ML17312A792
| ML17312A792 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 05/28/1996 |
| From: | Vandenburgh C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17312A791 | List: |
| References | |
| 50-528-96-01, 50-528-96-1, 50-529-96-01, 50-529-96-1, 50-530-96-01, 50-530-96-1, NUDOCS 9606030182 | |
| Download: ML17312A792 (42) | |
See also: IR 05000528/1996001
Text
ENCLOSURE
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-528/96-01
50-529/96-01
50-530/96-01
Licenses:
NPF-51
Licensee:
Arizona Public Service
Company
P.O.
Box 53999
Phoenix.
Facility Name:
Palo Verde Nuclear Generating Station,
Units 1, 2,
and
3
Inspection At:
Maricopa County. Arizona
Inspection
Conducted:
March 4-8 and April 22-26 '996
Inspectors:
Linda Joy Smith, Reactor
Inspector.
Engineering
Branch
Division of Reactor Safety
Chris Myers.
Reactor
Inspector.
Engineering
Branch
Division of Reactor Safety
Approved:
res
.
an en urg
,
e
,
ngineering
rane
Division of Reactor
Sa
y
a
e
Ins ection
Summar
Areas
Ins ected
Units
1
2
and
3
Routine,
announced
inspection of the
licensee's
self-assessment
.effort related to engineering
and corrective
action.
Results
Units
1
Z
and 3
~
The inspectors
determined that
a qualified self-assessment
team
conducted
an independent
and objective assessment
of the licensee's
engineering
and corrective action programs
(Section 1.1.2).
9606030182
960529
ADOCK 05000528
~ .
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The inspectors
found the scope
and depth of the self assessment
to be
ambitious
and sufficient to satisfy all the inspection
requirements of
NRC Inspection
Procedures
37550.
"Engineering,"
and 40500,
"Effectiveness of Licensee Controls in Identifying, Resolving.
and
Preventing
Problems"
(Sections
2. 1.2 and 2.2.2).
The inspectors
concluded that, with some minor exceptions,
the
self-assessment
team had appropriately identified and dispositioned
problem areas
and potential
weaknesses.
Neither the licensee's
self-assessment
team nor the inspectors
identified inoperable
equipment
(Sections 2.3.2 and 4.2.6).
The self-assessment
team concluded that the material condition of the
diesel
generators
and selected
important-to-safety
systems
was generally
good and that these
systems
were fully capable of
performing their intended safety functions (Section 3.2. 1).
The self-assessment
team noted that engineering
management
had focused
on prioritizing the workload and reducing the engineering
backlog.
They
determined that equipment
issues affecting system reliability were being
dealt with effectively (Section 3.2. 1).
The self-assessment
team found that the licensee
had formed engineering
teams'ed
by system engineering
personnel,
which were actively
maintaining
and improving system performance
(Section 3.2.3).
The self-assessment
team found that licensee
personnel
effectively used
information for decision making and
prioritization.
However. in two cases
(one identified by the
self-assessment
team and one identified by the
NRC), licensee
personnel
did not conservatively
address
risk implications (Sections 3.2.4
and
4.2.2).
The self-assessment
team found that licensee
personnel
were effectively
maintaining
a conservative
design basis for the plant.
The
self-assessment
team concluded that engineering activities were
improving (Section 3.2.5)
The inspectors
idencified one case
where licensee
personnel
had not
consistently translated
the licensing basis for the nonessential
train
of the auxiliary feedwater
system into the design basis for the plant
(Section 4.2.3).
The inspectors
noted that the licensee
had not performed
a design-basis
verification for the condensate
transfer
system.
which included the
condensate
storage
tank and the auxiliary feedwater mini-flow lines
(Section 4.2.4).
I'
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The self-assessment
team found that licensee
personnel
performed
engineering calculations'valuations.
and dispositions with
satisfactory rigor and technical
accuracy
(Section 3.2.5).
The self-assessment
team concluded that the new plant modification
program was working well.
However, they found that some older plant
modification program issues still existed,
such
as the need to improve
control of "abandoned-in-place"
modifications (Section 3.2.6).
The self-assessment
team concluded that engineering
personnel
effectively provided technical direction and input to help the plant
personnel
resolvesignificant
issues.
However. the self-assessment
team
found that engineering
personnel
did not always effectively deal with
emerging technical
issues
which were determined to be of lesser
significance
(Section 3.2./).
The self-assessment
team observed that management
oversight,
particularly through the large. process-oriented
self-assessments,
Nuclear Assurance audits'nd
Independent
Safety Evaluation assessments
had been rigorous
and critical for both the design modification and the
corrective action process
(Section 3.2.8).
The self-assessment
team concluded that
~ in general.
problems
were being
identified, evaluated'nd
resolved.
They found that the licensee's
ability to 'effectively resolve issues
and prevent recurrence of
significant conditions adverse to quality had improved (Section 3.2.9).
The self-assessment
team found
a general
reluctance to write condition
report/disposition
requests
(Section 3.2.9).
The self-assessment
team concluded that implementation of the recently
enhanced operability determination
process
was weak.
