) or a licensee's technical specifications.
These requirements remain in effect I
for maintenance activities. When preparing notices of violation for malatenance activities, the maintenance rule should be used for citations whenever a licensee has violated a specific requirement of the maintenance rule. When a set of facts indicates that there are violations of both the
maintenance rule and another NRC regulation, cite both requirements with only i
one " contrary to."
However, where maintenance violations are caused by
!
licensee activities not covered by the maintenance rule, cite against the
requirements of Appendix 8 or the plant technical specifications. Also,
please note that the failure to perform the safety assessment provided for in j
10 CFR 50.65 (a)(3) requires special attention.
This is addressed in Part A, j
Paragraph D in the attachment.
!
Because the maintenance rule takes a perfomance based approach to inspecting j
licensee maintenance operations (a relatively new technique with limited j
enforcement experience in these types of performance based inspection activities), it is anticipated that the guidance provided in the attachment
will require modification as more inspections are completed and further
experience is gained.
It is estimated that a minimum of six months will be
!
required until sufficient infon=ation can be collected. At that time, the
Office of Enforcement expects to revise the Enforcement l'olicy by adding j
further guidance to the supplements, after consulting with the Commission.
,
Additional enforcement guidance has been provided in EGM 96-001, dated July 3, 1996, which established a Maintenance Rule Enforcement Review Panel
that will meet periodically to review enforcement issues that are disclosed i
!
during the performance of maintenance rule and other routine NRC inspections.
This should contribute to the consistency of enforcement actions in this area.
i cc:
J. Milhoan, DEDR i
H. Thompson, DEDS
W. Russell, NRR i
J. Goldberg, OGC l
F. Gillespie, NRR
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ATTACMENT 1: NAINTENANCE RULE VIOLATIONS
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Examales of Activities That Would Be Violations of the I
A.
Failure to include safety related' or non-safetv2 i
systems, and components (SSCs)
related structures,
,(2)) within the scope of the pro (gram.as defined in 10 CFR 50.65 (b)(1) and
e 1.
. violations involving, for example:
j Failure to include one w more SSCs, where they should a.
i, clearly be included within the scope of.the rule, that as a i
result of the failure to include the SSC: 1) complicates the safety significant SSCs, causes a plant transientreco
i example applies and indicates programmatic failures (if this
involving high safety significant SSCs, then a violation at Severity Level II should be considered).
!
b.
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Failure to include multiple SSCs within the scope of the rule which indicates a programatic failure to implement the i
requirements of the rule.
e
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Severity Level IV - violations involving, for example:
j a.
Failure to include an SSC within the scope of the rule.
B.
Failure to establi for SSCs in (a)(2)gh goals for SSCs in (a)(1) or performance criteria
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Establishment of goals that are inconsistent with
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'All safety related SSCs should be clearly defined in the licensee's j
quality assurance program and should be identified and included within the j
scope of the rule.
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i Because of the flexibility in the rule, special consideration needs to
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be given to determine whether a non-safety related SSC was properly excluded
'
from the scope of the rule.
10 CFR 50.65 (b In determining whether a violation occ)u(2) governs non-safety related j
SSCs.
rred, consider the
experience and existing analyses (e.g. FSARreasonableness of the
IPE, etc.) to identify events that would indicate that a particular non-sa,fety related SSC should have been q
i included within the scope of the rule.
Since licensees are not expected to
consider hypothetical scenarios, it is possible that some SSCs (with no i
history of industry-wide ind plant experience of failures) that were excluded from the scope of the rule, may fail and cause an event.
The failure to include such an SSC in the scope of the. rule prior to the first failure of the
SSC or event would i
Eg1 be considered a violation. However, the licentee would be expected to' include the SSC within the scope of the rule following the first failure of the SSC.
.
The licensee has the option under (a)(2) of the rule to demonstrate that
.
the performance or condition of the SSC is being effectively controlled
]
through the performance of appropriate preventive maintenance such that the i
.
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violations.
1.
Severity Level III - violations involving, for example:
l i
l A single failure to establish a goal for an SSC under a.
t or a performance criterion under (a)(2) that: 1)
a
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the recovery from a plant transient or 2) in th l
hsafetysignificantSSCs,causesaplanttrnNet if s example applies with more than one failure and
i indicates prograsumatic failures involving high safat
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en a violation at Severity Level II -
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b.
Multiple examples of failures to establish either goals for
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SSCs under (a)(1) or performance criteria under (a)(2) that
indicate a programmatic failure to implement the maintenance rule.
I Multiple examples of the failure to take industry-wide c.
operating experience into account when establishing goals or perfomance criteria, where industry-wide operating experience was readily available, that indicats a programmatic failure to meet this requirement of the rule'.
2.
Severity Level IV - violations involving, for example:
(
A single failure to establish a goal for any SSC under a.
(a)(1) or a performa.ece criterion for any SSC under (a)(2).
.
C.
Failure to establish a monitoring program (this would include the failure to take timely and appropriate corrective action in the evaluation of monitoring activities) that adequately supports the goals
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set.under 10 CFR 50.65 (a)(1) or the performance criteria set under 10
,
CFR 50.65(a)(2).
'
The monitoring program must be sufficient in scope and i
SSC remains capable of performing its intended function.
NUMARC 93-01 uses the establishment of performance criteria to accomplish this.
The licensee also has the option of not establishing goals or performance riteria if a determination is made that low safety significant SSCs are ' herently reliable or could be allowed to run to failure.
However this determraation must be
,
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made and documented in advance of the failure.
~
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' Evidence that irdustry-wide operating experience was taken into
'
consideration is not required for :svery goal. However, if multiple examples of goals and performance criteria are reviewed where industry-wide operating experiences are readily available and examples are not found where the licensee can demonstrate thet they were taken into consideration, then the licensee's program indicates a p.:.9mmmatic failure.
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meeting their assigned goals or performance criteria
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j 1.
Severity Level III - violations involving, for example:
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a.
A single failure to establish a monitoring prograin that
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adequately supports a goal set under (a)(1) or a perfomance
!
criterion under (a)(2) that:
{
significant SSCsfrom a plant transient or 2) in the ca
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applies with more, causes a plant transient (if this example
!
than one failure and indicates programmatic failures involving high safety significant
SSCs, then a violation at Severity Level II should be considered).
b.
Multiple failures to establish a monitoring program that adequately supports a goal set under (a)(1) or a performance criterion under (a 2 to implement the re)q(u)rements of the maintenance i
A failure to establish a monitoring program that adequately c.
supports a goal set under (a)(1) or a performance criterion under (a)(2) that results in repetitive preventable functional failtres (MPFFs), maintenance i
2.
Saverity Level IV - violations involving, for example:
A single failure to establish a monitoring program that a.
adequately sv,, ports a goal set under (a)(1) or a performance criterion urter (a)(2).
D.
Failure to take timely a'id appropriate corrective action (this would l
include evaluation of menitoring activities) when a goal or performance criterion is exceeded.
Repetitive failures due to inappropriate or ineffective corrective action could be considered a violation under this rule for all SSCs within the scope of this rule or a violation of 10 CFR 50 Appendix B for safety-related SSCs.
1.
Severity Level Ill - violations involving, for example:
I A single failure to take timely and appropriate corrective a.
action when a goal or performance criterion for an SSC is exceedM (failed) which 1) complicates the recovery from a plant transient or 2) in the case of high safety significant
Maintenance Preventible Functional Failures (MPFFs) are defined i NUMARC 93-01, Appendix B, as the failura of an SSC within the scope of'the Maintenance Rule to perform its intended function, where the cause of the i
failure of the SSC is attributable to a maintenance-related activity.
staff has endcrsed the use of MPFFs as a tool for monitoring SSC maintenance The
performance in Revision 1 of Regulatory Guide 1.160 (January 1995).
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SSCs, causes a plant transient (if this example applies and
indicates programmatic failures involving high safety i
significant SSCs, then a violation at Severity Level II i
should be considered).
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b.
The failure to evaluate the results of monitoring activities
\\
which results in repetitive MPrFs.
l Multiple failures to take timely and appropriate corrective c.
action when a goal or performance criterion is exceeded
,
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(failed the requ)irements of the maintenance rule.that indicat l
{
2.
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Severity Level IV - violations involving, for example:
j A single failure to take timely and appropriate corrective 4.
)
action when a goal or performance criterion is exceeded (failed).
E.
of MPFFs of SSCs covered under (a)(2) would be' a v
develop a rationale or justification for continuing to cover an SSC Failure to j
under (a)(2
-
violation, ) after it has expertenced a repetitive MPFF would be a j-
i 1.
Severity Level III - violations involving, for example:
I Multiple failures to make a reasonable effort to determine a.
the cause of MPFFs of SSCs covered under (a)(2)
.
'
b.
j Muitiple failures to develop a rationale or justification for continuing to cover these SSCs under (a)(2) after they i
have experienced a repetitive MPFFs that indicate the l
programmatic failure to implement the requirements of the j
rule.
i
2.
Severity Level IV - violations involving, for example:
A single failure to make a reasonable effort to determine
a.
the cause of a MPFF of an SSC covered under (a)(2).
i i
b.
i The failure to develop a rationale or justificat' ion for i
continuing to cover that SSC under (a)(2) after it has experienced a repetitive MPFF.
i F.
Failure to perform the required periodic assessment for the activities describsd under (a)(3) would be a violation.
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Severity Level III - violations involving, for example:
'
The failure to perform any required periodic assessment a.
which indicated a programmatic failure to meet the requirement Jf the rule.
2.
Severity Level IV - violations involving, for example:
The failure to include a review of performance and a.
monitoring activities and associated goals and preventive j,
maintenance activities (i.e., all (a)(1) and (a)(2)
activities) in the periodic assessment.
>
b.
Completing this assessment in an untimely manner'.
The failure to take industry-wida operating experience into c.
consideration when performing the periodic assessment.
,
!
G.
Failure to periodically (once per refueling cycle, not to exceed 24 l
- ~
months between evaluations) balance reliability and unavailability due
'
to monitoring / maintenance activities would be a Severity Level IV violation.
,
H.
A failure to develop, implement or adhere to any of the procedures developed by a licensee to implement the rule may be a violation and could be assessed as a violation of the licensee's technical specifications or 10 CFR 50 Appendix B.
i
1.
Severity Level III - violations involving, for example:
4 A single failure to develop or follow procedures involving a.
'
the maintenance of an SSC that 1) complicates the recovery from a plant transient or 2 in the can of high safety significant SSts, causes a p)lant trar.sient (it this example
i
applies and indicates progre stic failures involving high safety significant SSCs, then a violation at Severity Level
.
11 should be considered).
,
b.
The failure to develop or follow procedures that results in
]
repetitive MPFFs.
}
Multiple examples of failures to develop or follow c.
- i procedures that indicate a programmatic failure to implement the requirements of the maintenance rule.
i
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Severity Level IV - violations involving, for example:
A single failure to develop or follow procedures.
a.
'At least one assessment during each refueling cycle provided the interval between assessments does not exceed 24 months.
.
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Er= ales of Activities That idould Not Necessarily Be Violations of the Maintenance Rule:
1.
i
A.
A failure to meet a licensee developed goal under i
be subject to enforcement action as long as appropr(a)(1) would not i
i action had been taken when the goal was not met.
iate corrective B.-
[
It is intended that licensees be allowed flexibility when establishing goals and not be subject to enforcement on goal
selection as long as these goals are reasonably based on safety j
and industry operating experience.
l i
second guess the details of these goals.Tha NRC does not intend to However the NRC will i
review these goals to ensure that they are reasona,bly based on
safety and industry operating experience.
!
j C.
The details of the monitoring program would not be subject to enforcement action as long as the monitoring was sufficient to
,
j adequately support the goals and provided for an evaluation
whenever a goal was exceeded (See example of violations C and 0
{
above).
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.
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D.
Since the rule states that, in perfoming monitoring and i
preventive maintenance activities, an assessment of the total j
j plant equipment that is out of service e ggld be taken into account to determine the overall effect on performance of safety i
functions, the failure to perform this assessment would not be ar j
violation of 10 CFR 50.65(a)(3).
to perform this assessment.
However, licensees are expected
'
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If the inspector finds that a licensee is not performing this
.
assessment using the methods detailed in NUMARC 93-01, Section 11, j
or equivalent methods, then the inspector should consider this to
i be an issue that should be referred for resolution to NRC i
management and the Maintenance Rule Enforcement Review Panel,
!
established by EGM 96-001.
<
r In a case where this failure to perform a safety assessment contributed to the severity of another violation of the regulations, or exacerbated the consequences of an event or j
transient, the failure to perform a safety assessment could be
i taken into account as an escalating factor in any escalated
!
enforcement action.
i
,
In addition, the failure to consider the overall impact of taking
i equipment out of service that: (1) exhibits a pattern supporting a
!
programmatic issue, (2) causes the initiation of a plant trip or a transient with the potential for a trip, or (3) demonstrates the
l j
i potential for a high risk system configuration is of significant
regulatory concern and should be considered for enforcement j
i action.
Depending on the circumstances, the enforcement related
!
action (enforcement conference, Demand for Information, Order, i,
etc.) should be utilized to focus the licensee en the need to
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modify its maintenance activities because of its demonstrated failure to consider the overall safety it.wct of removing equipment from service.
E.
Deficiencits in records and documentation would not in themselves
{
i be subjec. to enforcement. However, if they contribute to an i
inappropriate action or inaction to correct the performance of an SSC, these record or documentation deficiencies may be cited as contributing factors in an enforcement action.
.
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Multiple Addressees DISTRIBUTION:
JLieberman, OE OE Staff Enforcement Coordinators
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P.I. RII,.RIII, RIV
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Day File
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TAB B
A mT_,__muCE RULE COORDinTOR REVIEW /OUESTION SWmrF e
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r Maintenance Rule Coordinator Ouestions InsDector:
Licensee's Maintenance Rule Coordinator (s)-
Interview the maintenance rule coordinator to get a
basic understanding of the process and procedures the licensee used to implement the rule.
Ask the following questions:
1. How have you educated the appropriate plant staff regarding the requirements of the maintenance rule.
,
'
2. Does your management adequately support the implementation of the rule?
3. How are repeat failures identified?
4.
How are repeat MPFFs identified?
5. What actions are taken after they are identified?
6. How are generic implications taken into consideration?
7.
Are the persons responsible for implementing the rule clearly defined?
b Was NUMARC 93-01 followed when implementing the rule?
_ _ _
9. Are there any exceptions?
,
10. What SSCs are under the scope of the rule?
11. How are systems and trains defined?
12. How did you determine which systems were risk significant?
13.
How did you determine which structures were risk significant?
14. Which are being monitored at the plant, system, train, or component level?
15. Which are being monitored under (a) (1) of the rule?
16. How did you determine which SSCs should be monitored using goals under (a) (1) of the rule.
17. How is unavailability data recorded?
i
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P 18. Is trending' performed for all systems?
19. Who is responsible for trending?
20. Has your Plant identified SSCs that have been determined to be allowed to run to failure or that are inherently reliable?
21. How are these cieterminations documented?
22. What is your process for establishing performance criteria for SSCs within the scope of the rule.
23. How is industry-wide operating experience used to support the rule in the areas of Implementation and day-to-day operation.
i 24.
Which SSCs are being monitored using plant level performance criteria?
25. How was the decision made to use plant level performance criteria?
26. What action is taken when a plant level performance criterion is exceeded?
27.
Who has responsibility for evaluating failures and establishing corrective actions?
28.
Was past performance taken into consideration when establishing performance criteria?
29. Where you able to obtain reliability and unavailability I
and failure data for the previous two cycles?
,
30. What process is used ensure that the scoping list is maintained up-to-date (EOP changes, design changes, SCRAMS, etc.)?
31. Has specific training been given to those on the expert panel and those responsible for performance monitoring and trending, making (a) (1) (a) (2) determinations, and other rule activities?
.
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RIPERT PANEL REVIEW / QUESTION SHEET
.
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ExDert Panel Ouestions Insoector:
Interview the expert panel to det. ermine if the licensee is using the risk determination methods described NUMARC 93-01 to satisfy the requirements of (a) (1) and (a) (2) of the maintenance rule.
If so, review the implementation to determine if it is in accordance with the methods described in paragraph 9.3.1 of NUMARC 93-01.
Additional guidance is provided in IP 62706, general guidance section
" Safety Determination" and specific guidance section 03.01.b.1.
During this review ask the following questions:
N 1.
Has an expert panel been established?
2.
List the names, titles, and discuss qualifications of expert panel members.
(Members should have expertise in operations, maintenance, engineering.
Inspector should i
determine whether or not the expert panel - had appropriate expertise)
3. Was a PRA expert included as a member of the expert panel?
4.
Is there an expert panel charter or procedure that describes their duties and responsibilities.
