ML15239A021
| ML15239A021 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 04/11/1989 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15239A020 | List: |
| References | |
| 50-269-89-01, 50-269-89-1, 50-270-89-01, 50-270-89-1, 50-287-89-01, 50-287-89-1, NUDOCS 8904240237 | |
| Download: ML15239A021 (33) | |
See also: IR 05000269/1989001
Text
ENCLOSURE
INTERIM SALP BOARD REPORT
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
INSPECTION REPORT NUMBER
50-269, 270, 287/89-01
DUKE POWER COMPANY
OCONEE UNITS 1, 2, AND 3
AUGUST 1, 1987 - JANUARY 31, 1989
8904240237 8 90411
ADOCK 05000269
Q
TABLE OF CONTENTS
Page
I.
INTRODUCTION.1
A.
Licensee Activities
1......1
B.
Direct Inspection and Review Activities .................... 3
II. SUMMARY OF RESULTS
4
Overview
4.......4
III.
CRITERIA
6
IV. PERFORMANCE ANALYSIS
7
A.
Plant Operations ......................................... 7
B.
Radiological Controls .................................... 10
C.
Maintenance/Surveillance ................................. 13
0.
Emergency Preparedness ................................... 18
E. Security-& Safeguards .................................... 20
F.
Engineering/Technical Support ............................. 22
G.
Safety Assessment/Quality Verification ..................... 24
V.
SUPPORTING DATA AND SUMMARIES .................................
27
A.
Escalated Enforcement Action
....
27
B.
Management Meetings ...................................... 28
C.
Confirmation of Action Letters ............................ 29
0.
Review of Licensee Event Reports .......................... 29
E.
Licensing Activities ..................................... 29
F.
Enforcement Activity ..................................... 30
G.
Reactor Trips ............................................ 30
H.
Effluent Release Summary ................................. 31
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 on the basis of this
information. The program is supplemental to normal regulatory processes
used to ensure compliance with NRC rules and regulations. It is intended
to be sufficiently diagnostic to provide a rational basis for allocation
of NRC resources and to provide meaningful feedback to the licensee's
management regarding the NRC's assessment of their facility's performance
in each functional area.
An
NRC SALP Board,
composed of the staff members listed below, met on
March 20, 1989, to review the observations and data on performance, and to
assess licensee
performance in accordance with Chapter NRC-0516,
"Systematic
Assessment
of Licensee
Performance."
The
guidance
and
evaluation criteria are summarized in Section III of this report.
The
Board's findings and recommendations were forwarded to the NRC Regional
Administrator for approval and issuance.
This report is the NRC's assessment of the licensee's safety performance
at Oconee Units 1, 2, and 3 for the period August 1, 1987 through
January 31, 1989.
The SALP Board for Oconee- was composed of:
C. W. Hehl,
Deputy Director, Division of Reactor Projects (DRP),
Region II (RH) (Chairman)
A. F. Gibson, Director, Division of Reactor Safety, (DRS), RH
J. P. Stohr, Director, Division of Raditation Safety and Safeguards
(DRSS), RH
A. R. Herdt, Chief, Reactor Projects Branch 3, ORP, RII
D. B. Matthews, Director, Project Directorate 11-3, Office of Nuclear
Reactor Regulation (NRR)
P. H. Skinner, Senior Resident Inspector, Oconee, ORP,
RH
D. Hood, Project Manager, Project Directorate 11-3, NRR
Attendees at SALP Board Meeting:
M. B. Shymlock, Chief, Project Section 3A,
DRP,
RII
B. R. Bonser, Project Engineer, Project Section 3A, DRP, RH
L. D. Wert, Resident Inspector, Oconee, DRP, RH
S. Ninh, Reactor Engineer, Technical Support Staff, DRP, RH
A.
Licensee Activities
During this SALP period, Unit 1 was on line for a total of 460 days
with a unit capacity factor of 82.28%, Unit 2 was on line for 476
days with a capacity factor of 81.5%, and Unit 3 was on line for 486
days with a capacity factor of 85.4%.
These capacity factors are
much better than the plant lifetime factors of approximately 68%. The
forced outage rates were 0.34%, 2.62% and 4.28% for Units 1, 2 and 3
2
respectively.
This is much lower than
the lifetime average of
approximately 12%.
The operating history during this assessment
period is described below.
Unit 1
Unit 1 began this SALP period at 85% power, limited by high lake
water (condenser circulating water) inlit temperature.
The Unit
reduced power to 80% on August 18,
1987 due to the temperature
reading of 79.5 dagrees F.
On September 2, 1987 the Unit was taken
off-line for the end of cycle 10 refueling outage.
The Unit returned
to service on November 6, 1987 but was taken off-line to conduct
turbine generator balancing.
The Unit returned to 100% power on
November 15,
1987
and
remained
basically at full power until
February 17,
1988,
when the Unit reduced power to 61% due to a
feedwater pump problem. The feed pump problem was corrected and the
Unit returned to full power on February 24 until July 1 when power
was reduced to approximately 25% to add oil to the "182" reactor
coolant pump (RCP).
The reactor was returned to full power on
July 2, 1988 and then tripped on July 5 due to a false indication of
lost feedwater flow. The Unit was restarted on July 6, 1988 and
returned to full power on July 8, 1988.
On August 30,
1988 the Unit
was again removed from service to add oil to "182" RCP and returned
to service the following day. Full power conditions were attained on
September 1, 1988 and remained at this point until the reactor
tripped on January 2, 1989,
due to an -operator error.
During the
recovery from this trip on January 3,
1989 with the unit at
approximately 25%, a fire occurred in the ITA (6900v)
switchgear that
caused extensive damage forcing the operators to manually trip the
reactor and place the plant in a natural circulation condition for a
short period of time.
At this time the licensee decided to commence
the end of cycle (EOC)
11 outage which was previously scheduled for
January 27, 1989.
Unit 2
Unit 2 began this reporting period operating at approximately 85%
power, limited by high water level due to fouling in the "B" steam
generator.
The Unit reduced power on August 6 to 71% due to a low
oil level in a reactor coolant pump.
On August 12,
1987 power was
further reduced, oil added to the pump and power level returned to
approximately 85% on the following day.
The unit remained at 85%
power except for changes due primarily to minor equipment problems,
until February 3, 1988 when the Unit was shut down for the EOC-9
-refueling outage. The outage was completed in early April and the
Unit returned to 100% power on April 15,
1988.
Since the steam
generators were chemically cleaned during the outage,
power was no
longer limited due to steam generator water levels.
On April 17,
1988 the Unit experienced a turbine-generator runback to 44% due to a
stator coolant flow instrumentation problem. The Unit power was then
decreased to approximately 25% to repair the instrumentation and
3
returned
to
100% power
on April 20.
The Unit remained at
approximately 100% power, with the exception of short periods when
the Unit was used to load follow on the grid, until June 6 when it
was shut down due to steam generator tube leaks. It was returned to
service on July 16 and following resolution of several secondary
system problems returned to 100% power on July 29.
On August 26 the
Unit tripped from 100% power due to a faulty high moisture separator
drain tank level signal.
This was repaired and the Unit returned to
100% power on August 27 and remained at that power level for the
duration of this SALP period.
