ML17059B058
| ML17059B058 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 02/16/1996 |
| From: | Mary Johnson NRC (Affiliation Not Assigned) |
| To: | Sylvia B NIAGARA MOHAWK POWER CORP. |
| Shared Package | |
| ML17059B059 | List: |
| References | |
| NUDOCS 9602260359 | |
| Download: ML17059B058 (32) | |
See also: IR 05000220/1996201
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
WASHINGTON, D.C. 20555-0001
February
16,
1996
go -ZZ 0
Hr. B. Ralph Sylvia
Executive Vice President - Generation
Business
Group
Niagara
Mohawk Power Corporation
(NMPC)
Nine Mile Point Nuclear Station
P..O.
Box 63
Lycoming,
NY 13093
SUBJECT:
NINE MILE POINT STATION INTEGRATED PERFORMANCE ASSESSMENT
PROCESS
(IPAP)
PRELIMINARY ASSESSMENT
REPORT
(NRC INSPECTION
REPORT
NOS.
50-220/96-201
AND 50-410/96-201)
Dear Mr. Sylvia:
During the period from January
16 through January
26,
1996,
a team under the
direction of the Special
Inspection
Branch of the Office of Nuclear Reactor
Regulation
completed
the in-office review of an Integrated
Performance
Assessment
of the Nine Mile 'Point Nuclear Station.
This phase of the
assessment
consisted of an in-office review of the inspection record
and
performance history for a two year period spanning
January
1994 to December
1995.
The in-office review identifies performance
strengths
and weaknesses
in
the areas of Safety Assessment/Corrective
Action, Operations,
Engineering,
Maintenance,
and Plant Support.
The results
are
summarized
in the attached
report
and are depicted
on the attached
Preliminaty. Performance
Assessment/Inspection
Planning Tree.
The=second
phase of the assessment
will consist of a two week on-site
assessment
scheduled for the weeks of March 4 and March 18,
1996.
During this
phase of the assessment,
the team will validate its preliminary results
as
well as draw conclusions
in those
areas originally considered
to be
indeterminate.
The results of the on-site
assessment
will be evaluated
along
with those of the in-office review and documented
in a Final Assessment
Report.
The final results will also
be depicted
on
a Final Performance
Assessment/Inspection
Planning Tree.
This preliminary information. is being provided for your information only.
No
response
to this letter or the preliminary assessment
is required.
9602260359
960216
I
ADQCK 05000220,'
PDR,'umg
B~LI~ CEH7KK CSPV
B. Ralph Sylvia
Should you have
any questions
concerning this preliminary assessment,
or the
assessment
process
in general,
please
contact the assessment
team leader
Mr.
S.K. Malur at (301) 415-2963.
Sincerely,
Enclosure:
Inspection
Report
cc:
See next page.
Michael
R. Johns
n, Acting Chief
Special
Inspection
Branch
Division of Inspection
and Support
Programs
Office of Nuclear Reactor Regulation
Distribution:
Docket Files 50-220,
50-410
PSIB R/F
FPGillespie,
RHGallo,
MRJohnson,
DPNorkin,
CERossi,
SAVarga,
LBHarsh,
GEEdison,
SLLittle, NRR
BNorris, SRI
HEPoteat
Regional Administrators
Regional Division Directors
Inspection
Team
PUBLIC
ACRS (3)
OGC (3)
1S Distribution
t
II
Hr. B. Ralph Sylvia
Niagara
Hohawk Power Corporation
Nine Mile Point
Hark J. Wetterhahn,
Esquire
Winston
E Strawn
1400
L Street,
NW
20005-3502
Supervisor
Town of Scriba
Route 8,
Box 382
Oswego,
NY
13126
Mr. Richard
B. Abbott
Vice President
Nuclear Generation
Niagara
Hohawk
Power
Corporation
Nine Mile Point Nuclear Station
P.O.
Box 63
Lycoming,
NY
13093
Resident
Inspector
U. S. Nuclear Regulatory
Commission
P.O.
Box 126
Lycoming,
NY
13093
Gary D. Wilson, Esquire
Niagara
Mohawk Power Corporation
300 Erie Boulevard
West
Syracuse,
NY
13202
Regional Administrator,
Region I
U. S. Nuclear Regulatory
Commission
475 Allendale
Road
King of Prussia,
19406
Mr. F. William Valentino, President
New York State
Energy,
Research,
and Development Authority
2 Rockefeller Plaza
Albany,
NY
12223-1253
Hr. Martin J.
HcCormick, Jr.
Vice President
Nuclear Safety Assessment
and Support
Niagara
Mohawk Power Corporation
Nine Mile Point Nuclear Station
- P.O.
Box 63
Lycoming,
NY
13093
Hr. Norman L. Rademacher
Unit
1 Plant Manager
Nine Mile Point Nuclear Station,
P.O.
Box 63
Lycoming,
NY
13093
Hr. Kim A. Dahlberg
Plant Manager,
Unit 2
Nine Mile Point Nuclear Station
P.O.
Box 63
Lycoming,
NY
13093
Charles
Donaldson,
Esquire
Assistant Attorney General
New Yor k Department of Law
120 Broadway
NY
10271
Mr. Paul
D.
Eddy
State of New York Department of
Public Service
Power Division, System Operations
3 Empire State
Plaza
Albany,
NY
12223
Hs. Denise J. Wolniak
Hanager
Licensing
Niagara
Mohawk Power Corporation
Nine Mile Point Nuclear Station
P.O.
Box 63
Lycoming,
NY
13093
Mr. Richard Goldsmith
Syracuse University
College of Law
E. I. White Hall Campus
Syracuse,
NY
12223
Hr. Richard
H. Kessel
Chair and Executive Director
State
Consumer Protection
Board
99 Washington
Avenue
Albany,
NY '2210
Mr. John
V. Vinquist,
MATS Inc.
P.O.
Box 63
Lycoming,
NY
13093
U.S.
NUCLEAR REGULATORY COHHISSION
OFFICE
OF NUCLEAR REACTOR REGULATION
NRC Inspection
Report:
50-220/96-201
and 50-410/96-201
License
Nos.
and NPF-69
Docket Nos.:
50-220
and 50-410
Licensee:
Niagara
Hohawk Power Corporation
Facility Name:
Nine Hile Point, Units
1 and
2
Inspection
Conducted:
January
16 through 23,
1996
Inspection
Team:
S.K. Halur,
Team Leader, 'Special
Inspection
Branch
D.H. Barss,
Emergency
Preparedness
and Radiation
Protection
Branch
T.H. Boyce, Standardization
Project Directorate
T.Foley, Special
Inspection
Branch
J.A.
Isom, Special
Inspection
Branch
R.B. Hanili, Safeguards
Branch
R.K. Hathew,
Special
Inspection
Branch
D.J. Nelson,
Inspection
Program
Branch
H. Wang, Special
Inspection
Branch
J.E. Wigginton,
Emergency
Preparedness
and Radiation
Protection
Branch
Prepared
by:
S.K.
Ha ur,
Team Leader
Special
Inspection
Branch
Division of Inspection
and Support
Programs
Office of Nuclear Reactor Regulation
ate
Reviewed
by:
Donald
P. Norkin, Section Chief
Special
Inspection
Branch
Division of Inspection
and Support
Programs
Office of "Nuclear Reactor Regulation
Date
Approved by:
Hicha l R. Johnson,
cting Branch Chief
Special
Inspection
anch
Division of Inspect
on and Support
Programs
Office of Nuclear Reactor Regulation
ate
9602260365
9602'Lh
ADDCK 05000220
8
Enclosure
TABLE OF
CONTENTS
EXECUTIVE SUMMARY .
OVERALL ASSESSMENT
SCOPE
AND OBJECTIVES
.
ASSESSMENT
METHODOLOGY
1.0
SAFETY ASSESSMENT
AND CORRECTIVE ACTION .
1. 1
Problem Identification
1.2
Problem Analysis
and Evaluation
.
.
.
.
.
1.3
Problem Resolution
2. 0
OPERATIONS
2.1
2.2
2.3
2.4
Safety
Focus
Problem Identification/Problem Resolution
.
guality of Operations
.
