ML17290B064
| ML17290B064 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 03/11/1994 |
| From: | Narbut P, Vandenburgh C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17290B062 | List: |
| References | |
| 50-397-94-02, 50-397-94-2, NUDOCS 9403310115 | |
| Download: ML17290B064 (45) | |
See also: IR 05000397/1994002
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report
No.
'0-397/94-02
.
Docket No.
50-397
License
No.
Licensee:
Facility Name:
Inspection at:
Inspection
Conducted:
'ashington
Public Power Supply System
P. 0.
Box 968
Richland,
WA 99352
Washington Nuclear Project
No.
2 (WNP-2)
WNP-2 site near Richland,
January
10 through 28,
1994
Inspectors:
P.
C.
W.
A.
Narbut,
Regional
Team Leader
Hyers,
Reactor
Inspector
Wagner,
Reactor
Inspector
HacDougal,
Resident
Inspector
(Palo Verde)
Contractors:
Submitted by:
H. Kister, Parameter
Inc.
S. Traiforos,
Parameter
Inc.
P.
P.
ar ut,
earn
ea er
ate
Approved by:
~Summar:
. A.
an
en urg
, Act
g
eputy
erector
Division of Reactor Safety
and Projects
a(u4+
ate
Ins ection
on Januar
10-28
1994
Re ort No. 50-397 94-02
Areas
Ins ected:
An announced,
team inspection of WNP-2 engineering
and
technical
support.
The areas
examined
were design
changes,
temporary plant
modifications,
engineering
involvement,
design bases,
engineering
capabilities,
and self-assessment
programs.
NRC Inspection
Hanual
Chapters
61726,
62703,
37700,
40500,
and
a draft inspection
procedure entitled
"Engineering
and Technical
Support" were used for guidance.
Results of Ins ection
and General
Conclusions:
The inspection
found that the
licensee
had recently implemented
several
important improvement initiatives
which appear to be having positive results.
Examples of these initiatives
included engineering
backlog reduction,
temporary modification reduction,
and
an improved interface
between
engineering
and other organizations.
The team
9403310115
940315
ADOCK 05000397
also observed that the licensee
had decided to install
new metallic-seated
containment
purge
and supply isolation valves in order to end
a longstanding
problem with leaks in the rubber-seated
valves.
Two significant unresolved
items were identified involving the adequacy of the proposed modification and
the
10 CFR 50.59 safety evaluation for the
BWR level instrumentation backfill
system;
and the presence
of flow limiting orifices, which are larger than
described
in the
FSAR, for
115 instrumentation lines penetrating
containment.
Si nificant Safet
Matters:
None.
Summar
of Violations and Deviations:
One violation was identified for the
failure to periodically verify the position of manual
containment isolation
valves in accordance
with technical specification requirements.
The involved
valves were
115 manual
bypass
valves for the containment isolation excess
flow
No deviations
were identified.
Six open items were identified for followup.
Table of Contents
1.0
Introduction
2.0
Executive
Summary
.
3.0
Persons
Contacted
.
4.0
Examination of Design
Changes
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
4.1
In-Process
Modifications
4.1.1
Sample
and Criteria................
4.1.2 Findings
4. 1.2. 1
Containment Isolation Valve Replacement
4.1.2.2
Reactor
Water Level Instrumentation
Backfill Modification
.
.
.
.
.
.
.
.
.
4.1.2.3
Excess
Flow Check Valves
4. 1.2.4
Incorrect Orifice Size
4. 1.3 Conclusions
.
.
.
.
.
.
.
.
.
.
.
.
~
~
~
~
~
~
~
~
~
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~
10
15
17
18
4.2
4.3
Completed Modifications
.
4.2. 1 Sample
and Criteria
4.2.2 Findings
4.2.3 Conclusions
.
.
.
.
Temporary
and Minor Modifications
.
.
4.3.1
Sample
and Criteria
.
.
.
.
.
.
.
.
.
.
.
.
.
4.3.2 Findings
4.3.2. 1
Overall
Program Review
4.3.2.2
Hain Steam Isolation Valve (HSIV)
Hodification
4.3.2.3
Disabled Control
Room Annunciator
4.3.2.4
Inadvertent
Design
Changes
4.3.3 Conclusions
.
.
.
.
