ML13333B224
| ML13333B224 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 02/07/1985 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML13333B222 | List: |
| References | |
| 50-206-84-32, 50-361-84-31, 50-362-84-32, NUDOCS 8502270030 | |
| Download: ML13333B224 (59) | |
See also: IR 05000206/1984032
Text
SALP BOARD REPORT
U.S. NUCLEAR REGULATORY COMMISSION
REGION V
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
CYCLE 5
Report Nos:
50-206/84-32
50-361/84-31
50-362/84-32
SOUTHERN CALIFORNIA EDISON COMPANY
SAN ONOFRE UNITS 1-3
ASSESSMENT PERIOD:
June 1, 1983 -
September 30, 1984
s5D0 2 2 700 3 OeO5002 6
ID A
O
5000
Table of Contents
Page
I.
Introduction
1
II.
Criteria
1
III. Summary of Results
2
IV. Performance Analyses
3
A.
Plant Operations
3
B.
Radiological Controls
7
C.
Maintenance
9
D.
Surveillance
12
E.
Fire Protection
15
F.
16
G.
Security
17
H.
Refueling
18
I.
Quality Programs and Administrative Controls
18
J.
Licensing Activities
22
K.
Startup Testing
28
V.
Supporting Data and Summaries
28
A.
Licensee Activities
28
B.
Inspection Activities
30
C.
Investigations and Allegations Review
31
D.
Escalated Enforcement Actions
31
E.
Management Conferences Held During Appraisal Period
32
F.
Review of 10 CFR 21 Reports and Licensee Event Reports 32
Tables
Table 1 -
Inspection Activity and Enforcement Summary
37
Table 2 -
Licensee Event Reports, Unit 1
38
Licensee Event Reports, Unit 2
39
Licensee Event Reports, Unit 3
50
I.
INTRODUCTION
The Systematic Assessment of Licensee Performance (SALP) program is an
integrated NRC staff effort to collect available observations and data on
a periodic basis and to evaluate licensee performance based upon this
information. SALP is supplemental to normal regulatory processes used to
ensure compliance to NRC rules and regulations.
SALP is intended to be
sufficiently diagnostic to provide a rational basis for allocating NRC
resources and to provide meaningful guidance to the licensee's management
to promote quality and safety of plant construction and operation.
A NRC SALP Board, composed of the staff members listed below, met on
November 15, 1984, to review the collection of performance observations
and data to assess the licensee's performance in accordance with the
guidance in NRC Manual Chapter 0516, "Systematic Assessment of Licensee
Performance." A summary of the guidance and evaluation criteria is
provided in Section II of this report.
This report is the SALP Board's assessment of the licensee's safety
performance at the San Onofre Nuclear Generating Station (SONGS) for SALP
Cycle 5, covering the period June 1, 1983 through September 30, 1984.
SALP Board for San Onofre, Units 1-3:
D. F. Kirsch, Acting Director, Div. of Reactor Safety and Projects, RV
A. E. Chaffee, Chief, Reactor Projects Branch, RV
P. H. Johnson, Chief, Reactor Projects Section 3, RV
D. P. Haist, Project Inspector, RV
F. R. Huey, Senior Resident Inspector
J. P. Stewart, Resident Inspector, RV (by telephone)
A. J. D'Angelo, Resident Inspector, RV (by telephone)
A. D. McQueen, Physical Security Inspector, RV
G. P. Yuhas, Chief, Facilities Radiological Protection Section
H. S. North, Senior Radiation Specialist, RV
C. I. Sherman, Radiation Specialist
R. F. Fish, Senior Emergency Preparedness Analyst, RV
G. Temple, Emergency Preparedness Inspector
H. Rood, Project Manager SONGS-2/3, NRR
E. M. McKenna, Project Manager SONGS-1, NRR
II. CRITERIA
Licensee performance is assessed in selected functional areas, depending
on whether the facility is in a construction, preoperational, or
operating phase. Each functional area normally represents programmatic
areas significant to nuclear safety and the environment. Some functional
areas may not be assessed because of little or no licensee activities or
lack of meaningful observations.
Special areas may be added to highlight
significant observations.
The following evaluation criteria were used to assess each functional
area, as appropriate.
1.
Management involvement and control in assuring quality
2
2.
Approach to resolution of technical issues from a safety standpoint
3.
Responsiveness to NRC initiatives
4.
Enforcement history
5.
Reporting and analysis of reportable events
6.
Staffing (including management)
7.
Training effectiveness and qualification
The SALP Board, however, is not limited to these criteria and others may
have been used where appropriate.
Based upon the SALP Board assessment each functional area evaluated is
classified into one of three performance categories. The definition of
these performance categories is:
Category 1. Reduced NRC attention may be appropriate. Licensee
management attention and involvement are aggressive and oriented toward
nuclear safety; licensee resources are ample and effectively used so that
a high level of performance with respect to operational safety or
construction is being achieved.
Category 2. NRC attention should be maintained at normal levels.
Licensee management attention and involvement are evident and are
concerned with nuclear safety; licensee resources are adequate and are
reasonably effective so that satisfactory performance with respect to
operational safety or construction is being achieved.
Category 3. Both NRC and licensee attention should be increased.
Licensee management attention or involvement is acceptable and considers
nuclear safety, but weaknesses are evident; licensee resources appear to
be strained or not effectively used so that minimally satisfactory
performance with respect to operational safety or construction is being
achieved.
III. SUMMARY OF RESULTS
Overall the board finds that licensee performance is acceptable and
directed toward safe facility operation.
In addition, the board finds
that the licensee's overall performance has improved since the last SALP
evaluation period.
Individual areas which contributed to this overall
improvement are plant operations, maintenance, radiological controls and
security. The board found aggressive management attention and a high
level of performance in the areas of quality programs and administrative
controls and SONGS-3 startup testing, which were not specifically
addressed in the previous SALP evaluation period. The licensee's
performance rating in the area of plant operations has improved, but
requires continued attention to minimize instances of personnel error
and inadvertent compromises of engineered safety feature availability.
3
Rating
Rating
Trend During
Functional Area
Last Period
This Period
This Period
A. Plant Operations
3
2
Improving
B. Radiological Controls
3
2
Improving
C. Maintenance
2
1
Improving
D. Surveillance
2
2
None Apparent
E. Fire Protection
2
2
None Apparent
1
1
None Apparent
G. Security
2
1
Improving
H. Refueling
1
N/A
N/A
I. Quality Programs and
N/A
1
N/A
Administrative Controls
(includes Unit-I modifications)
J. Licensing Activities
2
2
None Apparent
K. Startup Testing (Unit 3) N/A
1
N/A
IV. PERFORMANCE ANALYSIS
A.
Plant Operations
1.
Analysis
During the current SALP assessment period, 3924 hours0.0454 days <br />1.09 hours <br />0.00649 weeks <br />0.00149 months <br /> of direct
inspection effort were applied in the area of plant operations
at San Onofre Units 1, 2 and 3. These inspection activities
resulted in the issuance of 4 notices of violation and 3 civil
penalties totaling $165,000. The summary assessment of
individual unit operation, overall conclusion as to site
performance category and board recommendations are discussed
below. With regard to the assignment of an overall site
performance category, it should be noted that more emphasis was
placed on Unit 2/3 performance than on Unit 1, which was shut
down during the entire assessment period.
Unit 1 Operations
During this SALP period, Unit 1 has remained in Mode 5 for the
completion of seismic modification activities. No violations
were issued during this period in the area Unit 1 operations.
Management has emphasized the use of prior planning and
assignment of priorities for the control of activities.
Conservatism is routinely exhibited by management at the Onsite
Review Committee meeting in that references are made to the
standard technical specification and any differences which
exist with the San Onofre technical specification.
Licensee responsiveness is usually technically sound and
thorough as exhibited by recent actions such as the addition of
temporary diesel generators onsite during the Transamerica
DeLaval (TDI) diesel generator inspection effort. A total of 3
Licensee Event Reports (LER) were issued during the period
4
applicable to plant operations. All LER's were reported in a
timely manner and adequately described the event.
Staffing for the period was adequate and appeared to be well
controlled. Backlog work activities and overtime by the
operations staff have been infrequent and do not appear to be
degrading their performance. In this regard, no serious
operator errors have occurred.
The training and qualification program appears to be adequate.
It has been noted, however, that a weakness existed in recent
training activities in that some Unit 1 design changes had not
been distributed to the training organization for inclusion in
the training program. This oversight was promptly corrected by
the licensee.
Units 2/3 Operations
Site management has been actively involved in Unit 2/3
operations. They have been aggressive in their pursuit of the
underlying causes of plant problems and have been thorough and
innovative in addressing proper and effective corrective
actions, particularly during the second half of this period.
Plant managers are frequently involved in site activities and
key evolutions. Frequent NRC resident interface with various
levels of plant supervision and management have demonstrated
generally a clear understanding of technical issues involving
plant safety. The Onsite Safety Review Committee has been
active and effective in providing conservative and technically
sound resolution of plant problems affecting safety. The
licensee has been responsive and straightforward in
dealings with the NRC in all levels of interface.
Staffing for the period was adequate and appeared to be
effectively controlled. Backlog work activities and light
overtime by the operations staff have been periodic but do not
appear to be degrading their performance. The training and
qualification program appears to be adequate; however, training
program weaknesses are indicated in the area of operator system
knowledge as demonstrated by the improper alignment of safety
system valves discussed below. The licensee has refocused the
operators training program in the areas of systems knowledge
and working knowledge of administrative controls to control
plant configuration. This has contributed to improved
performance in the second half of this period.
In spite of an overall aggressive pursuit of excellence by site
management, as noted above, a review of enforcement history and
reportable events during the current assessment period reveals
significant difficulty, during the first nine months of this
period, in the ability of management to effectively implement
and achieve the operational goals which they have set. As
noted above, the NRC cited, in the earlier part of this period,
four violations involving three civil penalties. The following
1)15
is a summary of all enforcement items and reportable events
occurring during this period.
Enforcement Items
1.
Improper isolation of charging pump rendered Unit 3
Emergency Core Cooling System inoperable on 9/29/83.
Level III violation. Civil penalty, $20,000.
2.
Failure to follow operating instruction S023-0-36, Control
of System Alignments, associated with the above item.
Level III violation. Civil penalty, $20,000.
3.
Improper isolation of Unit 3 containment spray system on
March 4, 1983, which was not discovered until March 17,
1984. Level III violation. Civil penalty, $125,000.
4.
Improper Mode 1 operation of Unit 3 with a diesel
generator inoperable and the redundant ESF train degraded
due to the inoperable containment spray system. Level III
violation.
A severity level IV violation, specifically identified in
Section B, Radiological Controls, was issued for failure to
declare and report an Unusual Event in a timely fashion. This
violation resulted from various contributing factors including
operator training and systems knowledge, response to alarms and
procedural inadequacies. In this case the alarm response
procedure did not refer the operator to the emergency plan
implementing procedure. Consequently, the alarm was not
recognized as signaling an Unusual Event. The operators failed
to consider recent past plant evolutions in the attempt to
identify and correct the cause of the release. When such
evolutions were evaluated, the release was promptly terminated.
The operators' evaluation of the event was hampered by the fact
that certain monitors were out of service and the indications
of available monitors appeared to be ambiguous unless the
peculiarities of the HVAC system were understood. The licensee
took prompt corrective action to deal with the identified
problems.
Reportable Events
Reportable events involving Unit 2 and 3 operations during this
SALP period resulted in the issue of 115 LER's. A review of
these LER's shows that 23 were the result of personnel error,
of which 20 were repetitive in nature. The repetitive events
appear to fall into four major areas:
1.
Lack of valve control -
9 LER's (Unit 2 83-118, 84-13;
Unit 3, 83-44, 83-46, 83-63, 83-73, 83-78, 84-09, 84-33).
2.