Programs
and Procedures
.
.
3.0
ENGINEERING
.
3.1
3.2
3.3
3.4
Safety
Focus
Problem Identification/Problem
guality of Engineering
Work
.
.
Programs
and Procedures
.
.
.
.
~
~
1
~
~
~
Resolution
.
4. 0
MAINTENANCE
10
4,1
4.2
4.3
4.4
4.5
Safety
Focus
Problem Identification/Problem
Equipment Performance/Material
guality of Maintenance
Work
.
.
Programs
and Procedures
.
.
.
.
~
~
~
~
~
~
Resolution
.
Condition
10
10ll
11
12
5.0
PLANT SUPPORT
.
5.1
Safety
Focus
5.1.1
Radiological
Controls
.
5.1. 2
Security
5. 1.3
Emergency
Preparedness
5.2
Problem Identification/Problem Resolution
.
5.2. 1
Radiological Controls
.
5.2.2
Security
5.2.3
Emergency
Preparedness
12
12
12
13
13
14
14
14
15
5.3
equality of Plant Support
5.3.1
5.3.2
5.3.3
Radiological Controls
.
Security
Emergency
Preparedness
5.4
Programs
and Procedures
.
5.4. 1
Radiological Controls
.
.
.
5.4.2
Security
5.4.3
Emergency
Preparedness
APPENDIX A LIST OF
REFERENCES
.
APPENDIX
B PRELIHINARY PERFORHANCE ASSESSHENT/INSPECTION
PLANNING TREE.
15
15
16
17
17
17
17
A-1
B-1
EXECUTIVE SUMMARY
The in-office review phase of the integrated
performance
assessment
of both
units of the Nine Mile Point Nuclear Station
was conducted
by the Special
Inspection
Branch of the U.S. Nuclear Regulatory Commission's Office of
Nuclear Reactor Regulation during the weeks of January
16 and 22,
1996.
The
purpose of this in-office review was to develop
an integrated
perspective
of
performance
strengths
and weaknesses
based
upon
a review of inspection
reports,
event reports,
and other
NRC and licensee
generated
information.
The
assessment
covered
a two year period from January
1994 to December
1995.
A
two week on-site
assessment
scheduled for the weeks of March
4 and March 18,
1996, will be conducted to validate the results
from the in-office review.
In the area of Safety Assessment/Corrective
Action, the licensee
was effective
in problem identification, but problem analysis
and problem resolution were
indeterminate.
The deviation/event
reports
were utilized effectively in
problem identification by all levels of the organization,
as documented
in
several
NRC inspection reports
and licensee quality assurance
audits.
Root
cause
evaluations for significant issues
appeared
to be properly conducted,
and the quality and depth vary appropriately with the significance of issues.
Audits performed
by the quality assurance
branch
were thorough.
For example,
the corrective action program audits required
by the technical specifications,
radioactive liquid and gaseous
waste control
program audits,
maintenance
program audits,
and surveillance of the
MOV program were broad in scope
and
good in technical
depth.
However, the trending
and evaluation of data from
the
DER process
appeared
to be
an area that needed to be improved,
particularly in cause identification, trend
code application,
and
identification of preventive actions.
The disposition ofissues
in the
DER
process
generally
was thorough,
although
some
examples of weaknesses
were
identified.
Resolution of recurring problems with rod position indication at
Unit 2, repeated
repairs to the reactivity control
system,
and missed
TS
surveillances
appeared
to be not thorough.
The licensee's
performance
in the
analysis
and evaluation of problems,
implementation of recommendations
from
assessments,
and the effectiveness
of corrective actions, will be further
assessed
by the team during its on-site inspection.
The performance of the operations
management
and personnel
in response
to
events
was good,
and the licensee
displayed
a conservative
approach
to
operation of both units.
Operations
was generally attentive to degrading or
unusual
equipment conditions,
but operators
missed opportunities to identify
abnormal
conditions
such as,
valves not in their correct position,
and
an
temperature
recorder for the safety relief valve tail pipe.
Procedural
weaknesses
and recurring personnel
errors
appeared
to have not been
completely addressed.
Operator
performance
during normal operation
was
satisfactory,
and operator
responses
during plant transients
was excellent.
Operations
programs
and procedures
including adequacy
and usage
where
indeterminate will be reviewed further during the site visit.
Generally,
the engineering staff demonstrated
proper safety perspective
in
thorough
and technically accurate operability evaluations of plant issues.
Engineering identified numerous plant problems
and resolved
them
appropriately,
although there were
a few instances
where problems
were not
noted
and properly evaluated.
For example,
Unit 2 emergency diesel
generators
had operated
outside their design basis
sitice initial plant startup
due to
a
design deficiency with the governor cooling water system,
and pressure
locking
and thermal
binding of risk significant motor operated
valves
(MOVs) in Unit 2
high pressure
core spray system were not identified for resolution.
Also, the
NRC had identified weaknesses
in the resolution of some of the plant issues
such
as the longstanding
problem of electrical
noise interference with neutron
monitoring system
and the corrective actions in response
to operational
experiences
regarding Agastat relay failures at Unit 1.
Plant modifications
and calculations
were technically sound,
and were properly documented.
However, design
changes
to the hydrogen
and oxygen systems
and installation of
a check valve in the service water line to a room cooler required further work
to make the equipment function acceptably.
Engineering
programs
and
procedures
including adequacy
and
usage
where indeterminate will be further
reviewed during the site visit.
The performance of maintenance
during the outages
at both units indicated
significant licensee
management
attention to the refueling
and outage
planning
activities.
Maintenance activities were generally well planned
and executed.
Pre-job briefings were generally satisfactory,
but where repetitive work was
being performed, briefings were not effective
as evidenced
by the
unintentional
reactor recirculation
pump runback incident.
Identification and
resolution of problems,
equipment
performance
and material condition,
and
programs
and procedures will be reviewed further on site.
In the Plant Support areas of Radiological Controls
and Security,
the licensee
demonstrated
strong performance
in safety focus, 'problem identification and
resolution,
and programs
and procedures.
Radiological
exposure
goals
were
met, thorough self-assessments
were performed,
and programs
and procedures
were effective.
The licensee
had thoroughly evaluated
the security program,
implemented corrective actions,
and the security plan
and procedures
were in
compliance with regulations.
Performance
in the area of Emergency
Preparedness
was weak as evidenced
by deficiencies
in the exercises
conducted
during the last two years.
During the October
1995 exercise,
the licensee
staff did not properly evaluate plant conditions
and did not recognize
and
properly classify the emergency
event in a timely manner
.
Also, dur ing the
October
1994 exercise,
the emergency
event
was incorrectly classified
due to
an error in the dose projection calculations.
OVERALL ASSESSMENT
SCOPE
AND OBJECTIVES
This Integrated
Performance
Assessment
of both units of the Nine Mile Point
Nuclear Station is being performed in accordance
with NRC Inspection
Procedure
93808 "Integrated
Performance
Assessment
Process."
The assessment
is divided
into:
an in-office review performed at
NRC headquarters;
an on-site
assessment
to validate the observations
from the in-office review;
and
a final analysis
of the results of the assessments
and development of inspection
recommendations.
The assessment
is being conducted
by the Special
Inspection
Branch of the Office of Nuclear Reactor Regulation.
The in-office review was
performed during the weeks of January
16 and January
22,
1996.
The on-site
assessment
is scheduled
to be performed during the weeks of March
4 and March
18,
1996.
The assessment
objectives
are to develop
an integrated
perspective
of licensee
performance
and arrive at recommendations
for future inspection
focus in the
areas of Safety Assessment/Corrective
Action, Operations,
Engineering,
Maintenance,
and Plant Support.
The in-office review covers
NRC inspection
reports,
licensee
event reports
(LERs), enforcement history, regional
assessments,
and licensee
internal
and external
assessments.
The results of
the in-office review are included in this preliminary report.
The references
contained
in the report are listed in Appendix A.