.
.
.
.
. .,.
.
.
.
.
.
.
18
18
19
19
19
19
20
20
20
20
'21
23
5.0
Engineering
Involvement in Plant
Problems
.
.
.
.
.
.
.
.
.
.
.
.
23
5.1
Nonconformance
Review
.
5.1.1
Sample
and Criteria,.
5.1.2 Findings
5.1.3 Conclusions
.
~
~
~
23
23
24
24
5.2
5.3
Engineering
Involvement in the Reactor
Pressure
Vessel
(RPV)
Nozzle/Safe-End
Stress
Improvement
Process
5.2.1
Sample
and Criteria
.
5.2.2 Findings
5.2.3 Conclusions
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Waterhammer
Incidents in the Standby Service Water System
(SSWS)
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
0
~
~
~
~
~
5.3.1
Sample
and Criteria
.
5.3.2 Findings
5.3.3 Conclusions
.
25
25
25
26
26
26
26
29
5.4
Suspected
HPCS Materhammer
Event
5.4.1
Sample
and Criteria
.
5.4.2 Findings
5.4.3 Conclusion
29
29
~
~
~"
30
30
5.5
Spray
Pond Icing
5.5. 1 Sample
and Criteria
.
5.5.2 Findings
5.5.3 Conclusions
.
.
.
.
.
~
~,
~
~
~
~
30
30
31
32
6.0
Engineering
Communications
and
Programs
.
.
.
.
.
.
6. 1
Sample
and Criteria
.
.
.
.
.
.
.
.
.
.
.
.
.
32
32
6.2
F
d
~
~
~
1 tldlngs ..
~
6.2. 1 System Engineering
Performance
6.2.2 Plant Performance
Monitoring and Trending
6.2.3 Design Engineering Effectiveness
6.2.4 Project
Management Activities .
.
.
.
.
.
6.2.5 Design Basis
Pr
~
~
~
ogram
33
33
36
38
41
41
6,3
Conclusions
.
t
7.1.1
Sample
and Criteria
.
7.1.2 Findings
7.1.3 Conclusions.....
8.0
Exit Meeting
7.0
Licensee Self Assessment
~
~
7.1
guality Assurance
Oversigh
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
~
42
44
44
44
44
45
45
1.0
Introduction
The inspection
was performed to assess
the licensee's
engineering
and
technical
support activities, particularly the effectiveness
of the
Engineering organization to perform routine
and reactive site activities,
including the identification and resolution of technical
issues
and problems.
2.0
Executive
Summary
The team inspection
was conducted
at .the
WNP-2 site for two separate
weeks.
The team consisted of a team leader,
three
NRC inspectors,
and two
contractors.
The purpose of the inspection
was to assess
the effectiveness
of engineering
and technical
support at WNP-2.
The areas
examined
were design
changes,
temporary plant modifications,
engineering
involvement, design
bases,
engineering capabilities,
and self-assessment
programs.
For inspection
samples,
important systems
and .components
were selected for examination
using
generic
and plant specific probabilistic risk assessment
(PRA) data.
The inspectors
noted that the licensee
had recently implemented
several
important improvement initiatives which appear to be having positive results.
Examples of these initiatives included engineering
backlog reduction,
temporary modification reduction,
and improved interface
between
engineering
and other organizations.
The inspectors
considered
that the licensee's
.decision to install
new metallic-seated
containment
purge
and supply isolation
valves in order to end
a longstanding
problem with leaks in the rubber-seated
valves
was commendable.
The inspectors
also noted two significant unresolved
items which suggest
additional
improve'ment
and management
attention is warranted.
The unresolved
items involved the adequacy of the proposed modification and the
safety evaluation for the Boiling Water Reactor
(BWR) level instrumentation
backfill system
and secondly,
the presence
of flow limiting orifices, which
are larger than described
in the Final Safety Analysis Report
(FSAR), in 115
instrumentation lines penetrating
containment.
The inspection also identified
a violation involving the failure to
periodically verify the position of manual
containment isolation valves in
accordance
with Technical Specification requirements.
The valves involved
were
115 manual
bypass
valves for the containment isolation excess
flow check
valves.
Detailed Conclusions
The inspection
concluded that completed modifications generally
appeared
to
meet regulatory requirements.
