ML15239A059
| ML15239A059 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 04/06/1992 |
| From: | Ebneter S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15239A058 | List: |
| References | |
| 50-269-92-01, 50-269-92-1, 50-270-92-01, 50-270-92-1, 50-287-92-01, 50-287-92-1, NUDOCS 9205050171 | |
| Download: ML15239A059 (29) | |
See also: IR 05000269/1992001
Text
ENCLOSURE
INITIAL SALP REPORT
U. S. NUCLEAR REGULATORY COMMISSION
REGION II
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
INSPECTION REPORT NUMBERS
50-269/92-01, 50-270/92-01 AND 50-287/92-01
DUKE POWER COMPANY
OCONEE UNITS 1, 2 AND 3
AUGUST 1, 1990 -
FEBRUARY 1, 1992
9205050171 920406
PDR ADOCK 05000269
G
TABLE OF CONTENTS
Page
I. INTRODUCTION
1...........
1
II. SUMMARY OF RESULTS.....................................
2
III. CRITERIA...............................................3
IV. PERFORMANCE ANALYSIS....................................3
A. Plant Operations...................................3
B. Radiological Controls..................7
C. Maintenance/Surveillance...........................10
D. Emergency Preparedness.............................12
E. Security.........................................
14
F. Engineering/Technical Support......................16
G.
Safety Assessment/Quality Verification ............... 19
V. SUPPORTING DATA AND SUMMARIES ........................... 22
A.
Licensee Activities ................................ 22
B.
Direct Inspection and Review Activities .............. 23
C. Escalated Enforcement Activities .................... 23
D. Management Conferences ............................. 24
E. Confirmation of Action Letters...................... 25
F.
Reactor Trips...................................... 25
G. Review of Licensee Event Reports .................... 26
H. LicensingActivities............................... 27
I. EnforcementActivity............................... 27
.
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
licensee management regarding the NRC's assessment of their performance
in each functional area.
An NRC SALP Board, composed of the staff members listed below, met on
March 13,
1992, to review the observations and data on performance, and
to assess licensee performance in accordance with the guidance in NRC
Manual Chapter NRC-0516, "Systematic Assessment of Licensee Performance".
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 the Oconee Units 1, 2 and 3 for the period August 1, 1990, through
February 1, 1992.
The SALP Board for Oconee was composed of:
E. W. Merschoff, Deputy Director, Division of Reactor Safety (DRS),
Region II (RH), (Chairman)
J. R. Johnson, Deputy Director, Division of Reactor Projects (DRP), RH
B. S. Mallett, Deputy Director, Division of Radiation Safety and
Safeguards, RH
A. R. Herdt, Chief, Reactor Projects Branch 3, DRP, RII
D. B. Matthews, Director, Directorate 11-3, Office of Nuclear Reactor
Regulation (NRR)
L. A. Wiens, Project Manager, Project Directorate 11-3, NRR
P. E. Harmon, Senior Resident Inspector, Oconee, DRP, RII
Attendees at SALP Board Meeting:
F. J. Remick, Commissioner
J. Guttmann, Technical Assistant to Commissioner Remick
A. J. Mendiola, Acting Chief, Quality Assurance Section, Division of
Licensee Performance and Quality Evaluation, NRR
G. A. Belisle, Chief, Project Section 3A, DRP, RII
W. H. Miller, Jr., Project Engineer, Project Section 3A, DRP, RII
S. Q. Ninh, Project Engineer, Project Section 3A, DRP, RII
B. B. Desai, Resident Inspector, Oconee, DRP, RH
W. K. Poertner, Resident Inspector, Oconee, DRP, RH
2
II. SUMMARY OF RESULTS
Oconee operated safely during this evaluation period. A loss of decay
heat and an overpressurization event during outage activities were the
result of inadequate control room command and control and ineffective
oversight of shutdown plant operations.
In addition to these outage
events, problems continue to exist in the areas of configuration control
and procedural adherence.
During the last three months of this
assessment period improvement has been noted in the oversight of control
room activities.
Performance in the radiological control area continues to be effective.
A strong ALARA program is evident as well as numerous ongoing projects to
reduce collective dose.
Programs for monitoring/collecting liquid and
gaseous effluents, maintenance of effluent monitoring and environmental
monitoring were effective.
Performance in the maintenance/surveillance area was inconsistent.
Programs such as shifting from reactive to predictive maintenance
activities, thermography and Inservice Inspection remain effective.
Problems continue in areas such as procedural adherence and reactor trips
during surveillance testing.
The licensee continued to maintain a strong emergency response organiza
tion.
Management attention and support was evident.
Several program
strengths were identified which included training and completion of a new
EOF. During two exercises this SALP period as well as during an ALERT in
November 1991 involving a reactor coolant leak, the Emergency Plan was
effectively implemented.
Performance in the security area was superior.
Security management at
both site and corporate was knowledgeable and highly supportive. Due to
a continuing problem with closed circuit televisions being out of
service, many protected area intrusion detection zones had to be
physically assessed.
The Fitness for Duty Program is effectively
implemented.
Design engineering and other support groups have been adequate and
responsive to station needs. Good communications exist between corporate
and site engineering. Engineering successfully implemented several major
modifications. However, poor modification design led to a water hammer
and multiple fittings were inappropriately used to transition between
different pipe sizes.
A new organization change is planned to move
engineering personnel on site in July 1992.
With the exception of shutdown operations, Safety Assessment/Quality
Verification performance demonstrated a thorough approach to assessing
conditions and activities relating to the operation of the plant.
Program initiatives to define the design bases and to investigate
significant operating events are considered strengths.
Several plant
3
modifications have been implemented that have enhanced safety, and some
improvements have been noted in the quality of licensing submittals.
However,
corrective actions have not been effective in preventing
recurrence of problems.
Overview
Performance ratings assigned for the last rating period and the current
period are shown below.