The team
identified cases
where operability determinations
were not completed in
a timely manner (Section 3.2.9)
The inspectors
identified additional
examples of operability
determinations
which were not performed
as
recommended
"Information to Licensees
Regarding
Two NRC Inspection
Manual Se'ctions
and Resolution of Degraded
and Nonconforming Conditions
and
On Operability."
While not
a requirement,
the licensee stated that
it was their policy'o implement Generic Letter 91-18 (Section 4.2.5).
The self-assessment
team noted that specific problems identified on
condition report/disposition
requests
were generally corrected
but
repetitive and/or related
problems were not always thoroughly analyzed
to determine if more extensive evaluation or corrective action was
needed
(Section 3.2.9).
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Summar
of Ins ection Findin s:
~
Two non-cited violations were identified (Section 3.2.9).
~
Inspection Followup Item 50-528/9601-01:
50-529/9601-01;
50-530/9601-01
was opened
(Section 4.2.3)."
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TABLE OF CONTENTS
DETAILS
1
TEAM COMPOSITION (40501)
1. 1
Qualifications. Objectivity, and
Independence
1.1.1
Inspection
Scope
.
1.1.2
Observations
and Findings
2
LICENSEE SELF-ASSESSMENT
PROCESS
(40501)
2.1
Scope
2.1.1
Inspection Scope....
2.1.2
Observations
and Findings
2.2
Depth
2.2. 1
Inspection
Scope
.
.
2.2.2
Observations
and Findings
2.3
Plan and Implementation
2.3.1
Inspection Scope.....
2.3.2
Observations
and Findings
3
SIGNIFICANT SELF-ASSESSMENT
TEAM CONCLUSIONS (40501)
3. 1
Inspection
Scope
3.2
Observations
and Findings
3.2. 1
Material Condition
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
3.2.2
Engineering
Work Backlog
.
.
.
3.2.3
System Engineering
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
3.2.4
Use of Probabilistic Risk Assessment
Information
3.2.5
Design Basis Maintenance
.
.
.
.
.
.
.
.
.
.
.
.
3.2.6
Plant Modifications
3.2.7
Technical
Support
3.2.8
Self Assessments
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
3.2.9
Problem Identification
.
4
INDEPENDENT NRC INSPECTION (40501)
.'.
1
Inspection
Scope
.
.
.
.
.
.
.
4.2
Observations
and Findings
4.2.1
Auxiliary Feedwater Mini-flow Line Insulation
4.2.2
Use of Probabilistic Risk Assessment
Information
.
4.2.3
License Basis for Nonessential
Auxiliary, Feedwater
4.2.4
Design Basis Validation Not Comprehensive
4.2.5
Lack of Formal
Prompt Operability Determinations
.
5
UPDATED FINAL SAFETY ANALYSIS REPORT
(UFSAR)
IMPLEMENTATION
2
2
2
2
2
2
3
3
3
4
4
4
4
4
4
5
6
6
6
6
8
9
9
9
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11
12
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ATTACHMENTS:
~
Attachment
1
- Persons
Contacted
and Exit Meeting
~
Attachment
2 - Team Member Credentials
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DETAILS
1
TEAN COMPOSITION (40501)
1. 1-
ualifications
Ob ectivit
and Inde endence
1.1.1
Inspection
Scope
The purpose of this inspection
was to determine the effectiveness
of the
licensee's
self assessment
of their engineering
and corrective action
rograms.
In letters.
dated
December
12,
1995,
and January
19,
1996. the
icensee
proposed to perform a self-assessment
of their engineering
and
corrective action programs in accordance
with the guidance ot
NRC Inspection
Procedure
40501,
"Licensee Self Assessments
Related to Team Inspections."
The
option of permitting licensees
to conduct
a self assessment
in lieu of planned
NRC team inspection is an
NRC program aimed at minimizing regulatory impact
and utilizing NRC resources
more efficiently.
Region
IV NRC team inspections
were planned to accomplish the core inspection
program requirements of NRC
Inspection
Procedures
37550,
"Engineering"
and 40500,
"Effectiveness of
Licensee Controls in Identifying, Resolving.
and Preventing
Problems."
The inspectors
reviewed the qualifications. objectivity and independence
of
the personnel
performing the self assessment.
1. 1.2
Observations
and Findings
The letters referenced
above included
a description of the qualifications of
the team members.
The inspectors
reviewed the qualifications of the team
members
and found they exhibited
a wide scope of engineering disciplines.
Each
member possessed
significant engineering
experience.
Subsequently.
the
licensee
added
one additional
member to the self-assessment
team.
A
description of his credentials.
which are also acceptable.
is attached to this
report.
The inspectors
noted that the self-assessment
team was primarily staffed with
personnel
from the Palo Verde Nuclear
Generating Station.
To provide an
independent
perspective,
the licensee
included two consultants
and two
engineers
on loan from other facilities as team members.
The
NRC accepted
the
credentials
and experience of the assessment
team in a
memo to William L.
Stewart,
Executive Vice President.
Nuclear, Arizona Public Service
Company,
dated February
15 '996.
'he
inspectors
noted that the self-assessment
team questioned
the
effectiveness
of several
programs
which minimally met regulatory requirements.
As
a result of questions
from the self-assessment
team,
the licensee
planned
program upgrades
in many areas.
In a few cases
the self-assessment
team did
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not identify all of the issues
associated
with their findings because of their
familiarity with current plant practices.