Lack of breaker control -
4 LER's (Unit 2 83-49, 83-85,83-100, 84-29).
6
3.
Lack of proper control of reactor coolant temperature
4 LER's (Unit 2 83-46,83-119, 83-151; Unit 3 83-80).
4.
Lack of proper manual control of steam generator water
level at low power -
2 LER's (Unit 2 84-20; Unit 3 84-32).
Of these LERs, approximately 80% occurred during the first
nine months of this period. This again shows a
comparative improvement during the SALP period.
The most significant weakness noted was in the area of
valve position control, of which 90% were identified in
the first nine months of this period. The control of
system valve lineups was identified as a significant
weakness during the last SALP period and carried over into
the first portion of this SALP period. The underlying
cause for this weak area appeared to be the inability of
site management to detect and correct remaining weaknesses
in the following areas:
a)
Inadequate administrative controls to ensure
independent verification of all critical valving
evolutions.
b)
Inadequate administrative controls to ensure
continuous operator understanding of the status of
critical plant valves.
c)
Inadequate monitoring of plant status changes by
operations supervision.
d)
Incomplete system knowledge by operators.
The licensee's aggressive attention to the problems
revealed during the first nine months of the SALP period
has resulted in measurable improvement, as demonstrated by
a reduction in the number of operator error caused LERs
and lack of any major enforcement actions. This has been
in large part due to a very aggressive management
involvement program which was initiated in May 1984. This
program has enabled the licensee to detect and correct
problems before violation of Technical Specifications
occurs. The most notable example was on August 7, 1984,
when licensee management successfully discovered a low
pressure safety injection pump suction valve in the
locked-closed position. The required position of this
valve for Mode 3 operation is locked-open. This valve
position error was identified by the licensee's Management
Monitoring Program prior to entry into Mode 3. Thus,
additional plant safety resulted. However, the licensee's
additional efforts have not been fully successful as
exemplified by an event on August 21, 1984.
In this event
both trains of Unit 3 HPSI were rendered inoperable for 18
minutes as a result of loss of control of valve status on
- 0
7
one train in conjunction with an outage on the other
redundant train.
In this case, the licensee identified
the error on a subsequent shift.
Fortunately, the
operation causing the inoperability lasted for only 18
minutes and no violation occurred. However, this event
demonstrates clearly that continuing emphasis in this area
is necessary.
2.
Conclusion
The licensee's performance during the first portion of
this period, particularly in the area of enforcement and
its reflection on training, was a category 3. The
licensee's subsequent performance, as indicated by the
lack of enforcement action and a lower operator error
rate, was significantly improved. The licensee's success
in early detection and correction of problems has
measurably improved with the implementation of an
aggressive management involvement program.
Consideration of the enforcement criterion alone would
indicate Category 3 performance by the licensee in the
Plant Operations area. However after considering stronger
licensee performance in other attributes (refer to Section
II above), particularly management involvement, approach
to resolution of technical issues, responsiveness,
staffing, and improved regulatory performance in the later
portion of this period, the SALP Board considers the
licensee's overall performance in the Plant Operations
functional area to be Category 2.
3.
Board Recommendations
The licensee should continue to evaluate the
administrative controls for repositioning valves critical
to plant safety from the standpoint of the continuity and
visibility of valve status in the control room.
Particular attention to valves and components which affect
safety system operability must be maintained, and the
increased management involvement demonstrated in the
latter part of this period should be continually
emphasized.
B.
Radiological Controls
1.
Analysis
A total of 29 inspections (Unit 1, 6; Unit 2, 12; and Unit 3,
11) were conducted by the Reactor Radiation Protection Section
during the appraisal period. A total of 385 inspection hours
were expended in the areas of:
a.
Radiation Protection
8
b.
Environmental Protection
c.
Waste Management
d.
Confirmatory Measurements
In addition, the resident inspectors provided continuing
observations in these areas.
During the appraisal period, two Severity Level III violations
were identified regarding the failure to conduct surveys
necessary to assure that contaminated materials were not
transferred or disposed in an unauthorized fashion. No
deviations or unresolved items were identified in these areas
during the appraisal period.
The preceding summary of enforcement history in this appraisal
area represents a significant reduction in the number of
violations identified when compared with the last SALP cycle (2
level III's, 4 level IV's and 3 level V's).
In addition, the
two level III violations resulted from activities which
predated this SALP cycle.
The enforcement history supports the previous SALP conclusion
that, "While the items of noncompliance are individually
important, they are not so closely related so as to conclude
that a serious breakdown of the licensee's 'radiological
control' responsibility has occurred."
The inspection
activities during this SALP cycle indicate that the area of
radiological controls has received strong and continuing
management support. This support has been evidenced in the
areas of radwaste shipping, audit program with resultant prompt
corrective actions and health physics reorganization to provide
for better outage support.
The licensee has demonstrated a positive approach to the
resolution of technical issues from a safety standpoint.
The
extensive and aggressive program to identify and recover
contaminated materials released from Unit 1, the improving
quality of environmental reports and the prompt action to
correct the degraded Unit 2/3 personnel decontamination
facilities are examples of the licensee's approach to such
issues.
Generally, the licensee has been responsive to NRC identified
issues, such as support of ALARA, and procedural compliance as
evidenced by the audit program. However, the licensee has
lagged in implementation of commitments with respect to
upgrading radiation monitoring systems and implementing
NUREG-0737 mandated PASS and monitoring system changes,
particularly with respect to Unit 1.
Reportable events have been reported in a timely fashion and
have provided adequate analysis of the events.
0
9
Licensee management support of staffing and training in the
radiological controls area has been both apparent and adequate.
The licensee has developed a well-qualified radiation
protection staff and a good radiation protection training
program.
The continued high Unit 3 primary system activity coupled with
present waste management practices, operational errors and
equipment problems has resulted in a significant number of
airborne radioactive material releases. The level of liquid
releases, while far above those proposed in the FSAR, have
remained within regulatory limits. Licensee efforts to
identify root causes and take effective corrective actions to
minimize releases should be aggressively pursued.
2.
Conclusion
The continued improvement in the areas of radiation protection,
radiological environmental monitoring and overall radiological
controls program supports an increase in the overall
performance classification. The delays in meeting Unit 1
commitments with respect to PASS and radiation monitoring
system modifications; in improving Unit 2/3 effluent monitoring
system performance; and in limiting Unit 2/3 radioactive
effluents are negative factors. An overall performance
classification of 2 is warranted in this functional area.
3.
Board Recommendation
The licensee is encouraged to continue the past strong support
of programs in this area which has been in evidence during this
appraisal period. Efforts to resolve the Unit 2/3 effluent
monitoring problems and to limit effluent releases should be
continued. With respect to Unit 1, timely resolution of PASS
and monitoring system problems is needed to support the return
to service effort.
C.
Maintenance
1.
Analysis
During the current SALP assessment period 143 hours0.00166 days <br />0.0397 hours <br />2.364418e-4 weeks <br />5.44115e-5 months <br /> of direct
inspection effort were applied in the area of plant maintenance
at San Onofre Units 1, 2 and 3. These inspection activities
resulted in one violation. The summary assessment of
individual unit maintenance activities, overall conclusion as
to site performance category and Board recommendations are as
follows.
Unit 1 Maintenance
A large number of maintenance activities have taken place
during this period even though the plant has remained in Mode
5. Some of the significant activities included the following:
0
10
o
RHR system outage
0
CCW system outage
o
TDI diesel inspection and repair
0
DC battery #1 replacement
These activities are not routine or normal plant evolutions;
however, all activities appeared to be properly preplanned and
controlled in accordance with explicit procedures. Prior to
the residual heat removal and component cooling water system
outages, the licensee submitted proposed plans including
compensatory measures such as enhanced surveillance, for staff
approval. The licensee kept the staff well informed of its
plans regarding the No. 1 battery replacement and provided
temporary batteries as an alternate source of DC power. In
instances where technical problems were evaluated, the licensee
demonstrated a good understanding of associated safety issues
and the evaluation results appeared to be technically sound
with thorough approaches used in all cases.
A violation was cited in the housekeeping area involving
foreign material exclusion (FME). There were no apparent
indications of a programmatic breakdown of FME control;
however, the need for additional management involvement was
indicated. Corrective action by the licensee was prompt and
effective.
Four Licensee Event Reports were submitted by the licensee
during this period, of which only two involved personnel error.
The reports were made in a timely manner with appropriate
analyses performed when required. Corrective action appears to
have been effective to prevent recurrence.
Unit 2/3 Maintenance
During the assessment period no violations were identified in
the area of plant maintenance performed by the station
maintenance organizations. However, one violation was
identified in the area of housekeeping, and this violation is
identified in the plant modifications section of this report
since the housekeeping deficiencies were identified primarily
in the areas where equipment alterations were in progress.
During the assessment period the licensee's Maintenance
Department has stabilized and developed into a more efficient
work group. The licensee has dedicated resources to correct
previously identified weaknesses from the previous SALP period.
Progress has been noted in the following areas which were
previously identified as areas of concern:
proper
documentation of maintenance and work, incorporation of vendor
information into technical manuals and procedures, and the
post-maintenance retest program. Though the licensee's
S
11
0
performance in the area of verbatim compliance with procedures
has also improved during this SALP period compared to the
previous, period, and has reached a satisfactory level,
weaknesses in this area still indicate additional improvement
is needed. The following two events are examples of the
weaknesses which exist in the area of verbatim compliance:
(1)
failure of a contract instrumentation and control foreman to
turn in out-of-calibration test instrumentation for
recalibration and (2) the flooding of the Unit 3 Boric Acid
Makeup Tank Pump room, when the mechanic failed to perform the
required safety precautions stated in the procedure. The
licensee's management responded promptly on both of the above
events utilizing the maintenance error investigation system,
which the licensee has used as an effective management tool to
identify weaknesses in the occurrence of non-reportable
concerns as well as reportable events.
Although the above noted weaknesses in the maintenance program
indicate a need for management attention, significant
improvements have been made in several safety-related
maintenance activities. These activities in which improvements
have occurred include the following: maintenance of reactor
trip breakers, reactor coolant pump seals, limitorque valve
operators and steam generator repairs. Also a review of the
Licensee Event Reports for Units 2 and 3 indicate that
significant improvements have been made. Only fourteen
Licensee Event Reports were issued in the maintenance area
during the sixteen month period. This is an improvement from
the last SALP period.
The licensee's staffing of the Maintenance Department is
adequate and scheduling of maintenance tasks appears to be well
controlled with the use of the computer based San Onofre
Maintenance Management System (SOMMS). The licensee has given
proper attention and prioritization to the backlog of
maintenance orders which existed during the SALP period. The
reduction of the large backlog of deficiencies in control room
indicators and alarms during the SALP period has reduced the
distractions to which the reactor operators were subjected
during the previous SALP period.
The Maintenance staff's approach to resolving technical issues
from a safety standpoint has been conservative and timely in
almost all cases. Response to Bulletin 84-03 was technically
well thought out and sound, but the response indicated a minor
weakness within the licensee's organization in the transmission
of important safety information on a timely basis to the
appropriate organizations.
Except for the deficiencies discussed above and in the
Surveillance section of this report, management's efforts in
the area of maintenance have improved significantly and have
resulted in increased reliability of the plant safety systems
during this SALP period.
12
2.
Conclusion
Category 1
3.
Board Recommendation
The licensee's management is encouraged to continue its support
of the maintenance program.
D.
SURVEILLANCE
1.
Analysis
During the current SALP assessment period 205 hours0.00237 days <br />0.0569 hours <br />3.38955e-4 weeks <br />7.80025e-5 months <br /> of direct
inspection effort were applied in the area of surveillances at
San Onofre Units 1, 2 and 3. One violation was identified:
Failure to assure that equipment made inoperable by planned
surveillance activities is returned to service in an operable
status with required test procedures completed (Inspection
Report 84-11, Level IV).