Unit 3
Unit 3 commenced this reporting period operating at full power until
January 3, 1988 when power was reduced due to a steam generator tube
leak.
The leak stabilized on January 10,
1988 and the unit was
returned to full power.
On April 2 power was reduced to 88% to
conserve the core for the summer load period, but was shut down on
April 17 due to steam generator tube leakage.
The Unit was returned
to power on May 11,
1988 and remained at power until the Unit was
shut down to begin the EOC 10 refueling outage on August 10,
1988.
The outage was completed on September 23, 1988 but several turbine
problems delayed the return to full power.
The unit was returned to
service and full power conditions on September 26,
1988 until
November 14,
1988 when the reactor tripped twice.
The cause of the
first trip could not be determined,- however, the unit was restarted.
At about 40%, the second trip occurred but this time the cause was
determined to be a faulty relay in the steam generator level
circuitry and was corrected.
The Unit was restarted and returned to
full power op November 16,
1988.
On January 11,
1989 the Unit was
shut down due to fouling of the reactor building cooling units
(RBCU).
The
RBCUs were cleaned, and retested. Unit 3 returned to
service and has remained at full power for the remainder of this SALP
period.
B.
Direct Inspection and Review Activities
During the assessment period, routine inspections were performed at
Oconee by the NRC staff.
Special inspections were conducted as
follows:
-
February 22 -
26, 1988, a special inspection in the areas of
Environmental Qualification (EQ)
of electrical equipment.
It
included a review of Duke
Power Company's implementation of
requirements of 10 CFR 50.49 for Oconee and an inspection of EQ
electrical equipment.
-
April
25 -
May 5,
1988,
a special inspection to review the
adequacy of Emergency Operation Procedures.
4
-
May 9 -
13 and May
19 -
27,
1988,
a quality verification
functional inspection (QVFI)
was conducted in the areas of
operations and surveillance testing, maintenance,
and design
control.
-
July 11 -
29,
1988, a special trial Maintenance Team Inspection
(MTI) of the methodology prescribed by NRC temporary instruction
TI 2515/97, Maintenance Inspecticn to evaluate the implementa
tion of the licensee's maintenance program.
-
January 4 -
14, 1989, an Augmented Inspection Team investigated
the reactor trip on January 2 and the fire on January 3, 1989.
II. SUMMARY OF RESULTS
Overview
Oconee was operated in an overall safe manner during this assessment
period. Strengths were observed in the areas of Plant Operations,
Radiological Controls
and Emergency
Preparedness.
A decline in
performance was identified in the areas of Security and Maintenance
and Surveillance.
Additional managerial attention is needed to
return these areas to their previous performance status.
Operations performance continued to be a strength.
The number of
a-utomatic trips were reduced well below the industry average and
below the goals established by the licensee.
Corporate interest and
oversight of plant activities was very apparent. Fire protection was
adequate. Good progress has been made in plant cleanliness which
resulted in a reduction of contaminated areas.
Management
was
frequently observed in various areas of the plant providing oversight
of activities and guidance to personnel in those areas. The operator
training and experience were excellent.
The
Radiological Controls area is considered a strength.
The
reduction of contaminated areas noted above and the continuing effort
to further reduce these areas was noteworthy.
The reduction of
person-rem by use of mockup training and use of remote devices and
other training activities is
also noteworthy.
A weakness was
identified in the extended period of inoperability of several
Radiation Indicating Alarms.
The
licensee
has
strong maintenance and surveillance programs.
However, over this assessment period, numerous performance problems
in maintenance were identified. These performance
problems were
characterized by inattention to detail,
miscommunication,
and
procedure/personnel
errors
resulting
in violations
of
NRC
requirements.
Over the period Oconee
station has had good
availabililty and few operational problems directly attributable to
maintenance.
5
Surveillance
activities have also experienced a decrease in
effectiveness. Surveillances were completed on time with only minor
problems identified. However, notable problems were identified in
the in-service testing of valves.
The chemistry program in
conjunction with the chemical cleaning of Unit 1 and 2 steam
generators and the continued attention being provided to meet the
guidelines recommended by the Steam Generators Owners Group
has
minimized degradation of the steam generator tubes.
Emergency Preparedness activities have been maintained as a strength.
The licensees many drills conducted in this area have been beneficial
as demonstrated by the utilities actions during several actual
conditions that occurred during this assessment period.
However, a
weakness was noted that involved an incorrect classification of an
emergency declaration during the conduct of the annual drill.
The Security area,
which histori-cally has been a strong area,
experienced a significant number of minor problems during this
assessment period.
Although no single problem was overly signi
ficant, the number of problems identified showed a distinct decrease
in the effectiveness of the security effort.
Of special note is the
continuing problem with the closed circuit television assessment
capability attributed to poor design and installation.
Management
reacted positively to weaknesses
identified in the
Engineering/Technical Support area during the previous assessment
period.
This effort was
noted
in the
assignment of design
engineering personal to the site and the restructuring of corporate
engineering groups to a site specific function rather
than
a
discipline function as was used in the past.
Management activities
have resulted in the self-identification of several significant
problems notable among these was the HPI system mode requirements
previously not addressed correctly by the operations staff. Although
progress has been made in this area weaknesses still exist such as
those associated with communications
and simulator hardware and
software. Additional management attention may be needed to achieve
the desired results in this area.
With respect to the Safety Assessment/Quality Verification area
several aspects of plant performance were assessed.
The licensee
continues to perform self initiated technical audits and use other
sources to improve safety performance.
QA,
and management
continue to provide good oversite of all activities.
The quality of
Licensee Event Reports have improved. Weaknesses were noted in the
area of complete follow through of activities. This was exemplified
by the lack of thoroughness associated with the HPI "piggyback" mode
of operation issue and several
issues concerning
10
CFR 50.59
evaluations.
6
Rating Last
Rating This
Functional Area
Period
Period
Plant Operations
1/2
-
1
(operations & fire protection)
Radiological Controls
2
1
Maintenance/Surveillance
1/1
2
1
1
Security
1
2
Engineering/Technical Support
2
2
(engineering, training & outages)
Safety Assessment/
2/2
2
Quality Verification
(quality programs & licensing)
III. CRITERIA
Licensee performance is assessed in selected functional areas, depending
on whether the facility is in a construction or operational
phase.
Functional areas normally represent 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, as applicable, to assess each
functional area:
1. Assurance of quality, including management involvement and control;
2. Approach
to the resolution of technical issues from a safety
standpoint;
3.
Responsiveness to NRC initiatives;
4.
Enforcement history;
5. Operational and construction events (including response to, analyses
of, reporting of, and corrective actions for);
6.
Staffing (including management); and
7.
Effectiveness of training and qualification program
However, the NRC is not limited to this criteria and others may have been
used where appropriate.
7
On the basis of the NRC assessment,
each functional area evaluated is
rated according to three performance categories.
The definitions of these
performance categories are as follows:
1. Category 1. Licensee management attention
and
involvement
are
readily evident and place emphasis on superior performance of nuclear
safety or safeguards activities, with the resulting performance
substantially exceeding regulatory requirements.
Licensee resources
are ample and effectively used so that a high level of plant and
personnel performance is being achieved.