In reviewing modifications in process
the
inspection
concluded that engineering
appeared
to be actively involved.
Their
involvement
was evident in the identification and resolution of a longstanding
technical
issue involving leaking containment
supply
and exhaust isolation
valves.
The inspection also observed that engineering
had been actively
involved in the development of the reactor vessel
level indication backfill
modification.
Their activities included involvement with the Boiling Water
Reactor Owner's
Group
(BWROG) in the development of the modification as well
as close coordination with operations
and maintenance.
However, the
inspection identified an unresolved
item regarding the adequacy of the
proposed backfill modification from the standpoint of the credibility,of
initiating an unanalyzed
event through the blockage of a single
instrumentation line,
and regarding the adequacy of the licensee's
10 CFR 50.59 review and safety analysis.
Also, in conjunction with the inspector's
review of the modification, the inspection identified
a longstanding violation
involving the failure to verify that the bypass
valves for the
115 excess
flow
check valves were closed or locked in their closed position.
Additionally,
the inspection identified another longstanding
problem regarding
improper
instrument line orifice sizes.
In the review of temporary modifications,
the inspection
concluded that the
licensee
had initiated programs
which significantly improved their oversight
and management
of the temporary modification program.
For example,
the number
and the
age of the modifications
had
been
significantly reduced.
However,
some problems
we) e identified in the area of
One problem involved an inadvertent
design
change to
the Post-Accident
Sampling
System
(PASS)
caused
by closing normally-open,
manually-operated,
demineralized
water valves.
This resulted in the loss of
the ability to remotely flush portions of the
PASS to reduce
area radiation
levels.
A second
problem involved a weakness
in the administrative
procedures
for controlling valve lineup exceptions.
Improvements
were noted in the involvement of engineering
in the plant
activities.
A review of nonconformances
indicated that engineering
was
involved in the identification and resolution of technical
issues
affecting
the plant.
Likewise, engineering
was found to be involved in major plant
maintenance.
Specifically, it was observed that engineering
was actively
involved in the reactor pressure
vessel
nozzle
and safe-end
stress
improvement
process
planned for the upcoming outage.
On the other hand, the inspection
concluded that the licensee's
examination of a recurrence of waterhammer
in
the Standby Service Mater system in late
1993 was not as thorough
as would be
expected for a repetitive problem.
Additionally, the licensee's
interim
disposition of increasing
the valve stroke time was not correctly calculated
and
may have contributed to another
waterhammer
event.
However, the team
noted that engineering
involvement in an apparent
waterhammer
event in the
High Pressure
Core Spray system that occurred during the inspection
was
prompt, thorough,
and responsive
to the needs of the plant.
Engineering
assistance
was evident,
and the appropriate
degree of analysis
and root cause
determination
was performed.
The inspection
concluded that,
although
areas requiring improvement remained,
the degree
and effectiveness
of the support provided by the engineering
organizations for plant operations
was clearly improving.
This was further
evidenced
by observed
improvements
in the implementation of the licensee's
programs for personnel
and equipment
performance.
For example,
the inspection
concluded that System Engineering
appeared
to have
improved
and was poised for
'Qa
more improvement,
although certain oversights
in program definition were
observed.
Additional staff needs
were being addressed,
and interviews with
operators
indicated that System Engineering
support of plant operations
had
improved.
Also, the inspection
concluded that the licensee's
plant performance
monitoring and trending programs
could have
been better
managed.
For example,
the program administrative control
docume'nt did not address all of the various
performance monitoring activities being performed
and certain monitoring
activities were being performed without benefit of a management-approved
procedure.
The inspection also concluded that the various engineering
improvement
initiatives that were in progress
or planned
should improve the effectiveness
of engineering
support for the operation of the plant.
Specifically, the work
that had
been
done
on reducing the engineering
backlog
had already
shown
a
significant impact.
Furthermore,
the plant staff's visits to other sites with
successful
programs
appeared, to be effective in improving performance
in key
areas
such
as System Engineering.
Additionally, the licensee's
increased
involvement in external
committee activities appeared
to improve focus
on
ongoing industry initiatives.
However, the inspection
concluded that it was
too early to assess
long term effectiveness
of the engineering initiatives and
some weaknesses
were identified.