Rating Last Period
Rating This Period
Functional Area
2/1/89 -
7/31/90
8/1/90 -
2/1/92
Plant Operations
1
2
Radiological Controls
1
1
Maintenance/Surveillance
2(Improving)
2
1
1
Security and Safeguards
2(Improving)
1
Engineering/Technical
1
2
Support
Safety Assessment/
2
2
Quality Verification
III. CRITERIA
The evaluation criteria which were used to assess each functional area
are described in detail in NRC Manual Chapter MC-0516, which can be found
in the Public Document Room files.
Therefore, these criteria are not
repeated here, but will be presented in detail at the public meeting to
be held with licensee management.
IV. PERFORMANCE ANALYSIS
A. Plant Operations
1. Analysis
This functional area addressed the control and performance of
activities directly related to operating the facility,
including fire protection.
While Oconee operated safely during this evaluation period,
recurring procedural violations and events during shutdown and
outage activities have caused significant concern. Performance
in this area has declined during the assessment period because
of these problems due to their number and significance.
Improvement was noted in the last three months of the
assessment period due in part to increased management attention
to conduct of operations and greater attention to detail.
4.
Power Operations
Certain programmatic
areas exhibited problems,
including
configuration control and procedural adherence.
The
configuration control errors involved mispositioned valves,
breaker tagging and equipment being taken out of service on the
wrong unit.
Events involving procedure violations include
mispositioning Low Pressure Service Water valves when a valve
checklist was not performed, sluicing core flood tanks without
a procedure, spilling radioactive resin and water due to
mispositioned valves, and lining up the Lee power station to
the standby bus without degraded grid voltage protection. Some
of these instances of failing to follow procedures also
involved specific decisions to inappropriately deviate from the
procedures,
in that, in two instances operators bypassed
procedural steps without careful consideration of the reason
for that step. Deficiencies in procedural compliance were also
noted in the previous SALP report as an area that should
receive continued management attention.
Based on the above
examples, management has not been fully successful in resolving
this problem.
Operator response to transient and upset conditions from power
was good, particularly with respect to runback management and
trip response. Runbacks were usually stopped by the operators
who were able to diagnose and correct the conditions causing
the runbacks.
During the November 1991
loss of coolant
accident (LOCA),
the operators performed well except for a
problem associated with the operation of the steam station
controls. Overall performance during this event indicated that
the operators were well trained and experienced.
Operators and shift supervisory personnel generally exhibited a
conservative approach to technical issues.
Plant operations
assisted as necessary to resolve technical issues, with special
emphasis placed on teamwork approaches to the resolutions.
The experience level of the shift personnel and the Operations
support group is considered very high. Each of the five shift
crews are staffed with two extra reactor operators. Recently
there has been a resultant decrease in overtime.
Shutdown Operations
Operations personnel sometimes exhibited a lack of attention to
detail.
One instance occurred when operations personnel
secured the cooling water to the operating control rod drive
mechanisms. Another example involved operations personnel not
questioning maintenance personnel performing a hydrostatic test
at the same time that the Reactor Coolant System (RCS)
was
5
being drained down for midloop operations.
Because there was
only a single valve boundary during the hydrostatic test,
leakage by this valve caused an RCS dilution.
Additionally,
both source range nuclear instruments were inappropriately
deenergized on two occasions.
Control room inattentiveness and poor communications at times
resulted in actual events and near misses,
including three
events that resulted in NRC Augmented Inspection Teams (AITs)
being dispatched to review the circumstances involved.
The
event that led to the AIT in March 1991 involved a loss of
and was caused by incorrect labeling,
inadequate
independent verification,
poor communications
between operations and technical personnel,
procedural
inadequacies and incorrectly using plant drawings.
The events
that led to the second and third AITs in September involved a
loss of decay heat removal
and overpressurizing the Low
Pressure Injection (LPI) system. These events were caused by
failure to implement or follow procedures, inadequate
communications, inappropriate conduct of operator responsi
bilities and inadequate facility management oversight.
Corrective actions implemented in the latter part of the
assessment period produced improvement in attention to routine
evolutions and shift duties.
In particular, communications
between various support groups improved due to work management
changes.
The licensee failed to recognize deficiencies in fundamental
watch standing practices, and command and control of shift
operations which were root causes for the Unit 1 RCS heatup and
the LPI overpressurization events.
However, efforts have been
taken to correct watch standing practices and improvements have
been observed during the latter part of this assessment period.
The Operations Support Group was staffed with experienced
personnel
including a large percentage of licensed,
shift-experienced personnel.
This group provided a valuable
resource to shift crews in several areas including "System
Expert" support, work control screening, scheduling and review,
and procedure review and revision.
Assistance in performing
complex and non-routine evolutions such as mid-loop approach
and High Pressure Injection (HPI)
system full flow testing was
considered a strength.
Attention to detail for planned evolutions was not always
evident. One example was the spill of 800 gallons of water from
the Letdown Storage Tank. This event occurred when operators
assumed a valid tank level indication was in error.
As a
6
result, recurring problems were evident in areas of independent
verification, spills from mispositioned valves, tagging errors,
and other configuration control problems.
Several significant control room modifications were completed
during the period, including ATWS Mitigation System Actuation
Circuitry (AMSAC),
Diverse Scram System, and instrumentation
upgrades addressing Regulatory Guide 1.97 issues. Modification
training for Operations personnel
was generally adequate.
Some instances were noted of a lack of operator familiarity
with recently completed modifications.
These included the
diverse scram system, the radiation monitor system and the
reactor coolant pump vibration monitor system.
The fire protection program as a whole was well implemented.
However, three
problems with
the
use of combustible
scaffolding, inoperable fire barrier between redundant safe
shutdown components and the failure to perform an adequate
operability verification for the Keowee C02 fire suppression
system were identified.
New state of the art fire detection
and control panels have been installed to replace the old
system panels.
Procedures to implement the program are
adequate. The fire brigade was well trained and equipped and
performed satisfactorily during drills.
The TS required fire
protection program audits performed by the licensee were
comprehensive and thorough.
Surveillance and maintenance of
the fire protection features and systems were adequate. System
impairments were generally corrected in a timely manner and
appropriate compensatory measures were established for degraded
conditions.
Nine violations were identified.
violations pertaining to two separate September shutdown events
were issued after the SALP cycle closed.
Two additional
violations were identified but not issued in this SALP period.