Reduced NRC attention may
be appropriate.
2.
Category 2. Licensee management attention and involvement in the
performance of nuclear safety or safeguards activities are good. The
licensee has attained a level of performance above that needed to
meet regulatory requirements.
Licensee resources are adequate and
reasonably allocated so that good plant and personnel performance is
being achieved. NRC attention may be maintained at normal levels.
3.
Category 3. Licensee management attention to and involvement in the
performance of nuclear safety or safeguards activities are not
sufficient. The licensee's performance does not significantly exceed
that needed to meet minimal
regulatory requirements.
Licensee
resources appear to be strained or not effectively used.
NRC
attention should be increased above normal levels.
The SALP Board may also include an appraisal of the performance trend of a
functional area. This performance trend will only be used when both a
definite trend of performance within the evaluation period is discernable
and the Board believes that continuation of the trend may result in a
change of performance level.
The trend, if used, is defined as:
Improving: Licensee performance was determined to be improving near the
close of the assessment period.
Declining: Licensee performance was determined to be declining near the
close of the assessment period and the licensee had not taken meaningful
steps to address this pattern.
IV. PERFORMANCE ANALYSIS
A.
Plant Operations
1. Analysis
During
this
assessment pertod
routine
inspections
and
evaluations of plant operations were performed by the resident
and regional inspection staffs. A total of five automatic trips
occurred during this rating period, two on unit 1, one on unit 2
and two on unit 3. One manual trip was also experienced. Seven
automatic trips occurred during the last rating period.
8
The quality of operations has been maintained at a high level of
performance.
The number of automatic reactor trips has been
reduced below the industry average of 2.1 automatic trips a year
and the goal established- by the licensee of no more than two
trips per unit per year.
Upper level management continues to be extensively involved in
all aspects of plant operation.
The licensee has taken action
to provide senior reactor operator training to most of the
superintendents
and many
senior supervisory personnel.
In
addition some of the superintendents have rotated positions in
order to provide a greater understanding of how each discipline
functions to support the overall effort of safe and efficient
operation.
Management
has
been observed frequently in the
control room and touring the plant areas. Outage management has
shown major improvement.
Outage time
has been reduced to
approximately 45 days without any significant reduction in the
quantity and quality of work being accomplished.
The Shift
Engineers, who are licensed senior operators, are very involved
in coordination of outage work during backshift and weekends.
The low turnover rate (less than 3%) maintained by the licensee
has been instrumental in maintaining a continued high experience
level and a high level of competence in the operations staff.
Due in part to this low turnover rate, the amount of overtime
required of the operators has not been excessive. In addition to
the experience in the operations group, senior personnel with
operating experience have been placed in various other groups.
Control
room demeanor and attentiveness has been good. There
have been several instances where operator attention and quick
action have prevented a reactor trip due to malfunctioning
components.
To promote professionalism,
the operators,
in
conjunction-with -the- operators* at Catawba and McGuire,
have
developed a set of operator principles. These are posted in the
control rooms and other operations areas and identify their
commitment to excellence. Operations staffing level continues to
exceed TS requirements for shift crew composition.
A high level
of attention to details beyond their normal duties on the part
of several non-licensed equipment operators (NEO) identified and
assisted in resolving several problems.
Examples of this were
the identification of a problem with the Emergency
Power
Switching Logic (EPSL)
and also identification of a containment
isolation valve being mispositioned.
Only two instances have
been identified where operators have failed to follow their
procedures. These primarily occurred during the early part of
this assessment period and were attributed to the incorrect use
of identifying steps as "not applicable" by the supervisor or an
isolated personnel error. Improvement in this area has occurred
during this period due to managements attention to this problem
and the continued emphasis
by management
to follow their
procedures.
9
Communications Ltween operations
and
other
groups
is
acceptable, but there have been several
instances where
inadequate communications have caused a problem.
Examples of
this
communication
problem
between operations
and
the
performance group involved a loss of all power on Unit 3 for
approximately 15 minutes while in decay heat removal during the
last refueling outage.
Another communication problem between
operations and the instrumentation and electrical group resulted
in a runback on Unit 3 as a result of a pulled fuse while
troubleshooting the rod drive system. Communications
between
operations and the General Office Engineering staff resulted in
a significant safety concern as discussed in more detail in
section G. Improvements have been noted in this area in recent
months, but continued management attention should be provided in
this area.
An Augmented Inspection Team (AIT)
reviewed two incidents that
occurred on January 2 and 3, 1989 on Oconee Unit 1. The AIT was
established to review the events associated with a reactor trip
from 100% power that occurred on January 2 and an explosion and
fire in the 6900 volt switchgear that resulted in a manual reactor trip from a low power level and subsequent operation in
a natural circulation condition on January 3.
The conclusion
reached by the AIT was that during the first incident, the
operators took appropriate actions to maintain the plant in a
safe condition. The AIT determined that during the second event
the firefighting techniques and results were adequate,
and that
the reactor trip that had occurred the previous day did not
contribute to the fire and trip on the following day.
In
addition the team concluded that management was highly involved
in both the actions taken during the evolutions and the repairs
following the stabilization of the unit.
The team identified
weaknesses in the training of operators and supervisors in areas
associated with .use
of pressurizer auxiliary spray,
the
requirements
for operation in the Thermal
Shock Operating
Region, and natural circulation with low decay heat conditions.
As a result of these findings, the licensee has taken action to
conduct additional training and provide additional guidance in
these areas.
An Emergency Operating Procedure (EOP) inspection found that the
Oconee Emergency Procedures (EP)
and Abnormal
Procedures (AP')
adequately cover the broad
range of emergencies and other
significant events required by Regulatory Guide 1.33, Section 6.
The team found technical discrepancies in the licensee's
procedures for cooldown using the HPI system, boron dilution,
loss of condenser circulating water intake canal/dam failure and
pump
operation.
Also inconsistencies in
operator interpretation of important terms indicated a need for
further operator training in EOP terminology use.
The licensee
is correcting these inconsistencies.
10
The plants housekeeping arcd material condition continued to be
acceptable and continued to improve. Although progress has been
made in housekeeping, specific areas are frequently identified
where debris has accumulated especially following outages.
Management is making an effort to correct this problem.
With respect to fire protection, the licensee's fire protection
procedural program
and implementation
of fire
prevention
administrative controls were found to meet NRC requirements and
guidelines. Fire systems required for protection of safety
related plant areas were
being maintained operable.
The
staffing of the Safety/Fire Protection Department onsite and in
the corporate Design Engineering group was adequate. The onsite
group was staffed with two fire protection specialists who have
primary responsibility for the implementation of the Fire
Protection Program.
The entire Safety/Fire Protection staff
actively
monitored
plant
activities
to
assess
proper
implementation of the program.
In addition, a Fire Protection
Engineer was also assigned to the site from the corporate Design
Engineering office.
The overall quality of the staff was a
program strength.
Two violations were identified in this area:
a. A- Severity Level
IV violation for failure to follow
procedures which resulted in a loss of low temperature
overpressure protection for a total of 8 minutes.
(88-28,
Unit 3 only)
b. A Severity Level IV violation for an inadequate procedure
for testing the Emergency Power Switching Logic causing a
complete loss of all AC power to Unit 3. (88-28,
Unit 3
only )
2.