For example,
the inspection
noted that
licensee
management
had not established
an agreed
upon set of expectations
to
assure
the effectiveness
of Design Engineering interface with Operations
or
System Engineering.
Also, the inspection
found that design requirements
documents
did not contain sufficient information to make them useful to plant
users.
In addition, the validation and verification of most of the documents
was not well controlled
and resulted in varying degrees
and types of
validation and verification'.
I
4
i
3.0
Persons
Contacted
Was
- J
- M.
- J
- J
- G
- R.
- H
- J
%J
~R.
~R.
C.
- D
J.
H.
- W.
- W
- S
- K.
- J
- J
- C.
- D
- G
- p
- D
W.
Bonneville Power Administration
- A. Rapacz
- R. F. Mazurkiewicz
hin ton Pub1ic
Power
Su
1
S stem
V. Parrish,
Assistant
Managing Director for Operations
P. Flasch,
Engineering Director
C. Gearhart,
guality Assurance Director
H. Swailes,
Plant Manager
O. Smith, Operations
Division Hanager
L. Webring, Technical
Services
Manager
M. Nonopoli, Maintenance Division Manager
M. Benjamin, guality Assessments
Manager
R.
Sampson,
Maintenance
Production
Manager
J.
Barbee,
System Engineering
Manager
L. Koenigs,
Design Engineering
Manager
M. Whitcomb, Engineering
Management
Support
Manager
W. Coleman,
Acting Regulatory
Programs
Manager
P. Albers, Radiation Protection
Hanager
E. Kook, Jr.,
Licensing Manager
S. Davison, guality Assuran'ce,
Plant Support Assessments
D. Shaeffer,
Operations
Manager
H. Peck,
Equipment Engineering
Manager
B. Lewis, Licensing Engineer
Snyder,
Plant Support Engineer
Baker, Technical Training Manager
D. Scott, Supervisor,
Plant Support Engineering
Matthews,
Design Engineering
Myers, Design Engineering
Moore, Supervisor,
Engineering
Data Bases
J. Inserra,
Supervisor,
Technical
Services
R.
Bauman,
Executive Assistant to the Managing Director
L. Heade,
Supervisor,
Technical
Services
L. Larkin, Manager,
Engineering Services
La Frambroise,
Structural
Engineer
Manager
United States
Nuclear
Re ulator
Commission
- P. H. Johnson,
Chief, Project Section I, Region
V
- R. C. Barr, Senior Resident
Inspector
- S. P.
Sanchez,
Resident
Inspector
- D. L. Proulx, Resident
Inspector
- T. P.
Gwynn, Director, Division of Reactor Safety,
Region
IV
- T. F. Westerman,
Chief, Engineering
Branch,
Region
IV
+Attended the Exit Meeting on January
28,
1994.
The inspectors
also interviewed various control
room operators; shift
supervisors
and shift managers;
and maintenance,
engineering,
quality
assurance,
and management
personnel.
I
4.0
Examination of Design
Changes
4.1
In-Process
Modifications
The inspector evaluated
the extent
and quality of engineering
involvement in
modifications which were in progress
during the inspection.
In-process
modifications were selected
to assess
the effectiveness
of recent engineering
initiatives.
4.1.1
Sample
and Criteria
The inspector reviewed portions of the existing design
packages for the
following in-process
plant modifications:
~
Purchase
Order 236550-001,
Containment Isolation Valve Replacement
~
Basic Design
Change
(BDC) 93-0089,
Reactor Water Level
Instrumentation Backfill Nodification
The inspector discussed
the development of the modifications with
cognizant licensee
personnel,
reviewed the associated
procedures,
and
walked
down accessible
portions of the modified components
and systems.
4.1.2 Findings
4.1.2.1
Containment Isolation Valve Replacement
The inspector found that the containment isolation valve
modification was in the preliminary stages of design
and
procurement.
The modification affected four butterfly valves that
provide the supply
and exhaust for the primary containment
atmosphere
(CSP V-3, V-4, and
CEP V-IA, V-2A).
These valves were
normally closed during power operation with the containment
atmosphere
inerted.
However, the valves
can
be open during
certain low power operating
modes
and are required to
automatically close for containment integrity.
The licensee
had
experienced
persistent
problems in obtaining acceptable
leak test
results following repositioning of the valves during outages.