The summary assessment of individual Unit activities is as
follows:
Unit 1
Unit 1 was in Mode 5 for the entire assessment period and the
surveillance program requirements were therefore minimal. No
significant failures or errors in the program were noted.
Units 2 and 3
Although only one violation was identified on Units 2 and 3,
the following five major program weaknesses were identified in
the licensee's surveillance programs:
o
Inadequate formal communications within the
instrumentation and control (I&C) maintenance
organizations.
o
Inadequate knowledge of equipment control requirements by
I&C technicians.
o
Poor procedure compliance by I&C technicians.
o
Inadequate surveillance procedures in that:
1)
Procedures lacked detailed steps to properly restore
the system under test to an operable status.
2)
Procedure failed to provide a second independent
verification of actions requiring independent
verification.
13
The above weaknesses were identified as the result of the
investigation of the following events, which occurred during
the SALP period:
a.
February 3, 1984:
An I&C technician signed the applicable
equipment control from ECF 30242 indicating that the Plant
Protection System response time surveillance testing was
complete. However, based on the review of the restoration
step of the surveillance procedure S023-II-3.1 and the
maintenance order and interviewing the licensee's
personnel, work was not completed until February 16, 1984.
This occurrence resulted in a violation and the licensee
initiated retraining of I&C technicians in the area of
equipment control.
b.
February 28, 1984:
While troubleshooting an inoperable
Reactor Trip Breaker (RTB), an I&C technician identified
that eight leads in the plant protection system cabinets,
which supply power to the RTB's shunt trip devices, had
been left disconnected during the completion of the
restoration section of surveillance procedure S023-II-3.1
(18 month response test) on February 16, 1984. Underlying
causes for this event included improper informal
communication practices between I&C technicians as well as
inadequate procedures due to failure to provide
independent verification and proper system restoration
steps.
c.
March 9, 1984:
Inadvertent initiation of a Safety
Injection Actuation Signal, Containment Cooling Actuation
Signal, and a Containment Spray Actuation Signal due to
the technician's failure to reset the trip in a previously
tested channel before testing the second channel. The
licensee's corrective actions included revising the
affected procedure to include independent verification of
the resetting of each channel.
d.
July 23, 1984:
Inadvertent initiation of the ESF Main
Steam Isolation Signal, when the I&C technician failed to
reset the trip in a previously tested channel before
testing the second channel. The licensee's corrective
action included revising the procedure to eliminate
assumed knowledge and practices of I&C technicians.
The licensee's management has pursued the completion of several
programs to eliminate the above noted weaknesses. The licensee
dedicated considerable resources to complete review of
safety-related surveillance procedures on all three units in
order to include proper restoration steps and independent
verification requirements in the procedures. The licensee
responded aggressively in communicating to all station
personnel each individual's responsibility to strictly adhere
to procedures and require formal communications in the
performance of all procedures. The licensee completed training
0
14
on equipment control requirements and has already demonstrated
improvements in this area. These corrective actions were
timely, well planned and appear to be effective based on
licensee performance during the last four months of the
evaluation period.
The licensee surveillance program was successful in properly
identifying reportable events which, with few exceptions, were
promptly reported. A total of 89 Licensee Event Reports
(LER's) on Units 2 and 3 were submitted during this period. Of
these, 20 represented errors which occurred in the
implementation of the surveillance program. Most of the errors
were due to technician errors during the performance of the
surveillance activities. Overall, the surveillance program has
shown an improved effectiveness over the previous SALP
evaluation period in the area of reducing technician errors
during the performance of the surveillance activities. Roughly
the same number of errors were made, however, the number of
surveillances performed during the period was more than double
that of the previous SALP period due to the fact that Unit 3
did not achieve initial criticality until this evaluation
period.
The scheduling and tracking of the surveillance program by the
Operations department has been excellent and the proper
assignment of priority items has been consistent.
Technician staffing for the period was supplemented by
contracted technicians to complete the large workload for 3
units. The licensee's training programs for technicians have
become more specialized with four distinct groups of
technicians within the licensee's staff. The four groups which
include approximately 200 technicians are:
Instrumentation and
Control, Computer, Radiological Monitor and Electrical Test.
The shortage of technicians in the industry has been recognized
by the licensee and management has aggressively pursued
obtaining the best qualified technicians available throughout
the country. Turnover of technicians is beginning to stabilize
and this should result in additional improvement in the
surveillance program with improved work task efficiency.
Overall, the training and qualification program for technicians
is adequate, but requires continuous attention and evaluation
by management until technician experience levels are improved.
2.
Conclusion
Category 2 -
No change from previous SALP perod.
3.
Board Recommendation
The licensee should continue to closely monitor and enforce
formal communications and procedural adherence by the working
level technicians, and to continue efforts to stabilize the
15
g
turnover of technicians and gradually eliminate the reliance on
large numbers of contract technicians.
E.
Fire Protection
1.
Analysis
During the current SALP assessment period 2 inspections
totaling 87 hours0.00101 days <br />0.0242 hours <br />1.438492e-4 weeks <br />3.31035e-5 months <br /> of direct inspection effort were applied in
the area of fire protection at San Onofre Units 1, 2, and 3.
In addition the resident inspectors provided continuing
observations in this area. Three violations were identified as
follows:
o
Failure to provide indication of reactor coolant cold leg
temperature on the essential plant parameter monitor panel
which is used if a fire makes the control room unavailable
(Units 2 & 3).
o
Failure to wrap redundant equipment power cables found to
be within 20 feet of each other with a one-hour rated fire
resistant material (Unit 3).
o
Failure to provide required fire protection for safe
shutdown equipment (Unit 3).
The above violations were corrected in a timely manner.
The licensee has demonstrated aggressive management involvement
in this area by the aggressive pursuit of a complete review of
the Fire Hazards Analysis (FHA). This review consisted of a
verification of plant conformance to this document and a
comprehensive review of this document for conformance to NRC
requirements. This activity has been essentially completed for
Units 2&3 with the submittal of the revised document to NRR for
approval. In addition, as a result of this work, 5 LERs were
identified which covered a number of cases wherein plant
configuration was not consistent with the FHA or NRC
requirements. The licensee is currently doing a similar effort
on Unit 1.
The licensee's staffing in this area appeared adequate and
included a large number of fire patrol personnel, a station
fire brigade, and an adequate management staff.
The training in this area was adequate and the fire watch
personnel appeared alert, knowledgeable and responsible. The
station has its own fire department which has been at the
station all year. The licensee's reporting of fire protection
system discrepancies appeared aggressive.
The licensee did have several LER's in this area -
21 on Unit
2, 3 on Unit 3 and 0 on Unit 1. Of these, three were caused by
personnel error, three were caused by defective procedure,
16
three were caused by component failure, and seven were caused
by design manufacturing or installation error. These LER's
appear to result in part due to a large amount of retrofit work
and the FHA review.
2.
Conclusion
Overall the licensee's performance in this areas has been
aggressive and responsive to NRC concerns; however, due to the
number of violations in this area, the failure on occasion to
perform required surveillances, the failure to ensure
compensation measures on occasion and the failure to ensure
configuration conformance to the FHA and NRC requirement during
initial construction on Units 2&3, this area is evaluated
Category 2.
3.
Board Recommendation
The licensee should aggressively pursue the completion of the
FRA evaluation on Unit 1 and should continue to emphasize fire
protection, particularly in light of the extensive retrofit
work.
F.
1.
Analysis
During the appraisal period, Region V conducted a routine
inspection of the SONGS emergency preparedness program and an
appraisal of the Units 2/3 Emergency Response Facilities (ERF)
and observed an emergency preparedness exercise that involved
the Units 2/3 facility as well as areas common for the site.
This inspection effort totaled 599 hours0.00693 days <br />0.166 hours <br />9.9041e-4 weeks <br />2.279195e-4 months <br /> onsite (Unit 1-54
hours, Unit 2-344 hours and Unit 3-201 hours).
No violations
of NRC requirements or significant deficiencies were identified
during the scope of this inspection effort. During this
appraisal period, however, one violation having impact in the
area of emergency preparedness was cited. This is discussed in
Section A, Unit 2/3 Operations.
The licensee's management has continued its support of the
emergency preparedness program. When asked, management readily
volunteered to be the first facility to have an NRC Emergency
Response Facilities (ERF) Appraisal. The inspection effort
confirmed the licensee's ability to adequately address
technical issues related to emergency preparedness and provide
a sound solution. SCE's response to NRC initiatives was timely
and aggressive as demonstrated by their evaluation of, and
action on suggested improvements resulting from the ERF
appraisal. The staff assigned to the emergency preparedness
program and those persons filling positions in the emergency
response organization are ample in numbers and these positions
are well defined. The licensee has a well defined emergency
17
0
preparedness training program that has been implemented and
appropriately documented.
2.
Conclusion
Category 1 - No change from previous SALP period
3.
Board Recommendation
The licensee's management is encouraged to continue its support
of the emergency preparedness program.
G.
Security
1.
Analysis
From June 1, 1983 through September 30, 1984, Region V
conducted six Safeguards inspections at San Onofre Nuclear
Generating Station for a total of 244 hours0.00282 days <br />0.0678 hours <br />4.034392e-4 weeks <br />9.2842e-5 months <br /> of inspection
effort. One inspection was a Material Control and Accounting
inspection and the remaining five inspections were in the
Physical Security area. Throughout the reporting period, all
three units at SONGS were inspected and no violations were
identified. Of the total inspection effort (244 hours0.00282 days <br />0.0678 hours <br />4.034392e-4 weeks <br />9.2842e-5 months <br />), 173
hours were devoted to routine inspection activities and 71
hours were devoted to reactive effort.
Physical security inspections during this SALP period showed
licensee management to be actively involved in the overall
security program. The entire management staff worked steadily
to improve the Security Plan. This effort resulted in a
complete rewrite and approval of the station Security Plan and
implementing procedures together with numerous improvements in
the Station Security Program.
Staffing of the security organization was judged by NRC to be
very adequate.
SONGS continued to effectively utilize a
uniformed security force comprised of both proprietary and
contract personnel. The security management staff was
responsive to NRC initiatives, demonstrated an understanding of
safety/security issues, and actively supported the total
Safety/Security Interface Program. The individual Security
Officers demonstrated a thorough understanding of security
requirements and a desire to comply with these requirements.
An effective program for the reporting and analysis of
reportable events was in place.
2.
Conclusion
Category 1 -
Improvement over previous SALP period.
g
18
3.
Board Recommendations
Licensee management is encouraged to maintain their support of
the station security program.
H.
Refueling
1.
Analysis
No refueling activities were conducted during the assessment
period.
2.
Conclusions
Not applicable
3.
Board Recommendation
Not applicable
I.
Quality Programs and Administrative Controls
1.
Analysis
Quality Programs
Management involvement in quality programs and administrative
controls has been apparent with substantial progress being made
during the assessment period to implement a unified and
consistent quality assurance program applicable to all three
units at SONGS. The SONGS-1 and SONGS-2/3 site quality
assurance groups were reorganized under the common control of
the site Quality Assurance Manager which has improved
communication and control. Various initiatives such as a June
1984 Unit 1 return-to-service audit, a special quality
assurance Construction Surveillance Program, a
Retrofit/Startup/Outage and Maintenance quality assurance group
upgrading of procedures, twenty-four hour quality control
coverage, and quality assurance involvement in a SONGS-1
technical specification surveillance requirement review
demonstrated a strong commitment to prior planning and the
assignment of priorities. The SONGS-1 quality assurance
organization manning level was increased above the previous
manning level for Mode 5 operation and maintenance, and
experienced quality assurance personnel were assigned to
SONGS-1 during modification activities. Various computer
tracking systems were developed to enhance the quality
assurance organization's ability to accurately maintain the
status of activities.