Performance Rating
Category: 1
Previous Rating: Operations:
1
Fire Protection: 2
3.
Recommendations
None
B.
Radiological Controls -.
1. Analysis
Inspections were conducted in the areas of radiation protection,
radiological effluents,
and confirmatory measurements during
this assessment period.
11
The
licensee's health physics (HP)
radwaste
and chemistry
staffing levels compared favorably to other facilities of
similar size.
Eighty-seven percent of licensee health physics
technicians were ANSI/ANS 3.1 qualified, with the remainder to
be qualified during the current
SALP period.
Contract HP
technicians
have usually been
hired
to support
refueling
outages. However, a refueling outage originally scheduled for
January 28,
1989, started three weeks earlier without contract
technicians.
The
licensee
provided
radiation protection
efficiently in the
interim period
by
reassigning
office
personnel to the field. The experience of contract technicians
was a program strength since a high percentage of contract HP
technicians had previous outage experience at Oconee.
The
licensee HP staff also had a low turnover rate.
A finding that retraining for contract HP technicians had not
been formalized was corrected by changing the HP manual to
require retraining for those who had not worked on site in the
last twelve months.
The site specific HP training course
contained elements required for course accreditation.
Management
support for the radiation protection program was
demonstrated by the installation and operation of Constant Air
Monitors, a state-of-the-art whole body counter,
an automated
laundry monitor for screening of protective clothing, and a new
radioactive waste sorting and compacting facility.
The licensee continued to have
an aggressive contamination
control
program.
Dedicated decontamination crews maintained
approximately ninety-three percent of
the
radiologically
controlled area (RCA) as non-contaminated.
The licensee's approach to resolving HP technical issues was
adequate. Problems associated -with the plant breathing
a-ir
systems were identified during an inspection and corrective
action included calibration of system pressure gauges,
operator
intervention
upon carbon monoxide monitor failure, as-built
drawings for the location of air manifolds and pressure gauges,
and provision for direct communication between the control room
and HP personnel concerning the breathing air system.
Weaknesses were identified in the licensee program to control
personnel exposure to radiation. Violations were identified for
workers
entering containment without reporting to
the HP
technician as instructed and for workers entering and exiting
high radiation areas without knowledge of area dose rates and
without adequate monitoring of self-reading pocket dosimeters.
In addition, high radiation area hot spots,
greater than 100
millirem per hour at 18 inches, were not labeled after shielding
had
been
installed.
Licensee
management
understood
12
the issue and committed to take the approprie-e and necessary
corrective actions.
The licensee established a goal of 1,000 person-rem for 1988 for
all three units. During 1988,
the licensee's collective dose
was 879 person-rem or 293 person-rem per unit as measured by
TLD.
The low station collective exposure was attributed to
efficient ALARA planning during outages and use of robotics in
maintenance of steam generators.
The dose received in 1988 is
the lowest dose since 1975 for the licensee which is usually at
or below the national average for PWRs.
Liquid and gaseous effluents for calendar year 1987,
and the
first half of 1988,
were within regulatory limits.
Offsite
doses did not exceed 10 CFR
50,
Appendix I ALARA criteria.
Liquid and gaseous effluents for 1985 through the first half of
1988 are summarized in this report (see
Section V.1).
The
licensee reported a total of three abnormal liquid releases and
no gaseous releases during July 1987 to June 1988.
Licensee management attention to and
involvement
in the
calibration and operation of process and effluent monitors was
not sufficient in that the Low Pressure Service Water radiation
monitors (RIA-35)
have been inoperable since 1985.
Corrective
actions to upgrade the entire RIA monitoring system are under
development but-will not be implemented for approximately three
years.
A confirmatory measurements inspection showed agreement between
licensee and
NRC measurements with the
exception of two
radionuclides in three counting geometries.
The licensee was
responsive to NRC initiatives as demonstrated by an agreement to
analyze additional spiked samples.
The results of these
analyses are currently- pending.
A violation was identified
during this inspection for failure to provide
an approved
procedure for the sampling of the Unit 1 condenser offgas.
Two violations were identified.
a.
Severity Level IV violation for failure to identify
radiation hot spot locations after shielding had been
installed and to instruct personnel in the precautions or
procedures to minimize exposure to radiation (89-02).
13
b. Severity Level
IV violation for failure to proviJe an
approved procedure for the sampling of the Unit 1 condenser
offgas (88-31).
2.
Performance Rating
Category: 1
Previous Rating: 1
3. Recommendations
None
C.
Maintenance/Surveillance
1. Analysis
Evaluation of this functional area was based on the results of
routine inspections performed
by
the resident inspectors,
routine inspections by regional
inspectors, and
special
inspections in the area of Environmental Qualification (EQ)
of
Electrical
Equipment,
a'
Quality
Verification
Functional
Inspection (QVFI), and a Maintenance Team Inspection (MTI).
Overall
the licensee has
adopted
strong maintenance
and
surveillance programs.
However,
over this assessment period,
numerous performance problems were identified. These performance
problems were characterized
by
inattention
to
detail,
miscommunication,
and procedure/personnel errors resulting in
violations of NRC requirements.
Over the period Oconee station has had good availability and
few operational problems directly attributable to maintenance.
The licensee's management
was very supportive of a strong
maintenance progra.- This, was exemplified by the presence of
the station manager and superintendent during daily outage
meetings and other meetings that become necessary during periods
of routine operations when meetings are not normally conducted.
Management also was observed frequently in the various plant
areas watching activities and reviewing the conditions in the
areas.
Management
has established goals to increase their
preventive maintenance/corrective maintenance ratio to 70% and
reduce their outsta-nding work requests that are over three
months old to less than 450. During the latter portion of this
assessment period the plant had nearly achieved their goal,
in
that the preventive/corrective ratio was about 65% and the work
requests greater than three months old numbered about 200
for the site.
14
The QVFI which included the areas of maintenance and surveil
lance testing identified a number of minor violations, and found
work practices and procedural controls to be acceptable. Also
the inspection concluded that based on the low component failure
rate and few repetitive failures the licensee's corrective and
preventive maintenance programs appeared to be effective.
However, one instance was identified by the resident inspectors
where safety-related components
had been
omitted from the
preventive maintenance program. This was a failure to provide
proper maintenance for the Reactor Building Cooling Unit (RBCU)
drop out plates. When the drop out plates were tested in their
as-found condition, the plates would not function as designed.
At the end of this SALP period, this issue was still under NRC
review for escalated enforcement.
Enforcement in this functional area has increased since the
previous assessment period.
Thirteen violations in the
maintenance and surveillance area were identified this period
compared with one violation in the maintenance area and one
violation in the surveillance areas during the previous SALP
period. Most of the violations during this period have had only
minor safety significance.
One of the violations was a failure to -follow procedures
associated with a freeze seal which thawed allowing a spill of
approximately
30,000
gallons
of
slightly
radioactively
contaminated water,
a small amount of which resulted in an
uncontrolled release to the chemical
treatment
pond
and
subsequently off-site (Violation a).
A second violation involved a failure to perform an adequate
verification to assure work was being performed on the correct
component prior to performing maintenance.