2. Performance Rating
Category: 2
3. Recommendations
The NRC is concerned with the execution of control room command
and control functions as well as the effectiveness of
management oversight of plant operations primarily during
shutdown conditions and refueling outages.
Enhanced NRC
inspection during shutdown conditions is recommended.
7
The licensee should evaluate the effectiveness of control room
command and control functions and the effectiveness of work
scheduling and plant operations during shutdown conditions and
the effect on safety system availability.
B. Radiological Controls
1. Analysis
The functional area addresses those activities related to
radiation safety and primary/secondary chemistry control.
Both Radiation Protection and Chemistry were well staffed to
perform scheduled operations.
Supervisors and managers were
well qualified and all positions were filled.
To assist the
health physics (HP)
staff for non-scheduled outages,
the
utility retained 15 HP vendor technicians at each Duke nuclear
site, thereby having another 30 HP technicians available on one
day notice to any site. The newly retained vendor HP group has
added more stability to radiological coverage at the early
onset of unscheduled outages.
Late in the assessment period,
the licensee planned to, but was not providing continuing
training or on-the-job training for the retained vendor
technicians.
The licensee's ALARA program was a strength with contributions
from engineering support and HP guidance, teamwork, and ALARA
techniques inherently designed into modifications and
radiological operations. The licensee's initiatives to reduce
out of core source term and collective dose were numerous. Two
of the more significant initiatives in the assessment period
were the replacement of the 4-inch diameter component Drain
Header and steam generator "J" leg drains, and the replacement
of highly radioactive hot leg shield blocks. As a result, dose
rates in the general areas of the containment basement and
cavities have been reduced by a factor of four and in some
areas by a factor of six.
The newly installed valves in the
component Drain Header and "J" leg drains are designed to
minimize crud build up and the new hot leg shield blocks have
multi-coatings to inhibit the adherence of radioactivity. The
licensee has also used several other methods to reduce the
source term and collective dose,
such as,
crud burst at
shutdown and subsequent filtration, flushing to remove hot
spots, temporary lead shielding, and removal of radioactive
piping no longer in use.
8
The licensee established a collective dose goal of 504
person-rem for 1991 with two scheduled outages.
The goal was
exceeded by 56 person-rem due to three unscheduled outages.
The licensee per-unit collective dose average for the years
1989, 1990 and 1991 was
228,
134,
and 187 person-rem
respectively, for a three year per unit average of 183
person-rem.
This three year average is indicative of the
aggressiveness of the program to reduce the source term and is
low for an older three unit pressurized water reactor.
The licensee's program to control contamination continues to be
effective.
One example was the effective cleanup and
monitoring of a November 1991, spill of reactor coolant due to
a failure of a compression fitting.
The station's program to
reduce contaminated square footage has leveled off over the
past two assessment periods at approximately six percent of the
107,750 square feet of radiologically controlled area (RCA)
as
contaminated.
Two examples where the contamination control
program was not effective were an increased number of personnel
contamination events and low level contaminated items located
outside the RCA.
The licensee experienced 141 personal
contamination events (PCEs)
in 1990 and 294 PCEs in 1991.
The
increase in PCEs can be attributed to two scheduled and three
unscheduled outages and the use of 23 new state-of-the-art
personnel monitors with increased sensitivity.
The licensee's program for monitoring and controlling liquid
and gaseous radioactive effluents was effectively implemented.
The whole body doses were less than one millirem/year each from
the liquid effluents and from the gaseous effluents released
during 1990 and 1991. Those doses were a small percentage of
their respective limits.
The licensee reduced by 62 percent
the fission and activation products released in liquid
effluents between the periods January 1989 through June 1990
and July 1990 through December 1991.
(These periods most
closely
coincide with the previous and current assessment
periods.)
The decrease was due, in part to, the leakage
control program; use of multi-element pre-filters to remove
cobalt and magnesium; use of resins with greater surface area;
and modification of demineralizers to reduce channeling. Also,
administrative procedures were changed to set a limit for the
maximum permissible concentration of cesium in liquid waste.
There was also a 39 percent decrease in noble gas released in
the gaseous effluents during the assessment period as compared
to the previous period. Although there were some increases in
halogens and particulates released in the gaseous effluents
during the assessment period as compared to the previous
9
period,
the licensee attributed these increases to the 3
outages during 1991.
No unplanned gaseous releases were
reported to have occurred during the assessment period but one
unplanned liquid release was reported.
On November 7, 1990, a
container being moved by a truck from one warehouse to another
turned over and approximately 7 gallons of water were spilled
from the container.
One gallon of water containing 9
microcuries was conservately estimated to have entered an open
yard drain.
The licensee's maintenance of effluent monitoring capabilities
was good during this assessment period.
The licensee had
completed installation of new Post Accident Liquid Sampling
(PALS) systems on Units 1 and 2. The new PALS systems have been
brought to operational status for all three units.
The
Radwaste Facility Ventilation Monitoring System was also
returned to operational status during the current assessment
period.
Good progress was made in the modification of the Low Pressure
monitoring systems.
These systems have
been inoperable since 1986 due to clogged sample lines.
Correction of the problem required a design change to the
system.
The modification for Unit 3 was completed and the
monitoring system for that unit was returned to service.
It is
anticipated that the Unit 1 and 2 LPSW monitoring systems will
be returned to service by mid 1992.
Significant progress was made during the assessment period in
replacement and upgrade of radiation monitoring instrumenta
tion. Digital readouts, with system failure alarms,
were
installed in the Control Room, the Technical Support Center and
the Radiation Protection office area. This program improvement
project is more than 50 percent complete.
The licensee's environmental monitoring program was effectively
implemented. The program results for 1990 indicated that there
was no significant radiological impact on the health and safety
of the general public resulting from plant operations.
Dose
estimates calculated from environmental monitoring program data
were in reasonable agreement with dose estimates calculated
from effluent release data and were well within 40 CFR 190 dose
limits.
The licensee's performance in the Environmental
Protection Agency's interlaboratory
crosscheck program
indicated that an effective quality assurance program had been
maintained for analysis of environmental samples.