The preliminary results
are
presented
on the Preliminary Performance
Assessment/Inspection
Planning Tree
in Appendix B.
Following the issuance
of this report,
the team will validate its observations
via a performance
based,
on-site
assessment.
The results of the on-site
assessment
and in-office review will be used. during the final analysis
and
development of inspection
recommendations
and will be documented
in a final
report to be issued after the conclusion of the on-site
assessment.
The final
assessment
report will include recommendations
on where to focus future
NRC
inspection effort,
and these
recommendations will be depicted
on
a Final
Performance
Assessment/Inspection
Planning Tree.
ASSESSMENT
METHODOLOGY
During the in-office review, the team evaluated
the Nine Mile Point inspection
record
and performance history for a two year period spanning
January
1994 to
December
1995.
Available licensee quality assurance
(gA) audit reports
and
other self-assessment
documents
were reviewed.
The review results
were
utilized to assign
performance ratings of either decreased,
normal, or
increased
inspection to the individual elements
in each
assessment
area.
Where the team's
review of inspection data
and licensee
information was
inconclusive,
or where sufficient information was not available to come to
meaningful
conclusions,
individual elements
were rated
as being indeterminate.
Ratings for the overall performance
in the areas of Safety
Assessments/Corrective
Action, Operations,
Engineering,
Maintenance,
and Plant
Support were not addressed
during the in-office review phase.
The results
obtained
from the in-office review will be used
by the assessment
team to develop individual on-site
assessment
plans for each of the assessment
areas.
During the on-site review, the team will focus
on those
areas
rated
as
indeterminate
and those
where the inspection or performance
data record
indicated potential
performance
weaknesses.
The team will also validate the
elements that were assigned
decreased
or normal inspection ratings.
Following
the on-site
phase of assessment,
the team will issue
a final assessment
report.
1.0
SAFETY ASSESSMENT
AND CORRECTIVE ACTION
1.1
Problem Identification
The licensee's
programs for identifying equipment,
human performance,
and
plant program deficiencies
are the deviation/event
report
(DER) process,
the
quality assurance
(gA) audits,
and self-assessments.
These
programs,
in
general,
were effective in identifying problems at both units.
On the basis of evaluation of about
40 safety-significant deviation/event
reports
(DERs),
an
NRC team determined that the
DER process
was
an effective
tool for identifying significant issues,
and the threshold for initiating DERs
used
by station shift supervisors
and other parts of the organization
was
appropriate
(ref. I).
Thousands
of DERs were written at the facility each
year by all levels of the licensee
organization.
In the first quarter of
1995,
945
DERs were written, of which about
13X were significant
and about
2X
required root cause
evaluations
to be performed (ref. 2).
Self-assessments
by line organizations
were effective in identifying problems.
For example,
in maintenance,
a self-assessment
on instrumentation
and controls
(I8C) post-job critiques identified that improvements
in feedback
on job
performance
and attention to detail
were needed (ref. 2).
Also, inspection
reports
noted that recent
self-assessments
of human errors
conducted
by each
department
were thorough
and critical.
Designated
branches
presented
findings
to-other branch
managers for peer review, identified predominant
and secondary
causes,
and trended
human errors (ref. 3).
Independent
assessments
by safety review groups,
including the Independent
Safety Engineering
Group (ISEG)(for Unit 2 only), the Station Operations
Review Committee
(SORC),
and the Safety Review and Audit Board
(SRAB) were
effective.
They reviewed
a considerable
number of plant activities
and
reports
such
as
DERs, licensee
event reports
(LERs), safety evaluations
and
proposed modifications, industry events,
NRC generic correspondence,
inspection reports, quality assurance
audit reports,
and other licensee
generated
reports.
The review activities
and final recommendations
were well
documented
(refs. I and 5).
The gA audits performed
by the Nuclear guality Assurance
Branch
appeared
to be
of particularly good quality and of sufficient depth to identify both failures
to comply with applicable requirements
and areas for improvement in the
licensee
programs
and management
oversight of the facility.
The gA audits for
the following were broad in scope
and good in technical
depth: radioactive
liquid and gaseous
waste control
programs (ref. 7);
maintenance
program (ref.
2);
and surveillance of the
HOV program (ref. 8).
A combined utility assessment
group
(CUAG) performed
an independent'assessment
of the effectiveness
of the licensee's
gA program.
The
CUAG review appeared
thorough, identifying weaknesses
in follow-up of gA findings that resulted
in
changes
to gA audit procedures
for post-audit evaluation of findings by the
audit team
and tracking of recommendations.
by the
gA branch (ref. 9).
The
ISEG reports for 1994
and
1995 covered all the plant activities,
and
provided many useful observations
and recommendations
regarding analysis of
plant activities
and operating. experience.
For example,
the
ISEG performed
periodic reviews .of the maintenance activities at Unit 2 and
made
recommendations
to correct long standing
unresolved
problems with the service
water strainers
(ref. 45).
Normal inspection
in this area is recommended.
1.2
Problem Analysis
and Evaluation
The licensee's
performance
in problem analysis
and evaluation
appeared
to be
satisfactory,
though weaknesses
in. evaluating repetitive problems
and
DER
evaluation
were noted;
Root cause evaluations'for significant events or those
directed
by the plant management
appeared
to be properly conducted,
and the
quality and depth of the evaluation varied appropriately with the significance
of the issue.
In general,
the analysis
and disposition of DERs were
effective.
Examples of effective dispositions
included
an analysis to support
the Unit 2 high pressure
core spray uni.t cooler operability concern (ref. 15),
and the review of the safety-related
issues
related to intergranular stress
corrosion cracking of the reactor
core shroud at Unit
1 (ref. 38).
The.DERs
evaluated
by the Unit .2 operations
department
were noted to be consistently
excellent (ref. 1).
However, several
DERs documented repetitive problems
which indicated that evaluation-and
resolution of problems were not always
effective.
Examples of these
included loss of rod position indication at Unit
2 (ref. 15), repeated
repairs to the redundant reactivity control
system (ref.
14), missed Technical Specification surveillances for leak rate testing the
personnel
airlock and emergency airlock (ref. 32),
and not identifying and
replacing Unit
1 Agastat relays before they were severely
degraded
(ref. 3).
Trending and'valuation of the
DER program appeared
to be
an area
where
improvements
were necessary,
based on'ssues .identified by the licensee
in gA
Audits and
ISEG reports.
The DER.program trends the conditions that led to
the initiation of the
DER using industry established
causal
factor codes.
This information was periodically evaluated .by th'e quality assurance
department
and presented
to the branch
managers
to assess
performance
trends.
The licensee identified errors in cause identification, trend code
application,
and identification of preventive actions in the
DER system.
The
licensee
also concluded that continued
management
attention
was
needed
to
assure that problem causes
were fully identified and that preventive actions
address
these
problems (ref. 9).
An NRC team noted that the most prevalent
causal
factors continued to be work practice failures, i.e.,
documents
not
followed correctly and poor self-checking.
Further,
some
gA assessments
identified the need to improve the quality of apparent
and root cause
determinations
because
some
DERs did not adequately
account for human
performance factors,
and thus did not provide actions that would prevent
recurrence
of the'vents
were not performed '(ref. 1).
Overall performance
in problem analyses
and evaluation is indeterminate
pending the team's on-site
assessment.
1.3
Problem Resolution
The dispositioning of DERs was generally timely, and the
DER backlog
appeared
to be satisfactorily managed
at both units.
For example,
although thousands
of DERs were issued
each year,
the backlog
was decreasing.
Prioritization and
periodic review, of the
DER backlog
was appropriate
to ensure that significant
safety issues
were promptly dispositioned (ref. 1).
In general",
the licensee's
corrective actions to resolve
issues
were
effective.
However, corrective actions
taken in response
to poor
human
performance
problems
appeared
to be not effective,
as evidenced
by continued
personnel
performance
issues
in the Unit
1 reactor recirculation
pump runback
event (ref. 22), Unit 2 reactor trip during swapping of battery chargers
(ref.
12), failure to verify logic circuit for the auto transfer feature of the
power board at Unit
1 (ref. 23),
and other instances
described
in the other
sections of this report.