This resulted in the
removal of packing from an instrument valve on an operating unit
rather than the shutdown unit. This error resulted in a leak of
approximately
40
gpm
in the auxiliary building.
Although
operations personnel did a good job in isolating the leak and
maintaining the unit in a safe condition, several persons were
contaminated and a spill of approximately 1,000 gallons of
contaminated water occurred (Violation b).
Inattention to detail was a major contributing factor in the
violations identified during the EQ inspection.
This resulted
in the failure to fully document essential information in the
licensee's EQ files and subsequently in a failure to include the
information concerning these specific EQ requirements in the
development of some surveillance and maintenance procedures
(Violation c, k and 1).
15
A Maintenance Team Inspection (MTI) was conducted in July 1988.
A weakness was identified in communication/coordination between
the plant maintenance department and the
Duke Transmission
Division.
This
was
exemplified in a violation
involving
verification and calibrations
in the Instrumentation
and
Electrical (I&E) maintenance area (Violation h).
During the MTI other weaknesses were identified that related to
10CFR50.59 reviews. One example involved the licensee's failure
to perform an adequate 50.59 review for the inoperability of the
ground detector prior to startup of Unit 2.
This issue is
discussed further in the Safety Assessment/Quality Verification
section of this SALP report.
The quality of maintenance and surveillance planning at Oconee
has been good. This area has been enhanced due to the efforts
of the integrated scheduling group and the use of dedicated
engineers permanently assigned to this group.
Through the
efforts of management and this group, the outage periods have
been *reduced without a reduction in the quantity or quality of
work being accomplished.
One major activity that was undertaken
was an effort to assure all work is completed on a component or
system when it
is
taken out. of service (through
closer
coordination of the various onsite groups) to preclude redundant
testing.
Materials
control,
which
includes procurement,
receiving
activity, and material storage, was good during this assessment
period. Violation (m) related to access control of material
storage areas
and does not impact the quality of material
handling and storage.
Because it
is a three-unit station and must plan for a minimum
of two major .refueling
outages per year,
the- station has
established a fairly large, stable work force in the area of
maintenance. The Oconee site is also the home base for the
Southern division of Duke Power Company's
Construction and
Maintenance Division (CMD),
which is an additional resource for
trained and qualified maintenance personnel.
-The chemistry program is being implemented in a satisfactory
manner to meet Technical Specification limits and the guidelines
recommended by the Steam Generators Owners Group.
The licensee
is continuing, through the effectiveness
16
of
plant components and chemistry control,
to minimize
degradation of the steam generator tubes.
Surveillance and
preventive maintenance programs
have been expanded for the
Once-Through-Steam-Generators
and the Decay Heat Removal Heat
Exchangers in order to identify potential problem areas.
The
licensee has made improvements in analytical methods with the
installation of online ion chromatography analyses systems.
Surveillances continue to be performed with only occasional
problems.
Surveillances have been performed as required by
Technical Specifications. There have been very few instances of
missed surveillances during this period.
The QVFI identified that licensee technicians performing a valve
stroke timing surveillance test did not recognize that the
stroke-time performance did not meet its acceptance criteria. A
review of previous testing also identified that the preceding
test had not met the acceptance criteria (Violation d).
Another inadequacy with the licensee's surveillance program was
stroke time testing was not being performed as specified by ASME
Section XI requirements.
Section XI of the ASME Boiler and
Pressure Vessel Code requires timing to begin at the signal
initiation and conclude at the actual closure as opposed to the
"light to light" criteria being utilized by the licensee
(Violation e).
The method in-use by the licensee was based on
the timing method that had been approved by the NRC for the IST
program established at the Catawba Nuclear Station.
Examples of licensee response to surveillance failures in MOVATS
testing were identified to be poor in that there was an apparent
attitude by
some personnel
that acceptance criteria for
Inservice Test Program
(IST) program valves was guidance and
not a requirement.
Additional examples were identified where
corrective actions for failed surveillances were delayed,
minimal,
or not performed.
Other items observed were a failure
to verify that all specified acceptance criteria in MOVATS
testing was performed (i.e. to verify ease of movement of an
actuated valve) and several valves which meet the requirements
for IST program valves were not entered into the IST program
(violation f).
The thirteen violations listed below represent a significant
increase over the previous SALP period.
There was one violation
in the maintenance area and one violation in the surveillance
.
area during the previous SALP period.
'Most of the violations
during this period have had only minor safety significance.
a. Severity Level IV violation for failure to follow procedure
on freeze seal of a line to the BWST resulting in a 30,000
17
gallon
spill of slightly contaminated
borated water
(87-51).
b.
Severity Level IV violation for inadequate procedures to
assure the correct component was identified prior to
performing work which resulted in a spill of contaminated
water due to the work being performed on the incorrect
valve and also with a main steam valve that was incorrectly
removed from a supply line to the auxiliary feedwater pump
turbine (88-08).
c.
Severity Level IV violation for inadequately documenting
the performance characteristics for the Victoreen High
Range Radiation Monitor System (88-03)(EQ).
d.
Severity Level IV violation for failure to keep accurate
records for PT/2/A/0150/22A, operational valve functional
test on May 11,
1988,
and nuclear equipment operator fire
watch logs on May 19, 1988 (88-13).
e.
Severity Level IV violation for failure to routinely
measure valve stroke times from actuation signal. initiation
to the end of the actuation cycle (88-13).
f. Severity Level IV violation for failing to include valves
LPSW-773 and HP-98 in the valve inservice testing program
(88-13).
g.
Severity
Level IV violati6n
for failure to follow
procedures relative to correctly filling out work requests
and for inadequate cleanliness levels in the reactor
protection and engineered safeguards cabinets (88-13).
h.
Severity .Level
IV violation for procedural problems related
to
verification
and
calibration
of
control
room
instrumentation
and battery undervoltage alarm relays,
circuit breaker maintenance,
4160 volt switchgear,
and
ground detection circuit alarm set points (88-17).
i.
Severity Level
IV violation for failure
to
follow
procedures resulting in overpressurization of a safety
related pipe section. (88-32, Unit 3 only)
j.
Severity Level V violation for failure to follow, in its
entirety, the procedure for component verification while
performing RPS Channel-"B" calibration and functional tests
(87-44).
k.
Severity Level V violation for the reactor building level
transmitter junction box not being maintained completely
18
filled with oil and,
therefore,
not in the as tested
configuration (88-03)(EQ).
1. Severity Level V for deficient EQ maintenance procedures in
that requirements in the Equipment Qualification Reference
Index
were
not properly addressed in the maintenance
procedures (88-03)(EQ).
m. Severity Level V violation for failure to maintain access
control to storage areas. (87-32, Unit 3 only)
2.
Performance Rating
Category: 2
Previous Rating:
Surveillance 1
Maintenance 1
3.
Recommendations
Increased management attention is warranted in this area due to
the reduced attention to detail and increase in personnel and
procedural errors.
1. Analysis
The regional inspection conducted during this assessment period
by both resident and regional inspectors included a routine
inspection and two annual
emergency
response exercises.
Four Emergency Plan revisions were also
submitted by the licensee for NRC review.
Overall,
during this SALP period,
the licensee, with one
exception noted below, continued to demonstrate the capability
to
fully
implement
the
critical
aspects
of
emergency
preparedness during simulated or actual emergency events.