5. If the expert panel is permanent, are there provisions for assuring that the required level of expertise is maintained when replacing members?
6. If the expert panel is not permanent, how will future plant modifications be handled?
7. What activities besides risk ranking (scoping, performance evaluation, etc.) are the expert panel members involved in?
e 8.
Were you trained on the use of PRA information and its limitations?
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9. What are some of the limitat. ions of the use of PRA?
(The inspector should try to make a evaluation of how well the expert panel understands PRA)
\\
10.
Were Risk Reduction Worth, Core Damage Frequency Contribution, Risk Achievement Mbrth methods used for determining risk when establishing goals under (a) (1)
or performance criteria under (a) (2) of the rule?
11.
Were risk considerations other than PRA used?
(The inspector should make a determination as to whether this method is adequate for purposes of the maintenance rule).
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l 12. How were systems not modeled by PRA determined to be risk significant?
13. Were there differences between what was considered PRA
risk significant and Expert Panel risk significant?
i 14. Is the reliability and availability data obtained through the maintenance rule monitoring activities being used to
update or evaluated against the assumptions used in the PRA?
,
15. Were any additional insights used by the expert panel to determine risk significance of SSCs?
'
l 16.
Does the selection of risk significant SSCs seem
,
reasonable?
(Af ter discussing this with the expert panel, the inspector should independently assess the adequacy of the risk determination process).
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SCOPE OF RULE 50.65(b) REVIEW /ODESTION SEElET J
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(b) Scone of the Rule Review
Inanector:
'
The inspector should independently select a sample from each of the following categories and verify that the licensee has included them within the scope of the maintenance rule.
See IP 62706 step 02.04
'
'and the guidance provided in section 03.04.
1. Safety-related SSCs i
'
2. Non-safety-related SSCs:
That are relied upon to mitigate accidents or transients;
That are used in EOPs have been included;
<
Whose failure could prevent safety-related SSCs from fulfilling their intended function; l
Whose failure could cause a scram or actuation of a safety system;
The inspectors should ask the maintenance rule coordinator to explain any SSCs which were excluded from the scope of the rule.
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TAB K
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PERTODIC REVIEN nun mar.wCING 50. 65 (a) (3) REVIEW /OUESTION Sn er i
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O (a) (3) Periodic Evaluation and Balancino Ouestions
.
Insoector:
The inspectors should review any evaluations that have already been performed and the licensee's procedures for controlling this activity.
Then the inspector should interview the persons responsible for performing the periodic evaluation and balancing reliability and unavailability and ask the following questions.
See IP 62706 steps 02.03.a and b and the guidance provided in section 03.03.a. and b.
1.
What is your schedule for performing these evaluations?
(the rule requires that the evaluation be performed at least every refueling cycle provided the interval does not exceed 24 months between evaluations)
2.
Does the periodic evaluation (or do the plans for the periodic evaluation) include an assessment of performance and condition monitoring activities and associated goals and preventive maintenance activities?
3.
Does the periodic evaluation (or do the plans for the periodic evaluation)
take into account, where practical, industry-wide operating experience?
4.
What process have you established for making adjustments where necessary to ensure that the objective of preventing failures of SSCs through maintenance is appropriately balanced against the objective of minimizing unavailability of SSCs because of monitoring or preventive maintenance activities?
(the inspector should briefly describe the method and make a
'
determination as to whether it meets the intent of the rule).
5.
Are there any examples where this activity resulted in changes to the preventive maintenance activities for specific SSCs?
.
6. Who will be performing the evaluation?
7.
Who in plant management will review the evaluation?
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TAB L
.SSCs OUT OF SERVICE 50. 65 (a) (3)
REVIEW /OUESTION SHEET
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- Review the licensee's process and procedures for determining if the licensee has implemented a method for performing this safety assessment in accordance the guidance contained in NUMARC 93-01, section 11, including:
identification of key plant safety functions, identification of SSCs that support key plant safety functions, and assessment and control of the effect of the removal of SSCs for service on those key plant safety functions.
See IP 62706 step 02.03.c. and the guidance provided in section 03.03.c.
1.
Interview the maintenance rule coordinator and ask him to explain the processes that the that are used to control this activity.
.
2.
Interview the PRA expert and ask him to explain how PRA information is used to make these safety assessments.
3.
What types of computer programs or calculational methods were used to perform these safety assessments?
4.
Interview planners and schedulers and ask them to explain their understanding of the rule and their particular role in performing these safety assessments.
5.
Interview maintenance engineers and ask them to explain their understanding of the rule and their role in performing these safety assessments.
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TAB M PLANT OPERATOR REVIEW /OUESTION SHEET
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Plant Ooerator Ouestions
'
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Inspector:
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Interview the plant operators and ask the following questions:
\\
1. Can you describe the key requirements of the Maintenance
,
Rule.
'
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2. What maintenance rule activities are you responsible for?
l (preforming safety assessments before taking SSCs out of I
service, keeping track of unavailability times?, etc.)
l
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3.
When do you deciase a SSC out of service and who is responsible for making that determination?
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4. How is unavailability data for maintenance rule systems
!
recorded?
J
5. Which systems is this data recorded for?
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6.
What purposes is this information used for under the
!
l maintenance rule?
l 7. What is a PRA is and how it is used for implementing the maintenance rule?
I 8. How is risk assessed prior to performing monitoring or.
preventive maintenance at your plant?
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9. Are you involved in this process?
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10. How can you determine which SSCs are out'of service at any given time.
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11. How can you determine which SSCs are within the scope of i
the rule?
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12. How can you determine which SSCs are risk significant?
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TAB N
i GOAL SETTING AND MONITORING 50.65 (a) (1) REVIEW / QUESTION SEEET l
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(a) (1) Goal Settina and Monitorina Ouestions For Selected SSC:
Insoector:
Select an SSC for review from those the licensee has identified as being handled under (a) (1) of the rule.
Include in this sample some SSCs that were dispositioned from (a) (2) to (a) (1).
Also attempt to include some SSCs that have been identified in the licensee's operating experience program.
See IP 62706 step 02.01 and associated specific guidance in section 03.01.
Interview the system engineer and ask the following questions.
Record the answers and any concerns.
i 1.
What goals were set and what monitoring was being performed? Was this monitoring activity part of an existing program?
2. If the system is risk significant, are both reliability and availability being monitored?
3. What was the basis for determining it to be (a) (1) ?
l i
4. Was plant management involved in the decision?
5. How will you know when it can be reclassified an (a) (2) ?
6.
How was safety (or risk) taken into consideration when establishing goals and monitoring against those goals?
7. Did you have any input into the risk determination process?
8.
Why is the SSC being monitored at the (plant, system, train, component)
level?
(the inspector should make an I
independent determination as whether the SSC is being monitored at the appropriate level)
9.
Is monitoring predictive in nature and is trending being performed?
10. Was industry-wide operating experience taken into account when establishing these goals?
,
11. How did this goal address the cause of the repetitive failure or the reason for exceeding its (a) (2) performance criteria?
12.
Did this SSCs experience any maintenance preventible functional failures or exceed an established goal?
13. What was the root cause? (the inspector should make an j
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independent assessment of the adequacy of the root cause determination)
14. What corrective action was taken? (The inspector should make an independent determination of the adequacy of the corrective action)
15. Was the effectiveness of corrective action verified either by post maintenance testing or modification of goals or monitoring activities?
16.
What are your - (the system engineers)
background and qualifications?
17. Describe your understanding of the Maintenance rule.
18. What is the difference between a performance criterion and a goal?
-
19. What is the purpose of establishing a goal?
20. Do you feel that your management would hold it against you for placing your system into (a) (1) ?
21. How do you view (a) (1) classifications?
22. How do you determine when to place an SSC into (a) (1) ?
23. What role did you play in establishing the goals for your system (s)?
24. Do you understand the basis for the goals for your system?
25. Do you agree with the goals that were established?
26. What maintenance rule activities are you responsible for?
i (setting performance criteria and goals taking into account risk and industry-wide operating experience, monitoring and
,
trending of system performance, establishing corrective action, moving f rom (a) (2) to (a) (1), etc?)
27. Describe your system.
28. How many other systems are you responsible for?
)
'
j 29. Are the number of assigned systems changed frequently?
(Based in the above discussions and reviews, the inspector
'
should rinexe a determination.whether monitoring against these goals will be sufficient to provide reasonable assurance that
.
SSCs are capable of fulfilling their intended functions)
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TAB O PREVENTATIVE MAINTENANCE 50. 65 (a) (2) REVIEW / QUESTION SHEET
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(a) (2) Preventive Maintenance Ouestions For Selected SSC:
Insoector:
Select an SSC being handled under (a) (2) of the rule.
Include in this sample SSCs that were dispositioned from (a) (1) to (a) (2).
See IP 62706 section 02.02 and the guidance provided in section 03.02.
Interview the system engineer and ask the following questions.
Record the answers and any concerns.
1.
Was safety or risk taken into consideration when establishing performance criteria?
Yes No Explain:
.
2. Did you have any input into the risk determination process?
3.
Did you make a determination that preventive maintenance
'
was not required because the SSCs was inherently reliable?
(If so, the inspector should make a determination as to whether or not this decision appears to be reasonable)
4.
Did you make a determination that preventive maintenance was not required for this SSC because of its low risk
'
significance and therefore could be allowed to run to failure?
(If so, the inspector should make a determination as to whether or not this decision appears to be reasonable)
5.
Has this SSC experienced a
maintenance preventible functional failure, or failed to meet the performance criteria?
6.
What was the root cause?
(the inspector should make an independent determination as to whether the root cause analysis was adequate)
7.
What corrective action was taken?
(the inspectors should make an independent assessment of the adequacy of the corrective action)
8.
Did the licensee reconsider the performance criteria or disposition this SSC to (a) (1) where it would be subject to goal setting and monitoring.
9.
What type of trending is being performed? (If the SSC is risk significant.
The inspector should make an independent assessment of the adequacy of this trending)
10.
Wha't are your (the system engineers)
background and qualifications?
11. Can you describe the key requirements of the Maintenance
t i
Rule.
12. What maintenance rule activities are you responsible for?
(setting performance criteria and goals taking into account risk and industry-wide operating experience, monitoring and trending of system performance, establishing corrective action, moving from (a) (2) to (a) (1), etc?)
13. What is the difference between a perfomance criterion and a goal?
14. What is the purpose of establishing a goal?
15. Do you feel that placing your system into (a) (1) could nave a negative impact on your personal performance appraisal?
16. How do you view (a) (1) classifications?
17. How do you determine when to place an SSC into (a) (1) ?
18. What role did you play in establishing criteria for your system (s)?
19. Do you understand the. basis for the performance criteria for your system?
20. Do you agree with the performance criteria that were established?
21. Are the performance criteria appropriate?
22.
For systems utilizing plant level criteria, can the systems affect the criteria?
23. Describe your system 24. How many other systems are you responsible for?
25. Are the number of assigned systems changed frequently?
(Based on these discussions and reviews, the inspector should make a
determination as to whether the licensee has demonstrated effective maintenance by establishing and monitoring against appropriate
" performance criteria" as described in NUMARC 93-01 or othet methods)
.
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EIERGENCY DIESEL GENERATOR REVIEW / QUESTION SEEET
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L Emeraency Diesel Generator Ouestions Insoector:
Verify that the maintenance program for emergency diesel generators satisfies the commitments made by the licensee in response to 10 CFR 50.63, Station Blackout Rule.
The inspector should ask the maintenance rule coordinator or the EDG system engineer the following questions.
See IP 62706 step 02.05 and the guidance j
contained in section 03.05.
(Note that this review is in addition j
to the reviews performed using the (a) (1) or (a) (2) checklists.)
i 1.
Have target reliability values or other alternate commitments made in response to the station blackout rule been incorporated into the maintenance program either as goals or performance criteria?
2. How have these commitments been implemented.
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TAB R
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RISK INSPECTION GUIDANCE
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SUPPLEMENTAL NAINTENANCE RULE BASELINE
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INSPECTION GUIDANCE REGARDING LICENSEE USE OF
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PRA FOR RULE IMPLENENTATION I
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l We expect that most licensees will use PRA based approaches to implement j
certain parts of the maintenance rule. Due to the variation of PRA.
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methodologies used by licensees, the baseline inspections must be performed by
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personnel with the proper background and training.
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The purpose of this supplemantal guidance is to provide addi,ional information to the PRA specialist who is performing the inspection of the licensee's use
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of their PRA for implementing the maintenance rule. This guidance should be j-used in conjunction with inspection procedure (IP) 62706, " Maintenance Rule."
This proposed supplemental guidance is intended to be refined as the baseline
Maintenance Rule implementation inspections are conducted. Comments and suggestions for improvement should be sent to P. Wilson or J. Shackelford,
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NRR, SPSB.
e
INSPECTION OBJECTIVES e
For licensees that have elected to utilize PRA in the implementation of
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certain parts of the Maintenance Rule, the following are inspection objectives j
to be accomplished during the base-line inspections..
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i Inspection Obiective 1.
Determine if a licensee has adequately established t
j the safety significance of structures, systems, and components (SSCs) covered by the rule.
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l Inspection Obiective 2.
Determine if a licensee has adequately set pe.Tarmance goals and performance criteria under (a)(1) and (a)(2) of the rule j
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(respectively), consistent with the assumptions used to establish the safety i
significance.
Inspection Obiective 3.
Determine if a licensee is using a rational approach to balance SSC unavailability for monitoring or preventive maintenance
activities with the intended. improvement in SSC reliability.
Insoection Obiective 4.
Determine if a licensee has adequately assessed the overall effect on the performance of safety functions when SSCs are removed from service for monitoring or preventive maintenance.
INSPECTION GUIDANCE General Guidance Inspection Reauirements. The NRC's inspection requirements are listed in Section 02 of IP 62706. However, inspectors should also note that while some items are listed under the inspection requirements, they may not be explicitly stated in the maintenance rule. Rather, these items may be derived from
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Regulatory Guide 1.160, " Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," or NUMARC 93-01, " Industry Guideline for Monitoring the
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Effectiveness of Maintenance at Nuclear Power Plants," which are optional and,
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therefore, would not apply to those licensees who implement the rule using
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other methods.
Implementation Guidance. Except when the licensee proposes an alternate method for complying with specified portions of the rule, the methods described in Regulatory Guide 1.160, " Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," will be used to evaluate the activities of licensees who are required to comply with the maintenance rule. This
'
regulatory guide endorses NUMARC 93-01, " Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and provides methods
acceptable to the NRC for complying with the maintenance rule. The inspector should become familiar with Regulatory Guide 1.160 and NUMARC 93-01 before initiating this inspection. The inspector should also be aware that licensees may use methods other than those described in Regulatory Guide 1.160 and
NUMARC 93-01 to satisfy the requirements of the maintenance rule. Where other methods are used, the licensee must demonstrate that those methods satisfy the requirements of the rule. Where a licenses implements the rule partly in accordance with Regulatory Guide 1.160 and NUMARC 93-01, and partly in accordance with other methods, the licensee must demonstrate that those other methods meet the applicable parts of the rule.
During the pilot site visits the NRC review team noted that the guidance contained in NUMARC 93-01 was used by the licensees at all nine sites. The lessons learned from these pilot maintenance site visits are provided in NUREG 1526. Prior to conducting inspections to verify the implementation of the maintenance rule, the inspectors should be familiar with the methods used by the pilot plants, since those methods appear to meet the intent of the rule and the guidance provided in NUMARC 93-01.
In addition, the inspectors should be aware that the results obtained from any PRA can be highly dependent on the plant configuration and the system reliability and availability data used to i
perform the calculations. Therefore, the licensees should reconsider safety-significance determinations whenever the plant design is modified, the PRA is updated, new insights become available from configuration management reviews, i
or new reliability and availability data become available.
Safety Determination. The rule requires that goals be established commensurate with safety.
Implementation of the rule in accordance with NUMARC 93-01 requires that a safety (or risk) determination be performed for all SSCs within the scope of the rule. This safety determination would then be taken into account when setting goals and monitoring under (a)(1) of the rule and when establishing performance criteria under (a)(2). The safety j
determination method recommended in NUMARC 93-01 involves the use of an expert
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panel employing the Delphi method of NUREG/CR-5424, supplemented by Probabilistic Risk (or Safety) Assessment (PRA) or Individual Plant Evaluation i
(IPE) insights, to identify safety-significant SSCs.
Within the context of quantitative methods, importance measures represent an acceptable approach to the determination of safety significance. Measures such as risk reduction worth (RRW), risk achievement worth (RAW), and Fussell-Vesely (F-V)/ core damage frequency (CDF) contribution have been demonstrated to provide useful information in assessing the safety significance of various SSCs. No single importance measure should be used as the sole determinant of
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safety significance.