The inspector discussed
the development of the licensee's
design
and the engineering
involvement in improving the reliable sealing
of the valves.
The inspector also reviewed six problem evaluation
requests
(PERS) identifying problems related to the containment
isolation valves.
The inspector
found that engineering
had
been
involved in attempting to improve the existing butterfly valves
for a period of four years.
This effort involved improvements
in
both the design of the resilient seals
and maintenance
practices
for the installation of the seals.
While achieving
some
success
in these efforts, acceptable
valve sealing
performance
was not
sustained.
-10-
In May 1993, the licensee
found apparent
valve body distortion
which affected the valve's sealing capability.
According to the
licensee,
the distortion appeared
to have
been
induced
by valve
flange bolting.
Due to the observed
lack of rigidity of the valve
body, the licensee
abandoned
further efforts to improve the
existing equipment
and initiated the procurement of higher
reliability replacement
valves.
The inspector
reviewed
Procurement Specification
No.
12111,
Revision
1,
and Purchase
Order 236550-001 for the new butterfly
valves.
The replacement
valves consisted of cast valve bodies
with metal seals,
rather than the resilient seals.
Conclusion
The inspector
found that engineering
had been
involved in the
development of improved performance for the containment isolation
valves.
In particular,
the inspector
noted that the licensee's
decision to replace the existing butterfly valves with higher
reliability valves represented
a substantial
resource
commitment
to improve the safety-related
performance of the valves
and the
overall reliability of the unit.
4.1.2.2
Reactor
Water Level Instrumentation Backfill
Modification
The inspector
reviewed Modification BDC 93-0089
and walked down
accessible
portions of the modification, which had been partially
installed.
The modification involved the reactor vessel
water
level instrumentation.
The modification installed
a backfill
system for the reference
leg of the condensing
pots in response
to
"Resolution of Issues
Related to Reactor
Vessel
Water Level Instrumentation
in BWR's".
The licensee
planned to.install the modification either during the next forced
outage of sufficient duration or during their next planned
refueling outage in April 1994.
Back round
The licensee initiated this modification to address
a generic
concern for dissolved
gases
accumulating in the reference
legs of
the reactor vessel
water level instrumentation
in boiling water
reactors
(BWR).
A high concentration of dissolved
gases
in the
reference
legs
has the potential to cause reactor vessel
water
level deviations
known as "notching".
A generic modification had
been developed
by the Boiling Water Reactor
Owner's
Group
(BWROG)
to continuously backfill the reference
legs with water containing
a low dissolved
gas concentration
in order to reduce the
concentration of dissolved
gases.
-11-
Potential
problems with this generic modification were described
in NRC Information Notice 93-89, "Potential
Problems with
Level Instrumentation Backfill Modifications".
The information
notice described
the potential effects of the inadvertent
closure
of a existing manual
root valve in the instrument line and the
severe reactor transient
which would result.
At WNP-2, the modification also introduced
a potential
pressure
source
from the Control
Rod Drive (CRD) system,
which provided
a
small continuous backfill.flow into each reference
leg for the
level instrumentation.
Inadvertent isolation of a reference
leg
from the reactor vessel
would result in the reference
leg being
pressurized
by the
CRD pump, thereby causing the instrumentation
connected to the reference
leg to indicate erroneous
plant
conditions.
Each reference
leg supplied other instruments
in
addition to the reactor vessel
water level instrumentation.
For
the worst case,
one
common reference
leg supplied the pressure
switches
associated
with automatic opening of 18 safety relief
valves
(SRVs).
Consequently,
the inadvertent pressurization
of
the one reference
leg that controls the actuation of the
18 SRVs
would result in the lifting of all
18 SRVs
and
a blowdown of the
reactor coolant inventory.
At WNP-2 all of the
18 SRVs can
be self-actuated
(spring lift) or
power-actuated
(pneumatic).
The
SRVs self-actuate
to lift as
Code safety valves.
In addition, the
SRVs are actuated
automatically to control
steam pressure
during
a large load
rejection.
Additionally, the Automatic Depressurization
System
(ADS) utilized seven of the
SRVs as part of the
ECCS system to
blowdown the reactor coolant system in the event of a small break
LOCA, to allow the function of low pressure
injection.