Two violations were identified.
10
2. Performance Rating
Category: 1
3. Recommendations
None
C. Maintenance/Surveillance
1. Analysis
This functional area addresses those activities related to
equipment condition, maintenance, surveillance performance, and
equipment testing.
The maintenance/surveillance functional
area exhibited
inconsistent performance throughout the assessment period.
Predictive
maintenance
and equipment monitoring were
agressively persued and were effective whereas weaknesses were
noted in areas such as procedural adherence, documentation of
problems during troubleshooting and repairs, plant transients
and reactor trips induced by maintenance and surveillance
activities.
The licensee's efforts continued this period to move from a
reactive or corrective maintenance program to a predictive and
preventive approach. Maintenance efforts were at a 60/40 ratio
of predictive to corrective maintenance.
The equipment
vibration monitoring,
pipe erosion/
corrosion,
and valve
maintenance and replacement programs are considered strong
areas. The piping erosion/ corrosion program, which is related
to piping systems with the potential for high energy releases,
has been expanded to include both large and small diameter
piping. Most findings to date involve secondary system piping.
A new thermography program was introduced this period and was
instrumental in resolving several issues such as locating
system leakage and identifying deficient piping insulation.
The station has an obsolete and aging equipment program. This
is a joint maintenance and engineering effort.
During this period,
significant operational
problems
attributable to maintenance activities occurred.
A loss of
coolant event due to improperly installed fittings occurred in
November
1991.
The actual installation of the defective
reactor coolant system fittings occurred several years ago.
The licensee's inspection of all fittings identified this as a
pervasive problem with approximately 25 percent of all fittings
not meeting installation criteria.
The program for
installation was changed after the event.
11
-
The
licensee submitted
one
LER
concerning a missed
surveillance.
One instance of post modification/maintenance
requirements not being performed was identified. This involved
not verifying the alignment of the turbine driven emergency
feedwater pump.
Surveillance activities directly caused or contributed to
several plant trips and events.
These included valving a
reactor coolant system flow transmitter
into service
incorrectly; incorrectly using test equipment during a
surveillance test that caused a reactor trip; and incorrectly
returning a low pressure injection pump flow transmitter to
service.
Equipment performance has adversely affected plant operations.
Specifically, six reactor trips from power were caused by
equipment failures.
These trips included an inadvertent trip
of the condensate booster pump and the failure of the standby
pump to start, a rod programmer problem dropped Group 7 rods
into the core, and a rod transfer switch failed in mid position
during rod transfer.
Several instances of independent verification errors resulted
in instrumentation not being properly returned to service nor
properly verified.
Examples include when instrumentation was
isolated during an LPI flow pump test and when instrumentation
test tees for the RCMUP were not tightened. Two instances were
noted of undocumented work activities involving lifting and
landing leads and replacement parts.
As part of the corporate reorganization plan instituted in
November 1991,
the Construction and Maintenance Department
(CMD) was eliminated. All CMD personnel permanently assigned
to Oconee were integrated into the maintenance department.
Training for CMD workers to site standards was initiated.
Use
of vendors and contractors was minimal, with most support for
modifications, maintenance and outage supplied by Duke Power
personnel.
The maintenance department was well staffed with
knowledgeable and experienced personnel.
A lower tier event investigation, root cause and corrective
action program,
Maintenance Incident Report or MIR,
was
implemented midway through this assessment period.
Program
upgrades were in progress and root cause training had been
completed by several maintenance personnel.
12
The inservice inspection program (ISI)
was being effectively
implemented.
ISI nondestructive examinations were being
conducted
by qualified personnel.
The procedures
and
examination techniques used to conduct examinations were
adequate and documentation of examination results was good.
Deficiencies were noted in the areas of pipe support and tendon
surveillance. Specifically, improper placement of radiography
penetrameters,
improper gap between washers and snubber rod
bearings and incomplete magnetic particle testing (MT)
records
were noted. Additionally, the licensee failed to investigate
and resolve the cause of a 2.5 inch difference in snubber hot
and cold settings from the drawing specifications.
Further
investigation identified that the hot and the cold settings
were reversed on the drawing.
Plant material conditions and routine housekeeping were
generally acceptable.
Instances of Unit 2 outage related
housekeeping problems were noted during a Unit 2 containment
closeout walkdown. This was observed early in the assessment
period; subsequent walkdowns indicated improvement in this
area.
Five violations including one Severity Level III violation were
identified.
2. Performance Rating
Category: 2
3. Recommendations
The Board is concerned with the adverse impact of equipment
performance and surveillance activities on plant operations.
Six reactor trips from power were caused by equipment failures
and surveillance activities caused or contributed to plant
events and trips.
Management attention to this area is
appropriate.
1. Analysis
This area addresses those activities related to the Emergency
Plan,
support for and training of emergency response
organizations both on and offsite, and licensee performance
during emergency exercises and actual events.
During this
assessment period the licensee continued to maintain a strong
emergency response organization capable of providing sufficient
protective measures to ensure public safety in the event of an
emergency.
jIII
13
Management attention and support for emergency preparedness was
evident throughout the period.
Program strengths identified
during inspection activity this assessment period included:
maintenance of emergency response facilities and equipment in a
high state of operational readiness, effective training of
onsite and offsite emergency response personnel and completion
and turnover of a new Emergency Operations Facility with
commitments to initially activate and staff the facility from
the Oconee site rather than from the corporate office.
Oconee demonstrated thorough preparation for dealing with site
emergency situations during an October 1990 partial partici
pation exercise and during a full participation October 1991
exercise.
During both exercises the licensee demonstrated it
could effectively implement the Emergency Plan and its
implementing procedures, effectively assign emergency response
organization responsibilities, and could take suitable actions
to mitigate the on and offsite consequences of the accident
scenarios.
Emergency classification was prompt and correct as
the scenarios progressed and operations of the emergency
response facilities and equipment observed during the annual
exercises were good.
Other exercise strengths identified
included effective fire brigade response and,
during the
October 1990 exercise, an effective response to a real medical
emergency onsite coincidental with the exercise.