However, the inspectors
concluded
that 'a qualified self-assessment
team conducted
an independent
and objective
assessment
of engineering
and corrective action activities.
2
LICENSEE SELF-ASSESSMENT
PROCESS
(40501)
2.1
~Sco e
2.1.1
Inspection
Scope
In the letters referenced
above,
the licensee
provided the
NRC their
engineering
and corrective action self-assessment
plan.
The inspectors
compared the submitted inspection plan against
the requirements
of NRC
Inspection
Procedures
37550 and 40500.
The inspectors
observed
in-process
assessment
activities
and interviewed licensee
personnel.
2. 1.2
Observations
and Findings
The inspectors
determined that the licensee's
assessment
plan included all the
key elements listed in NRC Inspection
Procedures
37550 and 40500.
The
inspectors
found that the self-assessment
team selected
two safety-related
systems for evaluation:
and the emergency diesel
generator
system.
These
systems
were selected
based
on their contribution to
core
damage
frequency
as identified in the Palo Verde Nuclear
Generating
Station individual plant examination.
The team also evaluated
engineering
and
corrective action activities for other important-to-safety
systems listed in
the referenced
NRC inspection
procedures.
The self-assessment
team examined engineering activities as they related to
maintaining the design basis
and improving system performance.
They evaluated
temporary
and permanent modifications to'ensure
compliance with design basis
documents.
The self-assessment
team conducted
system walkdowns and reviewed
past operating
and maintenance
history to assess
system reliability'.
The team
'lso reviewed corrective action documents,
operating experience
review
documents
and reports of oversight corwittee activities to assess
the
effectiveness
of licensee controls for identifying, resolving
and preventing
problems related to these
systems.
The inspectors
concluded that the scope of the self assessment
was sufficient
to satisfy the requirements of NRC Inspection
Procedures
37550 and 40500.
2.2
~De th
2.2. 1
Inspection
Scope
The inspectors
reviewed the compilation of the self-assessment
team's
requests
for information and the licensee's
response
to the self-assessment
team's
questions.
The inspectors
also reviewed the team's
completed checklists,
the
issued
self-assessment
report.
and the resulting condition report/disposition
requests.
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2.2. 2
Observati ons
and Findings
The self-assessment
team developed detailed audit checklists to implement the
assessment
plan. which had been provided to the
NRC.
Each team member
was
designated
responsibility for completing specified checklists to describe
their findings.
The self-assessment
team leader
used the completed checklists
to develop the self-assessment
report.
The inspectors
noted that the
self-assessment
team's
requests
for information were appropriately
focused
on
issues with potential nuclear safety impact.
The questions
were similar to
the types of questions
which would have
been
posed
by NRC personnel
inspecting
the
same subject area.
The licensee
committed significant resources
to this effort (i.e., well in
excess of the number of core inspection
hours planned
by the
NRC for similar
activities).
The 12-person,
self-assessment
team reviewed licensee activities
for 3 weeks, resulting in approximately
36 person-weeks
of inspection.
The number of requests
for information generated
by the self-assessment
team
also provided
a qualitative measure of the scope of the licensee's
review
effort.
The team
made
146 requests
for information, which resulted in the
initiation of 26 condition report/disposition
requests.
The licensee
uses
condition report/disposition
requests
to evaluate
improvement areas,
as well
as to identify adverse conditions.
Of the 26 condition report/disposition
requests.
17 were of sufficient significance to require response
by a line
organization.
The inspectors
'noted that the self-assessment
team identified
many possible
enhancements.
which exceeded
regulatory requirements.
The inspectors
found the self assessment
to be ambitious
and of sufficient
depth to satisfy the inspection
requirements of NRC Inspection
Procedures
37550
and 40500.
2.3
Plan
and
Im lementation
2.3. 1
Inspection
Scope
Two inspectors
reviewed the self-assessment
team's effort from March 4 through
April 26.
1996'n accordance
with NRC Inspection
Procedure
40501.
The
inspectors
observed
the performance of the self-assessment
team during the
first week of onsite inspection,
March 4-8.
1996.
The inspectors
performed
a
second
week of onsite
independent
inspection, April 22-26.
1996, to ensure the
satisfactory
completion of the team's
self-assessment.
The inspectors
performed in-office review of the self-assessment
team's findings during the
interim weeks.
The inspectors
observed
the self-assessment
team perform system walk
downs'nterview
personnel.
and conduct
team meetings.
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2.3.2
Observations
and Findings
The inspectors
concluded that the team appropriately identified problem areas
and potential
weaknesses.
The inspectors
concurred with the selt-assessment
team's disposition of the identified issues with some minor exceptions
discussed
below.
The self-assessment
team did not identify any examples of
equipment.
3
SIGNIFICANT SELF-ASSESSMENT
TEAM CONCLUSIONS (40501)
3.1
Ins ection Sco
e
The inspectors
reviewed the self-assessment
report,
which included three main
sections:
System Reviews:
Engineering;
and Ability to Identify, Evaluate
and
Resolve
Problems.
The inspectors
summarized the licensee's
conclusions
from
each section
and the information that the team highlighted in the executive
summary.