The information available to the team was not
sufficient to assess
the licensee's
performance
in the implementation of
recommendations
from assessments
and the effectiveness
of corrective actions.
Overall performance
in this area is indeterminate.
2. 0
OPERATIONS
2. 1
Safety
Focus
Generally,
the operators
and the operations
department
management
made
conservative
operational
decisions
and displayed
a conservative
approach to
operations of both Unit
1 and Unit 2.
Shift supervisors
directed
and
managed
plant scrams
and other plant transients well.
For example,
the Unit 2 shift
supervisor displayed
good
command
and control after the reactor recirculation
pumps tripped when the redundant reactivity control
system
was de-energized
for troubleshooting
(ref.
14)
and in response
to a high main turbine vibration
during
a unit shutdown (ref. 15).
The 'licensee
management
provided
good support to the operations staff during
a
forced shutdown at Unit 2 to address
various oper'ational
issues
(ref. 16).
Senior station
management
provided direction during the recovery
phase of a
partial loss of offsite power event
when Unit 2 was in cold shutdown (ref.
14).
Effective and significant management
involvement in the oversight of the
licensed operator requalification training program was noted (ref. 17).
4
Alth'ough, in general,
responses
to events
by both operators
and operations
department
management
were conservative,
in a few instances
the decisions
were
not.
In one case,
reviews performed
by the senior reactor operator
and
operations
planning personnel
did not identify the potential Technical
Specifications
(TS) implications of the erroneous
rod position indication
system.
This resulted
in the Unit
1 remote
shutdown
panel
being inoperable
during power operation (ref. 18).
In another instance,
a division of service
water system
was placed in service at Unit 2 without an operable radioactivity
monitor or appropriate
compensatory
action
as required
by the
TS (ref. 19).
Further, the licensee
management
decided to postpone repairing
a valve, which
was part of a reactor coolant system pressure
boundary,
during the Unit 2
third refueling outage.
Subsequently,
the unit was required to be shutdown
due to increased
reactor coolant system leakage
from the valve (ref. 20).
Normal inspection is recommended
in this area.
2.2
Problem Identification/Problem Resolution
Inspection reports
indicated that operators
were attentive to equipment
conditions
and identified problems.
For example:
during the performance of a
monthly test
on the liquid poison
system,
Unit
1 operators
identified and
corrected
a problem with the test equipment (ref. 5); Unit
1 operators
identified arcing
on the exciter end of 413 reactor recirculation
pump motor
generator
set while completing turbine rounds (ref. 21);
and operators
properly identified
a plant process
computer failure at Unit
1 (ref. 21).
These
issues
were appropriately
documented
in DERs.
Though problem identification by operations
personnel
was generally good,
a
few instances
were noted where the control
room, operators
did not identify
conspicuous
deficiencies.
Unit 2 control
room operators failed to notice that
(SRV) tail pipe temperature
recorder
had
been
because
of inadequate
monitoring of the recorder
by the operators
(ref. 14).
Also, the control
room operators
were not aware that the Unit
1
nitrogen tank low pressure
alarm did not come
on as designed
when the tank
remained
empty (ref.. 14)
and that one of the shutdown cooling system
temperature
control valves
was about
85X open instead of being shut during
power operations.
This condition was identified on. the control board
by an
NRC inspector
immediately following the operators'oard
walkdown during shift
turnover.
Subsequent
followup by the licensee identified that several
other
valves were out of position (ref. 13).
Throughout the period of review, the licensee
continued to experience
problems
attributed to operators'nvolvement
with the work control process.
During
the inspection of a reactor recirculation
pump
(RRP) runback event,
NRC
identified deficiencies
in operator review of the'ork order
and oversight of
the work (ref. 22).
A licensed operator misinterpreted
a procedure
step which
led to bearing
damage
on the Ill control rod drive pump (ref. 24).
Unit 2
lost shutdown cooling for fifteen minutes
due to an inadequate
review of a
markup (ref. 23).
The licensee
performance
in problem resolution,
and the
effectiveness
of corrective actions will be assessed
further on site.
Overall performance
in this area
was indeterminate.
2.3
guality of Operations
Numerous
examples of appropriate
operator
responses
to reactor
and
other plant transients
were noted.
For instance,
the operating
crew at Unit I
reacted
promptly and properly to a reactor
scram to minimize the transient
on
the plant (ref. 23).
Following the Unit I RRP runback event the operators
correctly assessed
plant conditions,
recognized
the low reactor core flow
conditions,
and reduced reactor
power level
away from the restricted
area of
the power-to-flow operating
map by inserting control rods (ref. 22).
The operators
generally demonstrated
adherence
to procedures,
displayed proper
communication,
followed effective self checking
and peer verification
techniques,
and demonstrated
a good questioning attitude.
Also, management
oversight created
a professional, efficient, safety-oriented
control
room
atmosphere.
The operations staff demonstrated
an excellent
knowledge of the
plant systems,
operating procedures,
and current plant status.
Shift
turnovers
and briefs, with few exceptions,
provided sufficient detail to
maintain proper continuity during ongoing evolutions
and to keep the
operations
crew knowledgeable
of current plant issues/problems
and upcoming
evolutions.
During special
evolutions,
systems
engineering staff and/or
operations staff provided
a technical brief and senior plant management
provided expectations
for the conduct of the evolution (ref. 25).
However, there were instances
of operator
performance that were not
satisfactory.
Examples include: Unit I reactor operators
had not performed
required voltage checks
across
an auto transfer logic circuit in accordance
with operating
procedures
which required additional operator actions to
restore reactor pressure
and water level following a reactor trip (ref. 23);
Unit I reactor operator did not properly position the reactor
mode switch
after
a reactor
scram (ref. 23); suppression
chamber
spray
mode of the
residual
heat
removal
system loop "A" at Unit 2 was disabled
because
the
reactor operator did not review the field copy to verify that each individual
valve had
been returned to the correct position (ref. 14);
and Unit 2 operator
inadvertently de-energized
an emergency
DC bus,
causing
both reactor
recirculation
pumps to trip (ref. 12).
In addition, the following examples of weaknesses
in operations
involvement
with the work control process
were noted:
inadequate
work order review and
control
room communication
which were partly responsible for Unit I
recirculation
pump runback
and turbine trip (ref. 22);
misinterpretation of a
procedure
step which led to bearing
damage
on the Ill control rod drive pump
(ref. 24);
lack of control
room operations
oversight at Unit I contributed to
a reactor
scram during performance of a surveillance
procedure
by maintenance
(ref. 41); loss of shutdown cooling at Unit 2 for fifteen minutes
due to an
inadequate
review of a markup (ref. 23);
and maintenance
was inappropriately
authorized
on two control rod hydraulic control units simultaneously
instead
of sequentially,
resulting in operations. failing to comply with a technical
specification action statement
at Unjt. 2 (ref. 26).
Normal inspection is recommended
in this area.
2.4
Programs
and Procedures
I
The licensee
had established
an effective operator training program.
For
example:
the training of the on-shift licensed
operators
was effective in
mitigating the consequences
of the recirculation
pumps runback event (ref.
22); senior reactor operator
(SRO)'and Unit
1 reactor operator applicants
exhibited very good performan'ce
during all parts of the examination with few
generic
weaknesses
(ref. 27); Unit 2
SRO applicant
crew briefs were complete
and concise,
and
command
and control
was strong (ref. 28).
There were examples. of inadequate
procedures
or inadequate
use of procedures
which have led to some errors
and operational
'events.
These included:
use of
a procedure that did not incorporate the.correct
system configuration led to
a
resin spill at Unit
1 (ref. 6); loss of .Unit 2 reactor recirculation
pumps
during
a reactor startup
and mispositioning Unit 2 suppression
pool spray
valve due to procedure
weaknesses
or inadequacies
(ref. 14);
and not
performing
TS surveillances
on 'primary containment isolation valves
because
operations
department
surveillance
procedure
was not updated (ref. 15).
Overall performance
in this area
was indeterminate,
pending further on-site
review of procedure
adequacy
and:usage.