Corporate management was found to be frequently involved in
site activities and special corporate quality assurance audits
were performed on SONGS-1 material/equipment supplier
qualifications and the interface aspects of SCE/Bechtel/Impell
19
design/analysis activities. Inspections in the areas of
design, design changes and modifications revealed strengths in
administrative controls, procedures and implementation.
Discussions with onsite engineering personnel revealed that
they had undergone training and indoctrination in the
engineering and QA procedures applicable to the work to which
they were assigned.
During the special team inspection, Station Orders and selected
Administrative, Engineering, General, Emergency, Abnormal and
Alarm response procedures applicable to Unit No. 1 were
examined. The procedures were found to be detailed and
consistent with industry and regulatory guidelines as to
format, scope, and content. At the end of the SALP period, the
licensee was developing administrative controls to more clearly
define (1) the use of "N/A" in procedures and (2) the process
for expediting issuance of temporary procedure changes.
The licensee is very responsive to NRC concerns in the area of
quality assurance. Investigations of quality assurance
concerns are thorough and timely when the potential for safety
significance exists. Corrective actions are generally
conservative reflecting consideration of the root and
contributing causes. These attributes were clearly
demonstrated recently by the licensee's response following NRC
identification of the installation of some potentially
nonconforming pipe fittings.
Event Review and Independent Offsite Review Groups
The effectiveness of licensee event review groups and
independent offsite review committees was examined during this
assessment period. Post trip/transient reviews were conducted
in accordance with applicable procedures with the cause of the
event and proposed corrective actions to prevent recurrence
identified in all cases. Station incident reports were well
written, accurate descriptions of the events with causes,
corrective actions, and reportability clearly identified.
Management review of station incident reports was prompt and
well documented. Proposed corrective actions were entered on a
tracking system to ensure resolution.
The Independent Safety Engineering Group (ISEG) is physically
located onsite and functions to examine plant operating
characteristics, NRC issuances, industry advisories, Licensee
Event Reports and other sources of plant design and operating
experience information which may indicate areas for improving
plant safety.
ISEG activities are reported offsite by the ISEG
supervisor to the Manager of Nuclear Safety. The licensee has
divided ISEG responsibilities into two programmatic areas:
surveillance of plant activities and review and analysis of
operating experience reports.
g
20
ISEG surveillances were well researched and the findings or
recommendations well documented. The quality of the
surveillances reflected the high experience level (20 years
average) of the ISEG engineers. The surveillances were
directed towards and appeared to be contributing to the goal of
enhancing plant operations and nuclear safety by recommending
solutions to existing or potential problems.
ISEG personnel
initially attempted to resolve actual or potential problems at
the individual station engineer level. Cooperation between
station operations and engineering and ISEG appears
satisfactory. Where disagreements have developed, appropriate
management involvement by the ISEG Supervisor and Manager of
Nuclear Safety was apparent.
The independent offsite review groups (Nuclear Safety Group and
Nuclear Audit and Review Committee) appeared to be effectively
assessing the safety implications of station events.
Individual safety reviews are adequately documented and
checklists used in the reviews are well developed and
comprehensive. Programs to quantify and improve nuclear
safety, which exceed technical specification requirements, are
underway and demonstrate aggressive action by the Nuclear
Safety Group and Licensee Management to enhance nuclear safety.
Licensee event review groups and independent offsite review
groups demonstrate conservatism and a clear understanding of
safety issues in their reviews. Staffing is ample and
experience levels exceed technical specification requirements
in all cases. Monthly management reports examined did not
adequately reflect the independent conclusions or judgments
which had been arrived at during the individual safety reviews,
but the licensee has initiated corrective action in this
regard.
Unit 1 Modifications
During the current SALP assessment period, 982 hours0.0114 days <br />0.273 hours <br />0.00162 weeks <br />3.73651e-4 months <br /> of direct
inspection effort were applied in the area of plant
modification effort. This inspection effort resulted in the
citation of one violation. The major plant modification effort
for the period involved the return to service effort for Unit
1. Extensive field inspections were performed by the NRC
during this period, including a large effort by Lawrence
Livermore National Laboratory (LLL) and a Region V team
inspection.
Findings as a result of the above effort identified a weakness
in the Quality Control inspection effort used for the seismic
modifications work in that minor welding deficiencies were not
being properly documented. The licensee responded to this
finding by forming a reinspection task force in order to
discover if any additional deficiencies existed. All
identified deficiencies have been corrected.
21
In the area of environmental qualification, a Notice of
Violation was issued against the design of the reactor head
vent system because SCE engineering had failed to specify on
the installation drawings the conduit fittings needed for
sealing of the electrical conductors where they enter the valve
solenoid operator. The licensee took immediate corrective
action and was responsive to NRC concerns.
Three Licensee Event Reports (LER) were received during this
period. The areas addressed by the LER's were as follows:
o
Modification to existing plant system.
o
Delinquent temporary change notice approvals.
o
Corrosion of reinforcing steel.
The LER's submitted were reported in a timely manner with
events adequately identified. Analysis of the intake structure
event was described in detail and provided valuable information
to the NRC.
The licensee currently has a large work force dedicated to
completing plant modifications in the following areas:
modifications on Unit 2, plant betterment modifications
(particularly Condensate Demineralizer Buildings), and
Radiation Monitoring System design changes, plus several
hundred other design changes to be implemented as a result of
minor deficiencies identified during the Startup period which
ended in March, 1984.
As a result of the large amount of construction/rework activity
ongoing on Units 2 and 3, the licensee has maintained a large
Unit 2 and 3 Projects construction/maintenance organization
onsite separate from the Station Maintenance organization. The
Project organization still includes a large contractor work
force of approximately 1500 engineers and maintenance
craftsmen, which are primarily supervised by Bechtel and
Catalytic construction companies. Due to the complexity of the
organization and the relatively high turnover rate of craft
workers, the licensee has experienced difficulties in managing
proper housekeeping in areas of construction and equipment
alterations. A decline in housekeeping standards occurred
during the last four months of the SALP period as the level of
Project supervised construction increased. The decline in
housekeeping was primarily noted in radiologically controlled
areas in the Safety Equipment Buildings to the extent that a
housekeeping violation was cited. The underlying cause for the
degrading trend in housekeeping was the lack of adequate
direction by the licensee's management as to which
organizations were responsible for housekeeping in the
radiologically controlled areas. The licensee has implemented
interim corrective actions and developed additional long term
corrective actions to upgrade plant housekeeping conditions.
22
2.
Conclusion
Category 1 (This area was not separately evaluated during the
previous SALP period).
3.
Board Recommendation
The licensee's management is encouraged to continue its support
of the quality assurance program and independent review groups
and to enhance the effort directed toward preventing
operational and equipment control problems of the type
discussed in Section A, Plant Operations.
J.
Licensing Activities
1.
Analysis -
Unit 1
This evaluation represents the integrated inputs of the
Operating Reactor Project Manager (ORPM) and those technical
reviewers who expended significant amounts of effort on SONGS-1
licensing actions during the current rating period.
The basis of this appraisal was the licensee's performance in
support of licensing actions that were either completed or
active during the current rating period. These actions,
consisting of amendment requests, exemption requests, responses
to generic letters, TMI items, and other actions, are
classified as follows:
Thirteen completed Multi-Plant Actions included in this
category are:
-
Decay Heat Removal Capability Technical Specifications
-
Radiological Effluent Technical Specifications
-
Containment Purge and Vent
-
Reactor Vessel Cavity Seal Ring Missile Potential
-
Automatic Actuation of Shunt Trip Attachment
-
Thermal Mechanical Report
-
Potential for Voiding in RCS
-
Containment Pressure Instrument
-
Containment Water Level Monitor
-
Containment Hydrogen Monitor
-
Automatic PORV Isolation
-
Report on PORV's
-
ECCS Outages
Seven completed Plant-Specific Actions included in this
category are:
-
Two revisions to station physical security plan
-
Technical Specifications on Coolant Activity Sampling
-
Evaluation of Spent Fuel Pool Racks
-
Steam Generator Inspection Program and License Condition
23
-
Revisions to Appendix B (Environmental) Technical
Specifications
-
Revision to Boron Concentration Limits in Cold Shutdown
and Refueling
Other major activities during the review period were the
seismic reevaluation program and SEP.
The licensee's performance evaluation is based on a
consideration of seven evaluation criteria given in the NRC
Manual Chapter. For most of the licensing issues considered in
this evaluation, only four of the evaluation criteria were of
significance. Therefore, the composite rating is based on the
following evaluation criteria:
-
Management involvement
-
Approach to resolution of technical issues
-
Responsiveness to NRC initiatives
-
Staffing
With the exception of Enforcement History, for which there were
no bases within NRR for evaluation, the remaining evaluation
criteria below were judged to apply only to a few licensing
activities.
-
Reportable events
-
Training
a.
Management Involvement and Control in Assuring Quality
San Onofre 1 has remained in the cold shutdown mode
throughout the evaluation period. During the first
several months of this period, a general slowdown of
licensee activity, both in plant modifications and in
licensing, was in effect. Meanwhile, SCE management was
developing plans and schedules for plant restart and for
long-term plant retrofit.
Management involvement over the last several months has
been very apparent; particularly with respect to issues
directly related to restart. There is evidence of
planning and assignment of priorities and that
decision-making is generally handled at the appropriate
level of management.
The licensee has proposed an "Integrated Living Schedule"
to establish priorities for plant backfits and to track
progress in completing these actions. This system should
be of benefit to both the NRC and the licensee.
As a result of the long shutdown, uncertainty about the
schedule for return to service and the resultant reduction
in effort during the beginning of the review period, many
licensing issues are not yet resolved. Increased
24
management attention should continue in the next
evaluation period to minimize schedule slippages such that
these issues can be completed.
On the basis of these observations, a rating Category of 2
is assigned to this attribute.
b.
Approach to Resolution of Technical Issues from a Safety
Standpoint
In the approach to resolution of technical issues from a
safety standpoint, the licensee's responses are generally
sound and viable. For example, for the Radiological
Effluent Technical Specifications, plant personnel showed
good understanding of the issues and were cooperative in
resolving them.
In the area of seismic reevaluation, the licensee is using
state-of-the-art analysis methodology and criteria; the
licensee has demonstrated clear understanding of the
issues.
For responses to generic letters, the licensee has
generally followed the guidelines provided with exceptions
dictated by unique features of the plant design.
For the SEP Integrated Assessment, the licensee has
provided responses to support the adequacy of the existing
plant design in many areas and, where warranted, has
proposed evaluation programs or other corrective measures
to resolve the open issues. These proposals are generally
sound and reflect an adequate degree of conservatism.
The overall rating for this category, based on inputs from
twelve subject areas, is Category 2.
c.
Responsiveness to NRC Initiatives
During the first several months of the review period,
licensee efforts to resolve outstanding licensing issues
were minimal for the reasons described above. However,
beginning in early 1984, the licensee has made great
strides in reducing the backlog of actions. This is
demonstrated by the large number of actions that have been
closed out and by the eleven license amendments that have
been issued since December. In addition to the completed
actions listed above, the licensee has submitted license
amendment applications for technical specifications on
NUREG-0737 items (Generic Letters 82-16 and 83-37),
Reportable Events (Generic Letter 83-43), Auxiliary
Feedwater System (TMI II.E.1.1 and II.E.1.2) and dc Power
Surveillance. These submittals generally proposed
resolutions which were acceptable to the staff, but in
several instances, it was necessary to request further
25
information to support some of the requested changes. The
licensee has been generally responsive to NRC requests for
information either by conference calls, meetings or by
letter, although schedule slips have occurred.
Although overall responsiveness has been good, delays for
some TMI Action Plan items will result in San Onofre 1
being one of the last plants to resolve these issues.
Most of these delays arise from the slowdown period
mentioned above and from the licensee devoting attention
to issues required for plant restart. The overall rating
for this criterion is Category 2.
d.
Enforcement
No basis exists for an NRR evaluation of this attribute.
e.