3.2
Observations
and Findin s
3.2. 1
Material Condition
The self-assessment
team concluded that the material condition of the
the diesel
generator,
and selected
important-to-safety
systems
was generally good and that these
systems
were fully capable of
performing their intended safety functions.
These
systems
were installed in
accordance with the design
and licensing basis of the plant.
The team's
conclusion
was based
on extensive
walkdowns.
.The team took notes of their
observations
and minor deficiencies
were passed to the licensee for action.
3.2.2
Engineering
Work Backlog
The self-assessment
team noted that engineering
management
had focused
on
prioritizing the workload and reducing the engineering
backlog.
The team also
noted that lingering equipment
issues
were being addressed.
For
example,
the
number of temporary modifications
and installed drip catches
had been
reduced.
The team also found that the auxiliary feedwater
and emergency diesel
generator systems'erformance
had improved.
They determined that equipment
issues affecting system reliability were being prioritized effectively.
3.2.3
System Engineering
The self-assessment
team found that the licensee
had formed engineering
teams,
led by system engineering personnel'hich
were actively maintaining
and
improving system performance.
3.2.4
Use of Probabi listic Risk Assessment
Information
For the most part, the team found that licensee
personnel
were effectively
using probabi listic risk assessment
information for decision making and work
prioritization.
As an exception.
the self-assessment
team identified one case
where risk implications were not conservatively
addressed.
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Specifically. the self-assessment
team identified that. during
a
evaluation of a proposed modification to the auxiliary feedwater
pump turbine
steam supply system.
licensee
personnel
had incorrectly determined that
a
modifications which resulted in an increase
in core
damage
frequency,
was
acceptable
because
the core
damage
frequency increase
was small.
The
self-assessment,
team noted the
10 CFR 50.59 evaluation
was inconsistent with
guidance the
NRC had previously provided to another licensee
(Virginia Power).
The
NRC had stated that the requirements
in 10 CFR 50.59 do not include
a
specific threshold
below which the effects of a core
damage
frequency
change
were considered to be inconsequential.
and the
NRC staff had not endorsed
a
threshold value below which the effects of a positive core
damage
frequency
change
were considered
inconsequential.
Licensee
personnel
reperformed
the probabi listic risk analysis with more
precise input assumptions
and found that the core
damage
frequency did not
increase.
As
a result. the conclusion
from the original
evaluation
remained
unchanged:
however.
the self-assessment
team determined
that the procedural'uidance
for performing
10 CFR 50.59 evaluations
was not
thorough with respect to the proper
use of probabilistic risk assessment
information.
The licensee
planned
an upgrade to the
10 CFR 50.59 procedure to
provide better guidance to the evaluators
in this area.
3.2.5
Design Basis Maintenance
The self-assessment
team found that engineering
personnel
w'ere effectively
maintaining
a conservative
design basis for the plant.
The team determined
that the design basis validation project for the auxiliary feedwater
system
successfully identified and corrected
many deficiencies
between the Updated
Final Safety Analysis Report
and the design basis documents'hich
were within
the scope of the project.
The self-assessment
team found that plant personnel
had accurately reflected the design basis in the design output and
configuration documents with a few minor exceptions.
The self-assessment
team found that engineering calculations,
evaluations,
and
dispositions
were generally performed with satisfactory rigor and technical
accuracy.
As an exception,
the self-assessment
team identified two cases
where engineering
provided nonconservative
technical
input to shift
supervisors to use to determine
equipment operability.
In one case
an
was performed to evaluate the operability of the
essential
pumps
when the associated
water-tight doors were
The operability determination relied on operator
compensatory
actions,
which were not consistent with the assumptions
of the design basis
flooding calculations.
However, the water -tight doors were operable at the
time the inadequacy in the operability determination
was discovered.
The
second
case
involved an operability determination to establish limits for the
amount of insulation which could be removed
from various safety systems
without exceeding
the cooling capacity in the
pump rooms.
These limits were
out-of-date
and nonconservative
for the low pressure
safety injection system,
one train of containment
spray
and for the auxiliary feedwater
system.
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However. the amount of insulation actually removed in the
pump rooms was less
than the minimum required
(based
on updated,
corrected values).
The
operability status of plant equipment
was unchanged
as
a result of discovering
these
inadequacies.
3.2.6
Plant Modifications
The self-assessment
team concluded that the new plant modification program was
working well.
They found that
some older plant modification program issues
still existed,
such
as control of "abandoned-in-place"
modifications.
The
team found that in some cases
systems
had been effectively abandoned-in-place
without completing modifications to actually remove the installed equipment.
The team concluded that this practice resulted in weak configuration controls.
3.2.7
Technical
Support
The self-assessment
team concluded that engineering
personnel
were effectively
providing technical direction and input to help the plant resolve significant
issues.
However, the team found that engineering
personnel
were not always
'ffectively
dealing with emerging technical
issues.
which were viewed by the
licensee to be of lesser significance.
3.2.8
Self Assessments
The self-assessment
team observed that management
oversight, particularly
through the large.
process-oriented
self-assessments.
nuclear
assurance
audits.
and independent
safety evaluation
assessments
had been rigorous
and
critical for both the design modification and the corrective action process.
The self-assessment
team found that problems associated
with the design
modification process
had been self-identified during
a previous self
assessment
and corrective action plans were in process.