It is critical for the licensee to use the appropriate
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3 interpretation of the given importance measure under consideration in making
safety determinations.
The " risk metric" which is used is a vital determinant
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in the interpretation of the results.
For example, imprrtance measures which i
l are based on CDF will not adequately convey the risk significance of SSCs.
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involved in maintaining the integrity of the containment. A more appropriate risk metric for evaluating SSCs related to containment integrity would be that
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l of the large early release frequency (LERF).
Importance measures, as well as other quantitative approaches are derived from L
some underlying analytical model. This analysis (usually a plant-specific PRA) must be technically sound in order for meaningful results to be obtained
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for decision making purposes.
It should be noted that the NRC has not conducted reviews of sufficient depth to specifically approve any particular PRAs for this type of application. Rather, the licensee's analyses are
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evaluated on a case by case basis within the context of the specific application which is being considered.
It is recognized that the plant
PRAs/IPEs can provide a valuable source of information to be used in the
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j maintenance process if used in a deliberate and prudent manner. The importance i
of the adequacy of the analysis used as the basis for quantitative decision
- making cannot be overstated.
It is expected that the licensee be able to e
demonstrate to the inspector that the underlying analysis used in the safety determinations be of sufficient scope, level of detail, and quality to perform
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j the intended functions.
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l During the pilot maintenance site visits, the NRC review team found that all j
licensees used an expert panel (or a working group) to make the safety i
significance determinations. These expert panels took PRA or IPE insights into consideration using the methods described in NUMARC 93-01, although there
were some exceptions. NUMARC 93-01 recommends that all three methods, RRW, RAW and CDF, be calculated and provided to the expert panel for its consideration. One licensee's expert panel, inappropriately, considered only CDF and not RRW or RAW. Another licensee considered CDF and RAW but not RRW.
Several licensees considered the F/V importance measure in addition to CDF, RAW, and RRW. The staff believes that the three methods described in NUMARC 93-01 (CDF, RRW, RAW should be considered the minimum when making the risk determination unless)the licensee had determined that a suitable replacem method such as F/V (or others) is. used to replace one of the methods.
Preliminary staff work indicates that F/V provides similar ranking information
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as RRW. Other methods may be developed in the future and could be used to replace either CDF, RRW, or RAW.
It is recommended that licensees use at least three methods. The results of all methods used should be given to the i
expert panel for consideration.
Safety Consideration for Goal Settina. The NRC staff endorsement of NUMARC 93-01, which allows some SSCs to be monitored using plant level criteria, was based, in part, on the understanding that any repetitive component, train, or system level maintenance preventible functional failures-(MPFFs) would be identified -and would trigger the establishment of component, train, or system level goal setting and monitoring under (a)(1) of the maintenance rule. The rule requires licensees to establish goals commensurate with safety.
.
Information on an SSC's contribution to plant safety can be obtained from
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various sources including the IPE or PRA results (if available)..Section 9.0
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of NUMARC g3-01 provides guidance on acceptable methods for establishing
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safety significance criteria. This safety determination would then be taken-into account when setting goals and monitoring under (a)(1) of the rule. The-
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i safety detemination method reconeended in NUMARC 93-01 ihvolves the use of an expert panel utilizing the Delphi method of NUREG/CR-5424, supplemented by PRA or IPE insights, to identify high safety significant SSCs. At a minimum, these insights should include the three. methods described in NUMARC 93-01:
RRW, RAW, and CDF. However, licensees may substitute other appropriate combinations of measures (e.g., Fussell/Vesely, Birnbaum) if they can provide similar risk insights.
It should be recognized that if less stringent goals are established than were assumed in the IPE/PRA, then the results of the risk ranking procedure may be invalidated. The licensee should ensure, at a minimum, that performance goals are consistent with the assumptions used to derive the results for determining safety significance.
A licensee may classify some SSCs as inherent 1v reliable. This provision might be.used where an SSC, without preventive maintenance, has inherent reliability and availability (e.g., electrical cabling).
It is expected that some structures, such as cable raceways, water storage tanks, and buildings, could be considered inherently reliable. However, it should be noted that such activities a's inspections, surveys, and walkdowns could be considered maintenance activities and, therefore, most SSCs woul'd be subject to some maintenance. Licensees should document their reasons for concluding that individual or groups of SSCs are inherently reliable. During the pilot site visits (See NUREG 1526), the inspectors noted that some licensees had made inappropriate use of this category by assuming that many structures were inherently reliable when in fact the licensees had many longstanding inspection and preventive maintenance activities already in place. The existence of these preventive maintenance activities was inconsistent with the assumption that these structures were inherently reliable.
A licensee may determine that an SSC provides little or no contribution to system safety function and may elect to allow the SSC to run to failure.
Methods for determining safety significance are described in NUMARC 93-01,
Section 9.3.3.
Licensees should establish an Wropriate methodology for
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determining safety significance and should use Cnese crite:ia to identify SSCs
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that could be allowed to run to failure.
Licensees should document these i
criteria and their reasons for deciding that individual SSCs could be allowed
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to run to failure. The inspector should evaluate the effects of the
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licensee's decision to allow certain SSCs to run to failure. The evaluation should include consideration of whether the decision would produce a significant affect on the overall frequency of core damage as well as whether an SSC's run to failure would affect the relative ranking of other SSCs within the scope of the rule (i.e. would allowing a given SSC to run to failure have
- the effect of increasing the relative importance of other SSCs such that an i
SSC which had been classified as LSS should in fact be classified as HSS).
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Balancina Unavailability and Reliability. The maintenance rule requires that licensees make adjustments where necessary to ensure that the objective of
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preventing failures of SSCs through maintenance is appropriately balanced
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against the objective of minimizing unavailability of SSCs due to monitoring l
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or preventive maintenance activities. The intent of this requirement is to:
. ensure.that monitoring or preventive maintenance activities do not result in
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excessive unavailability that would negate any improvement in reliability i
achieved as a result of the monitoring or maintenance activity and that
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deferring monitoring or preventive maintenance to achieve a-high availability j-does not result in low reliability.
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Due to the fact that it might be impractical to perform this balancing on a
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continuous basis, licensees may establish their own schedule for performing i
these reviews and make any needed adjustments to their preventive maintenance activities.
However, at a minimum, the licensee must perform this balancing at least every refueling cycle and include an evaluation of this activity as
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i part of the refueling cycle evaluation process described above.
!
can be qualitative, but it should be documented.
This process During the pilot maintenance site visits, the team reviewed the plans and procedures licensees had developed for accomplishing this activity.
Two licensees planned to balance unavailability and reliability on an ongoing
basis as an integral part of monitoring against performance criteria under the
rule.
Since performance history, preventive maintenance activities, and j
out-of-service time are taken into consideration when developing the
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performance criteria, these licensees believe that meeting these performance criteria will assure that a satisfactory balance of. reliability and
unavailability has been achieved. At another site, the licensee planned to
accomplish this balancing by calculating the safety (or risk) contribution
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associated with unavailability of the system due to preventive maintenance
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activities and the safety contribution due to the reliability of the SSC.
The licensee would then compare and attempt to balance the contribution to safety from each source to assure consistency with PRA/IPE evaluations.
The NRC
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review team concluded that either of these methods could be a reasonable approach to satisfying this requirement of the rule. However, neither
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i approach had been fully implemented at the time of the site visits and,
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therefore, could not be fully evaluated.
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Additional guidance is provided in NUMARC 93-01, section 12.2.4, " Optimizing
Availability and Reliability for SSCs."
The inspector should note that this l
section limits the need to make adjustments to balance availability and reliability to those SSCs that are high safety significance.
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Quantitative methods should consider the additional plant risk associated with
increased SSC unavailability due to maintenance uctivities as well as the effects of these same maintenance activities on the reliability of the
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l equipment and its impact on plant safety.
For example, increased maintenance on a given SSC may be shown to increase the overall reliability of the
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l equipment by some incremental factor. However, this increased maintenance may
reduce the overall availability of the same SSC by some other factor. The
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benefits of the increased reliability due to the additional maintenance should outweigh the ' penalty associated with the increased unavailability in order to
,.
justify the maintenance activity on a strictly analytical basis. A
complementary example would be that of increasing the availability of a given
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SSC by eliminating a particular maintenance activity at the expense of
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possibly reducing that same SSC's reliability. As before, the advantages of
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the increased availability should ouweigh the detrimental. effects of the j
reduced reliability in order to justify a reduction in the maintenance.
Assessment of Eauinment Out of Service.
In order to minimize outage time and i
reduce costs, many licensees are increasing the amount of preventive
maintenance being performed during power operation. This can result in the
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simultaneous renraal of multiple systems from service, which can result in
!
significant increases in risk during these periods.
The NRC is concerned that some licensees may not be adequately analyzing the risk or safety impact i
associated with these unavailabilities. The failure to adequately evaluate
,
safety when planning and scheduling maintenance has led to simultaneous
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unavailabilities of multiple redundant or diverse systems at some sites, Possibly leading to undesirable increases in risk despite the fact that s'uch i
E configurations may not be prohibited by technical specifications. The technical specifications for most sites were crafted for random failures;
voluntary removal of multiple systems from service may not be bounded by worst
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case single failure assumptions in technical specifications. The NRC is
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concerned that risk can significantly increase during periods when multiple i
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l-redundant or diverse systems are unavailable due to preventive maintenance.
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The maintenance rule addresses both on-line and shutdown maintenance. Under i
paragraph (a)(3) of the Maintenance Rule, the NRC expects licensees to assess the total impact on plant safety before taking plant equipment out of service for monitoring cr preventive maintenance. This assessment is to be performed
,
on an ongoing basis, not just during the ne ledic assessment performed during
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i every refueling cycle. Additionally, this assessment is not intended to be
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limited to situations whereby the equipment is fully removed from service.
Rather, it is expected that the assessments will cover all maintenance activities on SSCs within the scope of the rule regardless of whether the equipment is actually removed from service during the maintenance task. This ongoing assessment should be performed regardless of plant mode, i.e., whether i
the plant is operating or shutdown. As stated in the 500, assessing the cumulative impact of out-of-service equipment on the performance of safety functions is intended to ensure that the plant is not placed in safety (or risk) significant configurations. These assessments do not necessarily require that a quantitative assessment of probabilistic safety be performed.
i However the PRA or IPE may provide useful information on safety significance i
of various SSCs. The level of sophistication with which such assessments are performed is expected to vary. These assessments may range anywhere from a simple matrix based on qualitative and quantitative risk insights to the use of an on-line living PRA or risk monitor.
It is expected that, over time, assessments of this type will be refined as the technology improves and
,,
experience is gained.
In order to accomplish these assessments, licensees must keep track of the status (in or out of service) of plant equipment. This status may be kept as a manual list or on a database but must be easily accessible and kept up to date.
In order to be useful and accessible the information should be kept in one location and not scattered among several
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documents (shift logs, status boards, tag out status boards) in various locations. Additional guidance is provided in section 11.0 of NUMARC 93-01.
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During the pilot maintenance site visits, the NRC review team found that
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licensees planned to use, or had used, a variety of approaches for assessing
.
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i the overall effect on the performance of safety functions of taking plant i
equipment out of. service for monitoring or preventive maintenance.
It
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appeared that industry is developing a heightened awareness of the importance
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of managing the risk of performing maintenance during power operation. As stated above, the licensee's assessment of the effects of monitoring and I
j maintenance activities may be either quantitative or qualitative. Where
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quantitative methods are used, the inspector should verify that the analytical i
basis for the quantification (most likely a plant specific PRA or IPE) is of appropriate scope and quality to support the assessments. The same
considerations which were used in evaluating the fidelity of the analysis for-j'
determining safety significance also apply in evaluating total equipment out-of-service assessments.
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The specific format of the quantitative assessments used by licensees may
wy. However, the end result of the assessment should provide information as
to the effects of individual maintenance configurations on. plant risk. The
specific measure of plant risk being considered should be clearly defined
(i.e. core damage frequency, large early release frequency, etc.)
In this.
j respect, certain approaches have been shown to exhibit unique strengths and
~
weaknesses which are specific to the approach which has been used. The
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assessment should consider the risk impact associated with the proposed maintenance activities from SSCs used to mitigate events as well as the risk impact from SSCs that are considered to be event initiators (i.e. scheduling
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switchyard maintenance during an emergency diesel outage).
j The most detailed approach consists of actual quantification of the proposed i
maintenance configurations using a full plant PRA model 'or " risk monitor".
i Tools of this type are able to analyze a wide variety of unique plant l
configurations.
If this approach is used, the overall adequacy of the assessment will be a function of both the fidelity of the underlying PRA model
,
used in the quantification as well as the accuracy of the input assumptions
!
regarding the availability of the equipment beint considered for maintenance.
Since fast running PRA models have sometimes been simplified or optimized, the inspetor should review the licensee's process which has been used to validate
L the adequacy of the optimized model.
(i.e. The inspector should apply the
{
same considerations which were used in evaluating the risk ranking results in i
order to ensure that the model accurately reflects plant configurations.)
In i
addition, particular attention should be directed towards situations where the
proposed maintenance activities affect SSCs with differing safety functions.
For example, maintenance on ECCS systems concurrently with containment systems
,
l would reduce plant protection at two different levels (i.e. both accident i
mitigation and containment performance).
If the underlying analytical tool i
does not accurately medel containnient performance, then the output of such an
!
analysis may significantly underestimate the total plant risk.
Another analytical approach which has been used is that of a matrix of pre-i analyzed plant configurations. An approach such as this attempts to define i
acceptable maintenance configurations with the goal of reducing the analytical
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i burden of real-time calculations. When this type of approach is used, the j
inspecter should verify the technical adequacy of the matrix.
It should be
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r%iized.that this approach is limited in the number of allowable
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configurations which can be considered. It is possible that situations will
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arise whereby unexpected failures will occur of other SSCs within the scope-of-the rule after the licensee has entered an allowed configuration as specified
,
j by the matrix approach. This new configuration would then be outside of the-i scope of the pre-analyzed condition.
(i.e. The additional equipment out of
service caused by the failure in conjunction with the equipment outages
specified by the matrix have not been previously analyzed.) The inspector-i -
should determine what methods the licensee employs to detennine the
acceptability of the emergent condition and what contingency measures are in place to maintain plant risk at an acceptable level during such situations.
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At a minimum, the inspector should verify that the licensee has a program in -
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Place which will ensure that key plant safety functions are maintained even
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when the resultant configurations exceed the boundaries of the pre-analyzed
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configurations.
. State of the Art PRA Attributes i.
a.
Scope of Analysis. Where quantitative results are used, the inspector should verify that the underlying analysis is of sufficient Egn to incorporate all of the necessary SSCs.
For example, a typical " Level 1" PRA would not include SSCs related solely to containment integrity.
Thus, reliance on such an analysis would overlook the important SSCs related to the containment. Similarly, systems related to spent fuel pool cooling and radwaste systems are not typically addressed in such an analysis. Some important plant systems may only bs applicable to shutdown configurations and as such would not be addressed by typical PRAs.
(Most PRAs assume that the plant is initially at full power.)
The inspector should examine the scope of the underlying analysis to determine the extent to which the plant has been modelled. The scope of the maintenance rule extends to a variety of SSCs which are not commonly modelled in traditional PRA studies. The inspector should evaluate the methods by which the licensee incorporates known limitations of the scope of the analysis to ensure that important SSCs are not misclassified during the importance ranking process. The total reliance on an analysis of limited scope would not represent an acceptable approach to risk based decision support. Where it has been shown that the underlying analysis is not of sufficient scope to incorporate all of l
the relevant SSCs into the ranking process, the licensee should demonstrate that an expert panel process has adequately addressed the deficiencies.
b.
Level of Detail. The licensee's quantitative analysis must be of sufficient detail to support decisions regarding safety determinations.
Obviously, SSCs which are not modelled in the PRA will not show up as
"important" during risk ranking calculations. The modelling of SSCs
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with respect to component boundaries can be an important determinant in assessing the level of detail of the analysis. One important issue which has been identified in the past is that of whether the electrical power breakers are included within the component boundaries for individual pieces of equipment. Similarly, certain auxiliary equipment (i.e. cooling fans, lube oil pumps, etc.) is often subsumed within the
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component boundary of larger components. Many complex systems are
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consnonly modelled as super components or " black boxes" in PRA studies.
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(i.e. diesel generators, certain relay / logic switching circuits, turbine trip systems, etc.)
If the licensee's implementation of the maintenance l
rule does not address the individual SSCs in a manner consistent with
the treatment observed in the quantitative analysis, inappropriate i
decisions may result. The inspector should verify that the level of-detail associated with the analysis is appropriate to support the types
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of decisions which are being made.
In those areas where the level of detail of the analysis may not be sufficient, the licensee's expert
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j panel process should address the deficiencies.
c.