Two exercise weaknesses were identified during the October 1990
exercise. The first weakness was a failure to activate the
Technical Support Center in a timely manner. The licensee gave
increased attention to activation timeliness between the
exercises and, during the October 1991 exercise, the licensee
was able to demonstrate prompt activation of the Technical
Support Center.
The second weakness involved numerous
communication problems between the Technical Support Center and
the State Forward Emergency Operations Center which were
subsequently corrected.
Overall,
however, the licensee's
performance during the two exercises was good, with the
licensee meeting their exercise objectives and demonstrating a
capability to protect public health and safety in the event of
a radiological emergency.
Emergency
response facilities were kept in a state of
operational readiness, the TSC was remodeled to include an
enhanced emergency data system, and a significant upgrade was
implemented with the turnover and operation of the new
Emergency Operations Facility.
(EP)
staffing was well qualified and remained constant throughout
the period.
Late in the assessment period the licensee
committed to significantly increase the staffing level onsite
as a result of a corporate reorganization, which decentralized
14
staff and functions from Charlotte to the Oconee site.
During
the period the licensee made appropriate revisions and upgrades
of the Emergency Plan and EPIPs, conducted challenging drills
and exercises, assured proper upkeep of EP equipment,
and
maintained coordination with offsite support groups.
Management attention to program activities was evident
throughout the period. For example, senior technical staff and
management were assigned to emergency response organization
(ERO) functional areas
and were required to maintain
qualification to support response activities. The ERO training
program was thoroughly defined and supported. Lesson plans and
training modules were organized and appropriate for meeting
stated objectives.
During this assessment period, the licensee's Emergency Plan
was implemented twice in response to events,
one at the
Notification of Unusual Event (NOUE) level and one at the Alert
level.
In each case, the event detection and classification
was prompt and correct, offsite authorities were initially
notified in a timely manner,
good updates and periodic
communications were maintained with state and local emergency
operation centers as well as the NRC, and the onsite emergency
organization responded in an overall effective manner.
Two exercise weaknesses were identified.
2. Performance Rating
Category 1
3. Recommendations
None
E. Security
1. Analysis
This functional area addresses those security activities
related to protection of vital plant systems and equipment, and
the Fitness For Duty Program.
Security management at both the site and corporate levels was
knowledgeable and highly supportive of program activities.
Support was indicated by the implementation of a Protected Area
Upgrade Project, a Physical Performance Test Program and by
changing the contract security force to a proprietary security
force.
These initiatives contributed to a reduction in the
15
security staff turnover rate in this assessment period as
compared to the rate during the last period.
The licensee's primary system to assess alarms is a closed
circuit television system fixed and pantilt-zoom cameras. The
licensee could not fully utilize this system during this SALP
period due to equipment malfunctions and maintenance problems.
This issue was identified during the previous two SALP periods.
As part of a comprehensive Protected Area Upgrade Project, the
licensee put in place plans to address problems with the camera
assessment capabilities.
During this SALP period the licensee
improved the quality of a few of the operating cameras and
began installation of the rest of a new camera assessment
system during the latter part of this SALP period.
During this SALP period, the licensee made improvements in its
detection system.
For example, the licensee reconfigured the
protected area perimeter to improve the zones of detection.
Also, the licensee enhanced the physical structure of the
protected area perimeter barrier.
The licensee was in the
final stage of this upgrade project during the end of the
assessment period.
Other areas of the licensee security program were effectively
operated during this period.
For example,
the licensee's
access control program was enhanced to correct the access
control problems mentioned in the last SALP period.
The
licensee has also improved its program to account for and
identify security keys.
Alarm stations and communication
equipment associated with the stations were operated by capable
and knowledgeable personnel.
The testing and maintenance of
the security equipment were conducted as required.
The licensee had established, maintained and effectively
implemented a security program for the Independent Spent Fuel
Storage Installation (ISFSI).
The licensee's Fitness for Duty Program was effective in
obtaining drug-free workplaces while balancing the rights and
privacy of the workforce. It met the objectives of 10 CFR 26.
The licensee submitted three Security, two Contingency,
one
Training and Qualification, and one Independent Spent Fuel
Storage Installation (ISFSI)
Security Plan revisions during
this period.
These revisions were consistent with
10 CFR 50.54(p) and adequately coordinated.
The security force was well staffed, equipped, and trained to
perform their assigned duties. The security training staff was
dedicated, knowledgeable and motivated.
16
2. Performance Rating
Category:1
3. Recommendations
None
F. Engineering/Technical Support
1. Analysis
This functional area addresses those activities associated with
engineering and technical support, including activities
associated with design of plant modifications, engineering, and
technical support for operations and operator training.
The licensee's engineering (DE)
and other technical support
groups have been responsive to station needs.
Overall
engineering and technical support continues to effectively plan
and implement plant modifications.
The experience level of
engineering and technical personnel and their participation in
generic industry initiatives remains high.
Communications
between DE (General Office) and plant engineering have improved
as a result of reorganization of DE and establishment of an
onsite DE contingent.
Responsiveness to station needs is evidenced by the monitoring
and testing of the reactor building cooling units on line,
identification and investigation of problems associated with
the testing of pressurizer safety valves, and fire detection
system and radiation monitoring equipment upgrades.
Engineering support for successfully implemented modifications
included the emergency feedwater system, Anticipated Transient
Without a Scram
(ATWS)
mitigation safety actuation circuit
(AMSAC),
the diverse scram system and Regulatory Guide 1.97
emergency core cooling system instrumentation.
condensate system water hammer event as well as the failure of
a pressure fitting on the Reactor Vessel Level Instrumentation
System (RVLIS)
instrumentation were examples of inadequate
engineering support for modifications.
In the former example,
the modification was not correctly designed and on first use,
resulted in the water hammer.
In the latter example, the
modification depended upon excessive fittings to transition
from a one-inch pipe to a three-eights inch instrument line.
17
DE was actively involved in various industry initiatives such
as resolution of several Generic Letters.
DPC was also
involved in the Operating Experience Program,
Nuclear Plant
Reliability Database System,
Babcock and Wilcox Owner's Group
and various Nuclear Utility Management and Resource Counsel
initiatives.