The self-assessment
team found that corrective action program weaknesses.
which were
self-identified in 1994,
had been systematically dealt with by plant
management.
As
a result. the corrective action process
had been simplified to
provide better focus to significant issues.
The self-assessments
performed in
1995,
by both the line organizations
and the nuclear assurance
department,
also resulted in development of corrective action plans to address
identified
weaknesses
and improved performance.
The self-assessment
team viewed the
licensee's
commitment to developing
a self-assessment
culture as
a strength.
3.2.9
Problem Identification
In general,
the self-assessment
team concluded that problems were being
identified, evaluated,
and resolved.
They found that the licensee's
ability
to effectively resolve issues
and prevent recurrence of significant conditions
adverse to quality had improved.
However. the self-assessment
team found a
general
reluctance to write condition report/disposition
requests.
The team
noted cases
where plant personnel
identified apparent conditions adverse
to.
quality and failed to document these conditions using the condition
report/disposition
request
process.
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Personnel
involved in three different assessment
processes
failed to document
their findings on condition reports/disposition
requests.
As an example,
operations
personnel
identified eight adverse conditions related to tagging
and clearances
during an operations self assessment
without issuing
a
condition report/disposition
request.
To address
this issue licensee
personnel
provided additional training for site personnel
to ensure
understanding
of the need to initiate a corrective action document.
They
implemented
a media campaign to stress
the use of the corrective action
program.
Licensee
personnel
also developed
a long term action plan to
research
and address
the cause of the reluctance to write condition
report/disposition
requests.
The failure to,identify conditions adverse to
quality is
a violation of Criterion XYI of 10 CFR Part 50, Appendix B.
This
licensee-identified
and corrected violation is being treated
as
a noncited
violation, consistent with Section YII.B.1 of the
The self-assessment
team also concluded that implementation of the recently
enhanced operability determination
process
was weak.
The team identified
cases
where operability determinations were'ot completed in a timely
manner.
For example.
the self-assessment
team reviewed Plant Review Board
Minutes 95-29,
dated
December
1,
1995. which reviewed Justification for
Continued Operation 95-06-00.
Licensee
personnel
had identified and reported
a condition potentially outside the design basis,
which could lead to the
turbine driven auxiliary feedwater
pump tripping on overspeeed
(Reference:
Unresolved
Item 528/9521-02).
On January
10,
1996,
licensee
personnel
approved the justification for continued operation for this issue.
The
justification for continued operation
was prepared to provide information to
be used in an operability determination for associated
Condition
Report/Disposition
Request
9-5-0200.
On February
20.
1996 'he self-assessment
team requested
the operability
determination for this condition report/disposition .request
and was informed
that it had not been initiated.
As
a result, Operability Determination
97 was
prepared
and Condition Report/Deficiency
Request
9-6-0191
was written to
evaluate
and address
why an operability determination
was not performed
when
the justification for continued operation
was written.
The team also reviewed
a memorandum
from nuclear
regulatory affairs to
operations,
which documented
several
other operability determination
issues
related to the implementation of the operability determination
program and
establishing
the operability determination basis.
This included examples
where an operability determination
was not issued.
and its basis
was not
established
in a timely manner.
Most of the examples
noted in the memorandum
were concerns originally identified by the
NRC.
The self-assessment
team
concluded that these issues'ombined
with the technical
issues identified on
two of the operability determinations
reviewed from the auxiliary feedwater
system,
indicated that
a larger problem existed with the recognition
and
performance of operability determinations.
The self-assessment
team concluded
that operability determinations
were occasionally treated
as after-thoughts
instead of first-order-of-business
actions.
I
j
f'I
)
The licensee
prepared
Condition Report/Deficiency
Request
9-6-0300 to evaluate
and address
interface issues
between the followin'programs:
the operability
determination
program.
the condition report/disposition
request
program.
the
justification for continued operation
program and the
10 CFR 50.59 program.
Licensee
personnel
planned to clarify the applicable procedures.,
They planned
to provide management
expectations
to operations
personnel
concerning the
scope of operability determinations.
They also provided training for site
personnel
which emphasized
that it is necessary
to initiate a corrective
action document for degraded
and nonconforming conditions to ensure
followup
and closure.
In their media campaign licensee
personnel
stressed
the
. importance of reporting degraded
conditions to the control
room.
Procedure
"Operability. Determinations,"
requires that an
operability decision
be made within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of when
a non-conforming
condition is identified.
The failure to complete the operability
determination
associated
with Justification for Continued Operation 95-06-00
wi.thin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is
a violation of Technical Specification 6.8. l.
This
licensee-identified
and corrected violation is being treated
as
a noncited
violation. consistent with Section VII.B.1 of the
The self-assessment
team also noted that specific problems identified on
condition report/disposition
requests
were generally corrected,
but repetitive
and/or related
problems
were not always thoroughly analyzed to determine if
more extensive evaluation or corrective action was needed.
4
INDEPENDENT NRC INSPECTION (40501)
4.1
Ins ection
Sco e
The inspectors
reviewed the licensee's
self-assessment
reports
the detailed
audit checklists,
the information in the self-assessment
team request for
information notebooks.
and the associated
condition report/disposition
requests
to develop
an understanding
of the basis for the self-assessment
team's
conclusions.