3.0
ENGINEERING
3.1
Safety
Focus
The licensee's
engineering
management,
and engineering staff had established
a
go'od safety perspective
as demonstrated
by the thorough
and technically
accurate operability evaluations of plant issues.
Examples of conditions that
were evaluated
properly by engineering to determine that the plant could be
safely operated
included the following: core spray sparger rejectable
crack
indication at Unit
1 (ref. 12); incorrect fuse installation in Unit 2 reactor
protection
system (ref. 14);
and elevated
temperatures
at the termination
points
and fuses inside control
room panels
at Unit
1 (ref. 29).
The successful
implementation of the hardened
wetwell vent modification at
Unit
1 (ref. 30)
and the station blackout
(SBO) rule at Unit 2 (ref. 4)
demonstrated
management's
involvement in engineering activities.,
Although engineering activities were. performed well,
a few weaknesses
as
a
result. of inadequate
review or inattention
by management
were noted.
Examples
of such weaknesses
were:
NRC identified programmatic
weaknesses
in the Unit 2
Appendix J program
and Generic Letter (GL) 89-10 motor operated
valve
(HOV)
program (refs.
8 and 23);
and de'letion of the licensee's
commitment to install
R.G.
1.97 Category
1 instrumentation for drywell water level at Unit
1 without
proper review (ref. 32).
Normal inspection is recommended
in this area.
3.2
. Problem Identification/Problem Resolution
The engineering staff, in general,
were effective in identifying problems.
Specific. examples
included the following: the process
computer indication of
feedwater flow at Unit
1 was not consistent
with design calculations resulting
in operation at above the rated core thermal
power limit (ref. 15); the
reactor building integrity was not maintained at Unit
1 because
a secondary
containment
bypass flow path
was not accounted
for (refs.
16 and 33);
and part
of the control rod drive flow was'ot included in the heat balance
and core
thermal
power calculations resulting in operation
above Unit 2 rated core
thermal
power limit (refs.
3 and 34).
However, there were
a few examples
where the engineering staff failed to
identify plant issues
on
a proactive basis.
Examples of these
weaknesses
included the following:
Unit 2 emergency diesel
generators
(EDGs)
had
operated
outside their design basis
since initial plant startup
as
a result of
the inadequate
design of the governor cooling water system (ref. 12);
and
during the power ascension
testing associated
with the Unit 2 power uprate,
the reactor
had to be manually scrammed
because
of low flow to the stator
cool.ing heat
exchanger
because
of an inadequate
design review (ref. 10).
The licensee
implemented
a self-assessment
program to determine the
performance of nuclear engineering
and technical
support groups
and to
identify strengths
and weaknesses
of these
groups.
A review of Unit 2
DER
self-assessment
trends for the period July-September
1995 indicated. that. the
design configuration
and analysis
weaknesses
were the most frequent.
The
NRC
inspection reports
noted that the licensee's
self-assessments
of the
electrical distribution system
and the
SBO rule implementation
program at Unit
2 were comprehensive
and of high quality (ref. 4).
The gA audits of the
design. control
and configuration management
program were thorough (refs. Il,
29 and 35).
The
ISEG performed
adequate
oversight activities of the
licensee's
design
change
process
at Unit 2 (refs.
36 and 37).
In general,
the licensee's
engineering staff thoroughly evaluated
the
identified issues
and provided adequate
technical
support for resolving them.
For example:
ap analysis to resolve the Unit 2 high pressure
core spray system
switchgear unit cooler operability concern
was performed promptly (ref. 15);
safety-related
issues
related to intergranular stress
corrosion cracking of
the reactor core shroud at Unit
1 were thoroughly reviewed (ref. 38); steps
were initiated to improve the performance of Unit 2 service water system
and
to resolve deficiencies identified in a self-assessment
(ref. 15);
and issues
from the electrical distribution system functional inspection
(EDSFI) were
thoroughly evaluated
and corrective actions
were implemented (ref. 40).
However,
weaknesses
in the ability of the licensee's
engineering staff to
resolve plant problems effectively were noted.
The engineering staff was slow
in resolving the longstanding
problem of electrical
noise interference with
the Unit
1 neutron monitoring system (ref. 11).
The licensee's
corrective
actions in response
to operational
experiences
regarding Agastat
GP relay
failures
and potential
problems in using commercial-grade
7000 series
agastat
relays at Unit
1 were inadequate
(ref. 3).
Normal inspection is recommended
in this area.
3.3
guality of Engineering
Work
Both the engineering
and technical
support personnel
generally performed their
functions well and adequately
resolved plant problems.
Plant modifications
and calculations
were technically sound
and properly documented.
The safety
evaluations,
design input,
and technical
reviews were thorough (refs.
10, ll
and 35).
Good engineering
performance
was evident in the following: the
battery capacity
and effect of loss of ventilation calculations,
and safety
evaluations for Unit 2
SBO implementation (ref. 4); analysis for NRC
supplemental
information related to potential
problems with the
BWR water
level instrumentation (ref. 32);
and
APRH alarm and rod b1ock modification and
post-modification testing for Unit 2 (ref. 24).
However,
a few examples of less
than adequate
engineering
support were noted.
Examples of these
weaknesses
included the following: ineffective coordination
of Unit
1 hydrogen
and oxygen monitoring system modification that required
a
second modification to make the system functional.(ref. 35); ineffective
design
change for Unit 2 service water check valve replacement
that required
a
second
valve design
and replacement
(ref. 3);
and inadequate
consideration
of
system interactions for the modification to correct the Unit 2 'scram discharge
volume
(SDV) high-level alarm and control rod block signal that required
another modification to correct the problem (ref. 14);
and inadequate
evaluation of pressure
locking and thermal binding of NOVs resulting in not
identifying two risk significant Unit 2 high pressure
core spray system
which were susceptible
to pressure
locking (ref. 18).
Normal inspection is recommended
in this area.
3.4
Programs
and Procedures
The licensee effectively implemented
several
engineering
programs at both
units.
Examples
included:
a program to monitor the corrosion of the Unit I
torus
and the corrosion residue
on containment
and core spray components
(ref.
ll); an acceptable
program for implementing the
SBO rule at Unit 2 (ref. 4);
a
comprehensive
design-basis
reconstitution
program at Unit
1 (ref. 29);
a
comprehensive
and effective training program for the engineering
and technical
support staff at both units (ref. 35);
a program to simplify and upgrade
the
engineering
procedures
at both units (ref. 29);
and
a good like-in-kind
replacement
program for component
replacements
(ref. 35).
The plant
modification procedures
at both units provided detailed guidance to ensure
that plant modifications were designed
and implemented
in a safe
and
controlled manner (ref. 35).
However,
programmatic
weaknesses
were identified in a few engineering
programs.
For example,
the
NRC identified several
weaknesses
in the
motor operated
valve
(HOV) program at both units because
of inadequate
engineering justification and review (ref. 8).
Weaknesses
were also
identified in the implementing procedures
for the Appendix J program
and in
the surveillance
procedures
and their implementation for valves in the
inservice testing
(IST) program at Unit 2 (refs.
23 and 42).
Overall performance
in this area is indeterminate,
pending further review of
engineering
programs
and procedures.
4. 0
MAINTENANCE
4.1
Safety
Focus
The performance of maintenance
during the outages
at both units indicated
significant licensee
management
attention to the oversight of refueling
and
maintenance
outage planning.
Unplanned
outage delays
were minimized, backlog
of work orders
were reduced,
and outage
schedules
were adhered to.
The
licensee
met the pre-outage
goals for outage duration, radiation exposure,
industrial safety,
and contamination control.
The Unit
1 reactor core shroud
modificatio'ns were completed without any major difficulties, and maintenance
performance
and licensee
oversight of contractor activities were noted
as
satisfactory (ref. 12).
Though the reactor fuel vendor for Unit
1 had not
recommended
additional
inspections,
the licensee
was proactive in inspecting
all
new
GE ll fuel assembly
lower tie plates for possible debris
(machine
shavings)
because
GE 9 fuel assemblies
being fabricated for another utility
were reported to have
had debris
problems (ref. 44).