Reportable Events
Only one topic was evaluated with regard to reportable
events. This one evaluation (Category 1) was judged to be
too limited a sample to provide an overall rating.
f.
Staffing
A rating of Category 2 was assigned to this attribute.
The level of staffing is considered adequate, with some
delays of submittals that could be attributable to
staffing levels.
g.
Training and Qualifications
This attribute was judged to apply to only a few actions.
A rating of Category 1 was assigned for those instances
where a rating was applied.
2.
Analysis Units 2 and 3
The basis of this appraisal was the licensee's performance in
support of licensing actions that were either completed or
active during the current rating period. These actions,
consisting of amendment requests, exemption requests, responses
to generic letters, TMI items, and other actions, are
classified as follows:
Completed Multi-Plant Actions in this category include:
-
Thermal-Mechanical Report
-
Potential for Voiding in RCS
-
Relief Valve and Safety Valve Testing
-
Control of Heavy Loads (Phase I)
-
NUREG-0737 Technical Specifications
-
26
-
-
Operational Support Center
Completed Plant-Specific Actions in this category include:
-
Two revisions to station physical security plan
-
Issuance of a full power license amendment for Unit 3
-
Revised Technical Specifications for:
1.
Natural Circulation Test Exceptions
2.
Rod Bow Penalty Factors
3.
ESFAS Subgroup Relay Surveillance
4.
Allowed containment purge time
5.
Setting of Pressurizer Code Safety Valve
6.
Fire Protection equipment changes
-
Two exceptions to the regulations relating to
Appendix E and 10 CFR 70.24.
The licensee's performance evaluation is based on a
consideration of seven evaluation criteria given in the NRC
Manual Chapter. For most of the licensing issues considered in
this evaluation, only four of the evaluation criteria were of
significance. Therefore, the composite rating is based on the
following evaluation criteria:
-
Management involvement
-
Approach to resolution of technical issues
-
Responsiveness to NRC initiatives
With the exceptions of Enforcement History and Staffing for
which were no bases within NRR for evaluation, the remaining
evaluation criteria of
-
Reportable events
-
Training
were judged to apply only to a few licensing activities.
a.
Management Involvement and Control in Assuring Quality
During the evaluation period San Onofre Unit 2 has been in
commercial operation, and Unit 3 has received a full power
license, completed startup testing, and has begun the
first cycle of commercial operation. During this time
period, management involvement with licensing activities
has been evident. Specifically, as a result of previous
difficulties with the technical specifications, SCE has
submitted a large number of requests for changes to
improve the technical specifications. This represents an
improvement over past evaluation periods.
On the basis of these observations, a rating Category of 2
is assigned to this attribute.
27
b.
Approach to Resolution of Technical Issues from a Safety
Standpoint
In the approach to resolution of technical issues from a
safety standpoint, the licensee's responses have, in
general, been acceptable. In the areas of the ESFAS
subgroup relay technical specifictaion change, the steam
generator tube inspection criteria technical specification
changes, the control of heavy loads, and the allowed purge
time technical specification, the licensee's submittals
have been better than average.
The overall rating for this attribute based on inputs from
eight subject areas, is Category 2.
c.
Responsiveness to NRC Initiatives
The licensee has generally been quite responsive to staff
concerns. Requested information has been provided in a
timely manner, has been comprehensive, and has directly
addressed the issues of concern. Licensee responsiveness
was particularly good in addressing the ESFAS subgroup
relay issue, the control of heavy loads issue, and the
steam generator inspection criteria issue.
The overall rating for this attribute is Category 1.
d.
Enforcement
No basis exist for an NRR evaluation of this attribute in
the licensing area.
e.
Reportable Events
Only one topic was evaluated with regard to reportable
events. This one evaluation (Category 1) was judged to be
too limited a sample to provide an overall rating for this
attribute.
f.
Staffing
This attribute was judged to be Category 2, in that the
staffing of the SCE licensing effort appears to be
adequate.
g.
Training and Qualifications
This attribute was judged to apply to only a few actions.
A rating of Category 2 was assigned for those instances
where a rating was applied.
28
3.
Conclusion
In summary, licensee performance in the areas of management
involvement and responsiveness has improved over the rating
period. As a result the backlog of items has been
substantially reduced. Although some Category 1 ratings were
assigned, the majority were Category 2. Therefore, an overall
licensing performance rating of Category 2 has been judged.
4.
Board Recommendation
Continued management attention is recommended to ensure timely
completion of the remaining outstanding licensing issues.
K.
STARTUP TESTING (UNIT 3)
1.
Analysis
During the current SALP assessment period, 233 hours0.0027 days <br />0.0647 hours <br />3.852513e-4 weeks <br />8.86565e-5 months <br /> of direct
inspection effort were applied in the area of startup testing.
The resident inspectors observed startup tests performed by the
licensee on Unit 3 from initial criticality on August 29, 1983
through the completion of testing on March 27, 1984. No
violations were identified in this area.
One Licensee Event Report (LER) was submitted in this area.
This event involved a technician error while performing a
startup test procedure at 20 percent power when the technician
erroneously interrupted power supply voltage to the Reed Switch
Position Transmitters for 23 Control Element Assemblies (CEA)
associated with CEA Calculator No. 2. With the exception of
the technicians error, the startup test program implementation
for Unit 3 went smoothly.
2.
Conclusion
Category 1
3.
Board Recommendation
Not applicable
V.
SUPPORTING DATA AND SUMMARIES
A.
Licensee Activities
SONGS-1 has remained shut down during this assessment period to
accomplish seismic upgrading and TMI action plan items.
The
licensee has requested, by letter dated August 20, 1984, permission
to restart the unit which is scheduled for late November, 1984.
During this assessment period both SONGS 2 and 3 completed power
ascension testing and began full power commercial operation. A
brief summary of key events is as follows:
29
Unit 2 Startup
80%
power testing
May
16 -
June 5, 1983
100%
power testing
June 6 - August 8, 1983
Warranty Run
June 16 -
August 18, 1983
Unit 2 Outages
RCP seal replacement
24 days
6/16 -
7/10/83
18 month surveillance
28 days
11/15 -
12/13/83
RCP seal repair
28 days
1/13 -
2/10/84
Steam generator tube leak 20 days
6/19 -
7/9/84
RCP seal replacement
11 days
7/11 -
7/22/84
Unit 3 Startup
Initial criticality
August 29, 1983
Low power physics testing
August 29 -
September 5, 1983
20%
power
September 25 -
October 9, 1983
50%
power
October 11
-
October 31, 1983
80%
power
November 3
- November 15, 1983
100% power
November 17
-
January 6, 1984
Warranty run
March 18
-
March 27, 1984
Unit 3 Outages
Mode 5 delay for Unit 2
34 days
6/1
-
7/4/83
RCP seal repair
18 mo. surv.
55 days
1/7
-
3/2/84
Scheduled outage
2 days
3/29 -
3/31/84
Turbine generator balance
17 days
5/4 -
5/21/84
RCP seal repair
22 days
6/11 -
7/3/84
Steam generator tube leak
18 days
7/18 -
8/5/84
Significant license amendments are listed in Paragraph IV.J.1.
Major modifications took place on Unit-1 during the extended outage
as follows:
1)
Seismic Upgrade -
the licensee's restart plan provided for
upgrading systems to assure a hot standby plant condition will
be achievable following an earthquake of 0.67g. Completed work
activities include:
o
Structural Steel Members
a
New Auxiliary Feedwater Tank and Piping
o
Electrical Raceway Supports
0
Piping Supports
o
Backup N for Safe Shutdown Valves
o
Cross-connect of Spent Fuel Storage Pool to Charging
System for use as a Makeup Water Source.
30
2)
TMI - The return-to-service effort included completion of
modifications begun during the 1982 shutdown. To resolve TMI
action items these modifications included:
o
Wide Range Stack Gas Monitor
o
Containment H and Water Level Monitors
o
2
3)
Saltwater Intake Structure -
Underwater surveillances this
summer by the licensee indicated the possibility of structural
degradation of the walls. Following examination of the
dewatered structure modifications were completed to restore
full structural integrity and repair degraded gate slots. The
intake has been refilled.
4)
The return to service effort included completion of tasks begun
in 1982:
o
480V Halon System
o
Drip Shields in 480V and 4KV rooms.
5)
In addition to the upgrades noted above, the licensee has
included the following within the return to service scope and
has completed all required actions.
o
P&ID Drawing Verification
o
Replacement of Efcomatic Valve Operators
o
Replacement of No. 1 DC Battery
o
Replacement of Saltwater Intake Gates
o
Installation of Saltwater Pump Check Valves
o
Waste Gas System Improvements
o
Replacement of Safety Related Snubbers (Mechanical for
Hydraulics)
B.
Inspection Activities
Inspection activities conducted during the assessment period are
provided in Table 1. In addition to the routine inspection program,
a special team inspection of mechanical, electrical, design and
operations activities associated with hardware modifications, plant
maintenance and performance of shift personnel was conducted in
July, 1984. The team inspection involved 688 hours0.00796 days <br />0.191 hours <br />0.00114 weeks <br />2.61784e-4 months <br /> by twelve NRC
inspectors and 188 hours0.00218 days <br />0.0522 hours <br />3.108466e-4 weeks <br />7.1534e-5 months <br /> by three NRC consultants. No violations of
NRC requirements were identified within the scope of the inspection.
A number of perceived weaknesses were referred to the licensee for
consideration.
A substantial amount of inspection effort, including 230
inspection-hours by two NRC resident inspectors and 756 hours0.00875 days <br />0.21 hours <br />0.00125 weeks <br />2.87658e-4 months <br /> by NRC
contract personnel, was devoted to the seismic modifications on
SONGS-1.
31
C.
Investigations and Allegations Review
1.
Investigations
Inquiries Closed:
1-Hardware deficiencies
1-Falsification of records
Inquiries Open:
4-Falsification of records
2-Illegal drug use
Cases Open:
1-False statements and/or documents
2.
Allegations
All allegations associated with Unit 1 assigned to the Region V
staff are closed with the exception of the following:
o
RV-83-A-36 -
Anchor Bolts
It is currently believed that this allegation has a small
probability for substantiation but it only applies to work
performed from 1979-1981 which predates seismic upgrade
work on SONGS 1.
o
RV-84-A-94 - Reactive Aggregate in the Intake Structures
Based upon concrete testing by the licensee during the
investigation and repair of intake structure corrosion
problems, the Region V staff has seen no evidence that
reactive aggregate was used in the intake structure.
D.
Escalated Enforcement Actions
a.
Civil Penalties: Three civil penalties totaling $165,000 were
issued as described individually below.
1.
Improper isolation of charging pump rendered Unit 3
Emergency Core Cooling System inoperable on 9/29/83.
Level III violation. Civil penalty $20,000.
2.
Failure to follow operating instruction S023-0-36, Control
of System Alignments, associated with the above item.
Level III violation. Civil penalty $20,000.
3.
Improper isolation of Unit 3 containment spray system on
March 4, 1983, which was not discovered until March 17,
1984. Level III violation. Civil penalty $125,000.
b.
Orders
None relating to enforcement.
32
E.
Management Conferences Held During Appraisal Period
a.
Conferences
September 7, 1983
-
SALP Management Meeting
November 21, 1983
-
Enforcement Conference (Discussion of
circumstances behind isolation of the
discharge of the Unit 3 charging pumps
from the Reactor Coolant System
(Report No. 50-362/83-37)
May 9, 1984
-
Enforcement Conference (Discussion of
licensee's enforcement history and the
findings of a special inspection
conducted on March 17-19, 1984 of the
improper isolation of the Unit 3
containment spray system (Report No.
50-362/84-16)
August 8, 1984
-
Enforcement Conference (Discussion of
licensee action following issuance of
a Notice of Violation on May 16, 1984
involving improper isolation of the
Unit 3 containment spray system
(Report No. 50-362/84-26)
b.