The inspectors
also reviewed portions of the design basis
manual for the
diesel
generator
system
and applicable portions of
Updated Final Safety Analysis Report.
The inspectors
toured portions of the auxiliary feedwater
system
and the
emergency diesel
generator
system with the cognizant
system engineer
and the
cognizant self-assessment
team member.
The inspectors
reviewed the
self-assessment
team's
system walkdown=deficiency reports.
In addition, the
inspectors
performed
an independent
tour of; portions of the auxiliary
system
and the condensate
transfer
system.
The inspectors
interviewed self-assessment
team members
and other cognizant
licensee
personnel.
The inspectors
also attended
self-assessment
team
meetings
and the self-assessment
team exit.
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4.2
Observations
and Findin s
The inspectors
generally agreed with the conclusions of the self-assessment
team.
The inspection activities, which resulted in a divergent or amplifying
view are described
below.
4.2. 1
Mini-flow Line Insulation
During the independent
inspection of the auxiliary feedwater
system
and the
condensate
transfer
system.
the inspectors
noted that the exposed portions of
the safety related mini-flow return lines for the essential
auxiliary
pump were not insulated like the similar mini-flow return line for
the nonessential
auxiliary feed water pump.
The inspectors
requested
the
licensee to provide the basis for this difference.
The licensee initially determined that the installed configuration of the
essential
mini-flow lines (i.e., not insulated)
was not consistent with the
general
guidance for freeze protection provided in Arizona Nuclear
Power
Project Mechanical
General
Design Criteria, Part II. Section
6. 10,
Revision
13.
On May 7.
1996. the inspectors
telephoned
licensee
personnel
to discuss
the
results of the licensee's
investigation of the significance of this finding.
Licensee
personnel
had performed additional analysis
and determined that the
installed configuration of the essential
mini-flow lines was acceptable.
The
design criteria included
an exception,
which allowed insulation not to be
installed if partial blockage
due to freezing was acroptable.
Licensee
personnel
calculated that for the design basis
freeze
(24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at 25
F). the
expected partial freezing would not prevent the mini-flow lines from
erforming their protective function.
Licensee
personnel
stated that they
elieved the architect engineer
had intentionally omitted the insulation from
these lines, although they had no particular basis
for this belief.
The inspectors
discussed
with the licensee the fact that the inspectors
found
a potential
hardware deficiency. which was not identified by the self-
assessment
team.
The licensee
determined that this oversight
was caused
by a
system boundary change.
The mini -flow return piping for the essential
pumps
was designated
as being
a part of the condensate
transfer
system.
The licensee stated that the self-assessment
team stopped
their tour when they reached
system boundary.
4.2.2
Use of Probabilistic Risk Assessment
Information
The inspectors
reviewed
a condition report/disposition
request.
which related
to repeated tripping of the nonessential
pump due to
suction pressure
switch problems.
Despite the fact that the affected
equipment
was risk significant. the licensee
had not classified this condition
report/disposition
request
so that
a root-cause
analysis would be performed.
The inspectors
discussed
condition report/disposition
request classification
with the licensee
and found that the licensee
had downgraded the condition
report/disposition
request classification
so that
a root-cause
analysis
was
not required
because
there
was
no specific Updated Final Safety Analysis
I
e
l
Report.
Chapter
15 safety function for the pressure
switch or the pump.
While
consideration of the risk significance
was noted in the condition
report/disposition
request.
the inspectors
found that risk implications were
not conservatively
factored into the licensee's
classification of the
condition report/disposition
request.
The inspectors
noted that despite the repetitive nature of the pump trips,
personnel
from instrument
and controls engineering
had not been included in
the team assigned
responsibility for resolving the problem.
The inspectors
considered
the downgraded condition report/disposition
request classification
to have contributed to the lack of involvement by instrument
and controls
engineering
personnel.
4.2.3
License Basis for Nonessential
system consisted of three trains of equipment
for
providing cooling to the steam generators
in the event of a loss of main
Although originally designed
as non-safety related,
the
nonessential
train was modified during licensing to augment its reliability as
a defense-in-depth
design feature for accident mitigation.
The Technical
Specification Limiting Conditions for Operation were the same for the
nonessential
and the essential
pumps.
The nonessential
pump capability (with mini-flow secured)
was described in the basis section of
the Technical Specifications
as equivalent to the flow required for the
essential
pumps
(650 gpm to a steam generator at
1270 psia).
The nonessential
train of auxiliary feedwater
was also described
in the Updated Final Safety Analysis Report:
however, it was not specifically
credited in any Chapter
15 analysis
for accident mitigation.
The inspector
noted that licensee
personnel
had not specified design basis
flow requirements
for the nonessential
train of auxiliary feedwater for
accident mitigation.
The licensee's
design basis
manual for the auxiliary
system stated that there is no safety analysis
or design basis
requirement that the non-essential
pump actually deliver
650 gpm to a steam generator
at 1270 psia.
The individual plant evaluation
stated that the non-essential
train of auxiliary feedwater is capable of 650
gpm, which is consistent with the Technical Specifications.