Quality of Analysis. The overall auality of the PRA must be adequate if it is to be used to support quantitative decisions of safety significance.
In this context, quality refers to various attributes of the data, assumptions, and the methodology which has been used, as well as consistency of the results. Additionally, the PRA should have been subjected to some type of formal review process.
Ideally, the review process should include both internal and external peer reviews. Also, a comparison of other studies based on similar plant designs should be conducted. Any significant deviations between the comparison study and the licensee's PRA should be fully addressed. The inspectors should review the licensee's documentation which relates to the resolution of these types of discrepancies.
With respect to data, the analysis should reflect plant-specific information to.the maximum extent practicable. This data should be subjected to periodic reviews by the licensee and updated on a periodic and as-needed basis. The data used to support reliability and availability estimates should be of sufficient fidelity to provide meaningful results.
(i.e. The data should be derived from valid operational and test results when such data is available. The l
meaningfulness of a given result is dependent upon the number of observations used to derive the estimate.) The inspector should evaluate the empirical basis for the licensee's reliability and availability estimates to detemine if th'e supporting information i
reflects actual observed operational experience.
(i.e. the inspector
'
should select a sample of SSCs and compare the assumed estimates with actual plant records to determine whether the assumptions are consistent with actual observations).
Inspectors are not expected to perform
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actual statistical estimations of component reliability. Rather, inspectors should ensure that the licensee's performance goals and criteria are not inconsistent with observed equipment performance from a
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qualitative perspective (i.e. it would be inappropriate to make reliability estimates on the basis of limited component demand data).
However, inspectors can make quantitative comparis.sns between the licensee's availability goals and criteria and actual observed equipment outage times.(i.e. compare actual observed unavailability hours with that which was assumed in the PRA).
,.
The data should also reflect industry operating experience when it has been shown that such input would provide additional value to the
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analysis.
(i.e. Have other similar facilities experienced operational
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difficulties that would be applicable to the licensee.) LERs, SOERs,
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vendor correspondence, and other information which provides insight into
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SSC failure and reliability considerations should be incorporated by the
j licensee.
PRAs generally assume that maintenance outages of equipment occur randomly and, therefore, overlaps of equipment outages that can cause changes in the relative importances are also random. Actual plant-
specific maintenance practices, such as rolling periodic on-line
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maintenance schedules can introduce systemic effet;ts that result in more or less overlap of equipment outages. This could result in importance
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rankings that are different from those that would exist if these i
systemic effects were not present. Whether this results in an increase j
or decrease in the actual importance level of any particular component
compared to that estimated by the PRA (which assumed that the outages are random) depends on the licensee's sensitivity to avoiding concurrent
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outages of pieces of equipment that would substantially increase the.
accident frequency.
If actual maintenance practices are different from
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those modeled in the PRA, this information must be presented to the
.l i
panel along with an assessment of the potential impact of these I
differences on the relative risk importance rankings derived from the
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PRA.
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j The basic assumptions used in the PRA can affect the output of the quantitative decision making process. The PRA should be based on i
realistic, best estimate assumptions and data. Overly conservative
!
assumptions can lead to the elevation of the importance of certain SSCs i
at the expense of masking the true importance of others.
(i.e. A given i
success criteria which specifies that 2 out of 3 pumps be available when
!
in fact only 1 pump is required would represent an unnecessary
conservatism.
i This could cause importance measures associated with the pumps to be artificially higher, possibly at the expense of masking the
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importance of other components. Similarly, erroneous assumptions
!
regarding the reliability or maintenance unavailability of components i
can also skew the results.) The assumptions which are used to fom the i
basis for the model should be derived frca a sound engineering or
deterministic basis. The inspector should verify that the licensee has
'
sufficient justification to support the thermal-hydraulic and/or i
statistical basis for the important assumptions.
d.
Uncertainty.
It is recognized that any decision making process based on i
probabilisitic considerations is necessarily subject to a degree of j
uncertainty.
Various aspects of the process have a higher degree of
uncertainty than others.
In'particular, very rare events such as seismic events, or situations involving human error and recovery actions can be shown to exhibit larger uncertainty characteristics.
Uncertainties can generally be dealt with by the use of sensitivity j
studies and the use of the expert panel.
Re-ranking based on 95th and 5th percentile values will-point out events that might have to be moved
"
up in importance because their relative uncertainty bands are large.
If
.
i grouping of components is done correctly, the width of the risk
.
importance classes should accommodate PRA uncertainties.
The icw ranked./
components should not be overly sensitive to PRA uncertainties. The
,
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i licensee's expert panel process should address considerations of i
uncertainty in the decision making process when using quantitative i
methods.
!'
e.
Truncatnan.
In quantifying the PRA, truncation of low frequency events
is usually performed. The truncation limit should be chosen such that i
it is low enough that there is evidence of convergence towards a stable result. To ensure that insights (importance measures, sensitivities,
-
etc.) are not affected by truncated events and sequences, cutoff values
<
that are at least four orders of magnitude lower than the final CDF have i
,
been :uggested (this usually means cutoff values of around IE-9). Some
,
i studies suggest even smaller values at IE-11 to IE-14.
l
!
It should be noted that with the current PRA software and current
!
computers, cutoffs at 1E-11 are quite easily achieved. However, many l
licensees still do the sequence " recovery " manually, and using a IE-11 i
cutoff would significantly increase the effort involved this task.
!
The inspector should evaluate the truncation limit imposed by the
licensee on the PRA results. When cutoffs higher than 1E-9 are used, i
results should be care #ully reviewed.
Ideally, the licensee should i
perform sensitivity studies to show that conclusions will not be
)
affected when truncation limits are raised. However, it should also be
noted that some PRAs modularize to a great extent.
If this is the case, l
the inspector should realize that a IE-9 limit might actually be closer to a IE-11 limit once de-modularization is done.
j
,
Stating that the truncation value chosen will ensure 95% of the CDF is i
captured is generally not sufficient. The licensee should demonstrate i
that a sufficient amount of cutsets have been retained to ensure that
correct insights can be generated, (i.e., we need to ensure that a few j-dominant sequences cannot hide the contribution of other potentially important sequences). Therefore, the truncation value has to be chosen
,
j together with the pertinent decision criteria (e.g. F.V > 0.005 or RAW >
2) to ensure total risk coverage.
.
)
Expert Panel. The licensee's quantitative decision making process should be l
complementary to deterministic methodology.
PRA technology.is subject to j
certain limitations related to modeling, data, and quality as described above.
i While the results of a high quality, PRA-based process can provide meaningful
input into technical decision making, it is the ultimate responsibility of the
!_
licensee to verify and validate the results of this methodology. The outputs j_
-of the quantitative decision making process must be subjected to an expert i
. review to ensure that a proper integration of deterministic and probabilistic
!
insights has been achieved. The expert panel should have the final say in l
making the determinations as to the safety significance of the individual i
SSCs. NUMARC 93-01 provides general guidance as to the conduct and f
composition of an expert panel. The inspector should verify that the expert
panel is composed of individuals with a background in operations, maintenance and PRA technology. The panel should exhibit a structured approach to
'
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decision making such that when the composition of the panel changes
/
periodically, consistent decision outputs will be achieved.
(i.e. The panel's i
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decisions should be similar even when the panel is comprised of different-l individuals.) The panel's decision making process must be defined and i
documented in such a way that it is both scrutable and reproducible. The j
licensee should be able to demonstrate the rationale behind the decision
making guidelines which are used by the panel. PRAs generally assume that'
'
maintenance outages of equipment occur randomly and, therefore, overlaps of equipment outages that can cause changes in the relative importances are also
random. Actual plant-specific maintenance practices, such as rolling periodic
,
on-line maintenance schedules can introduce systemic effects that result in-more or less overlap of equipment outages. This could result in importance-
'
. rankings that are different from those that would exist if these systemic i
effects were not present. Whether this results in an increase or decrease in
}
the actual importance level of any particular component compared to that '
j estimated by the PRA (which assumed that the outages are random) depends on
!
the licensee's sensitivity to avoiding concurrent outages of pieces of equipment that would substantially increase the accident frequency.
If actual
,
maintenance practices are different from those modeled in the PRA, this
information must be presented to the panel along with an assessment of the
'
l potential impact of these differences on the relative risk importance rankings
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derived from the PRA.
Specific Guidance i
This inspection should be performance-based to the extent possible. The
'
following is a suggested method for performing the inspection.
If the licensee has elected to use methodologies that outside of NUMARC 93-01, then
i the inspector should consult with a regional or headquarters PRA specialist
!
' before proceeding with the applicable portion of this specific guidance.
4.
Insnection Obiective 1.
Determine if a licensee has adequately established
-
the safety significance of structures, systems, and components (SSCs) covered
,
j by the rule.
!
I.
Preliminary Assessment
/
l A.
Select a sample of SSCs covered by the rule that the licensee's l
expert panel has categorized as low-safety significant (LSS).
!
i 1.
The inspector should focus on those SSCs that the licensee
[
determined were just-below the selection criteria threshold for the high safety significant designation.
,
i
!
2.
The sample should include SSCs that are not explicitly modeled in the licensee's PRA..
'
3.
The sample should also include SSCs which have been removed
from the list of high safety significant SSCs (as determined
'
-
by NUMARC 93-01 numerical decision criteria) as a result of the decisions made by the expert panel.
,'
'
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.
B.
Review the licensee's basis for their categorization that these SSCs [
j were low-risk significant and verify that the licensee has properly i
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categorized these SSCs as LSS.
i 1.
Probabilistic Considerations
,
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a.
Do the SSCs meet the numerical decision criteria (CDF, RRW, and RAW) specified NUMARC 93-017 l
~
'
b.
Did the licensee adequately assess the safety significance of SSCs outside the ico.g.g of their PRA?
c.
Is the level of detail of the PRA adequate to support LSS determinations?
'
d.
Does the avality of the PRA support the LSS
.
determinations?
1)
Is the SSC correctly modeled in the PRA?
-
,
2)
Are the assumptions used in the PRA regarding
the SSC valid?
!
3)
Did the licensee's risk ranking process include
!
a consideration of the effects of j
periodic / systemic maintenance evolutions? (i.e.
" rolling maintenance" schedules)
If not, how i
have these issues been addressed?
.
e.
Are the licensee's PRA truncation limits low enough to
,
support the LSS determination
2.
Deterministic Considerations a.
Do the LSS determinations account for design basis
'
information and licensing commitments
<
b.
Do the LSS determinations account for the SSCs'
'
importance in supporting operator actions needed to safety operate the facility or to mitigate an event?
,
I c.
Does an LSS SSC have multiple applications in the plant and is susceptible to generic or common-mode failure that could affect redundant trains or multiple plant systems?
d.
Do the LSS determinations account for SSCs' functions in maintaining containment integrity and/or
!
containment isolation?
,
,
e.
Do the LSS determinations account for SSCs'
safety
.
functions during low power operation, shutdown,
.
refueling, and transitional modes of operation?.
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Do the LS5 deteminations account for SSCs'
safety
functions during external events such as fires,
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earthquakes and high winds.
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g.
Has an SE been improperly screened as LSS due to I
redundant LSS systems that perform the same safety function and therefore masked the significance of the
SSC.
i C.
If the inspector identifies problems regarding the licensee's
categorization of SSCs as LSS, then the inspector should expand the sample size to better assess the extent of the problems.
If the i
inspector did not identify any problems and, time permitting, the inspector should also consider expanding the size of the inspection i
j sample.
II.
Problem Assessment
J A.
If the inspector identified problems wit.h the licensee's safety
.
significance determinations then the inspector shall assess the
licensee's process (es) for making these determinations.
I
.
1.
Procedural Controls
a.
Was the level of guidance in Maintenance Rule
'
procedures adequate?
b.
Did the licensee follow the requirements of their l
Maintenance Rule procedures?
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2.
Performance of the Expert Panel
!
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a.
Were the expert panel's composition, its responsibilities, and its methods adequately defined?
)
.
I b.
Did the panel use clear criteria in classifying SSCs I
within safety significance categories?
i
!
c.
Did the panel have adequate guidance to address the i
technical or analytical limitations of the plant specific PRA.
,
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d.
Did the panel consistently give SSCs of similar safety l
significance similar quality treatment?
)
e.
Did the panel objectively consider deterministic and PRA infomation?
-
f.
Did the panel incorporate lessons learned from its activities or the experiences of implementing line
.
i organizations?
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Were expert panel activities documented so that the i
bases for important decisions and SSC classifications
.'
are recorded'l III.
Final Assessment A.
No Significant Problems 1.
If the inspector did not identify any noteworthy problems with the licensee's categorization of LSS SSC's, then the inspector can concluded that, based on the inspection sample, the licensee has adequately established the safety
'
significance of SSCs as part of their Maintenance Rule implementation process.
B.
Problems Identified 1.
If the inspector identified noteworthy problems with the with the licensee's categorization of LSS SSC's, then the inspector needs to perform the following:
a.
Determine if the problems are'the result of programmatic weaknesses or failure to properly implement the program-(i.e. failure to follow Maintenance Rule procedures).
b.
Assess the safety impact of the problems, c.
Determine if the problems represented potential violations.
See Inspection Procedure 62706 for detailed guidance.
Insoection Obiective 2.
Determine if a licensee his adequately set performance goals and criteria under (a)(1) and (a)(2) of the rule consistent with the assumptions used to establish the safety significance.
I.
Preliminary Assessment A.
Select a sample SSCs covered by the rule and modeled in the PRA.
1.
The sample should include both LSS and high safety significant (HSS) SSCs.
2.
The sample should include SSCs that the licensee has categorized as inherent 1v reliable.
~
3.
The sample should include SSCs that the licensee has elected
'
to run to failure.
'
B.
If the licensee has established SSC performance criteria and set SSC
,.
performance goals using their PRA, then verify that the reliability and availability assumptions used in the plant specific PRA are not
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invalidated.
C.
Review the sample of SSCs that have been determined to be inherentiv i
reliable, and verify that the SSC's condition or performance is acceptable without maintenance.
j D.
Evaluate the sample of SSCs that the licensee has elected to run to failure and verify that the licensee has followed their own methodology for determining safety significance. Review the licensee's PRA results to assess the safety significance of the SSC.
E.
If problems are identified, then expand the sample size to better assess the extent of the problems.
If no problems were identified and, time permitting, the inspector should also consider expanding the size of the inspection sample.
II.
Problem Assessment A.
If the licensee has used less stringent values for reliability and availability then assumed in the plant specific PRA, then the results of the risk ranking procedure to determine safety significance may be invalidated. Question the licensee to determine the affect on the risk ranking process when the less stringent values for reliability and availability are modeled into the plant specific.PRA.
B.
If the material condition of an inherent 1v reliable SSC is i
inadequate or the inherent 1v reliable SSC's material history indicates that it is unreliable, then review the licensee's
,
'
methodology for determining that an SSC is inherent 1v reliable.
If the licensee's methodology is unreasonable, then determine the extent of the problem.
C.
If an SSC that the licensee has elected to run to failure is safety significant, then review the licensee's methodology for determining i
that the SSC provided little or no contribution to system safety function.
If the licensee's methodology is unreasonable, then determine the extent of the problem.
III. Final Assessment A.
No Significant Problems 1.
If the inspector did not identify any noteworthy problems with the licensee's establishment of SSC performance criteria and SSC performance goals, of the licensee then.the inspector can concluded that, based on the inspection
,
-
sample, the licensee has adequately set performance goals and criteria under (a)(1) and (a)(2) of the rule consistent
/
.
with the assumptions used to establish the safety
/
significance.
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8.
Problems Identified
1.
If the inspector identified noteworthy problems with the with the licensee's establishment of SSC performance
,
i criteria and SSC performance goals, then the inspector needs to perform the following:
'
>
a.
Determine if the problems are the result of programmatic weaknesses or failure to properly implement the program (i.e. failure to follow
<
Maintenance Rule procedures).
'
b.
Assess the safety impact of the problems, Determine if the problems represented potential c.
violations. See Inspection Procedure 62706 for
-
detailed guidance.
Insnection Obiective 3.
Determine if a licensee is using a rational approach to balance SSC unavailability for monitoring or preventive maintenance
activities with the intended improvement in SSC reliability.
'
)
1.
Preliminary Assessment
.l A.
Obtain the following information from the licensee:
,
1.
The criteria used to measure SSC reliability.
T l
2.
Availability data for HSS SSCs that have been unavailable
!
(over the past 24 months) for periods of time that were i
significantly greater than assumed in the plant specific
!
PRA. The time period of interest is the past two years.
3.
{
Reliability data for HSS SSCs that have been significantly 1ess reliable over the past 24 months than assumed in the plant specific PRA.
4.
Select a sample of HSS SSCs that the licensee determined
that reliability and unavailability have been successfully
balanced.