Confirmation of Action Letters
None
F.
Review of 10 CFR 21 Reports and Licensee Event Reports (LER's)
a.
10 CFR 21 Reports
No 10 CFR 21 reports were submitted by the licensee during the
SALP period. The licensee has completed, or has in progress,
action to evaluate and respond to 10 CFR 21 notifications from
other organizations which may impact San Onofre.
b.
Licensee Event Reports
Analyses of significant LER's have been provided in the
applicable functional area sections of this report. A listing
of LER's received during the assessment period is provided in
Table 2. Additionally, an analysis of LER's for the period of
June 1, 1983 to May 31, 1984 was performed by the Office for
Analysis and Evaluation of Operational Data. The results of
this analysis are presented below.
SAN ONOFRE UNIT 1
The licensee submitted 9 LERs, including revisions, for SONGS-1
during the period, June 1, 1983 to May 31, 1984.
In addition,
33
8 other reports were submitted by the licensee. Based on the
review of the available reports, the findings are as follows:
1.
LER COMPLETENESS
a)
Was the information sufficient to provide a good
understanding of the event?
The LERs provided sufficient information to provide a
clear and adequate description of the occurrence, the
direct consequences, and corrective actions.
b)
Were the LERs coded correctly?
All of the entries reviewed appeared to be
essentially correct and the system codes agreed with
the information in the narrative descriptions. One
typographical error was found.
c)
Was supplementary information provided when needed?
Supplemental information was usually provided for
each of the LERs.
In two cases, supplemental
information was provided in separate letters without
an updated LER. The licensee should be encouraged to
submit an updated LER with supplemental information
to ensure that all information pertaining to a
reportable event is complete and referenced to an
LER.
d)
When follow-up reports are promised, are they
delivered?
The licensee generally provided promised follow-up
information in a timely manner.
e)
Were similar occurrences properly referenced?
None of the LERs referenced previous events.
2.
MULTIPLE EVENT REPORTING IN A SINGLE LER
No LERs contained information in a single LER that should
have been reported in separate LERs.
3.
PROMPT NOTIFICATION FOLLOW-UP REPORTS
Each of the prompt reports were followed-up by LERs or
special reports. It appears that LERs were also submitted
for reportable occurrences identified in Preliminary
Notifications.
34
In summary, our review indicates that based on the stated
criteria, the licensee provided adequate event reports during
the assessment period.
SAN ONOFRE UNITS 2 AND 3
The licensee submitted 237 reports, plus revisions, for the two
units during the period from May 1, 1983 to April 30, 1984.
The review included the following LER numbers:
UNIT 2
UNIT 3 83-037 to 83-156 83-037 to 83-120 84-001 to 84-022 84-001 to 84-013
The LER review followed the general instructions and procedures
of NUREG-0161 and NUREG-1022.
Because of the similarity of
both units, and of their respective LER preparers, this LER
review would be applicable to either unit. The specific review
criteria and findings follow.
1.
LER Completeness
a)
Was the information sufficient to provide a good
understanding of the event?
1983 LERs
The LERs provided sufficient information to provide a
clear and adequate description of the occurrence, the
direct consequences and corrective action. Many LERs
included specific details of the event such as the
time of the event, duration of the event, valve
identification numbers, LCOs that were violated,
etc., to provide a more complete understanding of the
event.
1984 LERs
The abstract described the major occurrences of the
event, including all component or system failures
that contributed to the event and significant
corrective action taken or planned to prevent
recurrence as stated in NUREG-1022.
b)
Were the LERs Coded Correctly?
1983 LERs
The codes the licensee selected were checked against
the narrative description of the event for accuracy.
Except for a few infrequent cases, AEOD agreed with
the licensees selection for the coded fields. When
AEOD disagreed, it was in coded fields of lesser
35
importance to the event described, and the
disagreements occurred randomly, so no licensee
misinterpretation of NUREG-0161 guidance was evident.
In addition, each coded entry was typed and centered
within the code box. There were no typos or
omissions. The form was neat in appearance and
readable.
It was evident that care was used in
preparation.
1984 LERs
With the fewer code boxes there is much less chance
for disagreement.
The only licensee error found was
the omission of an event title and a typo in the
event date for LER 84-06 for Unit 2.
c)
Was Supplemental Information Provided When Needed?
1983 LERs
All of the reports that were required to be reported
immediately contained the mandatory supplemental
information. In addition, a significant number of
reports contained voluntary additional supplementary
information. The attachments that were provided
typically included specific information useful in
assessing the full impact of the event. However, the
licensee's safety discussions were often not
commensurate with our perceived potential
consequences of the event, so it appeared that the
safety analysis was briefest for the most potentially
complicated events.
For instance, LER 83-37 reported
that the feedwater logic circuitry resulted in an
actual trip setpoint of 300 psid higher than assumed
in the FSAR. The licensee's safety explanation was
that public health and safety were not affected.
However, it was noted that the licensee usually
stated the number of available redundant systems and
that reports without attachments did not need
additional explanation.
1984 LERs
The text of the LER satisfied the requirements of
NUREG-1022. The licensee's safety assessment of the
event showed considerable improvement from the 1983
submittals but, in some cases, it still did not
completely discuss the safety consequences and
implications of the event.
36
i
d)
Follow-Up Reports
1983 LERs
The licensee promised to update a significant portion
of the LERs in this assessment period. These reports
were updated; they contained new information and they
were updated correctly in accordance with the
guidelines of NUREG-0161. Many reports were promised
to be updated by a specific date by the licensee; the
updated reports were received by this date.
1984 LERs
The same comments are applicable to the 1984 LERs.
e)
Were Similar Occurrences Properly Referenced?
1983 LERs
Previous LER numbers of events of a similar nature
appeared to be referenced correctly. Because there
were many repetitive events, the licensee would only
reference the last few occurrences in lieu of all
previous occurrences. This is acceptable. The
licensee also freely referenced LER numbers of the
other unit. However, on LERs that did not reference
a previous event, the licensee did not provide a
statement to the effect that this is the first event
of this type. Without this statement, it is
uncertain if this is the first occurrence of the
event, or if the licensee failed to reference
previous occurrences.
1984 LERs
The above comments are also applicable to the 1984
LERs, but the proportion of reports without
references seemed higher.
2.
Multiple Event Reporting in a Single LER
No reviewed LER contained information in a single LER that
should have been reported in separate LERs.
3.
Prompt Notification Follow-Up Reports
Eighteen PNs were issued in the SALP assessment period.
Eleven of these events resulted in an LER and the
remaining seven events were clearly unreportable. So, the
licensee appears to be reporting all events that are
required to be reported.
37
Table 1 - Inspection Activity and Enforcement Summary
(6/01/83 -
9/30/84)
Inspections Conducted
Enforcement Items
Functional
Inspection*
Percent
Severity Level**
Area
Hours
Effort
I II III IV V
1. Plant Operations
3924
61
4
2. Radiological
514
8
2
1
Controls
3. Maintenance
143
2
4. Surveillance
205
3
1
5. Fire Protection
87
1
3
6. Emergency
302
5
Preparedness
7. Security and
154
3
Safeguards
8. Refueling
9. Quality Programs
982
13
1
and Administrative
Controls Affecting
Safety (includes
Unit 1 modifications)
10. Licensing
0
0
11. Startup Testing
233
4
(Unit 3)
TOTALS
6,544
100
0
0
6
6 0
- Allocation of inspection hours vs. functional areas are approximations based
upon inspection report data. Resident inspector hours not assigned to another
specific area were counted as Plant Operations effort.
- Severity levels are in accordance with the NRC Enforcement Policy
38
Table 2 - Licensee Event Reports, Unit 1 (6/01/83 -
9/30/84)
LER No.1
Description
(83-001)
Temporary loss of automatic loading for the #1 diesel generator.
(83-002)
Bent upper lateral braces of the Spent Fuel pit storage racks.83-003
Oil change performed on the wrong charging pump resulted in all
three pumps out of service.
(83-004)
Outside air entering the control room bypassed the Control Room
Emergency Air Treatment System filters and charcoal absorber.
(83-005)
Inadvertent SI resulted in increased RCS pressurize and actuation
Pressurizer level increase 2 to 3% per day while at 50% due to
(Infor-
increased nitrogen pressure in the VCT.
mational
Report)84-001
Tear gas on the San Onofre Site.84-002
Spurious starting of No. 2 Diesel Generator.84-003
No. I 125-VDC battery less than required capacity.84-004
Results of inspection of the overspeed governoor/fuel
(Infor-
transfer pump on Transamerica Delaval, Inc., Diesel
mational)
Generator No. 2.84-005
Two boric acid flow paths were blocked due to boric acid
solidification in the flow path piping.84-006
Containment Fire Protection System inoperable during ILRT.84-007
Delinquent approvals of temporary change notices.84-008
Corrosion of intake structure
reinforcing steel apparently due to
long term chloride penetration into
the soil.
1 The 1983 reports enclosed in parenthesis were 14-day LERs; the reports
not enclosed by a parenthesis were 30-day LERs. All 1984 reports were
submitted pursuant to a 30-day reporting requirement.
(
39
Table 2 -
Licensee Event Reports, Unit 2 (6/01/83 -
9/30/84)
LER No.
Description
(83-10)*
Failure of control room emergency air cleanup system to
maintain the required positive pressure due to air leakage
from control room boundary.83-043
Failure of the auxiliary feedwater feedwater pump to manually
start.83-044
Kirk key interlock operation of HPSI pumps found to have an
electrical continuity within breaker contacts.83-045
Reactor trip circuit breaker associated with Plant Protection
System channel A tripped open, rendering channel A inoperable.83-046
Reactor Coolant Cold Leg Temperature was observed outside the
limits.
83-047*
Inoperable Toxic Gas Isolation System train "A" due to a
discharged battery supply and a misaligned alarm setpoint.
83-048*
Pilot flames of trains "A" and "B" Toxic Gas Isolation System
butane/propane monitors experienced persistent flame-out.
83-049*
Emergency Chiller failed to start following an invalad TGIS
due to misalignment of its supply breaker in its cubicle.83-050
Core protection calculator declared inoperable since it
experienced more than two automatic restarts during
the preceeding 12-hour interval.
83-051*
Control room emergency air cleanup system train A inoperable
due to failure of the control room complex isolation damper
to close.83-052
Purge/vent stack radiation monitor inoperable for greater
(Special
than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
report)83-053
Inoperable containment atmosphere gaseous radioactivity monitors
due to unauthorized manipulation of the set point controller.83-054
Misaligned control element assembly (CEA) due to sluggishness
of CEA grippers.
83-055*
Excess oxygen concentration in the waste gas holdup system.
40
Table 2 - Licensee Event Reports, Unit 2 (Cont'd)
LER No.
Description 83-056
Inoperable core protection calculator (CPC) D due to the loss
of a CPC cabinet cooling fan (due to a degraded power supply).
83-057*
Inoperable fire panel due to a smoke detector that was
incorrectly rewired following HVAC and lighting work.83-058
Inoperable core protection calculator channel B attributed to
a multipurpose acquisition and control system error Code 10.83-059
Inoperable train A component cooling water system (CCWS) due
to a broken oil feeder line for a CCWS pump.
83-060*
Failure to maintain a continous fire watch while the deluge
water spray system was inoperable.83-061
Inoperable core protection calculator Channel C due to cold leg
temperature resistance to current converter being out of
calibration.83-062
Secondary coolant system sampling and analysis for specific
activity had not been performed in the required time.
(83-063)
Motor-driven AFW pump failed to complete its 48-hour endurance
run.83-064
DNBR not within acceptable limits while the core operating limit
supervisory system was out of service.83-065
Misaligned control element Assemblies (CEA) due to malfunctioning
of the upper gripper on the CEA.83-066
Inoperable control room emergency air cleanup system due to
emergency chilled water unit failure to start.