The licensee
stated that only 350 gpm was needed to meet the individual plant evaluation
analysis criteria; they also stated that only 500 gpm was need to meet the
analysis
associated
with the functional recovery procedures
analysis.
Further, in NRC Inspection Report 50-528/95-21:
50-529/95-21;
50-530/95-21,
the
NRC identified that the licensee did not consider the capability to
promptly open the discharge
valves for the nonessential
train of auxiliary
feedwater following a main steam isolation signal actuation to be
a design
basis safety function of the valves.
On November
27,
1995, following a main
steam isolation signal actuation, it took operators
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to open these
valves.
The inspector concluded that the licensee's
design basis
requirements
did not ensure timely availability of the nonessential
train of auxiliary
system for accident mitigation.
10
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The inspector noted that the licensee's
design basis
requirements
for the
nonessential
train of auxiliary feedwater were not consistent with the risk
significance of the equipment.
The inspector
noted that the nonessential
train of auxiliary feedwater
ranked high in significance within the licensee's
probabi listic risk analysis.
The licensee's
individual plant evaluation
stated that the single highest dominant contributor to the unavailability of
system is the
human failure to restore the nonessential
train of auxiliary feedwater following a main steam isolation signal
actuation.
4
The inspector
concluded that the licensee
considered
only the Updated Final
Safety Analysis Report Chapter
15 analysis to define design basis
reauirements
and safety functions.
The inspectors
concluded that the licensee
had not
'consistently translated
the licensing basis for the nonessential
train of the
system
from the basis section of the Technical
Specifications into the design basis for the train.
The licensee verbally
, committed to clarify their position with respect to the use of the
nonessential
train of auxiliary feedwater.
This concern wi 11
be an inspection
followup item (50-528/9601-01;
50-529/9601-01;
50-530/9601-01).
4.2.4
Design Basis, Validation Not Comprehensive
The inspectors
noted that the condensate
transfer
system,
which included the
condensate
storage
tank and the auxiliary feedwater mini -flow lines,
was
needed to accomplish the safety functions specified for the auxiliary
system.
Both the self-assessment
team and the inspectors
identified
minor design discrepancies
related to the condensate
transfer system.
During
followup discussions
with licensee
personnel,
the inspectors
learned that
while the licensee
had developed
a design basis
manual
and performed
a design
basis validation for the"auxiliary feedwater
system,
they had not performed
a
similar review for the condensate
transfer
system.
I'o
address this weakness'icensee
personnel
stated that they planned to
complete
a design basis
manual for the condensate
transfer system
and perform
a design basis validation of approximately
20 percent of the manual.,
4.2.5
Lack of Formal
Prompt Operability Determinations
The inspectors identified two additional
examples of operability
determinations,
which were not performed for potentially nonconforming items.
The self-assessment
team originally identified both technical issues'ut
did
not follow through to ensure
prompt operability determinations
were performed.
because
they believed the equipment to be operable.
In both cases.
engineering
personnel
were actively resolving the technical
issues
and
'elieved
there
was
a technical
basis to support operability.
Following
discussions
with the inspector.
the licensee
performed
a prompt operability
determination for both technical
issues
and found the equipment to be
11
1
0
The inspectors
viewed these
instances
as additional
examples of an overall
weaknesses
in the prioritization of operability determinations.
which was
identified by the 1icensee's
self-assessment
team in Section 3.2.9.
5
UPDATED FINAL SAFETY ANALYSIS REPORT
(UFSAR)
IHPLEHENTATION
A recent discovery of a licensee
operating their facility in a manner contrary
to the
UFSAR description highlighted the need for additional verification that
licensees
were comp1ying with UFSAR commitments.
During an approximate
2-month time period all reactor inspections will provide additional attention
to UFSAR commitments
and their incorporation into plant practices,
parameters
and procedures.
While performing the inspections
which are discussed
in this report the
inspectors
reviewed the applicable portions of the
UFSAR that related to the
areas
inspected.
The self-assessment
team identified several
minor
inconsistencies
between the wording of the
UFSAR and the plant practices.
procedures
and/or parameters.
They identified the deficiencies
in their
corrective action system.
The inspectors
did not identify any additional
examples of UFSAR discrepancies.
12
I
ATTACHMENT 1
PERSONS
CONTACTED AND EXIT MEETING
1
PERSONS
CONTACTED
1. 1
Arizona Public Service
Com an
J. Bailey. Vice President,
Nuclear Engineering
B. Endsor, Visitor, Nuclear Electric
F. Gowers, Site Representative,
El Paso Electric
R. Henry, Site Representative,
Salt River Project
J.
Hesser.
Director. Nuclear Engineering
M. Hodge, Section
Leader,
Nuclear Engineering
D. Kanitz. Senior Engineer,
Nuclear Regulatory Affairs
A. Krainik, Department
Leader.
Nuclear Regulatory Affairs
D. Leech.
Section
Leader,
Nuclear Assurance
Engineering
M. Powell,
Department
Leader.
Nuclear Engineering
C. Seaman'irector,
Nuclear Assurance
G. Shanker.
Department
Leader,
Nuclear Assurance
Engineering
1.2
NRC Personnel
K. Brockman,
Deputy Division Director, Division of Reactor Safety
J.
Kramer, Resident
Inspector,
Division of Reactor Projects
C. Myers, Reactor
Inspector.