However,
the inadvertent pressurization
of one instrumentation
reference
leg would only actuate
one channel of the sub-logic for the
ADS,
but would not cause
an actuation of the
ADS.
Observations
The inspector
found that the licensee
had evaluated
and the consequences
of inadvertent
instrumentation
line root valve closure
as part of their safety evaluation for the
modification.
For the worst case
instrument line, the licensee
had determined that the inadvertent closure of the .manual
isolation valve with the backfill system in operation would
increase
pressure
in the instrument line up to the
CRD system
pressure
of 1450 psi, which exceeded
the normal reactor
pressure
of 1050 psi.
The instrument line pressurization
would result in
the simultaneous
false signals of low reactor vessel
water level
and high reactor pressure.
The false high reactor pressure
signal
would actuate
the pressure
switches for all of the
18 safety
relief valves
(SRV) because
the pressure
sensed
was from one
common instrument line.
Since the normal
CRD pressure
exceeded
12
the setpoint for the
SRV relief function, all
18
SRVs would open
and blowdown of the reactor coolant system into the suppression
pool would occur.
The licensee
indicated that this blowdown would
not be bounded
by the
FSAR analysis,
which addressed
only the
inadvertent
opening, of one
SRV.
Another consequence
of the inadvertent pressurization
of an
instrument line was that
one 'division of the residual
heat
removal
and low pressure
(RHR/LPCS)
systems
would be inhibited
due to the false high reactor pressure
signal.
Despite actual
depressurization
of the reactor coolant system resulting from the
SRV blowdown, the low pressure
permissive interlocks for the
RHR/LPCS injection valves would prevent the valves from opening
due to the false high reactor pressure
signal.
However, the other
division of RHR/LPCS low pressure
injection would be available,
unless
a single failure was
assumed.
The most critical single
failure that the licensee
assumed
was the failure of the low
pressure
injecti'on line interlock for the opposite division.
In
that case,
the licensee
concluded that the operators
would not
have low pressure
injection available
and core
damage
would most
likely result,
except
as mitigated
by the
Emergency Operating
Procedure
(EOP) actions for beyond-design-basis
accidents
using
nonsafety-related
systems for core flooding.
The inspector
discussed
the vulnerability of the licensee's
design
in comparison with the other designs
referenced
The inspector
found that the operators
at
WNP-2 did
not have
a keylock switch to bypass
the low pressure
injection
interlock permissive
as described
in the information notice
as
a
mitigating feature at another utility.
The WNP-2 backfill
injection point was
on the instrument rack side of the manual
isolation valve.
Other utilities referenced
in the information
notice with this design
had revised their original design to
inject on the reactor side of the manual isolation valve.
The inspector
noted that the licensee's
original design
recognized
the potential for the reactor coolant
blowdown scenario,
but the
licensee
had concluded that they had implemented
adequate
administrative controls to prevent the inadvertent closure of the
instrument root valves.
The administrative controls consisted of
a chain
and lock for the valve handwheel,
which was procedurally
controlled.
Because of the severe,
unanalyzed
event which could
occur at WNP-2 following the inadvertent closure of one
instrumentation line root valve, the inspector
was concerned
that
the licensee's
measures
to preclude inadvertent closure did not
appear to be appropriate.
Later, during the inspection, the
licensee
decided that more positive control of the valve was
warranted.
The licensee initiated
a revision to their design to
a device
on the
open root valve to preclude valve operation.
The licensee
has committed to complete this design modification
for the one root valve which affects all eighteen
SRV's.
- 13-
The inspector
also noted
an additional potential for an event
initiator beyond the potential for inadvertent closure of the
instrumentation
root valve discussed
The inspector
noted that the instrumentation
tubing from the
instrument rack to the root valve was exposed
to potential
damage
and inadvertent
crimping.
At the time of inspection,
the tubing
was in an area
where scaffolding
had
been erected for an upcoming
unrelated modification.
The tubing had
a 1/2-inch outer diameter
and
a wall thickness of 1/16-inch.
Therefore,
the inspector
concluded that it was susceptable
to being crimped or crushed.
In
addition, the tubing contained
an expansion
loop which appeared
to
be especially vulnerable to damage.
Additionally, the inspectors
noted that there
was
a potential for
a foreign object to block the small
passages
in the line.