Although the licensee
management prioritized and completed
work to ensure
appropriate
safety equipment
performance
and reliability (ref. 35), instances
were noted where equipment
problems
were not effectively resolved.
Repetitive
and continuing control rod position indication problems at Unit 2 were not
aggressively
pursued (ref. 15).
The redundant reactivity control
system at
Unit 2 failed and was declared
each time after repair,
because
the
root causes
and long-term solution were not determined until numerous failures
occurred (ref. 14).
Pre-job briefings generally were adequate,
however, for
repetitive work that was successfully
performed previously, briefings were not
adequate
as evidenced
by the unintentional
RRP runback incident at Unit
1
(ref. 22).
Normal inspection
in this area is recommended.
4.2
Problem Identification/Problem Resolution
The .licensee's
maintenance
department,
theISEG,
and
gA organizations
identified maintenance
related
problems through the use of the
DER process.
For example, electricians
at Unit 2 wrote
DERs to correct environmental
qualification discrepancies
noted
on solenoid operated
containment isolation
valves.
Thorough followup by the licensee
was evidenced
by inspection of all
similar valves, operability determinations,
and consultation with the vendor
(ref. 24).
The licensee
monitored
an increasing
trend in the Unit 2 emergency
diesel
generator start time, identified problems with the air starting
system,
and replaced
the system
components
to correct the problems (ref. 3).
The
licensee
management
promptly. resolved
problems with the master
power
10
connecting rod.on the Unit 2 emergency diesel
generators
after receipt of
vendor notification of the defect (ref. 16).
During a review of a completed preventive maintenance activity, gA identified
non safety-related
electrical
contacts
being
used in safety-related
applications.
This was promptly 'corrected
(ref. 21).
Also,
gA audits
identified and required the correction of deficiencies
in the implementation
and documentation of the
TS snubber examinations,
which were resolved
by the
licensee
through
a series of corrective actions (ref. 49).
Periodic reviews
of the maintenance activities at Unit'
were performed
by the
ISEG, including
review of maintenance
related
DERs, review'of hardware
problems,
assessment
of
work,packages,
and observation
of, ongoing'aintenance
work.
ISEG provided
recommendations
for resolving noted problems.
The licensee's
performance
in resolution of long standing
and repetitive
problems
was less
than adequate
in the following examples:
the loss of rod
position indication at Unit 2 (ref.
15)
and personnel
er'rors resulting in
missed
TS surveillances
(ref. 32).
Resolution of identified problems,
and
comprehensiveness
and tracking of corrective actions require further review.
Overall performance
in this area is indet'erminate,
4.3
Equipment Performance/Material
Condition
Equipment performance
problems
were identified such as,
inadequate
cooling of
Unit 2 emergency diesel
generator-governor
{ref. 12),
recombiners
at Unit 2 due to obstruction in its flow path (ref. 46)
and
excessive
wear of the backwash
arm assembly of the service water self-cleaning
strainer at Unit 2 (ref. 45):
The licensee
implemented corrective actions to
resolve these. problems.
Equipment performance
and mater'ial condition problems
had caused
reactor
trips, forced shutdowns,
or plant transients
at both units.
Examples at Unit
I included electrical
noise in intermediate
range monitors (ref. 47),
steam
leaks in reheater
drain tank manway (ref. 23),
and failure of generator
protective relay (ref. 48).
Examples at Unit 2 included nitrogen leak from a
solenoid valve in drywell (ref. 25),
a switch failure in the turbine generator
electro hydraulic control system (ref. 25),
and inoperability of both
because
of governor oil temperature
concerns (ref. 12).
Overall performance
in this area is. indeterminate,
pending the team's on-site
review equipment
p'erformance
and maintenance .history.
4.4
guality of Maintenance
Work
Maintenance
work practices,,communications,
direction
and control,
and
personnel
knowledge contributed to achieving pre-outage
goals during the
outages
at both units (refs.
2 and 23).
Examples of well planned
and executed
maintenance activities with good pre-job briefings, coordination,
supervisory
oversight,
and
ALARA considerations
were: Unit I reactor core shroud
modifications (ref.. 38); repairs to Unit I main steam line break temperature
switches (ref. 10); Unit 2 service water
pump discharge
check valve repairs
(ref. 24); installation of spent fuel racks in Unit
1 (ref. 24);
and
replacement
of the valve body of the solenoid-operated
pilot air supply
isolation valve at Unit 2 (ref. 21).
Post-outage
critiques identified such
areas for improvement
as,
planning,
implementation,
and outage oversight to
strengthen
the outage
process. for future outages
(ref. 23).
However,
a few examples of poor work practices
and inadequate
self-checking
and peer verification were identified.
These included:
catch containments
under leaking valves in Unit
1 were allowed to remain in place without active
work orders or assigned
problem identification numbe'rs (ref.,3); deficient
pre-job briefing, not following work order, lack of independent verification,
and deficient control
room communication during reactor recirculation
pump
controller mai'ntenance
at Unit
1 that caused
a plant transient (ref. 22); poor
work practices that allowed metal filings, grinding wheel dust,
and excessive
lubricant to remain in tubing during replacement
of flexible pneumatic
supply
lines to pilot solenoid valves
on safety relief valves (ref. 39);
and
fasteners
on environmentally qualified covers
on solenoid valves were missing,
loose,
or of the wrong type (ref. '24).
Normal inspection is recommended
in this area.
4.5
Programs
and Procedures
In general,
work orders,
maintenance
procedures,
and surveillance
procedures
were noted to be adequate
for the associated
activities.
Safety-related
work
packages
appropriately
documented
the work including proper verifications
and
material control (ref. 15).
Weaknesses
in procedure quality were noted in the inspection reports.
The
surveillance test procedure for reactor water level high/low level inputs to
the reactor protection
system at Unit
1 was poorly written and
cumbersome
to
use (ref. 21).
The program for Unit 2 emergency diesel
generator
governor oil
changeout
did not identify operating temperature limits and did not
incorporate. vendor recommendations
(ref.
12 and 50).
Personnel
errors
associated
with Unit
1 reactor recirculation
pump controller maintenance
were
caused,
in part,
by work order development
process
deficiencies
in format,
detail, direction, precautions,
and sequence/order
(ref. 22).
The licensee's
maintenance
programs
and procedures will be further examined during the on-
site assessment.
The licensee
performance
in this area is indeterminate.
5.0
PLANT SUPPORT
5.1
Safety
Focus
5. 1. 1
Radiological'Controls
The licensee
management
consistently
placed strong
emphasis
on improving the
material condition of the plant by actively reducing contaminated
areas.
This
enhanced
the general
working conditions for the plant staff and allowed easy
access
to* plant, areas
(refs.
2, 5,
10,
and 51).
The performance
in the
12
radiological controls
area continued to be generally strong
and met the
comprehensive
site radiation goals.
The radiological. exposure
goals at both
units were met or exceeded
(refs.
44 and 52).
The recent
outages
in both
units were well planned
and managed,
and were indicative of good communication
and cooperation
among the operations,
crafts,
and radiation controls staff
(refs.
5 and 54).
Reduced
inspection
in this area is recommended.
5.1.2
Secur ity
The'licensee
management
continued to provide strong support to the physical
security program at the site.
A Commitment to Excellence
Program
(CEP)
was
implemented
by the licensee to enhance
security performance.
Since February
1994, monthly management
CEP audits were performed in which different aspects
of the overall security program were evaluated
and analyzed
as to the adequacy
of the program.
Observations
and recommendations
were written and security
work requests
initiated.
These monthly audits further look for adverse
trends
or repeat
problems.
Although no safety issues
were identified in the licensee
reports,
NRC inspectors
noted that the licensee
should consider whether normal
security measures
or identified deviation reports
had
any impact on, station or
personnel
safety (ref. 56).
Reduced
inspection in this area is recommended.
5. 1.3
Emergency
Preparedness
The licensee
performed the required
emergency
preparedness
(EP) drills and
exercises
to demonstrate
the ability to protect the health
and safety of the
public by taking appropriate
actions to mitigate the effects of postulated
emergency
events
on the surrounding population.