'
B.
Review the criteria used to measure reliability. Compare the this criteria with how the licensee models reliability in the PRA.
If
'
the reliability criteria is significantly different that used in the i
'
PRA, determine if the criteria is reasunable.
If the licensee does l
not have criteria for measuring reliability, then question the licensee on how they are balancing reliability with unavailability.
,
C.
Review the availability data and determine if licensee actions to improve SSC availability have been successful without a significant
/
,
,
j-decline in SSC reliability.
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D.
Review the reliability data and detemine if licensee actions to improve SSC reliability have been successful without a significant
decline in SSC availability.
I E.
Review the licensee's underlying analytical basis for their
'
determination that the reliability and unavailability of sample of HSS SSCs were balanced.
.
II.
Probles Assessment A.
If the licensee's criteria to measure reliability does not exist or is not reasonable, then go to step III.B.1 below.
B.
Availability I.
If there has not been notable improvement in an SSC's availability, then review and assess the actions the
'
licensee had taken to improve availability.
2.
Request the licensee to evaluate the change in risk associated of any significant decline in SSC reliability resulting from the licensee's efforts to improve availability.
C.
Reliability 1.
If there has not been notable improvement in an SSC's reliability, then review and assess the actions the licensee had taken to improve reliability.
2.
Request the licensee to evaluate the change in risk associated with any significant decline in SSC availability resulting from the licensee's effort to improve SSC.
reliability.
D.
If the underlying analysis that the licensee used for determining that HSS SSCs were successfully balanced is flawed, then question the licensee regarding their basis for determining that balance had been achieved.
If the licensee's basis is not rational, then go to
,
!
step III.B.3 below.
III. Final Assessment A.
No Significant Problems 1.
If the inspector did not identify any noteworthy problems with the licensee's ' efforts to balance reliability and unavailability then th inspector can concluded that the
-
.
licensee used a rational approach to balance SSC unavailability for monitoring or preventive maintenanco e
activities with the intended improvement in SSC reliability.
/
._
. _ _ _.. _
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.
'
B.
Problems Identified 1.
If the licensee's criter sa to measure reliability does not exist or is not reasonable, then the licensee cannot successfully balance reliability and unavailability. The licensee's maintenance rule program guidance is inadequate.
2.
If the licensee has not been able to adequately balance SSC reliability and unavailability, then determine if the problems are the result of programmatic weaknesses or failure to properly implement the program (i.e. failure to follow Maintenance. Rule procedures).
3.
If the licensee does not have a rational basis for balancing reliability and unavailability, then determine if the problems are the result of. programmatic weaknesses or failure to properly implement the program (i.e. failure to follow Maintenance Rule procedures).
i 4.
Assess the safety impact of the problems.
5.
Determine if the problems represented potential violations.
See Inspection' Procedure 62706 for detailed guidance.
-
Insoection Ob.iective 4.
Determine if the licensee has adequately assessed the
'
overall effect on the performance of safety functions when SSCs are removed from service for monitoring or preventive maintenance.
I.
Preliminary Assessment A.
Obtain plant operating / maintenance records for a several month period.
1.
Select two or three periods of high maintenance activities during power operation with particular focus on periods where trains of components were removed from service or where components from differett trains are out.of service simultaneously for monitoring :r preventive maintenance.
2.
Select two or three periods of outage monitoring or preventive maintenance activities with particular focus on periods of reduced reactor coolant system inventory, reduced shutdown cooling availability or reduced electric power availability.
3.,
Obtain the licensee's safety assessment of those selected maintenance periods
,
B.
Verify the licensee safety assessment encompassed all the SSCs
-
(within the scope of the rule) that were out of service and or
/
proposed to be removed from service for monitoring or preventive
'
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.
'
maintenance. Verify that the licensee has process controls in place that ensure safety assessments are performed prior to removing SSCs from service for monitoring and preventive maintenance activities.
C.
Review the i.nr.Fae's safety assessments of the selected maintenance periods. Determine if the licensee adequately evaluated the risks resulting from the monitoring or preventive maintenance activities.
1.
In evaluating the licensee's assessment of maintenance activities, the inspector should ensure that the licensee has included a consideration of the following risk factors:
a.
The likelihood that a given maintenance activity will
>
increase the frequency of an initiating event, b.
The probability that the activity will affect the ability to mitigate the initiating event.
c.
The probability that the activity will affect the ability to use the containment as a measure of defense in depth.
2.
Additionally, the licensee's assessments should include considerations which address the following factors:
a.
Whether multiple trains are affected by the maintenance activity.
b.
Whether the assessment is based on probabilistic insights.
c.
Does the assessment adequately address component and system dependencies?
d.
What assurances are made to prevent the concurrent
,
unavailability of important combinations of equipment
necessary for accident mitigation?
.
!
e.
What methods are employed to determine the duration of l
the maintenance and whether the projected duration is I
accounted for in the assessment?
3.
In the event that the licensee chooses to use an approach such as a matrix of pre-defined allowable configurations, the inspector should ensure the following:
.
!
'
What is the analytical basis for the allowed a.
configurations? (i.e. is the matrix based on
'
quantitative or qualitative considerations?)
.
i b.
What provisions exist for accommodating configurations
/
'
which may arise which are not encompassed by the
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i matrix 7 The licensee should have a well documented process which specifies the procedures to be used in assessing the acceptability of such a configuration.
Additionally, provisions should be made for exiting plant configurations which are either unacceptable or which cannot be adequately assessed.
4.
In the event that the licensec chooses to quantify the proposed maintenance configurations using a " risk monitor,"
the inspector should ensure the following:
The underlying analysis should be sound with respect a.
to the technical attributes of the " risk monitor" model related to scoDe, level of detail, and ouality.
,
'
b.
Did the " risk monitor" model accurately reflect the actual maintenance configuration?
Did the licensee adequately validate the adequacy of c.
the " risk monitor" model?
,
D.
If problems are encountered while assessing the licensee's evaluation of risk due to maintenance, then the inspectors should i
contact a regional or headquarters PRA specialist for assistance and where a more detailed risk profile could be performed.
,
II.
Problem Assessment A.
If the inspector identified problems with the licensee's plant configuration risk management then the inspector shall assess the licensee's process (es) for managing risk for maintenance activities.
1.
Determine if the licensee has procedural requirements for
'
evaluating affect of maintenance on plant risk. Determine
.
if the guidance is adequate and is being followed.
2.
If the licensee is relying on a " risk monitor" to manage risk, determine the extent of the weaknesses in the " risk monitor" mooel.
3.
If the licensee has elected to manage risk by the developmer.t of risk windows (rolling maintenance schedule),
determine if the licensee has appropriately utilized PRA insights in their development of these windows.
.
III. Final Assessment A.
No-Significant Problems
'
l.
If the inspector did not identify any noteworthy problems
/
with the licensee's management of plant configuration risk
/
resulting from maintenance activities, then the inspector
/
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can concluded that, based on the inspection sample, the j
licensee has adequately plant risk associate with maintenance activities.
8.
Problems Identified i
1.
If the inspector identified noteworthy problems with the
'
with the licensee's management of plant configuration risk, then the inspector needs to perform the following:
a.
Detemine if. the problems are the result of programatic weaknesses or failure to properly implement the program (i.e. failure to follow procedures).
j
,
b.
The inspector shall also assess the effect on plant safety resulting from this weakness.
c.
Determine if the problems represented potential violations. See Inspection Procedure 62706 for detailed. guidance.
.
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I TAE_.ft MAINTENANCE RULE NRR OBSERVER CONDUCT The NRC Maintenance Rule Baseline Inspection Team has several NRR observers.
It is essential that each of these observers are cognizant of the inspection plan, their objective and adhere to the following guidance to ensure the observer's actions are appropriate and they present a professional image without causing additional
,
impact to the licensee.
i MISSION / PURPOSE: The NRR observer will function only as an aide to the assigned individual inspectors.
The observer is not an inspector.
The observer will takc directions from the team leader j
and assigned team inspector.
The observer will monitor activities
associated with the ongoing inspection to develop future improvements to this inspection process and to help ensure uniformity.
The observer will help the inspector develop the
-
individual inspection. plan and ensure that each plan is completed within the allocated time.
The observer helps the inspector i
develop questions for interviews and shadows the assigned inspector during tours, visits, and interviews.
The observer is only an
'
l OBSERVER and is assigned the mission to develop improvements to the inspection plan, helps ensure uniformity, and develops recommended j
improvements through a written after action report.
The observer
'
SHALL NOT interfere with the inspection, shall not be asking technical questions of the licensee, interrupting the inspector, talking during an interview, or making informal or official request of the licensee.
All recommendations and request should come i
s through the inspectors and team leader. The observer should remain silent during interviews and take notes to be included within the after action report.
During the team meeting each day, after the
inspector has briefed the team leader on the daily findings, the observer will provide an on-the-spot recommended adjustments for the following days activities and record these recommendations into the observer's af ter action report notebook with a copy to the team leader.
The final af ter action report will be developed during the documentation phase of the inspection and submitted to the team leader with recommended improvements.
If question arise during the inspection that need clarification, the observer should contact the Team Leader or Assistant Team Leader for directions.
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&.,p 5 & L INSPECTOR'S INPUT INPUT FOR ST LUCIE INSPECTION REPORT No. 50 335.338/96 04 DATES OF INSPECTION: MARCH 25 29, 1996 A.
Inspector Concurrence:
J. L. Coley, Jr. Reactor Inspector Branch Chief Concurrence:
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O. M. Verrell1 Acting Branch Chief Special Inspection Branch B.
1.0 Persons Contacted
- R. Ball. Supervisor. Maintenance
- E. Benken. Licensing
- D. English. Supervisor. Maintenance
- H. Jacobs. Supervisor. Maintenance
- G. Madden. Acting Licensing Manager
- A. Menocal. Supervisor. Maintenance Programs and Planning
- L. Motley. Supervisor. Maintenance
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- J. Scarola. Plant General Manager
- S. Valdes. Information Services Other licensee employees contacted during this inspection included craftsmen. technician, and engineers.
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Input for appropriate inspection area.
3.0 Maintenance - (62703)
3.1 Observation of In-process Corrective Maintenance Activities -
Units 1 and 2 Portions of the mechanical maintenance for the equipment listed below were observed by the inspectors to verify that corrective maintenance activities for systems and components are conducted in a manner which results in reliable safe operation of the plant and plant equipment.
Specific elements verified during this assessment included the following: applicable tools were properly calibrated: correct parts and tools were used: personnel were qualified and knowledgeable: suoervision and OC (where aDplicable)
were acequate: proper appr' ovals were obtained before work began; safety and radiation controis were in place: and approved procedures / instructions were followed.
Procedures used to control this work consisted of the 'following: ADM-08.02 Revision 8.
" Conduct of Maintenance" GMP-05. Revision 3. " Control of Welding Special Processes". STD + 012. Revision 1. " Examination Reauirements for Welds". General Maintenance Procedure No. M-0043.
Revision 15. and General Maintenance Procedure No. 2-M-0041.
Revision 29.
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Replacement of Valve No. V23113 on Unit 2 was observed.
This is the 4 inch 1 solation valve for the Steam Generator Closed Blowdown to the Heat Exchanger 2A-1 Inlet.
Work was conducted in accordance with Master Work Order Task No. 95-028027-1A.
The inspector observed welding preparations and fitup.
In addition. the inspectors verifled that work was performed in accordance with written instructions. proper revisions of procedures were used, welder certification, i
welding procedure parameters and weld filler material j
controls and certifications were satisfactory.
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Weld'ing activities for ACC-3B were observed.
This is the Unit 1 air cooled condensing unit for the control room ventilation system.
Work was conducted in accordance wi.th Work Order Task No. 96-0065401.
Welder certification.
welding procedure parameters. and weld filler material controls and certifications were verified satisfactory.
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Liquid penetrant examination activities were observed for a new pipe / valve assembly on the Unit 2 Steam Generator Closed Blowdown system.
Work was conducted in accordance with Work Order Task No. 96003894 and Traveler Nos.96-373. 4. 5. and
6.
Examination of welds No. 2001, 2002. 2003 and 2004 for valves No. V23139 and V23140 were observed.
The inspector verified that the examinations were conducted in accordance with approved procedure No. PT-1. Method 1. Technique sheet i
9.5. Rev. 5.
Welding filler materials, welder certification and welding procedure parameters were a?.o verified.
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Portions of maintenance activities involving the replacement of packing for Unit 2 Charging Pump No. PP2B were observed.
This work was per1ormed in accordance with Master Work Order
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Task No. 96006925-01 and General Maintenance Procedure No.
2-M-0041. Revision 29.
The inspectors verified that work was conducted in accordance with the approved procedure.
craftsmen were knowledgeable of the work process, and the proper revision of the work procedure had been verified.
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Corrective maintenance for Unit 2 Steam Generator Closed
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Blowdown system Valve No. V23139B was observed.
This is a 3/4 inch root valve for the 2B1 heat exchanger which had developed a steam leak in the valve's bonnet to body connection.
Master '.sork Order Task No. 96003894-01 and General Maintenance Procedure No. M-0043 was used to performed this maintenance activity.
However. Corrective maintenance was ineffective due to valve's state of qeterioration.
A determination was subsequently made to l
replace the valve.
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Dortions of the tube cleaning activities in the 1A2 Inlet
.<aterbox on the Unit 1 Condenser (1A) was observed.
This e.ork was conducted in accorcance with Master Work Order Task
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10. 9600612101.
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G During the above work activities the inspectors noted that the craftsmen would go verify that the procedure they were using was the appropriate revision in accordance with the requirements of
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paragraph 4.5 in Procedure No. 016-PR/PSL-1 (Document Control).
One occasion when the inspectors accompanied the craftsmen to i
perform this verification the craftsmen found that Revision 14 of
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Procedure No. M-0043 which the planner had furnished in the maintenance package was not the current revision when compared
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with the maintenance control copy in the North Service Building.
Further review by the inspectors also revealed that the procedures i
index was not being updated when new procedure revisions were
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received as the cover sheet of the index stated.
The inspectors also questioned whether the control procedures were available to
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backshifts since the doors of the room had locks on them.
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Discussions held with appropriate management personnel regarding
the above procedure control concerns.
The discussion revealed
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that document control only considered the procedure index correct on the date indicated on the index cover sheet.
In accordance with procedure this is a dated once every three months when control copies of the procedures are audited against an up to date t
index.
The inspector was also informed that the craft know to verify their procedures against the control copies of the documents verses the index.
Since the index is a memorandum and by procedure does not supersede the requirements of a control document.
Based on observations of craftsmen audited this inspection, procedures in the maintenance package are verified against the control copy of the procedure.
In addition, the craftsmen audited followed the document control procedure and used the correct revision of the procedure in each case.
The apparent
discrepancy of the planner issuing the incorrect revision of
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General Maintenance Procedure No. M-0043 resulted because the planner had entries to made in the procedure and on the date he.
i made these entries he had verified revision as the correct revision on that date.
This therefore, was not a discrepancy but one of the reason the craftsmen are required to verify the i
procedure before use.
As a result of above findings and questions raised by the
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inspector, two STAR Action Reports were written (Nos. 960456 & 7)
l to evaluated the effectiveness of document control.
Management's i
attention focused on corrective actions in response to these reports and during the week the inspector was on site (March 25-29. 1996. the following corrective measures were established.
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All maintenance groups now will use only one new centralized library in the North Service Building.
This library has an l
attendant manning it and updating control procedures 10 Hrs.
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The room where the library is located has also had
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Ine locks removed from the doors in order that no backshift
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personnel are excluded from using the facility.
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The document index cover sheet has been revised to insure inat this uncontrolled document is not used for procedure i
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When planners now verify procedure revisions during the R
planning stage they will double stamp the procedure and only sign one verification blocks.
This will require the user to also verify the procedure.
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An up to date procedure index will be established on all on-line computers by approximately August 1996.
When this enhancement is fully implemented the index will supersede all documents for establishing 3rocedure status. All plant
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personnel will have access to t1e index at that time.
The inspectors considered the steps taken or in the process of being taken by the licensee to be substantial improvements in document control.
All actions observed during the above corrective maintenance were also found to be satisfactory.
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7.0 Exit Meeting The inspection scope and results were summarized on March 29.
j 1996 during a pre-exit meeting with the licensee.
The inspectors described the areas inspected and discussed in detail the inspection results.
Proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
E.
8.0 Review of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR description highlighted the need for additional verification that hcensees were complying with the
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UFSAR commitments.
During an approximate two month time period all reactor inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices, procedures, and/or parameters.
While performing the inspections which are discussed in this report the inspectors reviewed the applicable portions of the Updated Final Safety Analysis Report (UFSAR) that related to the areas inspected.
The inspectors verified that the UFSAR wording was consistent with the observed plant practices. procedures, and parameters.