Compo-
nents,
such
as the excess
flow check valves
and flow limiting
orifices, contained restricted
passages
which could become
blocked
by foreign objects
from normal maintenance
tasks
on the instrument
racks.
The inspector
recognized
the fact that maintenance
work is
performed under cleanliness
controls,
but was concerned that these
controls
may not be completely effective to preclude the
occurrence.
The inspector
also noted that there could
be other
methods for line blockage,
which had not been
addressed.
Discussions
with the licensee
indicated that the blocking of the
instrumentation line, the opening of all eighteen
valves to the
suppression
pool,
and the subsequent
reactor transient
were not
bounded
by accidents
described
in the
FSAR.
10 CFR 50.59 Evaluation
The inspector
reviewed the
10 CFR 50.59 evaluation
performed
by
the licensee for the backfill modification and discussed
the basis
for the licensee
evaluation with cognizant licensee
personnel.
The licensee
had concluded that the modification did not involve
an unreviewed safety question.
The licensee
considered that the
circumstances
necessary
to block the instrument line either
through valve closure or any other mechanism
were not credible
occurrences.
The licensee
considered that the potential
accident
resulting from the closure of the root valve with the backfill
system in operation
was less likely than the events
analyzed in
the
FSAR since closure of the root valve would require,
what the
licensee
considered
to be,
two active failures (or operator
errors).
The licensee
stated
the first failure (or error) would
be the issuance
of the key by the shift supervisor
and the second
failure would be the use of the key by an operator to unlock and
close the valve.
The licensee
stated that the modification met
the single failure design criteria since
no single failure would
result in closure of the root valve.
Therefore,
the licensee
considered that they had met the single failure criteria and
had
established
adequate
preventative
measures
to assure that
a new
accident scenario
would not be introduced
by the modification.
-14-
The licensee identified that their
10 CFR 50.59 evaluation
used
two screening criteria for addressing
the question of whether
a
new accident
cou')d
be created
by a modification.
The first
criteria addressed
whether
a new accident
could
be created.
The
second criteria addressed
whether that
new accident
was credible.
The licensee
used the industry guidance
contained
in Nuclear
Management
and Resources
Council,
NSAC 125, "Guidelines for
10 CFR 50.59 Safety Evaluations," in'onducting their 10 CFR 50.59
evaluation.
The guidance
contained
an example which stated that
meeting the single failure criteria was sufficient.
That is, if
multiple safety system failures were required to initiate
a new
accident,
then the
new accident
would not be considered
credible.
The guidance established
that meeting the single failure design
criteria assured
that the probability of occurrence of subsequent
accidents
due to the failure of the safety
systems
to perform
their safety function would be equivalent to that of the accidents
originally analyzed in the
FSAR.
The licensee's
10 CFR 50.59 evaluation for the backfill
modification considered that multiple failures of administrative
controls would be required to initiate the
new accident.
The
licensee
also considered
that the redundant administrative
controls satisfied the single failure criteria for the system
design,
in that multiple administrative failures would be required
to initiate the accident scenario.
As
a result,
the licensee
concluded that the modification did not introduce
an accident of a
new type because their design satisfied their interpretation of
single failure criteria.
The inspector did not agree with the
licensee's
interpretation that the breaching of two administrative
control systems
would constitute
two independent
single failures.
The inspector considered that the closure of a single valve
constituted
a single failure, regardless
of how many
administrative control boundaries
were established.
Conclusions
The inspector
concluded that the engineering
and technical
support
groups
had
been actively involved in the development of the
modification for the backfill system.
For example,
the licensee
had participated
in the
BWROG testing in the development of the
generic modification,
and
had conducted
extensive
mockup testing
and preoperational
system testing
had
been
conducted to verify and
optimize the system performance prior to installation.
In
addition, the inspector
found that the licensee
had coordinated
inputs from Operations,
Maintenance,
Engineering
and industry in
the expeditious
development
and installation of the modification.
However, the inspector identified unresolved
concerns
in the
following areas:
~
The adequacy of the proposed backfill modification from the
standpoint of the credibility of initiating an unanalyzed
event through the blockage of a single instrumentation line
from any line blocking mechanism.
~
The adequacy of the licensee's
10 CFR 50.59 review and
safety analysis
determining whether the modification
involved an unreviewed safety question.