(83-067)*
Fire panel 3L-198 failed a routine 6-month surveillance and
compensatory measures prescribed were not implemented.
(83-068)
Reactor coolant system hot leg sampling nozzle loads were
determined to exceed stress limits considered acceptable by CE.83-069
Inoperable control element assembly calculator (CEAC) 1 due to
intermittent and erractic position indication from CEA 20.83-070
Turbine-driven auxiliary feedwater pump (AFW) declared inoperable
in order to isolate two steam leaks in the line to the AFW pump.
41
Table 2 -
Licensee Event Reports, Unit 2 (Cont'd)
LER No.1
Description 83-071
Inoperable diesel generator due to failure to start during
surveillance testing.
(83-072)
Circulating water system traveling screen water level differential
pressure was offscale indicating clogging of the screens.
(83-073)
Inoperable core protection calculator (CPC) channels B and D
due to incorrect CPC constants.
(83-074)
While the turbine building sump effluent monitor was inoperable.
A scheduled grab sample was not taken and analyzed while releases
were being made.83-075
Regulating CEA's (Group 6) exceeded the time allowed below the
long term stead state insertion limit.
83-076*
Extinguished pilot flames of trains "A" and "B" toxic gas isolation
system butane/propane monitors.83-077
Inoperable core protection calculator channel D due to several
spurious trips.83-078
Condensate storage tank water level fell below the technical
specification limit due to water demand higher than make-up to
tank.
(83-079)
Failure to maintain one operable isolation valve in a penetration.83-080
Inoperable reactor coolant boronometer due to leaks at its
connection flange and the flange between the flow indicator and
adjacent check valve.83-081
Inoperable turbine stop valve due to failure of the valve to
reopen after stroking closed.
83-082*
Failure of the supervisory circuit for nine zones due to an
inadvertent circuit interruption by a contract electrician.83-083
Inoperable steam generator wide range level indicator due to
gas entrapped in the instrument's sensing line when
last calibrated.
42
Table 2 - Licensee Event Reports, Unit 2 (Cont'd)
LER No.
Description 83-084
Inoperable core protection calculator due to a low power supply
voltage trip.83-085
Transfer of normal power supply to the safety related KV bus
due to an opened breaker.83-086
Indication on subcooled margin monitor "A" failed to zero.83-087
Inoperable control element assembly calculator (CEAC) #1 when CEA
- 20 analog position indication appeared faulty.83-088
The power supply voltage on the channel D plant protection system
was found to be out of the specified range.83-089
Inoperable train "B" salt water cooling system (SWCS) when the
flow rate was determined to be less than required.83-090
A misaligned control element assembly due to intermittent loss of
power to the control element drive mechanism control system power
switch.
83-091*
A fire barrier penetration seal in the cable riser room was
discovered to be inoperable due to an error in construction.83-092
On two occasions a containment airborne radiation monitor was
rendered inoperable when the associated sample pump motor
breaker tripped. The redundant monitor was out of service.
83-93
Annual surveillance test for fire suppression valves not completed
within the required surveillance interval, and compensatory
measures prescribed were not implemented.
83-94
Fire detector electrical panel failed the supervisory circuit
surveillance test.
83-95
Heat detectors failed the 6-month surveillance test.83-096
Misaligned control element assembly (CEA) due to dirty contacts
on the CEA timer card.
83-097*
Spurious fire protection system deluge actuation.83-098
Inoperable control element assembly calculator (CEAC) 2 due to
inaccurate position indication on three target CEA's.
43
Table 2 -
Licensee Event Reports, Unit 2 (Cont'd)
LER No.
Description 83-099
Inoperable pressurizer level instrumentation when its recorder
pen failed to track.83-100
Inoperable component cooling water return containment isolation
valve when control power to the valve was lost.
83-101*
Inoperable Toxic Gas Isolation System train B when the chlorine
analyzer spuriously actuated and could not reset.83-102
Misaligned control element assembly due to a malfunction in the
upper gripper.83-103
Tc observed outside the limits following a rapid reduction in
power.83-104
Purge/vent stack monitor discovered to have low flow and was
declared inoperable.
83-105*
Pilot flames of trains "A" and "B" Toxic Gas Isolation System
butane/propane monitors were found extinguished.
(83-106)
QA audit revealed the 125V battery bank had unsatisfactory results
during a surveillance test, but no required actions were taken.83-107
Diesel generator building pre-action flame detector alarmed and
could not be reset.83-108
Turbine governor valve failed to reopen after testing trip
solenoid "A" due to a stuck plunger.83-109
During ISI valve testing, containment isolation valve gave a
steady dual indication following a demand to close, rendering the
valve inoperable.
(83-110)
Failure of train B emergency chiller to start due to a fuse
failure.
83-111*
Inoperable penetration seals of fire rated barriers due to
damage during construction activities.
(83-112)*
Forty-one (41) heat detectors were found in zone 12, but 42 heat
detectors were required by technical specifications.83-113
CEAC 2 had 3 auto-restarts within the previous 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and a
required channel functional test was not completed within the
time limit.
Table 2 -
Licensee Event Reports, Unit 2 (Cont'd)
LER No.
Description 83-114
Containment isolation valve gave a dual indication of its position
and was rendered inoperable.83-115
During a surveillance the TGIS train "A" amonia analyzer was
declared inoperable due to a change of amplifier gain.83-116
With the core operating limit supervisory system out of service,
calculations indicated DNBR margin was not within allowable limits.
(83-117)
Pressurizer level instrument on essential plant parameters
monitoring system panel varied from its correct reading by 15%.83-118
Containment isolation valve was found locked open.83-119
Tc dropped below technical specification limits due to a
restrictive Tc limit.83-120
Failure of the iodine removal system flow control valve to open
due to a cracked o-ring.83-121
With the core operating limit supervisory system out of service,
calculations indicated DNBR margin was not within allowable limits.83-122
CPC channel D had more than 3 auto-restarts in the previous 12 hr.
period and was declared inoperable due to failure of its power
supply.
83-123*
Two inoperable electrical penetration seals in the auxiliary
building control area.83-124
Inoperable control element assembly calculator (CEAC) 2 due to
spurious position indication from CEA 20.
(83-125)
Three reactor trip breakers demonstrated anomalous behavior
during surveillance testing when their under voltage devices were
tested.83-126
Surveillance of NIS safety channels not completed within the
required surveillance interval.
83-127*
Inoperable fire rated assemblies in various fire zones.83-128
A containment mini-purge in progress, containment airborne
radiation monitor channel C was discovered to be in alarm defeat.
'I
45
Table 2 -
Licensee Event Reports, Unit 2 (Cont'd)
LER No.
Description 83-129
With the core operating limit supervisory system out of service,
calculations indicated DNBR margin was not within allowable limits.
(83-130)*
Train B emergency chiller tripped and was declared inoperable.83-131
With the core operating limit supervisory system out of service,
calculations indicated DNBR margin was not within allowable limits.83-132
Inoperable steam generator remote shutdown monitoring
instrumentation pressure indicator.83-133
During a reactor trip the excore linear power level channel C
failed due to a failed linear amplifier card.83-134
Unacceptable actuation time of the CCW pump sequence timer relay.83-135
Core Protection calculator channel C declared inoperable following
a spurious trip.
83-136*
Inoperable data gathering panel when a ground fault alarm was
received.
83-137*
Train A containment emergency cooling unit failed to meet
acceptance criteria.83-138
Containment isolation valve failed to close during the waste gas
quarterly valve test due to a loose connection on the terminal
block in the closing circuit.
83-139*
TGIS train "B" chlorine analyzer spuriously initiated and was
declared inoperable.83-140
Inoperable electrically driven fire pump due to an open local
controller shut off switch.83-141
Incorrect control element assembly position indication caused a
reactor trip on a low DNBR signal.
83-142*
Inoperable cable tray fire barriers in various fire zones.83-143
Failure to report an inoperable snubber in the time required.
83-144*
Excessive oxygen concentration in the waste gas holdup system.83-145
Inoperable PPS channel C excore safety channel.
(83-146)
Safety injection tanks exceeded their nitrogen pressure limit.
83-147*
Inoperable control room emergency air cleanup system train "A"
when control room fan failed to automatically start on a TGIS
signal.
46
Table 2 -
Licensee Event Reports, Unit 2 (Cont'd)
LER No.
Description
83-148*
Inoperable diesel driven fire pump starting battery due to a low
electrolyte level in the fire pump battery.83-149
Not issued.
83-150*
A power supply overload protection circuit in fire detection Data
Gathering Panel deenergized the panel, rendering it inoperable.83-151
Tc dropped below the allowable limits previous to a manual reactor trip. Following the trip, a condensate storage tank level dropped
below the allowable limit.83-152
Inoperable remote shutdown boronometer due to a failed display.83-153
Reactor trip breaker undervoltage trip device exhibited
(Infor-
scattered and unacceptable response times.
mational)83-154
Inoperable pressurizer level transmitter due to an empty reference
leg.83-155
Inoperable control element assembly calculator (CEAC) 1 due to
spurious position indication on CEA 20.83-156
Inoperable snubber on the main steam supply line to the auxiliary
feed pump turbine. Also, failure to complete the required
engineering evaluation for the steam supply line as required.84-001
Deficiencies in the fire protection program.84-002
Spurious actuation of the containment purge isolation system due
to an electrical noise spike.84-003
Containment purge isolation system actuation due to a conservatively
established setpoint.83-004
Spurious actuation of containment purge isolation system due to
an electrical noise spike.
84-005**
Flow rate estimates required were not being performed.84-006
Spurious Toxic Gas Isolation System actuations.84-007
Spurious main steam isolation signal due to voltage fluctuations.
0470
Table 2 -
Licensee Event Reports, Unit 2 (Cont'd)
1
LER No.
Description 84-008
Failure of plant monitoring system resulted in inadvertent mode 3
entry.
84-009**
Decalibration of calculated static thermal power.84-010
Partial loss of extraction steam feedwater heating resulted in a
reactor power surge.84-011
Containment purge isolation system actuation due to the failure of
containment airborne monitor gaseous channel "C".
84-012**
Spurious Toxic Gas Isolation System actuations.84-013
Containment negative pressure limit exceeded due to
misinterpretation of the venting procedure.
84-014*
Reactor coolant system flow rate verification not determined as
according to technical specifications.
84-015*
Fire protection program discrepancies.84-016
Inadvertent ESF actuations due to a technician error.84-017
Shutdown cooling valve found fully open contrary to surveillance
requirements.
84-018*
Manual control room isolation system actuation when a dirty
filter caused a low flow alarm.84-019
A false position indication caused control element assembly
calculator to generate a reactor trip on low DNBR.84-020
High steam generator level trip.
84-021**
Spurious Toxic Gas Isolation System actuations.
84-022*
Automatic control room isolation system actuation due to electrical
spikes.
84-023*
Automatic control room isolation system actuations due to electrical
spikes.
84-24*
Fire protection program discrepancies.84-025
Reactor trip breaker undervoltage device anomaly.
(Infor
mational)
84-026*
Spurious Toxic Gas Isolation System actuations.
84-027**
Waste gas processing system valve failure resulting in a
release of Xe-133.
480
Table 2 - Licensee Event Reports, Unit 2 (Cont'd)
LER No.
Description
84-028**
Waste gas sampling system valve failure resulting in a release of
84-029**
Inadvertent de-energization of emergency chiller due to personnel
error.
84-030*
Fire protection program discrepancies.
84-031**
Inoperable emergency chiller due to microswitch malfunction.84-032
Spurious Toxic Gas Isolation System actuations.
84-033**
Leakage through the hydrostatic test boundary valves, pressurized
the entire firemain, causing a break in the piping.84-034
Failure to establish a fire watch.84-035
Containment purge isolation system actuation due to a brief
increase in airborne activity following maintenance.
84-036**
Deficiency with the high pressure safety injection motor
(Infor-
operated loop isolation valves.
mational)
84-037**
Spurious Toxic Gas Isolation System actuations.