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9.0 Summary Statement Plant corrective maintenance was conducted in accordance with the applicable approved instructions by knowledgeable craftsmen.
l Cdrrective actions taken by the licensee to improve the control of I
documents were considered appropriate for the situicion.
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IFS Forms
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Attached to hard copy j
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tompleted NOV
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None File S:\\DRS\\ SIB \\STL9504.JC
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j INSPECTION PLAN INSPECTION OF:
ST Lucie 1 & 2 INSPECTION DATES:
May 6-9 St. Lucie. May 10th EPRI and May 13-17. 1996 l
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REPORT NUMBERS:
50-335.328/96-06 For inspection performed on May 6-9
50-335.328/96-To Be Announced May 13-17. 1996
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TYPE OF INSPECTION: Core (Maintenance and Surveillance) May 6-9. 1996 May 10. 1996 EPRI Review of Southwest Research Institute Qualification Data for St Lucie Reactor Vessel Inspection May-13-17. 1996 Core (Inservice Inspection of Reactor i
vessel.
INSPECTOR:
J. L. Coley
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INSPECTION OBJECTIVES:
To evaluate the effectiveness of the licensee's maintenance and surveillance activities and to examine Automated Ultrasonic Examination of Reactor Vessel plus other ISI activities.
INSPECTION REQUIREMENTS:
Preplaning review of maintenance documents. TS.
FSARs. PPR, SALP Reports, and Plant Status Report for this inspection will be performed May 2-3, 1996.
ANALYSIS OF SITE MATRIX:
Matrix will be reviewed before inspection is performed as part of the preplaning review detailed above.
IPE IMPORTANT SYSTEMS:
High Pressure Safety Injection. Emergency Power Systems. and Component Cooling Water Senior Resident Perspective: The senior resident inspector stated that he
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would like me to focus on the visual Reactor Vessel internals examination. Steam Generator eddy current examinations, anc the Reactor Vessel 10-Year automated ultrasc.nc examinations Outstanding Items:
Unresolved Item No. 335/94-008-03. Quality Level of PORV and SRV Discharge Piping Lodging During Inspection:
Holiday Inn @ Jensen Beach 407 225 3000 Lodging At EPRI : Hampton Inn Charlotte (Unversity Place) 704 548-0905 In Charge of Exit Interview: Senior Resident Inspector (End of Month) Briefing with management at end of this inspection J. L. Coley Franch Chief's Instructions:
None to date Approving Branch Chief: D. Verrelli
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Date Submitted to Branch Chief: 4 17 96 Date Projects Informed: 4 17 96 l
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Date Plan Provided to Projects: 4 17 96 Copies Provided:
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Maintenance Branch Chief: Chris Christensen. 4 17 96
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Project Branch Chief: K. Landis, 4 17 96
' Project Engineer: E. Lea. 4 17 96 f
Original to Branch Files:
Special Inspection Branch
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INSPECTOR'S INPUT
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St. Lucie 96-06 i
A.
Inspector Concurrence:
J. L. Coley. Jr. Reactor Inspector Branch Chief Concurrence:
P. E. Fredrickson Branch Chief Special Inspection Branch
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B.
1.0 Persons Contacted G. Boyers. Level III. Eddy Current Examination Examiner F. Carr. Section Supervisor. Nondestructive Examination (NDE)
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J. Connor. NDE Supervisor C. Ward. Mechanical Engineer Electrical Power Research Institute (EPRI)
P. Ashwin. Project Manager. RPV Performance Demonstration L. Becker. Performance Demonstration Administrator T. Kimoall. NDE. Specialist
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Licensee employees contacted during this inspection included maintenance technicians. nondestructive examination technicians, and engineering personnel.
C.
Input for appropriate inspection area.
3.0 Maintenance Implementation 3.1 Uoservation of In-process Corrective Maintenance Activities (62703) Unit 1 The inspector observed maintenance activities on the components listed below to determine if the activities were conducted in accordance with regulatory requirements, technical specifications (TS). approved procedures, and appropriate industry codes and standards.
3.1.1 Master Work Order: 95-02643-01C. Jack and Lap New Pressurizer Safety Valves Due to seat leakage problems experienced with the previous design pressurizer safety valves. Florida Power and Light (FP&L) elected to replace these valves with a new forge body design which accommodated a flexi-disc seat enhancement.
During site verification nitrogen seat set pressure and
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oubble tests conducted in accordance with Master Work Order l
No. 95-026432-01B. Crosby's Technical Manual No. 8770-5460 Revision 10. and Maintenance Procedure No. M0017 Revision 33. two of the new valves. Serial Nos. N84217-00-0002 and N84217-00-0004 failed to pass the seat leak test.
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result, the valve bonnets with the valve internals for the two valves +. hat failed were required to be disassembled from the valve body so the valve seats could be lapped.
From May 6-8. 1996, the inspector observed the " Jack and Lap" activities conducted in accordance with MWO 95-02643-01C by a Crosby Valve and Gage Company representative. FP&L Maintenance personnel and site engineering.
The inspector also observed that the retest of both valves was conducted in accordance with MWO 95-026432-01B and Maintenance Procedure M0017. The valve retests were satisfactory and all work activities observed were conducted in accordance with the approved written instructions by Knowledgeable personnel, i
3.1.2 MWO-95028905-01. Clean Component Cooling Water Heat Exchanger
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On May 8. 1996, the inspector observed maintenance personnel performing heat exchanger tube hydrolazing operations on Component Cooling Water He3!
w hanger 1A in accordance with MWO 95-028905-01.
During review of the work package for this cleaning and repair activity the inspector noted that the information copies of the control procedures had not been verified as the correct revision with the control document, initialed. and dated as required by Document Control Procedure No. 01 6-PR/PSL-1.
The procedures involved were MMP-14.1 Revision 6. Component Cooling Water Heat Exchanger Cleaning and Repair". GMP-02 Revision 13.
"Use of M&TE By Mechanical Maintenance", and Maintenance Procedure M-0064 Revision 1".
The inspector subsequently verified that the procedures in question were in fact, the correct revision.
However, upon being notified. FP&L maintenance supervision personnel stopped all work on the Component Cooling Water Heat Exchanger until the cause of this discrepancy could be determined.
Corrective actions included replacing the lead maintenance technician on this
. Job and conducting briefings with maintenance personnel on all shifts to insure that outage maintenance personnel knew
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they were personally responsible for insuring work was conducted in accordance with current revision of procedures and that, procedures are stamped. signed, and dated as requi red.
This failure constitutes a violation of minor significance and is being treated as a Non-cited Violation
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(NCV) consistent with Section IV of the NRC Enforcement Policy.
The NCV was 10entified as NCV No. 50-335/96-06-01.
"Fa11ure to Document Verification of Current Procedure Revisions 3.1.3
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Inservice Inspection (ISI) Unit 1 The inspector reviewed documents and records. and observed activities as delineated below to determine whether ISI activities were conoucted in accordance with applicable procedures regulatory requirements. and licensee
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commitments.
The inspector's objective was te examine the licensee's steam generator examination and evaluation activities and the 10-year ultrasonic examination of the reactor vessel.
The applicable code for this ISI is the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code.Section XI. 1983 Edition with Summer 1983 Addenda.
St Lucie Unit 1 is presently in the first outage of the third 40 month period, of the second 10-year ISI interval.
This is the thirteenth refueling cycle for Unit 1.
Eddy current acquisition activities were conducted by ASEA.
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Brown & Boverla INC (ABB)/ Combustion Engineering.
Primary analysis of eddy current data was conducted by Zetec in
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Issaquah. Washington and the secondary analysis was conducted by ABB at the Florida Power and Light NDE
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Laboratory in West Palm Beach. Florida.
The Unit 1. 10-year
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Reactor Vessel examinations were conducted by Southwest Research Institute.
3.1.3.1 Review of Procedures. Guidelines. and Licensee Documents (73052)
The following documents were reviewed by the inspector
during the assessment of ISI activities.
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FP&L Eddy Current Examination Procedure No. NDE 1.3 Rev. 8. Entitled: Eddy Current Examinations of Non Ferromagnetic Tubing Using Multi-Frequency Techniques MIZ-18/MIZ-30
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FP&L Document No. CSI-ET-96-11 Rev. A. Unit 1 Steam Generator Eddy Current Examination Plan
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FP&L Letter of Response to Generic Letter 95-03. Dated June 23. 1995
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FP&L Safety Evaluation No-. JPN-PSL-SEMP-95-112. Rev.1.
Entitled: Cracking of Westinghouse Alloy 600 Mechanical Steam Generator Tube Plugs
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PC/M 125-195M. Rev. 1. Entitled: Steam Generator Tube Plugging and Plug Repair
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St. Lucie Unit 1 Eddy Current Data Analysis Guideline and Performance Demonstration. Dated May 1996
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Southwest Research Institute (SwRI) Procedure No. SLC-AUT-14 Rev. 1. Change 1. Entitled: Automated
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Ultrasonic Inside Surface Examination of Pressure Piping Welds
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SwRI Procedure No. SwRI-AUT2 Rev.9 Change 1. Entitled:
Automated Ultrasonic Inside Surface Examination Indication Resolution and Sizing
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SwRI Proceaure No. SLC-AUT15 Rev. 2. Change 1.
Entitled: Automated Ultrasonic Inside Surface Examination of Ferritic Vessels Greater Than 4.0 Inches in Thickness
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FP&L Document No. PSL-100-A0A-95-1 Rev.0. Dated April 5. 1995. Entitled: Request For Authorization of Alternative Examination
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NRC Safety Evaluation of FP&L's Request for Authorization of Alternative Reactor Pressure Vessel l
Examinations For St. Lucie Plant. Unit 1
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SwRI Procedure No. SLC-PDI-AUT1 Rev.0. Change 1.
J Entitled: Automated Ultrasonic Inside Surface i
Examination of Ferritic Vessel Wall Greater Than 4.0 Inches in Thickness
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SwRI Procedure No. SLC-PDI-AUT2 Rev. O. Change 1, Entitled: Automated Inside Surface Ultrasonic Flaw
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Evaluation and Sizing
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The inspector's review of the above documents revealed they were in accordance with the applicable ASME Code. Technical Specifications. licensee commitments and industry guidelines.
In addition. the inspected noted that, the licensee's augmented eddy current examination plan, plug-a-
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plug tube plugging activities and alternative reactor
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pressure vessel examinations revealed good outage planning had been performed and component safety should be enhanced, based on these defensive barriers.
3.1.3.2 Observation of Steam Generator Eddy Current Acquisition and Steam Generator Plug-A-Plug Repair Activities (73753) Unit 1 From May 6th until May 9th. 1996 the inspector observed portions of the licensee eddy current data acquisition and the Westinghouse tube plug cleaning activities.
These
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activities were conducted in accordance with the approved procedures delineated above and the FP&L Examination Plan.
3.1.3.3 Review of SwRI Ultrasonic Examiner Performance Demonstration Records at the Electric Power Research (EPRI) In Charlotte N.C.
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On May 10. 1996. the inspector and a representative from FP&L visited the EPRI NDE Center to review the performance
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demonstration examination results for the four SwRI data analyst that would be used by FP&L to examine the Unit 1
reactor vessel.
This review was necessary because FP&L's
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relief request entitled. " Request for Authorization of Alternative Examination Methods" which was applicable for Unit I reactor pressure vessel welds which had limiting
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conditions that prevented 100 percent examination coverage had two alternative examinations proposed by the license that had changed since NRC had approved the relief request.
The first change was that the licensee had initially stated that a full vee 45* shear wave examination would be i
performed to the extent practical to compensate for recorded limitations.
However, the current SwRI examination procedures did not have this examination method in them.
The second change to the April 1995 Relief Request stated that. FP&L would employ as they became available additional examinations. inspections and/or techniques that would
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provide a substantial increase in the examination of areas currently missed under the current examination techniques.
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To comply with their commitment to employ examination techniques that provide a substantial increase in the examination of weld areas currently missed. FP&L had SwRI qualify to the performance demonstration examinations conducted by the EPRI NDE Center for a single side weld access examination.
These examinations are conducted in accordance with Appendix VIII of later editions of the ASME Code.
The editions of the Code which include Appendix VIII have not been approved for use by NRC at this time.
The applicable ASME Section XI Code presently requires that a weld be examined from two directions (both sides of a weld).
Therefore to supplement the Unit 1 Reactor Vessel examinations with these new alternative techniques the licensee invoked paragraph IWA-2240 of the applicable ASME Code which states that. " alternative examination methods, or newly developed techniques may be substituted for the methods specified provided the inspector (the Authorized Nuclear Inspector [ANI]) is satisfied that the results are demonstrated to be equivalent or superior to thost of the specified method" Although the ANI had approved the single side Weld examination techniques the inspector had the following questions concerning the single side weld access test parameters and the examiner's performance.
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How many of the defects were in the test blocks were on the far side of the weld?
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Was the depth location of the defects represented on both sides of the weld?
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How many of the far side weld defects were notches verses cracks?
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What was the effective focal length of the SwRI Duplex Send and Receive transducers?
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How effective had the SwRI examiners been during their qualification effort on the far side weld indications?
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Could an examiner pass the test and miss one or more far side weld indications?
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Detection Criteria delineated in Paragraph 8.1.(2)(b)
of SwRI Procedure No. SLC-PDI-AUT1 stated that. "if an indication cannot be confirmed with at least 2 channels, it will be considered irrelevant".
SwRI one
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sided examinations will only have two channels active.
representing two different examination angles.
Since
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far sided weld indications should be oriented at a slightly different angle than near side weld indications because defects tend to follow the weld f
heat affected zone on both sides of the weld.
Is it logical to presume that 100% detection capability will l
be achieved with both angle beam transducers on indications when weld location and defect orientation differ?
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EPRI's Performance Demonstration AG2inistrator reply to the
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inspector's first question was that there was no weld in the
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test blocks used for the single side access weld
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qualification test.
EPRI's position was that the weld would
not make a sionificant difference in the ability to detect or size indications in the carbon steel reactor vessel.
The inspector however, was concern that the acoustical differences between the vessel base material and the weld.
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and the defect orientation differences had not been at least analytically defined and factored into the difficultly of the performance demonstration test.
Therefore. the performance test may not be ultrasonically representative of the reactor vessel welds.
Discussions with EPRI personnel and review of documents and examiner test results satisfactorily resolved the questions listed above other than those that related to the failure of the test sample to include a weld.
The inspector returned to the St, Lucie facility on May 13.
1996 to continue his examination of inservice inspection activities.
At that time the inspector will addressed this concern with the appropriate licensee management personnel
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and determined the licensee position on this matter.
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Continuation of the insoection will be reported in NRC
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Inspection Report No. 96-08.
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e 7.0 Exit Meeting The inspection scope and results were summarized on May 13. 1996.
during a meeting with the licensee.
The senior resident inspector described the areas inspected and discussed in detail the inspection results listed below.
Proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
(0 pen)/(Closed) Non-cited Violation 50-335/96-06-01. " Failure to Document Verification of Current Procedure Revisions" Paragraph No. 3.1.2.
E.
8.0 Review of UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR description highlighted the need for additional verification that licensees were complying with the UFSAR commitments.
During an approximate two month time period all reactor inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices, procedures, and/or parameters.
While performing the inspections which are discussed in this report the inspectors reviewed the applicable portions of the Updated Final Safety Analysis Report (UFSAR) that related to the areas inspected.
The inspectors. verified that the UFSAR wording was consistent with the o] served plant practices, procedures and/or parameters.
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9.0 Acronyms
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ASEA. Brown and Boveria ASME
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American Society of Mechanical Engineers B&PV
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Boiler and Pressure Vessel
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Electrical Power Research Institute FP&L
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Inservice Inspection M&TE
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Mechanical & Test Equipment MWO
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Master Work Order NCV
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Non-Cited Violation NDE
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Nondestructive Examination NRC
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Nuclear Regulatory Commission RPV
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Reactor Pressure Vessel swr 1
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Southwest Research Institute TS
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Technical Specifications UFSAR -
Updated Final Safety Analysis Report G.
10.0 Summary Statement Maintenance activities which upgraded the Pressurizer Code Safety Valves with a new moroved design valve. the 11censee's augmented eddy current examination plan plug-a-plug steam generator tube plugging activities which prevent tube plug leakage, and alternative reactor pressure vessel
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examinations revealed good outage planning had been performed and i
component safety should be enhanced. based on these defensive barriers.
Work activities observed were conducted by well qualified and
knowledgeable 3ersonnel.
However. one non-cited violation was also addressed in t1is report whi dealt with improper control of work j
procedures.
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Y INSPECTOR INPUT FOR ST LUCIE MAINTENANCE TEAM INSPECTION REPORT INPUT FOR INSPECTION REPORT NO.: 50 335,389/96 13 INSPECTOR:
James L. Coley, Jr.