Continued good communication and cooperation between corporate
and site engineering groups during this assessment period was
evidenced by the motor operated valve test program which
required coordination of engineering calculations, system
reviews,
the development of a program and procedures,
and
implementation of diagnostic testing of valves under design
basis conditions.
Strengths were identifi.ed with the motor
operated (MOV)
program.
These included well documented and
thorough switch setting calculations,
the initiation of
differential pressure testing and knowledgeable personnel.
DE was responsible for the ongoing Design Basis Documentation
(DBD) program. The DBD was started in 1989 to provide accurate
design base documentation of all safety related systems.
This
program continued to involve significant engineering resources.
The program is scheduled to be completed in 1995 and has
resulted in the identification and correction of several
significant electrical system design deficiencies as well as
other system discrepancies.
The Operating Experience Review program was effective and led
to the identification of susceptibility to certain fault types
at the Keowee Hydro units.
Additionally, several breaker
coordination problems were identified during design reviews of
breaker and relay trip settings. The licensee's resolution of
these problems was thorough and timely.
Followup on the
potential for hydrogen intrusion and degradation of high
pressure injection (HPI)
pumps was not effective in that DE
failed to recognize the severity of this issue and actions
necessary to resolve the issue were not timely.
In general,
DE produced procedures were adequate although
instances of inadequate procedures were noted.
Specifically,
procedures involving the installation of compression fittings
and testing of the HPI system were inadequate. The HPI system
was determined to have been inoperable for extended periods due
to improperly installed flow instruments and orifice plates.
The ISI program was effectively implemented by highly skilled
and knowledgeable engineers and technicians, and knowledgeable
and technically competent contractor personnel.
Inspections
were well planned and included use of mock ups for steam
generator work, and use of state-of-the-art equipment.
Test
.
18
results were well documented. The use of previous test results
in evaluation of inspection findings and conservative decisions
relative to inspection findings were noted.
Concerns were identified in the DE and technical support area.
For example the inoperability of a startup transformer was due
to inadequate reading of a manufacturer's relay setting curve
and an inadequate post modification test. Another weakness was
identified during the repair of a pipe crack on a Low Pressure
Injection (LPI)
system dropline.
These included failure to
detect and resolve LPI
pump vibration before the crack
developed, failure to adequately review and pre-plan spool
piece fabrication to prevent distortion, failure to adequately
pre-plan and control purging in the welding process,
and
inability to readily retrieve replacement component quality
records after the repair.
Additional management attention is required in the area of
licensed operator training. Sixteen Generic Fundamental
Examinations were administered during the assessment period
with four failures.
Insufficient effort by the Oconee Training
Department in support of the requalification program was noted.
Some
NRC requested changes provided to examinations were
omitted, and the simulator scenario bank was developed at the
minimum rate.
Operational validation of examination material
was often lacking and some scenarios were short and simplistic.
Poor support was identified during the pre-review of the
January 1992 Initial Examination written portion which resulted
in post examination comments on a large portion of the.
examination.
During simulator examinations, weaknesses were
noted in manual operation of feedwater controls.
The plant
specific simulator exhibited deficiencies in Engineered
Safeguards component modeling and the inability to fail some
major components.
Poor planning of post maintenance testing has resulted in the
submittal of several relief requests requiring expedited review
by the NRC.
During the Unit 1 outage in August 1991, work on a
RCP required removal of the pressurizer safety valve tailpiece.
A request for relief was submitted late in the outage, when the
need for the relief should have been determined when planning
for the outage.
Similar examples occurred during the Unit 2
outage in October 1990,
when three relief requests were
submitted at the end of the outage related to the testing of
repair welds. These relief requests were submitted only a few
days before the approval was needed.
19
Four violations including two Severity Level III violations
were identified.
2. Performance Rating
Category:
2
3. Recommendations
Increased management attention is warranted in the area of
licensed operator training.
Specifically, support of the
requalification examination program is weak and operational
validation of examination material is often lacking.
G. Safety Assessment/Quality Verification
1. Analysis
This functional area addresses those activities related to
implementation of safety policies; amendments,
exemptions and
relief requests; response to Generic Letters, Bulletins, and
Information Notices; resolution of safety issues; reviews of
plant modifications performed under 10 CFR 50.59; safety review
lacommittee
activities;
and the use of feedback
from
self-assessment programs and activities.
During the assessment period several plant modifications and
program changes enhancing plant safety were initiated or
completed. Hardware changes included Emergency Feedwater test
loop installation, a new Radiation Monitoring system,
switchyard access control with fences established, and a new
fire detection system installed in the turbine and auxiliary
buildings.
Design Baseline Documentation (DBD)
reviews of
several safety systems continued during this assessment period.
A "lower tier" event investigation processes for each
organizational unit was initiated.
Management decisions were generally conservative and adequately
considered plant, system, and personnel safety.
Although not
strictly required by TS,
Unit 3 was shut down to repair the
Standby Shutdown Facility (SSF)
Reactor Coolant Makeup System,
and HPI full flow testing was voluntarily initiated.
There
were instances where less conservative approaches were
employed.
These included a decision to continue with RCS
draindown without ultrasonic level instruments in service;
allowing workers to suspend work required to promptly restore
the dewatered Keowee hydro units; and starting up a unit with
an intermediate excore neutron detector inoperable.
20
The corporate and site reorganization has incorporated most
independent,
safety oversight functions under the Safety
Assurance Manager and his staff.
These include Regulatory
Compliance,
Safety Review,
Environmental
Compliance,
and
An accurate assessment of the
reorganization's
impact on plant safety and safety
consciousness was not made due to its implementation late in
the assessment period.
The licensee normally demonstrated an aggressive approach to
the resolution of those issues which are clearly safety
significant.
Their actions were generally conservative and
thorough,
and involved interaction with NRR staff when
appropriate.
Examples included the
installation of
modifications to start Emergency Feedwater pumps on low steam
generator level and corrective actions for HPI system operation
in light of SBLOCA concerns.