The licensee's response to simulated emergencies during the
annual emergency
preparedness exercises demonstrated their
capability to effectively implement the Emergency
Plan.
A
partial participation exercise was performed on November 11,
1987. A full scale exercise was performed April 14,
1988.
An
exercise
weakness
involving
an
incorrect .
emergency
classification was identified during .the latter exercise.
Specifically, a Site Area Emergency should have been promptly
declared based on
the simulated loss of reactor shutdown
capability concurrent with a LOCA greater than
50 gpm.
In
response to this finding, the licensee promptly revised the
Emergency Plan and respective implementing procedure to more
clearly define Site Area Emergency,
Emergency Action Levels
(EAL)
regarding loss of shutdown function.
Additionally, the
19
respective revised Emergency Plan implementing procedure was
rendered more user friendly.
Corrective action also included
training
of all operations personnel regarding
and
emergency classification.
The license also effectively demonstrated their capability to
correctly use EALs and promptly identify and classify an actual
Alert resulting from the loss of functicns needed to maintain
Unit 3 in cold shutdown.
Additionally, four Notification of
Unusual Event (NOUE)
were promptly classified including a fire
and a steam generator tube leak.
The annual exercises demonstrated the licensee's proficiency in
promptly
implementing
protective
action
recommendations
consistent with the licensee's Emergency Plan and respective
emergency procedures, and EPA Protective Action Guidelines. The
exercises also disclosed the licensee's prompt and effective
implementation of dose assessment and projections attending
simulated
offsite
releases
of
radioactive
materials.
Comprehensive critiques were conducted following each exercise.
Licensee-identified findings were recorded
and corrective
actions required were implemented.
The routine emergency preparedness inspection found that the
licensee maintained the capability for prompt notification and
effective -communications with-offsite support agencies and
emergency
response facilities.
Instrumentation
and supplies
were
appropriate
and
emergency
preparedness
training
was
complete and effective.
The site emergency organization continued to demonstrate a
strong commitment to training by development of drill scenarios
and consistent use of Oconee plant specific Probabilistic Risk
Assessment
(PRA)
.data to render
such drills realistic and
challenging. The experience developed as a result of frequent
unannounced drills and practice exercises has significantly
enhanced the capability of emergency response personnel during
evaluated exercises and actual emergencies.
No emergency preparedness violations were identified during this
assessment period.
2.
Performance Rating
Category:
1
Previous Rating:
1
3.
Board Comments
Failure to promptly and correctly classify a simulated event during
an emergency exercise is normally considered by the NRC to show a
significant weakness in a licensee's emergency preparedness program.
20
Such a wea.kness would not be expected in a SALP Category 1 program.
It was noted however, that the licensee implemented a prompt and very
effective response to the exercise weakness.
Subsequently, the
licensee effectively demonstrated this capability during this
assessment period, during an actual Alert and four NOUEs.
The Board
therefore concluded that the performance in this area was SALP 1.
E.
Security and Safeguards
1. Analysis
The Physical Security functional area evaluates and assesses the
adequacy of the security force to provide protection for the
stations vital systems and equipment. To determine the adequacy
of the protection provided, specific attention was given to the
identification
and
resolution
of
technical
issues,
responsiveness
to
NRC
initiatives, enforcement
history,
staffing, effectiveness of training, and qualification.
The
scope of this assessment includes all
licensee activities
associated with access control, physical barriers, detection and
assessment,
armed
response,
alarm stations, power supply,
communications,
and compensatory measures for degraded security
systems and equipment. This evaluation is based on routine and
special inspections conducted by the NRC in this area and
related functional areas.
Authority and responsibilities associated with the security
organization
were
clearly delineated and appeared
to be
effective. The site contract force is adequately staffed and
appropriately trained and equipped.
The facility guard Training
and Qualification Plan is implemented on a continuing basis at
all levels of the security organization using the onsite
training staff.
The licensee has provided the security force with adequate
procedures. Security plan changes are submitted on a timely
basis and licensee records are complete, adequately maintained
and available. Licensee events reports are prompt and complete.
The
licensee's independent security program audit covered
various aspects of the site security program and the program
auditors were
thorough
and well acquainted with licensee
commitments.
The regional staff identified a problem with the closed circuit
television (CCTV)
assessment capability at the beginning of this
rating period. This poor CCTV assessment was partially due to
low priority maintenance but more significantly due to poor
design and installation. This problem was not resolved at the
end of the rating period, demonstrating a slow response to
regulatory concerns and a lack of urgency in addressing this
21
issue.
The li-ansee has been relying on long term compensatory
measures to provide this assessment capability.
One Material Control and Accountability inspection was conducted
during the SALP period.
This inspection was performed to
determine whether the licensee had limited his possession and
use of special nuclear material
(SNM)
to authorized locations
and uses, and had implemented an adequate and effective prografm
to account for and control all SNM in possession under license.
The inspection determined that the licensee had developed and
was maintaining an adequate safeguards program for the control
and use of both fuel and non-fuel SNM.
External reporting was
found to be accurate and timely.
While the licensee has experienced an increase in the number of
security related violations, they are not indicative of a major
security program breakdown.
Six of the violations cited during
this reporting period were
licensee identified.
Analysis
indicates that the majority of the violations are attributable
to errors by individual members of the security force relative
to adherence to procedural requirements and documentation rather
than hardware
and equipment associated problems.
The one
violation identified by regional inspection concerned a degraded
vital barrier that had not been previously identified by the
licensee. These violations indicate a need for additional
attention-to detail, and increased regulatory sensitivity on the
part of the security force.
The violations identified were as follows:
a. Severity Level
IV for allowing an employee into the
protected area without a picture badge. (87-45)
b. Severity Level IV for allowing a visitor into the protected
areas without a hands-on search.
(87-46)
c.
Severity Level IV for failure to control
Safeguards
Information.
(87-50)
d.
Severity Level IV for transmitting Safeguards Information
over unprotected telecommunication circuits.
(87-50)
e.
Severity Level
IV for degradation of the Central Alarm
Station barrier bullet resistivity.
(88-10)
f. Severity Level V for allowing the training certification
of a member of the security force to expire.
(87-46)
g.
Severity Level V for allowing an escorted visitor into the
protected
area
with
incorrect access authorization
documentation. (88-10)
22
2. Performance Rating
Category: 2
Previous Rating:
1
3. Recommendations
The Board recognized the continued high level of management and
oversight and support provided the contract security force in
the areas of training, staffing and procedural guidance.
However, the lack of responsiveness in resolving a long standing
issue relating to the assessment capability of the closed
circuit television system and the increase in the number of
violations, attributable to personnel error, detract from an
otherwise favorable evaluation of the security program.
The
Board recommends management emphasis in these areas.
F. Engineering/Technical Support
1. Analysis
The Engineering Technical Support functional area addresses the
adequacy of technical and engineering support for all plant
activities.
To determine the adequacy of support provided,
specific attention was given to the identification and
resolution -of
technical
issues, responsiveness to NRC
initiatives, enforcement history, staffing, effectiveness of
training and qualification.