Division of Reactor Safety
L. Smith.
Reactor
Inspectors
Division of Reactor Safety
The personnel
listed above attended
the exit meeting.
In addition to the
personnel
listed above.
the inspectors
contacted
other personnel
during this
inspection period.
2
EXIT MEETING
An exit meeting
was conducted
on April 26,
1996.
During this meeting.
the
inspectors
reviewed the scope
and findings of the report.
The licensee did
not express
a position on the inspection findings documented
in this report.
The licensee did not identify as proprietary any information provided to. or
reviewed by. the inspectors.
On May 7,
1996 the
NRC further discussed
the
insulation requirements
for the mini-flow lines associated
with the essential
auxiliary feedwater trains.
On May 24,
1996 the
NRC reviewed the overall
conclusions of the inspection report with licensee
management.
Licensee
personnel
agreed to provide
a commitment in writing to clarifiy their position
on the use of the nonessential
train of auxiliary feedwater.
f
I
l
(
I
JOHN D. STAMM
EDUCATION & TRAINING:
~
B.S., Mechanical Engineering, Kansas State University, 1976
ATTACHHENT 2
TEAH HEHBER CREOENTIALS
PROFESSIONAL REGISTRATIONS AND CERTIFICATIONS:
~
Professional Engineer, Missouri, E-19644
EXPERIENCE:
4/81 to Present
WolfCreek Nuclear 0 eratin
Co
WolfCreek Generating Station
Summary
Multiple positions
held
at Wolf Creek
Generating
Station
covering
a
broad
range
of
Engineering
duties
and
responsibilities
beginning
during
the
plant
construction
phase,
continuing through startup, power ascension,
and power operations.
During my tenure at
WCGS,
I have held the following positions.
Supervisor, Safety Analysis
Responsible for supervision of the Safety Analysis and Probability Safety Assessment
groups.
USAR Chapter
15
accident
analysis,
thermal
hydraulic
analysis
and
risk assessment
techniques are performed in support of in-house core design and other plant activities.
Division Manager, System Engineering
Responsible for administering the NSSS, BOP, Auxiliary, and Electrical systems groups whose
job functions assured
system health including plant trending, prioritization of system activities,
generation
of plant modifications, operability determinations;
reportability evaluations,
and
screening/assignment
of field generated documents.
Division Manager, Engineering Support
Responsible
for administering the Project Engineering,
Configuration Management,
ASME,
Design/Drafting, and Design Bases groups.
Manager, Plant Design Engineering
Responsible
for administering the onsite Mechanical, Electrical, and Stress/Civil Engineering
groups;
Functions
included development
of design
changes,
performance
of operability
determinations
and
reportability
evaluations
in
support
of
plant
operations,
and
screening/assignment
of all plant generated
docume'nts
to the
Engineering
Department.
Additionally, the administration of A/E support for major projects was performed.
Manager, Project Engineering
Responsibilities included supervision of the Project Engineering,
Estimating, and Scheduling
groups as well as the supporting
clerical staff who developed
the annual
capital budget;
developed
the scope,
schedule,
and cost estimates
for all proposed
projects valued over
$25K; prioritized and
assigned
all work documents
to the
Engineering
department,
and
developed cost/benefit analysis for proposed plant modifications.
Page
1 of 2
0
1
JOHN D. STAMM
ATTACHNENT 2
TEAN NENBER CREDENTIALS
Lead Mechanical Design Engineer
Accountable for review/approval of design changes
and supervision of the site mechanical
design group.
Lead Shift Test Engineer
Supervised
the power ascension
test crew throughout Initial Core Load, Low Power Physics
testing, and Power Ascension testing required for commercial operation.
Senior Engineer
Performed
construction inspection
activities, coordinated
Initial Surveillance test procedure
write-up for the IST, HVAC, ILRT/LLRT activities; developed
the initial plant performance
monitoring program; and wrote, reviewed, and performed pre-operational test procedures.
10/77 - 2/81
Performance Testin
& Consultants
Inc.
Vice President and 25% Shareholder
Administered the following projects:
~
Monthly Heat Rate testing of 10 separate
Electric Generating
Stations for a midwestern
utility.
~
Air pollution compliance, efficiency, and acceptance
testing of pollution control equipment
for various electric generating
stations,
hospitals, and industrial facilities throughout the
country.
~
Energy and Technical Assistance Audits performed under the National Energy Audit Policy
Act of 1978, Title III, sponsored by the Department of Energy.
Also served
as Personnel
Manager and participated in managerial
duties such as business
development, computer programming, estimating, proposal and technical report writing.
8/72 - 10/77
Burns & McDonnell En ineerin
Co.
Mechanical Engineer
Air Quality Control Division. Participated in design of a flue gas desulfurization system for a
170 MW unit in Illinois and the FGD system and electrostatic precipitators for three 600 MW
units in Wyoming.
Served as Test Director for EPA compliance tests at seven generating
stations in Kansas, Missouri, and Kentucky.
Cooperative Education Student
Alternated
semesters
while working towards my engineering
degree.
Participated
in source
testing, ambient air testing, computer based
dispersion
modeling, and technical writing of
Environmental Impact Studies.
Page 2 of 2
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