Reactor Inspector Special Inspection Branch Division of Reactor Safety DATES OF INSPECTION: September 16 20, 1996 Inspector:
James L. Coley, Jr. Reactor Inspector Date Signed D. M. Verrell1. Chief Date Signed Maintenance Branch i
Division of Reactor Safety I. OPERATIONS
Operator Knowledge and Performance 04.1 Operator Knowledge of Maintenance Rule a.
Insoection Scoce (62706)
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During the inspection. the inspector interviewed one senior reactor operator (SRO) to determined if he understood the general requirements of the Maintenance Rule and his duties and responsibilities for its implementation.
The inspector asked the SRO to explain the general requirements of the Maintenance Rule and to describe his responsibilities for implementing these requirements.
The inspector also had the SRO to explain in detail the risk assessment matrix.
.b.
Observations and Findinos The tasks associated with the rule that operators were responsible for included:
Determining the impact on availability of SSCs when tagging equipment e
out-of-service and performing administrative requirements for tagging.
Determining SCCs out-of-service logging requirements and impact on e
availability.
Evaluating priorities for system restoration.
e Evaluating job scheduling activities.
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Evaluating plant configuration to determine if work authorization created undue risk.
The operator understood the purpose of the rule and his required duties for
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Rule implementation, which included logging in-and out-of-service equipment within the scope of the Rule and assessing the risk of emergent work items in accordance wit 1 the plant configuration risk assessment matrix.
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Conclusions The senior reactor operator interviewed understood the purpose of the rule.
and his assigned duties for implementing the rule.
II. MAINTENANCE fil Conduct of Maintensnce M1.3 Periodic Evaluation a.
Insoection Stone (62706)
Paragraph (a)(3)of the Rule requires that performance and condition monitoring activatles and assoClated goals and preventive maintenance act,v,t,es be evaluated taking into account. where practical, industry-wide operating experience.
This evaluation is required to be performed at least one time during each refueling cycle not to exceed 24 months between evaluations.
The inspectors reviewed site procedure Nos. ADM-17.08. " Implementation of 10 CFR 50.66. The Maintenance Rule". ADM-17.03. " Operating Experience Feedback program" and SCEG-008. " Guidelines for Maintenance Rule Periodic Assessments" which implemented the licensee's commitments regarding periodic evaluations.
held discussions with the Maintenance Rule Administrator who is responsible for preparing Maintenance Rule periodic assessments. reviewed the July 9.1996 quarterly report. and reviewed a draft copy of the licensee 1st periodic assessment for the emergency diesel generator (EDG) system.
b.
Observations and Findinas j
On June 29. 1995. license amendments were issue to remove EDG accelerated testing and special reporting requirements from the ST. Lucie Technical Specifications.
The amendments required thP 1mplementation of an EDG maintenance program that complies with the requ,.'ements of 10 CFR 50.65 and Regulatory Guide 1.160 within 90 days.
As a result. a commitment date of September 29. 1995 was established for EDG Maintenance Rule implementation.
Due to the early implementation of the Maintenance Rule for the EDGs. the requirements for the performance of a periodic assessment have become due for the EDGs.
The remainder of the site Maintenance Rule program began implementation on July 10. 1996. in compliance with 10CFR 50.65 and will be due next year shortly after July 10. 1997.
Both Units will be performed concurrently at this time.
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The licensee's commitments regarding periodic evaluations of the Maintenance Rule activities are as follows:
e Maintenance Fule Quarterly Report - A report whicn documents the results of structures. systems, and components (SSCs) performance. SSCs considered for goal setting and monitoring per section (a)(1) of the rule. as well as SSC degracations. trenos and pertinent inaustry wlde operating experience.
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Periodic Assessment - A higher-level, comprehensive evaluation performed
annually at mid-year following Maintenance Rule implementation dates.
The inspector reviewed the licensees quarterly report dated July 9. 1996 for all SSCs and a draft copy of the St. Lucie Maintenance Rule Periodic Assessment for the EDGs.
The Emergency Diesel Generator system is currently not meeting established performance criteria and is in Maintenance Rule (a)(1)
status for the following conditions:
Unit 1&2 EDGs have experienced repetitive maintenance preventable e
functional failures with the governors.
Unit 1 B EDG has exceeded its performance criteria for unavailability e
hours and has exceeded trigger values prescribed by the Emergency Diesel Generator Rellability Program.
The inspector confirmed that corrective actions were taken. Industry-wide operating experience was reviewed, and goal setting and monitoring activities have been established by the licensee.
The inspector also noted that preventive maintenance activities were adjusted as required by paragraph (a)(3) whenever a goal or performance criteria was exceeded or whenever a SSC experienced a maintenance prevent 1ble functional failure.
c.
Conclusions The licensee's procedures, draft periodic assessment for the EDGs. and quarterly report for all SSC's implemented the requirements of the Rule and were considered a maintenance program strength.
M1.6 Goal Settina and Monitorina for (a)(1) 55Cs a.
Insnection Scoce (62706)
The inspector reviewed program documents and records in order to evaluate the process that had Deen established to set goals and monitor under paragraph (a)(1) of the Rule.
The inspectors also discussed the program with the Maintenance Rule Administrator and system engineers.
The inspector reviewed the systems described telow to verify: that goals or performance criteria were established with safety taken into consideration:
that industry-wide operating experience was considered where practical; that appropriate monitoring and trending was being performed: and. that corrective action was taken anen SSCs Miled to meet goal or performance criteria. or when SSC experienced a maintenance prevent 1ble functional failure (MPFF).
b.
Observations and Findinos The inspector reviewed selected sy tems containing SSCs that were considered
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as within the sccDe of the Mainten nce Rule and were monitored under paragraph (d)(1) of the Rule.
These system, included SSCs wnich have not met established performance criteria or were a leading contributors in exceeding plant level perfc"mance criteria for unavailability.
Scecifically the inspector verifiec that the licensee had.1mplementeo goal setting and monitoring as recaired by paragraph (a)(1) of the Rule fcr the Unit 1
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Auxiliary Feedwater (AFW) Train and the Reactor Coolant Pump Seals.
The Unit 1 'C'AFW train exceeded its performance criteria for e
reliability when it experienced three MPFFS in an 18 month period.
The primary cause of the MPFFs was due to corrosion on electrical contact surfaces in the turbine pump governor coil and a motor operator valve (MOV)(SMB-000) torque switch.
As corrective action the licensee upgraded the SMB-000 actuator and the Unit 1 EGR coil resistance PMs from a 18 months frequency to a 6 months frequency and required that as-found and as-left resistance checks be performed.
The reliability criteria was also changed from s 2MPFFs/ train per 18 months to no SBM-000 actuator PMT contactor failures after new the PM is implemented for 18 months and no as found out of spec EGR resistance checks for 18 months.
The inspector however noted a problem with the goals established by the licensee in that, the system engineer had no basis for the acceptance criteria had been established for the resistanco checks.
The system engineer had elected to establish a starting point for monitoring resistance of one hundred OHMS resistance for the governor coil and adjust the acceptance criteria after monitoring the PM values for 18 months.
This seem satisfactory to him because the as-found failed condition of the governor coll was one thousand OHMS.
The torque switch resistance check start monitoring point was set at two hundred Mil-OHMS per instructions from a electrical engineer.
The inspector noted however. that the value given for the governor coil resistance checks in the technical manual was 35 OHMS.
The inspector considered the technical manual values should have been used when establishing preliminary acceptance criteria for taking resistance readings and additional points could be obtained by taking measurements on in-hocse spare.; and/or values established by industry using industry oper % c: a ience.
The system engineer could still monitor oev1ations from this norm to align the criteria for the environmental conditions at the St. Lucie Plant.
As a result of questioning the
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acceptance criteria, the system engineer contacted an electrical engineer who advised the system engineer to use resistance check criterla within 125% of the 35 OHMS recommended in the vendor technical manual.
The system engineer 'nformed the inspector that value would be
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used.
However, the inspector considered the licensee's failure to use l
l acceptance criteria recommended in the vendor technical manual when l
l setting a goal to be a weakness in the licensee's maintenance program.
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The Unit 1 and Unit 2 Reactor Coolant Pump (RCP) Seals were a large l
contribution to exceeding the plant level unavailability criteria when i
1A2 RCP seal failed in August 1995 and in April 1996. and the 2A2 RCP experienced a failure in September 1995.
However. the RCP seals in
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themselves aid not lead directly to tne criteria being exceeded.
The l
i licensee's expert panel elected as a conservative entry to put the RCP l
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seals into category (a)(1) in order to establish realistic goals and closely monitor the performance of a risk significant SSC.
The inspector interviewed the system engineer for the reactor coolant system and noted with pleasure that this engineer keep an excellent notebook on his system. this notebook included trending data on each pump to determine approorlate RCP seal life.
Other data requested during the interview was also found well documented in this noteDook.
The inspector attended a management training meeting on the RCP seals:
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expert panel meeting minutes on the RCP seals were reviewed: as well as corrective action documents such as STAR 1-950988. Problem Report 95-017. Condition Report 96-598 and RCP 1A2 Seal Root Cause Analysi's dtd August 25, 1993.
The inspector also reviewed the corrective action taken by the licensee as well as the goals set to improve the performance of the RCP seals which included increasing the frequency for changing the RCP seals out to no more than two cycles.
In addition next outage the licensee will install an enhanced (N9000 Series) seal in one RCP pump to verify its improve performance capabilities with the intention of going to this seal if upgraded performance can be established.
c.
Conclusion The licensee has considered safety in establishment of monitoring and goals for the above SSCs.
However, failure of the licensee use vendor establish acceptance criteria for verifying -acceptable contact point resistance in the governor coil for the turbine pump on the Unit 1
'C' AFW train was considered to be maintenance program weakness.
M1.7 Preventative Maintenance and Trendina SCCs (a)(2)
a.
Inspection Scoce (62706)
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The inspector reviewed licensee documentation and records in order to evaluate the process that had been established to set performance criteria and monitor under paragraph (a)(2).
The inspector also attended a expert panel meeting on revisions to the scoping document for monitoring the effectiveness of maintenance on structures, discussed the program for the steam generators and structures with the Maintenance Rule Coordinator. and interviewed the system engineers for the SSCs examined.
The inspectors reviewed the systems and structures described below to verify:
that performance criteria were established with safety taken into consideration: that industry-wide operating experience was considered where practical; that appropriate monitoring and trending was being performed; and that corrective actions were taken when SSCs failed to meet performance criteria or when a SSC experienced a MPFF.
b.
Observations and Findinas The inspector reviewed portions of selected systems containing SSCs that were considered as being within the scope of the Maintenance Rule. but were not monitored under paragraph (a)(1) of the rule.
These systems included main steam and reactor coolant for the steam generators and select structures which specifically incluced the Unit 1 refueling tank and foundation. Unit 1 intake structure and retaining walls, and operations support building.
l Structures - Based on interviews with the cognizant engineer within the
licensee's civil engineering organization and review of the following implementing procedures: ADM-17.08 (Implementation of 10 CFR 50.65. The Maintenance Rule). Scoping Document for the Implementation of the Maintenance Rule for Monitoring the Effectiveness of Maintenance on Structures (Revision 2). SCEG-003 Rev. 1 (Guldeline for the Condition
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Survey of Structures and Supports by Plant Personnel). and SCEG-009 Revision 0 (Guideline for Maintenance Rule Structural Condition Monitoring by a Qualified Inspector). the inspector concluded that the licensee had selected the correct structures to be monitored under the Maintenance Rule and had established a systematic program for monitoring the condition of these structures.
The licensee has begun the initial baseline survey of structures which to date has consisted of the Unit I refueling water storage tank and the Unit 1 intake structure and retalning walls.
All baseline inspections are to be completed by December 31, 1997.
Periodic surveys will then be performed throughout the life of the plant on intervals not to exceed five years.
The inspection attributes used in the walkdowns for baseline inspections and the periodic surveys of structures are based on applicable design criteria as implemented in the above procedures using surveillance check sheets.
Significant discrepancies identified during walkdown down inspections are identified in condition reports and photographs are taken of the findings in order that comparisons can be made of discrepant conditions during subsequent inspections.
The licensee uses knowledgeable and experienced civil engineers to perform the structural i
inspections.
The inspector reviewed the results of the licensee's baseline inspection for the Unit 1 intake structure and discovered that the Condition Report for intake structure listed 15 different line items of discrepancies for this structure.
Photographs of the discrepancies revealed cracks and segregatjons.
However. the inspector also found that the licensee has no established performance criteria for moving a structure from the (a)(2) category and placing it in the (a)(1) category for additional monitoring and goal setting.
The inspector questioned the civil engineer as to how bad of condition would the intake structure would have to be in before it would place into the (a)(1) category.
The engineer stated that. although there was no criteria he would probably place this structure in (a)(1) the next interval inspection if degradation continues.
The engineer also stated that. he would revise his structural procedure to set performance criteria that would get him to (a)(1).
However, the problem of no performance criteria for structures is a industry wide problem and has been identified before by NRC. The reason for the problem is that there is presently no industry guidance in this area.
Inspector Followup Item No. 50-335.389/96-13-04
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.was identified by the inspector for the licensee to provide procedural guidance associated with performance criterla for structures after resolution of this issue with the industry.
The main steam system was reviewed by the inspector to determine why the e
Unit 1 steam generators were in (a)(2) and not (a)(1) when they had caused a 40 day extension of the July 1996 outage and are scheduled to be replaced next refueling outage.
The licensee's position for the i
steam generators not being in (a)(1) was that the major tube degradation that they are finding now was cause when the plant first went
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l operational and sulfur was found in their secondary cooling water.
This l
problem was corrected several years before the 3 year historical review required by the Rule and no other corrective action can be taken at this point that is not already being taken to correct this problem.
Therefore, the licensee contends that further tube degradation is not maintenance preventable. but caused by the design of their steam generator supports and additional industry reviews are ongoing to
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support this theory The licensee also stated that. the Unit 1 steam-generators are tentatively st Mdule to be replaced during the next refueling outage.
The inspector however. considered that sufficient historical data of degraded tubes existed for these generators to have been placed in (a)(1) and failure to do so was considered a program weakness.
The inspector interviewed the main steam system engineer, to obtain information on tube failures and the status of eddy current examinations and subsequent plugging activities.
The inspector found that the system engineer for the main steam system has held the job for less than two months and although, the steam generators are listed as the major component in the main steam system, the risk significant portion of the steam generators and associated Maintenance Rules functions derived from the Technical Specifications are listed under the reactor coolant system.
Neither the main steam nor the reactor coolant system engineer knew they had the steam generator tubes.
However, both enginsers had a basic understanding of the Maintenance Rule.
During subsequent discussions, the Maintenance Rule Administrator stated that he considered as least the primary side and possibly the entire steam generator and should be under the reactor coolant system and that he intended to change the program to reflect this.
The inspector however, considered the lack of ownership of the steam generator tubes to be a weakness in the licensee's program.
c.
Conclusions The inspector concluded that the licensee had selected the correct structures to be monitored under the Maintenance Rule and had establishea a systematic program for monitoring the condition of these structures.
However. Inspector Followup Item 50-335.389/96-13-04 was identified for the licensee to provide procedural guidance associated with performance criteria for structures after resolution of this issue with the industry.
The licensee also contends that present steam generator tube degradation is not caused by a maintenance preventable functional failure but by the design of their steam generator supports and additional industry reviews are ongoing to support this theory.
The inspector however. considered that sufficient historical data of degraded tubes existed for these generators for them to have been placed in (a)(1) and failure to do so was considered a program weakness.
In addition. the inspector considered the lack of ownership of the steam generator tubes to be a weakness in the licensee's program.
M2.1 Maton al roncition Walkdowns a.
Insoection Scope (62706)
In the scope of verifying the implementation of the Maintenance Rule using NRC Insr,ection Procedure 62706. the inspector performed a walkdown to examine material condition on portions of the Auxiliary Feeowater system.
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Obspevat'cas and Finainos
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The inspector's material condition walkdown of selected portions of Auxiliary
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i, Feedwater system revealed that: housekeeping in the general areas around system and components was acceptable: piping and components were painted and no indications of corrosion. oil leaks. or water lea (s were evident: and no damage. or degraded equipment was noted.
c.
Conclusions
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The material condition of selected portions of the Auxiliary Feedwater system
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examined during the inspection was satisfactory.
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E2.1 Review of UFSAR Commitments While performing the inspections discussed in this report. the irispector reviewed the applicable portions of the UFSAR that related to the areas inspected.
The inspector verified that the UFSAR wording was consistent with the observed plant practices. procedures and/or parameters.
E4.1 Enaineer Knowledae of Maintenance Rule a.