The scope of this assessment
includes all
licensee activities associated with plant
modifications,
technical support provided for operation,
maintenance,
testing and surveillance, operator training,
procurement,
and configuration control.
This evaluation is
based on routine and special inspections conducted by the NRC in
this area and related functional areas.
Engineering and technical support in this assessment period has
been generally good.
Design engineering
(DE)
activity has
resulted in a number of self-identified plant problems as well
as improvement initiatives.
The effective utilization of
engineering resources has been demonstrated by a number of
issues addressed by the licensee.
An exception to the generally
good performance was a recurrence of a communications weakness
which was identified in the previous SALP assessment period.
The commdtnication effort has improved during the latter part of
-this SALP period.
The plant engineering staff, outside the DE organization, is
assigned to various plant functional activities,
(i.e.,
operations, maintenance, and radiological controls), providing
more timely evaluation and resolution of plant problems.
In
particular, maintenance engineering support was strong with
23
regard to involvement in field work and accessibility by craft
personnel.
Maintenance engineering activity involving failure
analysis, preventive maintenance, and material qualification was
effective.
The quality of engineering
and technical support has been
compromised by the quality of the communication between the
plart and DE. The OE/plant communication was identified as a
weakness
in the previous
assessment period and
has
been
demonstrated as a weakness during this assessment period.
The
DE organization failed to provide the plant with adequate
information regarding HPI
system mode requirements and Safe
Shutdown Facility HVAC configuration requirements.
The former
issue resulted in a violation
(see
violation (a)-Safety
Assessment/Quality Verification).
Although the initial
design deficiency was licensee identified the resolution was
initially inadequate due to a DE/plant communications failure.
Management
has
taken action to resolve the communication
problem. This action was to reorganize DE on a site dedicated
basis, establish a small on-site DE contingent to facilitate the
DE/plant interface,
and assign system engineers to selected
safety significant systems.
These actions were
not fully
implemented prior to the occurrence of the communications
deficiencies discussed above.
The operator training and requalification training programs are
good although some simulator weakness were identified during
this assessment period.
The
supplementation of
simulator
training staff with experienced plant operators on a two year
rotation was a notable contributor to training program quality.
Generally the simulator is
updated to incorporate Unit 1
modifications,
however,
simulator hardware
and
software
nonconformances existed this assessment period which impacted
the value of simulator training.
An example of a hardware
nonconformance was
the control
instrumentation
for the
Pressurizer Power Operated Relief Valve which differed between
the control room and simulator.
A modification completed at the
end
of
the
assessment
period
corrected this
hardware
nonconformance.
The Loss of Instrument Air simulation which did
not accurately reflect the actual plant evolution was an example
of a software -nonconformance.
Although the overall training
program was generally good,
simulator nonconformances which
required performance compensations by the operators-in-training
impacted the value of the training.
Two
replacement examinations were
administered during the
assessment period. Eleven of eleven SRO candidates passed and
six of seven RO candidates passed. Material submitted for exam
24
development contained minor information deficiencies but was
generally adequate and legible.
The violation identified below is an outage related violation.
During refueling outages on all three units, containment
isolation was compromised by open one-inch emergency hatch
equalizing valves and small gaps (3 to 4 square inches) in hatch
seals.
These failures to maintain containment isolation were
the result of an inadequate temporary modification and
inadequate attention to detail regarding all aspects of
maintaining containment isolation during refueling outages.
This violation was identified by Duke Power staff and reported
to the NRC.
One violation was identified during this assessment period.
a. Severity Level IV for failure to maintain containment
conditions during refueling outages (87-49)
2. Performance Rating
Category: 2
Previous Rating:
Engineering Support 2
Training 2
3.-- Recommendations
The board noted an improved performance in this area over the
assessment period. While many positive attributes were observed
in this area relating to self-identified plant problems, there
was recurring weakness in the quality of communications between
design engineering and other plant organizations.
To achieve
further improvement, management attention is required in this
area.
G. Safety Assessment/Quality Verification
1. Analysis
This section includes an assessment of licensee activities
associated with the implementation of licensee safety policies;
licensee activities related to amendment, exemption and relief
requests; response to Generic Letters, Bulletins, and other NRC
initiatives.. This section also includes licensee activities
related to the resolution of safety issues and self assessment
activities.
The evaluation of licensee activities is based upon observations
of numerous licensing actions active or completed during the
assessment period. This included about 252 licensing activities
for the three Oconee units, of which 54 were licensing
amendments completed during this period.
25
Management involvement is evident at the corporate
and station
levels through planning
and
assignment of priorities for
activities associated with licensing.
Duke
is an active
participant and often assumes leadership roles for the industry
regarding generic issues. This industry involvement includes,
for example, the Association of Edison Illuminating Companies,
various codes and standards committees,
owners group
committees,
trade groups much as the American Nuclear Society
and Health Physics Society and numerous others.
The extent of
Duke's involvement is commendable and much is accomplished that
could not be achieved on an individual plant basis.
However,
Duke has not provided timely resolution and implementation of
several significant, longstanding generic issues for Oconee such
as ATWS mitigation design approvals, Regulatory Guide 1.97 and
several TMI issues.
Duke is also an active participant in the B&W Owners Group
(BWOG)
safety and performance improvement program (SPIP)
which
has
recommended
numerous
modifications
to
enhance
plant
performance. Duke has made significant contributions to the
SPIP and has incorporated a large number of these recommenda
tions at Oconee.
However, a significant number
which should
enhance performance of systems such as the main feedwater system
and the integrated control system are still being evaluated
for implementation.
Duke's staff generally displays in-depth knowledge of the plant
and of technical and regulatory issues.
Duke tends to be well
prepared and to provide ample support during meetings, site
visits and conference calls.
Licensee Event Reports submitted by the licensee were generally
well written and provided a sufficient depth of information.
The reports describe the relevant aspects of the events,
including component or system failures that contributed to the
events and the significant corrective actions taken or planned
to prevent recurrence.
Previous similar occurrences were
appropriately acknowledged in the reports.
The licensee has demonstrated the capability to identify plant
problems and has dedicated resources to resolve these problems.
Mechanisms to identify plant
problems
include corporate
self-initiated technical audits (SITA),
audits required by
Technical Specification 6.1.3 information sharing with other
Duke plants, and a design calculation review program. The SITA
program and design calculation review program were developed
using the
NRC Safety System Functional
Inspection (SSFI)
philosophy as guidance.
Oconee developed a prioritized list of
systems which they will examine.
These mechanisms identified
problems related to the High Pressure Injection (HPI)
system,
start-up transformer circuit breakers, containment penetration
fire barriers, Reactor Building Cooling Unit (RBCU)
capacities,
26
electrical sliding link problems,
and emergency power system
overloading.
The resources
to evaluate and resolve these
problems,
particularly the
RBCU fouling problems,
have
been
considerable and reflect management commitment to operate and
maintain a safe plant. Engineering activity in response to an
NRC identified potential control panel configuration control
problem was timely and comprehensive once the operability
impact implications were recognized.
Additionally, the
Oconee
performance group and
design
engineering have been extensively involved in heat transfer
performance testing of the Reactor Building Cooling Units (RBCU)
for most of this assessment period.