The licensee continued to support interaction with the NRC
staff to resolve issues,
and ensured that knowledgeable
technical personnel were available. Numerous conference calls
have been held,
and a number of significant meetings were
conducted, such as to provide an overview of the Oconee IPE
submittal, describe the IST program submittal in response to GL 89-04 and discuss the ISI reactor vessel inspection.
Responses to NRC requests were usually provided within the time
frame
requested
and written notice was
provided if
circumstances prevented meeting the requested schedule.
Although the responses were normally timely, the licensee has
been slow to complete some actions.
Examples include
implementing the recommendations of GL 88-14 concerning
instrument air systems,
which is still not completely
implemented and delays in implementing the program recommended
Improvements in the licensee's
program for the procurement and dedication of commercial grade
components was
not implemented in accordance with the
recommended NUMARC schedule, which was endorsed by the NRC.
Licensee proposals and responses were generally well-prepared,
accurate, and thorough. In particular, the quality of proposed
license amendments
has improved during this SALP cycle.
Proposed amendments submitted early in the evaluation period
required supplements to provide clarification, missing
information, or correct errors in the original submittal,
but
more recent submittals have generally required no revision or
additions.
The quality of ISI and IST relief requests were
poor. Some requests were written such that it was difficult to
21
determine what was being requested or the justification for the
relief. Examples included a relief request associated with the
removal of a temporary expandable plug in a LPSW pipe and a
request to modify the inspection schedule of reactor coolant
outlet nozzles.
The licensee's response to Generic Letter
(GL)
88-20,
"Individual Plant Examination," was thorough, well documented,
and included an analysis of external events,
which was not
required to be submitted with the original IPE response.
The
response to NRC Bulletin 88-08, "Thermal Stresses in Piping
Connected to the Reactor Coolant System," only satisfied the
Bulletin recommendations for one Oconee unit. The licensee is
currently preparing a response to a Request For Additional
Information concerning this issue for Units 2 and 3.
The licensee's response to many other issues has been good.
After the NRC raised concerns about the time required to
activate the Oconee Crisis Management Center, the licensee
expeditiously revised the appropriate procedures.
After
deficiencies were identified in the Oconee Technical Specifi
cations relating to shutdown requirements,
the Oconee staff
performed a self-evaluation of their Technical Specifications
and presented the results of their review to the NRC, including
proposed corrective actions.
The response was prepared in a
very short time period and was thorough.
The licensee submitted three Security, two Contingency, one
Training and Qualification, and one Independent Spent Fuel
Storage Installation Security (ISFSI)
Plan revisions during
this period.
These revisions were consistent with 10 CFR
50.54(p) and adequately coordinated.
The ISFSI revision was
forwarded to headquarters for review.
The licensee has developed a program where a Significant Event
Investigation Team (SEIT)
is dispatched to a site after
notification of a significant event.
The SEIT assists the
station safety review group in determining the cause of the
event, safety implications, and necessary corrective actions.
These teams evaluated the shutdown events that occurred at
Oconee Unit 1 in September 1991 and the instrument line leak
that occurred at Unit 3 in November 1991. The teams appeared
to be effective and in the case of the shutdown events, had
findings similar to the NRC AIT findings.
During this assessment period, several events occurred which
reflected management's failure to recognize deficiencies in
fundamental watchstanding practices, and command and control
of shift operations. These events were the loss of decay heat
removal in March and September 1991,
and the overpressuriza
tion of the LPI system in November 1991.
27
3.
Eight Special Reports were submitted but are not
included in the above tabulation.
4. The above information was derived from a review of
LERs
performed by the NRC staff and may
not
completely coincide with the licensee's cause
assignments.
H. Licensing Activities
In addition to QA and security submittals, there were approximately
147 active licensing actions for the three Oconee units during this
SALP period. Of these, 69 were completed. A total of 33 licensing
amendments were submitted and 21 were issued.
I. Enforcement Activity
No. of Deviations and
Violations in Each Functional Area
Dev. V
IV
III
II I
Plant Operations (1)
9
Radiological Controls
2
Maintenance/Surveillance (2)
4
1
Security
Engineering/Technical
Support (3)
2
2
Safety Assessment/Quality
Verification
TOTAL
17
3
Notes:
(1) Two Severity Level III violations pertaining to two
separate September shutdown incidents were issued
after the SALP Cycle closed.
(2) The Severity Level III violation consisted of three
separate violations, the aggregate of which was
determined to be a Severity Level III.
(3) One Severity Level III violation (269,270,287/
90-17-01) was fully discussed in the previous SALP
period but not counted.
26
June 9, 1991:
Reactor tripped from 100 percent power when when
Group 5 control rods dropped into core during exercise of Rod
12 of Group 12.
July 3, 1991:
Reactor tripped from 100 percent power due to
loss of suction to condensate booster pumps caused by faulty
powdex master controller while bypass valve was not in
automatic.
November 23,
1991:
Reactor tripped from 35 percent power
following a turbine trip on loss of both main feedwater pumps
while shutting down the unit. The unit was being shutdown due
to RCS leakage into containment.
Pressure swings in the
feedwater system caused both feedwater pumps to trip.
January 14, 1992:
Reactor tripped from 94 percent power due to
high steam generator level when both main feedwater pumps
tripped during maintenance troubleshooting operations.
G. Review of Licensee Event Reports (LER)
During the assessment period
32 LERs were analyzed.
The
distribution of these events by cause as determined by the NRC staff
was as follows:
Unit 1
Cause
Totals
or Common Unit 2
Unit 3
Component Failure
6
1
2
3
Design/Procedures
11
10
1
Construction/Fabrication
Installation
4
1
1
2
Personnel
-
Operating Activity
1
1
-
Maintenance Activity
2
1
1
-
Test/Calibration Activity 3
1
1
1
-
Other
1
1
Other
4
2
1
1
Totals
32
17
5
10
Notes:
1. With regard to the area of personnel,
the NRC
considers lack of procedures, inadequate procedures,
and erroneous procedures
to be classified as
personnel error.
2. The Other category is comprised of LERs where there
was a spurious signal a totally unknown cause.
22
Following these events, the licensee took steps to improve the
command and control function for control room operations as
well as to strengthen procedures for assuring safety during
shutdown operations.