Insnection Scoce (62706)
The inspectors interviewed licensee engineers within the system engineering
' organization to assess their understanding of the Maintenance Rule and associated responsibilities.
b.
Observations and Findinas The System Engineer for the RCP seals and the civil engineer for structures had considerable engineering experience and knowledgeable of their assigned area.
The system engineer for the RCP seals been proactive in development and implementation of corrective actions.
Both of these engineers had i;een active participants in the development of the Maintenance rule criteria (including procedures for the civil engineer) for their systems. 'The system engineers for AFW and the main steam systems are newly assigned to these systems and laQad some of the historical information for their assigned systems.
The AFW systen: engineer had been a system engineer for another system two months prior to the lnspection and had a better much better understanding of the Rule and his system than the main steam system engineer.
All the engineers interviewed by the inspector understood the specific requirements of the Maintenance Rule.
However, the performance criteria for the AFW and the main steam systems had been developed for the system engineers prior to their system assignment.
c.
Conclusions All engineers interviewed by the inspector knew the specific requirements of the rule.
Two of the system engineers had only had their systems two months prior to the inspection.
The system engineers for the Auxiliary Feedwater System and the Main Steam System lack some historical information for their assigned systdms.
Documents received from the licensee durina conduct of my insoection activitias 1.
Palo Verde Plant Update (Technology Transfer) dated September 19.1996
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St. Lucie Unit I and 2 Steam Generator Plug Status l
3.
St. Lucie Condition Report No. 96-2037 (Steam Generator Tube i
degradation)
St. Lucie Unit 1 Steam Generator Eddy Current & Tube Plugging History 5.
St. Lucie Condition Report 96-598 (RCP 1A2 Pump Seal)
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RCP 1A2 Seal Root Cause Analysis Dated August 25. 1993
St. Lucie STAR 1-950988 8.
St. Lucie ADM-17.03 Revision 6 " Operating Experience Feedback" 9.
NUMARC 93-01 Revision 2. " Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants" 10.
St. Lucie Plant SCE Problem Report 95-017. (RCP 2A2)
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St. Lucie Plant Maintenance Rule Periodic Assessment (Draft)
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Scoping Document for the Implementation of the Maintenance Rule for Monitoring the Effectiveness of Maintenance on Structures. Rev. 2
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File No 5:\\DRS\\ SIB \\ INPUTS \\STL9613.JLC i
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,1 INSPECTOR'S INPUT St. Lucie 96-08 A.
Inspector Concurrence:
J. L. Coley. Jr. Reactor Inspector Branch Chief Concurrence:
P. E. Fredrickson Branch Chief Special Inspection Branch B.
1.0 Persons Contacted
- E. Benkien. Licensing Engineer
- W. Bladow. Site Quality Manager
- C. Burton Site Service Manager
- F. Carr. Nondestructive Examination. Technical Specialist
- J. Connor. Manager. Components and Systems Inspection
- D. Denver. Manager. Engineering
- R. Dietz. Licensing Engineer
- H. Johnson. Manager. Operations
- J. Marchese. Manager. Maintenance
- J. Scarola. Plant General Manager
- E. Weinkam. Manager. Licensing Other licensee employees contacted during this inspection included technicians. and engineers.
C.
Input for appropriate inspection area.
3.0 Maintenance 3.1 Observation of Inservice Inspection Work Activities - Unit 1 (73753)
This inspection is a continuation inspection, see NRC Inspection Report 96-06 for additional details involving this area of examination.
On May 13. 1996 the inspector returned to the St. Lucie facility inspector to observed inservice inspection activities and to determine if these activities are conducted in accordance with applicable procedures, regulatory requirements. and licensee commitments.
The inspector's ODjective was to examine the licensee's steam generator examination and evaluation activities and the 10-year ultrasonic examination of the reactor vessel.
The applicable code for this ISI.s the American Society of Mechanical Errgineers (ASME) Boller and Pressure Vessel (B&PV) Code.Section XI. 1983 Edition with Summer 1983 Addenda.
St Lucie Unit 1 is presently in the first outage of the third 40 month period. of the second 10-year ISI intervai.
This is the thirteenth refueling l
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Eddy current acquisition activities were conducted by ASEA. Brown
& Boveria INC ( ABB)/ Combustion Engineering.
Primary analysis of eddy current data was conducted by Zetec in Issaquah. Washington and the secondary analysis was conducted by ABB at the Florida Power and Light NDE Laboratory in West Palm Beach. Florida.
The 10-year Reactor Vessel examinations were conducted by Southwest Research Institute.
3.1.1 Observation of Steam Generator Eddy Current Acquisition ana Data Analyses Activities
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On May 13. 14. and 16. 1996. the inspector observed portions of the licensee's eddy current data acquisition activities.
These activities wer.e conducted in accordance the with approved procedures delineated in NRC Inspection Report No.
96-06 and the FP&L Steam Generator Eddy Current Examination Plan.
On May 15. 1996, the inspector went to FP&L's NDE Center in West Palm Beach. Florida to examine FP&L's eddy current analyses activities.
These activities were also conducted in accordance with approved procedures and industry guiuelines delineated in NRC Inspection Report 96-06.
At this point of the inspection the licensee had identified numerous rejectable indications.
However, some of the rejectable indications were found in areas where they were not expected.
These areas included two tubes which exhibited circumferential cracking at the top of the tube sheet in the A Steam Generator Cold Leg.
This will require i
the cold leg side of both steam generator to be examined 100% with a motor rotating pancake coil.
In addition an.
axial-indication was found in the free span area between support plates 7 & 8.
This is an area of concern that will require expansion examinations because there is no inherent condition which should cause crack initiation in this area.
As a result of the present expansion' examinations the licensee has added approximately a week to the steam generator eddy current and plugging activities.
The inspector also reviewed qualification and certification records for all eddy current personnel.
In addition, equipment calibration records were verified.
During the inspection period the inspector was also a party to NRC's Office of Nuclear Reactor Regulations (NRR)
telephone calls with the licensee.
These calls dealt with FP&L's steam generator tube inspection plans. tube expansion plans. in-situ pressure testing plans and tube plugging plans.
The licensee was pro-active in keeping NRR informed of their inspection findings and correction action plans and
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all actions taken by the licensee at this point appeared to be conservative.
During the next refueling outage (Cycle 1M the licensee intenas to replace the steam generator tube bundles in both Unit 1 steam generators.
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t 3.1.2 Observation of Work Activities Associated with the 10-Year Inservice Inspection of the Unit-1 Reactor Pressure Vessel As a result slippage in the defueling schedule the ultrasonic examinations of reactor vess31 were not conducted during this inspection period.
However, as partially reported in NRC Inspection Report 96-06, the inspector did reviewed the applicable nondestructive examination
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procedures. visited the Electric Power Research Institute (EPRI) in Charlotte. N.C. to review EPRI's methods of testing for one sided access examinations, reviewed analyst performance demonstration qualification records, verified ultrasonic equipment calibration records, and verified the setup of the ultrasonic system both in the plant and in the remote acquisition and analysis station.
During the inspector May 10. 1996 visit to the EPRI NDE Center (as report in NRC Inspection Report No. 96-06) the l
inspector was surprised to find that the qualification examinations given for or.e sided weld access examinations were conducted on test samples which did not have a weld joint in them. The inspector was concern that the
demonstration test did not accurately depict plant
conditions because the acoustical differences of the weld metal an< the base material which should have some limiting effects on the examination.
In addition. the differences in the lay of defect indications on far side of the welds had l
not been addressed by EPRI even in an analytical manner.
EPRI position was that in their opinion the missing weld l
would not make a significant difference in the detection and l
sizing of indications in the carbon steel reactor vessel.
l Although not disagreeing with EPRI. the inspector felt that i
the difference should be defined and factored into the l
difficultly of the single side weld access performance j
demonstration test, and actual reactor vessel examinations
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if necessary.
On May 13. 1996, when the inspector returned to the St.
Lucie plant, the above issue was discussed with FP&L licensing and NDE personnel.
As a result of these discussions the licensee offered the following response to this item.
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"FPL Response: We contend that a weld is not necessary in carbon steel vessel material.
Because this is a completely
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1sotropic medium which has minimal influence on the passage
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of ultrasonic waves.
We intend to prove this by the following:
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As a member of the Performance Demonstration In'iative (PDI). FPL has initiated action at the EPRI NDE Center to address the issue.
The PDI program was used to conduct the demonstration therefore it is incumbent of
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them to defend their position.
We expect them to produce empirical data from previous study or a
demonstration to show that the presence of a weld in vessel material is insignificant.
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The examination contractor (Southwest Research Institute) will look at producing similar empirical data form their studies.
If necessary, will measure ultrasonic beam attenuation in similar material with and without a weld"
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The licensee also stated they would assign a licensing i
No. to this item to insure that the issue is properly
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tracked and that a copy of the result, would be i
forwarded to the inspector.
The inspector considered the licensee actions to be responsible and adequate to resolve this concern.
D.
7.0 Exit Meeting The inspection scope and results were summarized on May 17, 1996.
during a pre-exit meeting with the licensee.
The inspector described the areas inspected and discussed in detail the inspection results which included FPL's response to the inspector concern that EPRI's performance demonstration qualification test samples did not include a weld for one sided access weld examinations.
Proprietary information is not contained in this report.
Dissenting comments were not received from the licensee.
E.
8.0 Review of UFSAR Commitments
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A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR description highlighted the need for additional verification that licensees were complying with the UFSAR commitments.
During an approximate two month time period all reactor inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices.
procedures, and/or parameters.
While performing the inspections which are discussed in this report the inspectors reviewed tne applicable portions of the Updated Final Safety Analysis Report (UFSAR) that related to the areas,nspected.
The inspectors verified that the UFSAR wording was consistent with the observed plant practices. procedures ar1d/or parameters.
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ASEA. Brown and Boveria ASME
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American Society of Mechanical Engineers
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Electric Power Research Institute Florida Power and Light
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Nondestructive Examination NRC
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Nuclear Regulatory Commission NRR
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Office of Nuclear Reactor Regulations.
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Performance Demonstration Iniative UFSAR -
Updated Final Safety Analysis Report
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10.0 Summary Statement The licensee's inservice inspection activities for the steam generator tube eddy current examination activities and the 10-year reactor vessel examinations were well planned.. performed, and managed by very talented and knowledgeable NDE personnel.
No violation or adverse tend was noted
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in any area examined.
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INSPECTOR INPUT TO INTEGRATED INSPECTION REPORT
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St. Lucie INPUT FOR INSPECTION REPORT NO.:
50 335.389/96 14 s
INSPECTOR:
James L. Coley, Jr.
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Reactor Inspector. Special Inspection Branch
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Division of Reactor Safety i
DATES OF INSPECTION:
No onsite inspection performed. This input documents l
actions taken by the Florida Power and Light (FP&L)
and the Electric Power Research Institute's (EPRI),
Nondestructive Evaluation Center in Charlotte. North Carolina to address an inspector's concern regarding one sided weld inspections performed on the Unit 1
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reactor vessel in May 1996.
FP&L forwarded EPRI letter on above subject on August 15, 1996.
Inspector:
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James L. Coley, Jr. Reactor Inspector Date Signed Approved:
P.E. Fredrickson. Chief Date Signed i
Special Inspection Branch Division of Reactor Safety 1.0 Persons Contacted:
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Licensee Employees T. Quinlen. Regulatory Compliance Engineer M8 Miscellaneous Maintenance Issues M8.1 Significance and Effect of Weld Volumes within ASME Section XI. Appendix VIII.. Supplement 4 and 6 Performance Demonstration Test Specimens
'Although the Authorized Nuclear Inspector (ANI) for Florida Power and Light (FP&L) had approved single side weld examination techniques demonstrated by Southwest Research Institute (SwRI). nondestructive test (NDE) examiners at the Electric Power Research Institute, the inspectors had questions concerning single side weld access test parameters and examiner's performance that could only be addressed at the EPRI NDE Center (see Region 11 Inspection Report 96-06 for further details).
On May 10. 1996. the inspectors and a representative from FP&L visited the EPRI NDE Center in Charlotte. North Carolina, to review the performatice demonstration examination results for the four Southwest Research Institute data analysts that would be used by FP&L to examine the Unit 1 reactor vessel.
This review was necessary because FP&L's Relief Request entitled " Request for Authorization of Alternative Examination Methods" had two alternative examinations proposed by the licensee that had changed since NRC had originally approved the relief
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request.
The relief request addressed Unit I reactor pressure vessel
welds which had limiting conditions that prevented 100% examination
coverage.
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i The first charige was that the licensee had initially stated that a full vee 45 shear wave examination would be performed.to the extent practical to compensate for recorded limitations However. SwRI
examination procedures did not have this examination method in them.
The second change to the April 1995 Relief Request stated that, FP&L
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would employ. as'they became available. additional examinations.
inspections and/or techniques that would provide a substantial increase
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in the examination of areas currently missed under the current examination techniques.
To comply with their commitment to employ examination techniques that provide a substantial increase in the examination of weld areas currently missed. FPSL had SwRI qualify to the performance demonstration examinations conducted by the EPRI NDE Center for a single side weld
access examination.
These examinations are to be conducted in-accordance with Appendix VIII of later editions of the ASME Code. The editions of the Code which include Appendix VIII have not been approved for use by NRC at this time.
The applicable ASME Section XI Code i
presently requires that a weld be examined from two directions (both sides of a weld). Therefore, to supplement the Unit 1 Reactor Vessel examinations with these new alternative techniqu9s the licensee invoked paragraph IWA-2240 of the ap)licable ASME Code wioch states that, l
" alternative examination metlods, or newly developed techniques may be l
substituted for the methods specified provided the ANI is satisfied that l
the results are demonstrated to be equivalent or superior to those of the specified method".
During the inspectors visit to the EPRI NDE Center the inspectors identified that the qualification examinations given for' one sided weld access examinations were conducted on test samples which did not have a weld joint in them.
The inspectors were concerned that the demonstration test did not accurately depict plant conditions because there are acoustical differences between weld metal and base material which could effect the results of the examinations.
In addition, the differences in the lay of defect indications on far side of the welds had 'not been addressed by EPRI even in an analytical manner.
The EPRI position was that, the missing weld would not make a sianificant
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difference in the detection and sizing of indications in the carbon steel reactor vessel.
Although not disagreeing with EPRI. the inspectors felt that the difference should be defined and factored into
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l the difficultly of the single side weld access performance demonstration i
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test, and actual reactor vessel examinations if necessary.
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On May 13. 1996. the inspectors returned to the St. Lucie plant and the
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i above issue was discussed with FP&L licensing and NDE personnel. As a i
result of these discussions the licensee offered the following response l.
to this item:
FPL Response: "We contend that a weld is not necessary in carbon steel
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vessel material.
Because this is a completely isotropic medium which has minimai influence on the passage of ultrasonic waves.
We intend to prove this by the following:
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As a member of the Performance Demonstration Initiative (PDI). FPL has initiated action at the EPRI NDE Center to address the issue.
The PDI program was used to conduct the demonstration therefore it is incumbent of them to defend their position.
We expect them to produce empirical data from previous study or a cemonstration to show that the presence of a weld in vessel material is insignificant.
OR/
The examination contractor (Southwest Research Institute) will look at producing similar empirical data form their studies.
If necessary, will measure ultrasonic beam attenuation in similar material with and without a weld">
The licensee also stated they would assign a licensing No. to this item to insure that the issue is properly tracked and that a copy of the result, would be forwarded to the inspector.
On August 15. 1996. FP&L provided the inspectors an August 8. 1996.
letter from EPRI to FP&L which addressed an evaluation conducted by EPRI to determine the significance and effect of weld volumes within ASME Section XI. Appendix VIII. Supplement 4 and 6 performance demonstration test specimens.
The evaluation was conducted on a practice mockup.
The i
material for practice specimen was obtained from the nozzle course of.
the same vessel that was used for the PDI PWR shell performance demonstration specimens.
To facilitate the evaluation the original weld seam was identified by acid etch of the plate. An EDM notch and a side drilled hole were fabricated in the specimen at appropriate positions (Note: specimen ID and reflector dimensions are not used in this report to protect the identity of PDI practice and/or test mockups).
Ultrasonic measurements were taken from both reflectors with the sound passing only through the plate material and then with the sound passing
.through the plate material and the weld seam.
From the results obtained. the EPRI NDE Center reached the following conclusions:
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Comparison for the attenuator/ amplitude measurements from both the hole and the notch indicate the weld seam does not have any measurable effect on the amplitude of an ultrasonic reflector.
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Plotting of the ultrasonic Deam indicates tne Deam continues in a straignt line and is not redirected by the weld seam.
l The inspector considers actions taken by FP&L and EPRI regarding the
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insDector's concern to be resoonsible and adeouate.
This issue is considered closed.
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