84-038**
Spurious control room isolation system actuations due to electrical
noise spikes.
84-039**
Missed in-service inspection test on shutdown cooling heat
exchanger valves.84-040
Main steam isolation system inadvertent actuation due to a
technician error.
84-41*
Fire protection program discrepancies involving cable separation
and fire wraps.84-042
Spurious Toxic Gas Isolation System actuations.84-043
DNBR reactor trip due to erroneous control element assembly
position indication.
84-044**
Actuation of Toxic Gas Isolation System due to fumes from a
cleaning solvent.
49
Table 2 - Licensee Event Reports, Unit 2 (Cont'd)
LER No.1
Description 84-045
Inoperable charging pump due to leakage from a crack on the
cylinder block.
84-046*
Inoperable Component Cooling Water Trains.
84-047*
Spurious control room isolation system actuations due to noise
spikes.84-048
Delinquent Surveillance of the Electrical Power Systems.
1. The 1983 reports enclosed in parenthesis were 14-day LERs; the
reports not enclosed by a parenthesis were 30-day LERs. All 1984
reports were submitted pursuant to a 30-day reporting requirement.
- Common system LER for Units 2 and 3
- LER for Unit 2, but applies to Units 2 and 3.
50
Table 2 -
Licensee Events Reports, Unit 3 (6/01/84 -
9/31/84)
LER No.1
Description 83-034
Qualified safety parameter display system found to have the
potential for a loss of indication during and after a seismic
event.83-038
Inoperable fire spray system and fire detection instrumentation
due to corrosion of the panel internals caused by water
intrusion from improper closure of the panel.
(83-039)
See Unit 2, LER No.83-063.
(83-040)
See Unit 2, LER No.83-068.
(83-041)
See Unit 2, LER No.83-072. 83-042
Early warning fire detectors found inoperable due to a melted
element in the fusible heat detector.
(83-043)
Emergency chilled water unit failed to start during Control Room
Emergency Air cleanup system surveillance testing.
(83-044)
Contrary to technical specifications, a manual containment
isolation valve was opened.83-045
Damaged fire barrier penetration seals in the diesel generator
building.
(83-046)
Inoperable diesel generators due to isolation of the normal
diesel fuel supply from the fuel transfer pumps to each of
the day fuel tanks.83-047
Inadvertent actuation the deluge spray system.83-048
See Unit 2, LER No.83-110
83-049
Low volume control tank level due to a lifted relief valve that
failed to reseat.83-050
The outer containment airlock door jammed in the open position.83-051
Low flow readings from the condenser air elector monitor.83-052
See Unit 2, LER No.83-085
83-053
Boronometer declared inoperable due to readings drifting downward.83-054
Inoperable Containment Spray Chemical Storage Tank.
S0
51
Table 2 - Licensee Event Reports, Unit 3 (Cont'd)
LER No.
Description 83-055
Core protection calculator channel A was declared inoperable
due to a failed high reactor coolant cold leg temperature input.83-056
Level indication for fuel oil storage tank was discovered to be
off-scale low rendering the associated diesel generator
Inoperable system generator wide range level indicator.83-058
Inoperable containment isolation valve due to poor position
indications.83-059
Inoperable main steam line radiation monitor.83-060
Inoperable control element assembly calculator 1 and core
protection calculator channel B.83-061
Inoperable pressurizer pressure indicator.83-062
Failure of control element assembly shutdown group to maintain
position.83-063
Inoperable steam-driven auxilary feedwater pump due to steam
inlet valve not opening completely.83-064
Inoperable excore logarithmic power safety channel C and B due
to failed connectors.83-065
Inoperable high range in-containment radiation monitor due to
a failed low condition.83-066
Excessive auto restarts of the control element assembly
calculator 2.83-067
Partial trip of the individual supply breaker for part length
CEA 32 rendered the CEA incapable of withdrawal.
(83-068)
Violation of LCO 3.0.4 when mode change was made while control
room cabinet area emergency air conditioning was out for
maintenance.83-069
Inoperable condenser air ejector wide range gas monitors.83-070
Control element assembly calculator inoperable due to control
element assembly is giving spurious indication of rod movement.
52
Table 2 -
Licensee Event Reports, Unit 3 (Cont'd)
LER No.
Description 83-071
Unusual event due to an unidentified leakage of 1.19 gpm.83-072
Containment water level-wide range train B instrumentation
failed during a channel check.
(83-073)
Technical specifications violated when charging and letdown
flows were isolated.83-074
Inoperable containment airborne radiation monitor.83-075
Inoperable low pressure turbine stop valve due to a piece of
wood between the disc and the seat.83-076
Inoperable control element assembly calculator 2.83-077
Fire detection and actuation panel failed a 6-month supervisory
circuit surveillance test.83-078
Inoperable boronometer due to the isolation of the charging and
letdown.83-079
Failure of core protection calculator channel A.83-080
While performing a Reactor Coolant System Water Inventory
Balance, tc dropped below minimum temperature (544 0F).83-081
RCS water inventory balance was not completed within the required
surveillance interval.83-082
Inoperable qualified safety parameter display system train B
due to a failed circuit board.83-083
A diesel generator tripped during surveillance testing and could
not be restarted.83-084
During a monthly surveillance, the auxiliary feedwater flow rate
channel was declared inoperable.83-085
The low pressure turbine no. 1 intercept valve failed the trip
solenoid A and B tests due to a failed logic card in the control
circuit.83-086
Inoperable control element assembly calculator (CEAC) 2 due to
technician error.
53
Table 2 -
Licensee Event Reports, Unit 3 (Cont'd)
LER No.
Description
(83-087)
Plant monitoring system computer failed while the plant was
under special test exception.83-088
Reactor coolant system hot leg sample valve showed intermediate
2
indication and could not be closed from the control room.83-089
AFW pump was declared inoperable to replace a broken torque
switch on the motor operator for a steam inlet valve.83-090
Fire detector electrical panel failed a 6-month surveillance test.83-091
The undervoltage armatures for reactor trip breakers were found
not to be fully picked up.83-092
Core protection calculator B was declared inoperable due to trips
received from a faulty RTD.83-093
Core protection calculator (CPC) and excore linear power level
(ELPL) channel C were declared inoperable while CPC and ELPL
channel D were out of service.83-094
Plant protection system channel C was observed to be in the
tripped condition.83-095
Inoperable channel A accident monitoring instrumentation for the
pressurizer water level indication due to erroneously high level
indication.83-096
AFW pumps rendered inoperable to allow repairs on emergency
feedwater actuation system no. 1 circuitry.83-097
Misaligned control element assemblies (CEA) due to sluggishness
Qualified safety parameter display system channel A was
continuously cycling through the pages of its display, and
was declared inoperable.93-099
Failure of the steam driven auxiliary feedwater pump to start
during a reactor trip due to the pump being in the tripped
condition.83-100
Constant alarm state of containment airborne radiation monitor
rendered the leak detection system gaseous channel inoperable.83-101
Core protection calculator channel B experienced more than 3
auto-restarts within the previous 12-hour period.
0
54
Table 2 -
Licensee Event Reports, Unit 3 (Cont'd)
LER No.
Description 83-102
Failure of channel A of the post Loss of Coolant Accident (LOCA)
During plant stabalization following a manual trip, the
condensate storage tank level dropped below the technical
specification limit.83-104
Inoperable auxiliary feedwater (AFW) flow rate channel due to
erroneously high AFW flow rate indication when no flow existed.83-105
Mini-purge exhaust containment isolation valve failed to close
within its maximum isolation time.83-106
With the core operating limit supervisory system out of service,
calculations indicated that the DNBR was not within allowable
limits.83-107
Inoperable train A containment emergency cooling unit and train B
diesel generator.83-108
Inoperable qualified safety parameter display system channel A.83-109
Qualified safety parameter display system channel A began
intermittently failing and was declared inoperable.83-110
Misaligned control element assemblies (CEA) due to sluggishness
Reactor coolant system specific activity exceeded 1.0
microcurie/gram dose equivalent 1-131.83-112
Regulating group 6 control element assemblies exceeded the time
allowed below the long term steady state insertion limit.83-113
Failure of control element assembly calculator 2 due to a 83-114
Nitrogen cover pressure in the safety injection tank was below
the minimum value.83-115
Inoperable core protection calculator channel C due to a failed
module card.83-116
Reactor trip breaker under voltage trip device exhibited a
(Infor-
procedurally unacceptable response.
mational
Report)
w
55
Table 2 -
Licensee Event Reports, Unit 3 (Cont'd)
LER No.
Description 83-117
Misaligned control element assembly due to a faulty IC chip on
the rod's timer card.83-118
With the core operating limit supervisory system out of service,
calculations indicated that the DNBB was not within allowable
limits.83-119
Inoperable core protection calculator channel A due to the
multipurpose aquistion and control system error code 10.83-120
During plant stabalization following a manual trip, the
condensate storage tank level dropped below the technical
specification limit.84-001
Precautionary evacuation of personnel due to an inadvertent
release of radioactive material.84-002
Hourly fire watch patrols were suspended following evacuation
of the Penetration Building due to airborne iodine and
noble gas concentrations.84-003
Reactor trip due to control element assembly slipping thirty
inches.84-004
Inadvertent safety injection actuation due to dirty contacts
on the "relay hold" pushbutton.84-005
Reactor Coolant System dose equivalent iodine limits exceeded
(dated
due to iodine spiking following a power change.
2/6/84)84-006
Reactor trip breaker #8 undervoltage device did not actuate.84-007
Spurious Reactor Protection System trip.84-008
Reactor trip on loss of load.84-009
Inoperability of containment spray system.84-010
Spurious Containment Purge Isolation System Actuations84-011
Disconnected leads in plant protection system cabinets.84-012
Failure of main steam isolation valves to meet technical
specification surveillance requirements.
56
Table 2 -
Licensee Event Reports, Unit 3 (Cont'd)
LER No.
Summary Description 84-013
Reactor coolant system dose equivalent iodine limits exceeded
due to iodine spiking following a power change.84-014
Charging pumps inoperable due to the failure of the discharge
check valve and discharge relief valve.84-015
Dose equivalent iodine limits exceeded and RCS samples were
not taken and analyzed as required.84-016
Reactor trip breaker undervoltage trip device exhibited an
unacceptable response time.84-017
High steam generator water level reactor trip during routine
reactor shutdown.84-018
Reactor trip breaker undervoltage trip device exhibited an
(Infor-
unacceptable response time.
mational
Report)84-019
Post maintenance testing on containment isolation valves was
not performed as required.84-020
Missed condenser evacuation system sample because the sample pump
was isolated.84-021
Actuation of the safety relief valve on the nuclear sample system.84-022
Failure in the turbine control system caused a "loss of load"
Reactor Coolant System Dose equivalent iodine limits exceeded
due to iodine spiking following a power change.84-024
Reactor trip on low DNBR due to hardware failure on one of five
computer boards.84-025
Containment pressure transmitter inoperable due to closed
isolation valve.84-026
Containment purge isolation system actuation due to equipment
failure.84-027
Missed iodine and particulate sample following a reactor trip.84-028
Delinquent processing of overtime request forms.
57
Table 2 -
Licensee Event Reports, Unit 3 (Cont'd)
LER No.
Description 84-029
Reactor power increase above rated power due to partial loss of
extraction system feedwater heating.84-030
Containment purge isolation system actuation due to a spurious
instrument fail signal.84-031
Containment purge isolation system actuation.84-032
High steam generator water level reactor trip during manual
operation of the feedwater control system.84-033
Condensate storage tank flow path blocked.84-034
Fire protection discrepancy due to missing conduit fire wrapping.
1. The 1983 reports enclosed in parenthesis
were 14-day LERs; the reports not enclosed
by a parenthesis were 30-day LERs. All 1984
reports were submitted pursuant to a 30-day
reporting requirement.