The licensee
management
involvement
and proper safety focus were observed
as evidenced
by management's
involvement in
EP drill critiques (ref. 15).
However, during an exercise
in October
1994, the emergency
event
was
incorrectly classified
on the basis of an .erroneous
dose projection
calculation (ref. 15).
A failure to properly evaluate plant conditions
and to
recognize
and properly classify the emergency
event during the October
1995
exercise
was cited by the
NRC as
a violation.
This was
a further indication
of the. need for additional licensee
management
attention to the
EP program
(ref. 3).
The licensee's
emergency
response facilities were found to be well equipped
and consistent with facility descriptions
in the site emergency
plan.
Overall
these facilities were in very good operational
cohdition.
However,
two
portable air samplers
in the emergency
operational .facility (EOF) were found
to be out of calibration (ref. 57)
This was corrected
immediately
and
no
repeat
occurrences
were observed (ref. 15).
Normal inspection in this area is recommended.
13
5.2
Problem Identification/Problem Resolution
5.2. I
Radiological Controls
The gA audit programs for all areas of the radiological controls program
and
self-assessments
and surveillances
were thorough,
and incorporated
proper
technical
focus
and level of detail (refs.
7,
58,
and 59).
The licensee's
refueling outage reports
were good examples of the licensee's
thorough
and
self-critical assessments.
These reports describe
successes,
and note areas
needing
improvement in
a comprehensive,
detailed
manner (ref. 59).
Licensee
self-assessment
results
documented
in the
DER process,
continued to
report events
where contract, craft,
and operations
personnel
had not adhered
to site radiological
work controls procedures
and practices.
Examples
included failure to comply with radiation work permit
(RWP) requirements
and
failure to communicate properly and fully with the assigned
health physics
technicians
(ref. 51).
In addition,
the licensee
had identified minor issues
involving the performance of the radiation protection department
(ref. 60).
In response
to the above repetitive personnel
problems,
the licensee
had
increased
worker training, audits,
and surveillances.
The licensee
had taken
appropriate
short-term corrective actions to resolve
access
control problems,
and long-term corrective actions
were in progress
(ref. 51).
Reduced
inspection in'his area is recommended.
5.2.2
Security
The licensee
gA audits
were conducted within the time frame required
by
commitments,
and covered the security program, fitness-for-duty program,
and
safeguards
information controls.
The audit reports identified
a number of
inconsistencies
in the security plan
and procedures,
security systems,
training of security staff, fitness for duty program
and access
authorization
program concerning
adequacy,
and implementation of plan or procedure
commitments.
However, the security, fitness-for-'duty,
and access
authorization
programs
were determined
by the
NRC to be effectively
implemented
and in compliance with regulatory requirements.
None of the
findings appeared
to be programmatic
weaknesses
(ref. 56).
The licensee
issued
DERs for weaknesses
identified by audits
and took prompt
corrective actions that prevented repetition of these
problems.
Several
security personnel
were formally trained in root-cause
analysis,
and the
licensee
planned to use
them to conduct analysis of security issues
(ref. 56).
Reduced
inspection is recommended
in this area.
14
5.2.3
Emergency
Preparedness
The licensee's
critique process,
observation .and evaluation of performance
during an
EP drill'n August 1995,
and assessment
of the October
1995 exercise
were determined to be thorough
and critical (refs.
3 and 15).
The licensee's
quality assurance
organization
audited the emergency
preparedness
program.
These audits were thorough
and identified. such concerns
as',
weaknesses
in the
training program, failure to follow administrative
procedure
guidance,
out of
date procedures,
and missed or incomplete documentation of surveillances
(ref.
61).
Emergency
preparedness
drill or exercise'weaknesses
were prioritized and
assigned
to individuals for resolution,
and were tracked.
These
items were
generally completed within the prescribed
time period (refs.
15 and 57).
Most of the open findings from previous
NRC inspections
were resolved
by the
licensee
and were closed in subsequent
inspections
(ref.
13,
15
,
and 57).
Normal inspection
in this area is recommended.
5.3
equality of Plant Support
5.3. 1
Radiological
Controls
The radiological protection
program provided effective job coverage
and
support during normal operation
as well as during plant outages.
The licensee
initiated
a new, user, friendly, radiation work permit
(RWP) process
(ref. 2).
Especially noteworthy was the highly effective radiological
support for the
Unit
1 reactor core shroud inspection
and repair work (ref. 53).
The external
and internal
dose control programs. w'ere strong.
Some
examples
included:
reducing the number of respirators
used
from greater
than 3000 in 1993 to 54
in 1994
as
a result of the implementation of the revised
and
the installation of closed circuit television
cameras
throughout the site to
remotely view high radiation areas
(ref. 44).
The use of local, close-capture
portable
HEPA filtration units was another
good example of the high quality
support provided to minimize workers'ntakes
by maintaining work area
airborne radioactivity levels
ALARA (ref. 60).
The licensee
supported
radiation protection. technician continuing training program
and provided
continued professional
devel.opment for the health physics
management staff.
One instance of a failure to properly survey
and evaluate
the need for posting
and controlling
a high radiation area in the Unit
1 old radwaste building
resulted
in a violation (ref. 54).
No recurrences
were noted during the
assessment
period.
I
Normal inspection effort in this area is recommen'ded.
5.3.2 Security
The licensee
was properly implementing the physical security plan
and
procedures.
The protected
area
and vital area barriers
were well maintained,
access
control for protected
and vital areas
were in accordance
with
procedures,
security posts
were adequately
staffed
and equipped,
fitness-for-
15
duty program was being
implemented properly, intrusion detection
systems
were
tested without deficiencies,
and personnel
were complying with the security
plan
and procedures
(refs.
32 and 56).
The
NRC conducted
an Operational
Safeguards
Response
Evaluation
(OSRE) during
October .1995, to determine the licensee's a";lity to respond to an external
threat.
The
OSRE team determined that the licensee security force
demonstrated
effective contingency
response
capabilities
based
on observations
during drills at site.
An NRC special
inspection
was conducted to verify corrective actions for
previously identified weaknesses
i.n the areas of maintenance
of security
equipment,
compensatory
measures,
training and qualification,
and access
control.
Malfunctioning equipment
was corrected
in a timely manner,
and
no
deficiencies
in compensatory
measures
were .noted.
Examination of a random
selection of records
indicated that all training and qualification information
was properly documented.
The
NRC noted that the licensee
needed to improve on
the consistency
and frequency of contingency drills.
In addition,
performance
testing of protected
area
access
con.rol
equipment
and intrusion detection
systems
were conducted,
and assessment
capabilities
and contingency
responses
were evaluated for their effectiveness.
The testing detected
no
vulnerabilities except in contingency drills (ref. 63).
Weaknesses
in the performance of security functions,
such
as unintentional
disclosure of safeguards
information in a public document (ref.
63 and 64)
and
a third instance
since August
1993 of a visitor entering the protected
area
without a proper escort (ref. 24), were identified.
The licensee
implemented
appropriate corrective actions (ref. 16).
Normal inspection is recommended
in this area.
5.3.3
Emergency
Preparedness
During the October
1995 exercise,
the licensee's
staff did not properly
evaluate plant conditions
and did not recognize
and properly classify the
emergency
event.
NRC issued
a notice of violation for licensee's
performance
during this exercise.
Also, problems
noted during the previous exercise
in
October
1994 indicated
a weakness
in the ability to accurately classify
emergency
events.
A communications
aide did not activate the pager
system
when the exercise
event escalated
to the alert level (ref. 13).
The control
of secondary
responder training, the adequacy of emergency director training
on dose
assessment
and protective action recommendations,
and the practice of
considering drill observation
as equivalent to drill participation
as
a
training event were assessed
as potential
weaknesses
(ref. 57).
Increased
inspection in this area is recommended.
16
5.4
Programs
and Procedures
5.4. 1
Radiological Controls
The licensee
had established
effluent and environmental
controls programs,
with detailed,
well written procedures
and supported
by a comprehensive
site
laboratory
gA/gC program (ref. 7, 62,
65,
and 66).