Although some improvement was noted
during a Unit 2 refueling outage at the end of this assessment
period, the effectiveness of long term actions has not been
determined.
No violations were identified.
2. Performance Rating
Category: 2
3. Recommendations
None
V. SUPPORTING DATA AND SUMMARIES
A. Licensee Activities
A major reorganization was announced in November
1991,
including relocating Design Engineering to the site.
Implementation of the reorganization has not been fully
completed.
During this assessment period, Unit 1 completed a scheduled
refueling outage in September 1991.
The ten year Inservice
Inspection (ISI), including inspection of the Reactor Coolant
System, was completed during the outage. Several events while
shutdown resulted in two AITs
during this outage.
In
addition, problems with the SSF resulted in a short duration
outage.
Unit 2 completed a scheduled refueling outage in October 1990.
A refueling outage was entered in January 1992.
Unit 3 completed a scheduled refueling outage in March 1991. A
loss of LPI resulted in an AIT on Unit 3 during this outage.
An RCS leak and a subsequent loss of 87,000 gallons of reactor
coolant occurred in November 1991.
This event caused the unit
to be shutdown for over a month.
During the subsequent startup, a through-wall crack in the
decay heat removal dropline, requiring replacement of a portion
of the LPI piping, was discovered.
23
A total of eight automatic and one manual reactor trip occurred
during the assessment period; three trips on Unit 1 and six
trips on Unit 3. In addition several outages of short duration
occurred during the assessment period.
B. Direct Inspection and Review Activities
In addition to the ongoing routine resident inspections, 33 regional
inspections performed at the Oconee facility by the NRC staff, six
special inspections were conducted as follows:
March 12-15, 1991:
Augmented Inspection Team inspection of
loss of decay heat removal event of March 8, 1991.
July 15-19, 1991:
Procurement Assessment.
September 9-13, 1991:
Augmented Inspection Team inspection on
degradation of the low pressure injection system event of
September 7, 1991.
September 20-23, 1991:
Augmented Inspection Team inspection on
over-pressurization of low pressure injection system event of
September 19-20, 1991.
November 23 -
December 21,
1991:
Special inspection of
circumstances associated with primary system leakage due to
failed mechanical fitting on an instrument line for the reactor
coolant system.
December 9-13, 1991: Shutdown Risk Inspection
C. Escalated Enforcement Activities
1. Orders
None.
2. Civil Penalties (CP)
A Severity Level III violation (EA 90-119) was issued for ESF
valves which would have failed in the closed position in lieu
of the open position upon loss of instrument air. ($25,000 CP)
A Severity Level III violation (EA 91-049) was issued for three
violations associated with the Unit 3 loss of decay heat
removal and discharge of approximately 14,000 gallons of water
into the Unit 3 containment (No CP).
24
A Severity Level III violation (EA 91-052)
was issued for
improper installation of flow orifice instrumentation in the
Units 1 and 2 high pressure injection systems. (No CP)
D. Management Conferences
October 18, 1990:
A management meeting was held at the Oconee
Station to discuss the
SALP Board assessment of Oconee's
performance.
December
11,
1990,
and September 4, 1991: A Duke/NRC Interface
Meeting was held at the McGuire facility to discuss issues of
interest to both organizations.
February 12, 1991: A meeting was held at NRC Headquarters for Duke
to give a presentation on the Individual Plant Examination (IPE)
review for the Oconee Station.
February 14,
1991:
A management meeting was held at the Oconee
Crisis Management Center (CMC)
to discuss the activation timeliness
for the CMC in the event of an emergency at the Oconee facility.
March 21, 1991: A management meeting was held in Region II for the
licensee to present details of their investigation of the March 8,
1991, event concerning the loss of decay heat removal capability
while the unit was in cold shutdown.
May 7, 1991:
An enforcement conference was held in Region II to
discuss the circumstances surrounding the March 8, 1991, loss of
decay heat removal capability while the unit was in cold shutdown.
May 22, 1991:
An enforcement conference was held in Region II to
discuss the concerns associated with one high pressure injection
crossover valve in both Units 2 and 3 being incapable of performing
its intended safety function for an extended period of time.
September 25, 1991: A management meeting was held in Region II to
discuss the Unit 1 events associated with the September 7, 1991,
degradation of the decay heat removal and the September 19-20, 1991,
over-pressurization of the low pressure injection system, and the
action taken by Duke on the NRC Confirmation of Action Letter dated
September 20, 1991.
November 5, 1991: A management meeting was held for the licensee to
give a self-assessment of the performance at the Oconee Station from
August 1, 1990.
25
December 18, 1991:
An enforcement conference was held in Region II
to discuss the Unit 1 September 7, 1991, reactor coolant system
heat-up event and the September 19-20, 1991, over-pressurization of
the Unit 1 low pressure injection system event.
E. Confirmation of Action Letters (CAL)
September 20, 1991: A CAL was issued which outlined the actions to
be taken prior to the startup of Unit 1 following the September 7,
1991, degradation of decay heat removal event and the September
19-20,
1991,
over-pressurization of the low pressure injection
system event.
Unit 1
Three automatic reactor trips occurred:
August 28, 1990:
Reactor tripped from 100 percent power due to
high RCS pressure caused by the trip of Condensate Booster Pump
lB due to spurious signal indicating a closed pump discharge
valve.
May 16, 1991:
Reactor tripped from 100 percent power due to
Flux/Flow imbalance.
All four reactor protection system
channels tripped. The unit event recorder failed immediately
prior to the trip.
October 2, 1991:
Reactor tripped from 73 percent power
following a turbine trip on a false generator lockout signal
caused by a loose electrical connector.
Unit 2
No automatic reactor trips occurred.
Unit 3
Five automatic and one manual reactor trip occurred:
November 13, 1990:
The operators manually tripped the reactor
from 100 percent prior to an automatic trip when all group
seven rods dropped into the core,
due to a faulty rod
programmer.
April 1, 1991:
Reactor tripped from 70 percent power during
power escalation due to spurious activated alarms on diverse
scram system channels 1 and 2.