Due to fouling problems
discovered at McGuire, Duke began looking at all heat exchangers
for reduced
heat removal
rates
due to fouling.
It was
discovered by performance testing and calculations that the
RBCU's were not capable of removing their design heat capacity
due to both air and water side fouling.
Although the problem
has not yet been fully resolved, this group (with support from
design engineering personnel) has dedicated significant effort
toward resolution of this issue.
Duke has displayed a
cooperative attitude with the NRC regarding its experiences in
this field which has been a benefit to the NRCs efforts to
develop generic conclusions and assess the need for future
regulatory-guidance.
The station manager initiated a program to conduct detailed
reviews of specific INPO Significant Operating Event reports
(SOERs).
This review consists of extensive discikssion and
analysis
sessions
involving most of the
senior onsite
management. Several changes contributing to safety enhancement
have been incorporated into procedures as a result of these
discussions.
Breakdowns in communication, however, have hindered the
resolution of problems once they have been identified.
One
significant example
of this, which resulted
in escalated
enforcement,
was the failure of Design Engineering to provide
the plant with adequate information regarding HPI system mode
requirements. This resulted in a lack of procedural guidance
associated with the high pressure injection "piggyback" mode of
operation (violation a).
Another example of a communication
breakdown as mentioned in the Engineering/Technical
Support
section was the Safe Shutdown Facility HVAC system circulating
water pump requirements.
27
The licensee provided timely, sound responses to NRC generic
letters, and bulletins.
This was evident in the licensees
resolution of issues in NRC Bulletins on main steam safety
valves,
masonary
wall
designs,
nonconforming
materials
and fastener testing.
Oconee initiated a program during this SALP assessment period to
upgrade 10 CFR 50.59 evaluations.
This resulted in improved
evaluations for permanent and temporary modifications, however,
documentation of some evaluations for valve replacements and
alarm/setpoint
changes
was
weak.
This
resulted
in
violation (b).
Another example of this problem is addressed in
the Maintenance/Surveillance section.
Two violations were identified during this assessment period.
a. A Severity Level III violation with a $50,000 civil
penalty for a lack of procedural guidance associated with
high pressure injection piggyback operation during a loss
of coolant accident. (88-25)
b.
Severity Level V violation for failure to provide the basis
for determination that changes did not affect an unreviewed
safety question for multiple alarm and set point changes
(88-13)
2.
Performance Rating
Category: 2
Previous Rating:
Quality Programs 1
Licensing Activities 2
3.
Recommendations
Management attention as provided during the latter portion of
this SALP period should continue in this area.
V.
SUPPORTING DATA
A.
Escalated Enforcement Actions
1. Civil Penalties
Severity Level III violation issued on December 13,
1988 for a
lack of procedural
guidance associated with high pressure
injection "piggyback" mode of operation during a loss of coolant
accident. ($50,000 CP)
28
2.
Orders
August 6, 1987 -
Elevated lake water temperature, Oconee 1
August 19, 1987 -
Elevated lake water temperature, Oconee 2
B.
Management Meetings
October 27, 1987
-
SALP meeting with licensee at Oconee
site
March 1, 1988
-
NRC/DPC meeting at NRC office in
Washington to discuss Integrated Safety
Assessment Program
January 15, 1988
-
Enforcement Conference at Region II
related to protection of safeguards
information in electronic transmission
January 28, 1988
-
Technical meeting with Duke Design
Engineering in Charlotte, NC to discuss
current issues and concerns
June 7, 1988
-
Meeting in Atlanta Region II offices
to discuss findings of
NRC
Quality
Assurance Team
July 1, 1988
Enforcement Conference at Region II
related to environmental qualification
of electrical equipment
September 8, 1988
-
Meeting at Oconee to discuss fouling
of Reactor Building Cooling Units
September 12, 1988
-
Enforcement Conference at Region II
related to high pressure injection
"piggyback" mode of operation
29
October 6, 1988
-
Enforcement Conference at Region II
related
to
potential
degraded
capabilities of the Reactor Building
Cooling Units (RBCU)
January 6, 1989
-
Enforcement Conference at Region II
related to the inadequate design of the
Lee Station transmission system
January 12, 1989
-
Meeting at Oconee site by with Duke
Licensing group,
NRC licensing Project
Managers, and NRC Region II personnel
C.
Confirmation of Action Letters (CAL)
January 5, 1989
-
CAL issued following switchgear fire
to maintain equipment related to the
fire in the "as found" condition
0.
Review of Licensee Event Reports (LERs)
During the evaluation period,
29 LERs for Units 1, 2, and 3 were
analyzed. The distribution of the events by cause, as determined by
the NRC staff, was as follows:
Cause
Total
Component
4
Design
7
Construction, fabrication
or installation
0
Personnel:
-
operating activity
3
- maintenance activity
2
- Test/calibration activity
6
- Other
4
Other
3
29
E.
Licensing Activities
During the evaluation period, review of 252 licensing actions and 54
licensing amendments was completed for the three Oconee units.
30
F.
Enforcement Activity
No. of Deviations and Violations in
Functional
Each Severity Level
Area
Dev.
V
IV
III
II
I
Plant Operations
2
Radiological Controls
2
Maintenance/Surveillance
4
9
Security
2
5
Engineering/Technical
1
Support
Safety Assessment/Quality
1
1
Verification
TOTAL
7
19
1
G.
.
A total of five automatic trips occurred during this rating period,
two on Unit 1, one on Unit 2 and two on Unit 3.
Seven automatic trips occurred during the previous rating period. One manual trip
was also experienced. The trips are described in more detail below.
1.
Unit 1
a. On July 5 an automatic trip occurred from 100% power due to
an error by an Instrument and Electrical (I&E)
technician
while troubleshooting a turbine header pressure instrument.
b. On January 2, 1989, a trip from 100% power occurred during
surveillance of the Reactor Protection System due to an I&E
technician error.
Channel D was tripped when Channel A was
also in a tripped condition.
c.
On January 3, 1989, a manual trip from less than 15% power
due to a fire in a 6900V Reactor Coolant Pump switchboard.
2.
Unit 2
a.
On August 26,
1988,
an automatic trip occurred from 100%
power due to a anticipatory reactor trip on turbine trip
caused by a faulty Moisture Separator Reheater high level
instrument.
31
3.
Unit 3
a.
On November 14,
1988,
the reactor tripped from 100% power
due to a main turbine trip.
The reason for the main
turbine trip could not be identified and the reactor
returned to power.
b.
On November
14 while recovering from the trip discussed
above, the reactor again tripped. Power was at 39% and the
reason for the trip was a main turbine trip due to faulty
relay in the steam generator high level circuitry.
The
reactor tripped
due
to
high reactor
coolant
system
pressure.
H.
Effluent Release Summary
(First
Half)
Activity Released (Curies)
1985
1986
1987
1988
1. Gaseous Effluents
Fission and Activation
2.35 E+4 2.43 E+4
1.05 E+4
1.85 E+4
Products
lodines and
6.14 E-3 5.41 E-2
1.58 E-2 9.74 E-2
Particulates
2. Liquid Effluents
Fission and Activation
4.16 EO
5.85 EO
2.90 EO
1.57 EO
Products
1.24 E+3 1.34 E+3 9.49 E+2 4.28 E+2