The offsite dose
calculation
manual
was well written and very detailed (ref. 66)., The radwaste
and transportation
programs at both units were judged to be well implemented,
and contained effective training
programs (ref. 69).
The licensee
properly
and effectively implemented
and integrated
the revised
requirements
into the site health .physics
programs (ref. 67).
Reduced
inspection in this area is recommended.
5.4.2
Security
The licensee's
security plan
and procedures
were in compliance with regulatory
requirements.
The licensee
security staff were trained in accordance
with
training and qualification plans
and
implemented security procedures
appropriately (ref.
55 and 56).
The fitness-for-duty program met the
established
policies
and procedures
(ref. 56).
Reduced
inspection in this area is recommended.
5.4.3
Emergency
Preparedness
The emergency
plan
and implementing procedures
were,
in general,
being
effectively implemented (ref. 57).
Procedures
have
been revised to eliminate
redundant
or. unnecessary
information and steps (ref. 57).
The licensee
revised the emergency
action levels
(EALs) to incorporate
the methodology
specified in NUMARC/NESP-007,
"Methodology for Development of Emergency Action
Levels."
Training on the
new EALs including table top exercises
was
considered
useful (ref. 10).
Due to an over sight, the licensee's
quality
assurance
audit for 1994 was not made available to state
and local officials
as required.
It was later provided to them,
and administrative
procedures
were changed to correct this over sight (ref. 57).
Normal inspection in this area is recommended.
17
'I
APPENDIX A
List of References
l.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.-
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
41.
42.
43.
44.
45.
and 50-410/94-27
and 50-410/95-13
and 50-410/95-24
and 50-410/95-12
and 50-410/94-15
and 50-410/95-22
and 50-410/95-11
and 50-410/95-16
50-410/93-99
and 50-410/95-01
and 50-410/94-23
and 50-410/95-23
and 50-410/95-18
and 50-410/94-29
and 50-410/94-11
and 50-410/95-80
and 50-410/95-03
and 50'-410/94-18
and 50-410/94-05
and 50-410/94-06
and 50-410/95-02
and 50-410/94-31
and 50-410/94-07
and 50-.410/94-20
and 50-410/94-05
and 50-410/94-22
and 50-410/94/14
and 50-410/94-32
A-1
NRC Inspection
Reports
50-220/94-23
NRC Inspection
Reports
50-220/95-13
NRC Inspection
Reports
50-220/95-24
NRC Inspection
Report 50-410/95-07
NRC Inspection
Reports
50-220/95-12
NRC Inspection
Reports
50-220/94-13
NRC Inspection
Reports
50-220/95-22
NRC Inspection
Reports
50-220/95-11
NMPC NgA Audit No.
94017
NRC Inspection
Reports
50-220/95-16
NRC SALP Report
No. 50-220/93/99
and
NRC Inspection
Reports
50-220/95-01
NRC Inspection
Reports
50-220/94-21
NRC Inspection
Reports
50-220/95-23'RC
Inspection
Reports
50-220/95-18
NRC Inspection
Reports
50-220/94-26
NRC Inspection
Report 50-410/94-26
Unit
1 Licensee
Event Report 95-001
Unit 2 Licensee
Event Report 95-004
Unit 2 Licensee
Event Report 94-007
NRC Inspection
Reports
50-220/94-09
NRC Inspection
Reports
50-220/95-80
NRC Inspection
Reports
50-220/95-03
NRC Inspection
Reports
50-220/94-16
NRC Inspection
Reports
50-220/94-05
Unit 2 Licensee
Event Report 94-006
NRC Inspection
Report 50-220/94-25
NRC Inspection
Report 50-410/94-10
NRC Inspection
Reports
50-220/94-06
NRC Inspection
Reports
50-220/95-.02
NRC Inspection
Reports
50-220/94-28
NRC Inspection
Reports
50-220/94-07
Unit
1 Licensee
Event Report 94-006
Unit 2 Licensee
Event Report 95-011
NRC Inspection
Reports
50-220/94-18
ISEG Report
No. 89461
NMPC ISEG Report
No. 89479
NRC Inspection
Report 50-220/95-09
.
NRC Inspection
Reports
50-220/94-05
NRC Inspection
Reports
50-220/94-20
Unit
1
LER 94-007
NRC Inspection
Reports
50-220/94-12
Unit 2 Licensee
Event Report 94-003
NRC Inspection
Reports
50-220/94-29
ISEG Report
No. 89476
46.
Unit 2 Licensee
Event Report 95-009
47.
Unit
1 Licensee
Event Report 94-004
48.
Unit
1 Licensee
Event Report 95-002
49.
NRC Inspection
Report 50-410/94-09
50.
Unit 2 Licensee
Event Report 95-002
51.
NRC Inspection
Reports
50-220/95-10
52.
NRC Inspection
Reports
50-'220/95-04
53.
NRC Inspection
Reports .50-220/95-08
54.
NRC Inspection .Reports
50-220/94-11
55.
NRC Inspection
Reports
50-220/94-'01
56.
NRC Inspection
Reports 50-220/95-14
57.
NRC Inspection. Reports
50-. 220/94-15
58.
NRC Inspection
Reports
50-220/95-20
59.
NRC Inspection
Reports
50-.220/94-04
60.
NRC Inspection
Reports
50-220/94-19
61.
NMPC NgA Audit No.95010
62.
. NRC Inspection
Reports
50-220/94-17
63.
NRC Inspection
Reports
50-220/94-27
64.
Licensee
Event Report
94-.SOI
65.
NRC Inspection
Reports
50-220/95-17
66.
NRC Inspection
Reports
50-220/94-08
67.
NRC Inspection
Reports
50-220/94-24
68.
NMPC NgA Audit No. 95017
69.
NRC Inspection
Reports
50-220/94-16
and 50-410/95-10
and 50-410/95-04
and 50-410/95-08
and 50-410/94-13
and 50-410/94-01
and 50-410/95-14
and 50-410/94-17
and 50-410/95-20
and 50-410/94-04
and 50-410/94-21
and 50-410/94-19
and 50-410/94-30
and 50-410/95-17
and 50-410/94-08
and 50-410/94-28
and 50-410/94-18
A-2
NINE MILE POIN
UNITS
1 AND 2
PRELIMINARYPERFORMANCE ASSESSMENT/INSPECTION PLANNING TREE
1.0
SAFETY
ASSESSMENT/
CORRECTIVE
ACTION
2.0
OPERATIONS
3.0
ENGINEERING
4.0
MAINTENANCE
5.0
PLANT
SUPPORT
SAFETY FOCUS
3.1
SAFETY FOCUS
SAFETY FOCUS
5.1
SAFETY FOCUS
1.2
PROBLEM
IDENTIFICATION
2.2
PROBLEM
IDENTIFICATION Y
PROBLEM
RESOLUTION
Y
3.2
PROBLEM
IDENTIFICATION N
PROBLEM
RESOLUTION
N
PROBLEM
IDENTIFICATION Y
PROBLEM
RESOLUTION
RC
SEC
G
G
N
5.2
PROBLEM
IDENTIFICATION
PROBLEM
RESOLUTION
PROBLEM
ANALYSIS
AND
EVALUATION
Y
QUALITY OF
OPERATIONS
3.3
QUALITY OF
ENGINEERING
WORK
EQUIP PERF/
MATL COND
RC
SEC
G
G
N
QUALITY OF
1.3
PROBLEM
RESOLUTION
2.4
PROGRAMS
AND
PROCEDURES
Y
3.4
PROGRAMS
AND
PROCEDURES
Y
4.4
QUALITY OF
MAINTENANCE
WORK
RC
SEC
N
N
B
O
REDUCED
INSPECTION
O
MAINTAIN
INSPECTION
O
INCREASED
INSPECTION
O
INDETERMINATE-MORE
INSPECTION REQUIRED
4.5
PROGRAMS
AND
PROCEDURES
Y
5.4
PROG & PROC
RC
SEC
G
G
N
f'