The licensee
acknowledged
the inspector's
concerns.
These
concerns wil'i be considered
an unresolved
item pending further
NRC
review.
(Unresolved
item 50-397/94-02-01)
Excess
Flow Check Valves
The inspector identified
a separate
issue regarding
containment
integrity as
a result of the review of the
BWR backfill
modification.
The inspector
had reviewed the design of the excess
flow check valves installed in the instrument lines involved in
the backfill modification for the reactor vessel
water level
instrumentation.
The inspector
found that the excess
flow check
valves contained
an integral
manual
bypass
valve which was
normally closed.
However,
these
manual
bypass
valves
had not been
included in the list of manual
containment isolation valves that
were required to be locked closed or verified shut every 31 days
in accordance
with the Technical .Specification requirements.
The function of the manual
bypass
valve was to temporarily
equalize
pressure
across
the excess
flow check valve after
actuation of the excess
flow check valve.
This allowed the check
valve return spring to restore the check valve to an open
position.
The inspector found that the manual
bypass
valve was
not uniquely identified on the plant drawings.
In addition, there
was
no position indication for the manual
bypass valve, either
locally or remotely in the. control room..'The inspector
was
concerned that, if the valve was left open, it would bypass
the
excess
flow check valve which was credited in the
FSAR as
an
automatic containment isolation valve in accordance
with the
guidance of Regulatory Guide l.ll, "Instrument Lines Penetrating
Primary Reactor Containment."
The licensee
indicated that they had
an informal practice of
removing the valve handle after closing the valve and storing the
handle in the control
room to preclude unauthorized
manipulation.
However, the inspector noted that several
manual
bypass
valve
handles
were installed,
which indicated that this informal
practice
was not always carried out.
In response
to the inspector's
concern,
the licensee initiated
PER
240-032.
The licensee
performed
a surveillance of all accessible
-16--
excess
flow check valves
and found that they were all correctly
positioned.
Based
on the results of their surveillance,
the
licensee
concluded that all the manual
bypass
valves
were closed.
In addition, the licensee
added the manual
bypass
valves to
Surveillance
Procedure
PPH 7.4.6.1. 1 pending the resolution of the
PER.
The licensee
stated that they did not consider the Technical
Specification surveillance
requirement to be applicable to the
manual
bypass
valves.
Although they noted that the excess
check
valves were identified in Technical Specification Table 3.6.3-1
as
containment isolation valves,
they stated that neither the excess
flow check valves,
nor the integral
manual
bypass
valves were
required to close in an accident.
The licensee
stated that they
based their position
on the
FSAR Chapter
15 analysis of the
blowdown and dose
consequences
which did not take credit for the
check valve functioning in the event of an instrument line break
outside of containment.
Nevertheless,
the inspector
concluded that the excess
flow check
valves were required to be closed in an accident.
The inspector
based this position
on the following Technical Specification
requirements
for operable
excess
flow check valves
and the
guidance of Regulatory
Guide
1. 11.
Technical Specification 3.6.3 required that the reactor
instrumentation line excess
flow check valves,
shown in
Table 3.6.3-1 to "...be
OPERABLE during
OPERATIONAL
CONDITIONS 1,
2 and 3."
Regulatory Guide 1.11 provided guidance that each
excess
flow check valve should function as
an automatic isolation
valve in order to satisfy General
Design Criteria 55 and
56
(for containment integrity).
Regulatory
Guide 1. 11 stated that "...there should
be
a high
probability that the valve...will close if the instrument
line is ruptured downstream."
Regulatory
Guide l. 11 provided guidance that each instrument
line contain
a flow-restricting orifice appropriately sized
to independently limit the consequences
of an instrument
line failure outside of containment.
The inspector found
that the
FSAR Chapter
15 analysis
supported
the appropriate
sizing of the orifice; however,
the
FSAR analysis did not
obviate the need for the excess
flow check valves to perform
the safety function to automatically close
as isolation
valves.
FSAR Paragraph
6.2.4.3.2.4
stated,
in part,
"The Excess
Flow
Check
(EFC) valves
each
have
an integral
manual
bypass
valve
17-
which may be used to reset
an actuated
disc.
In order to
minimize a possible potential
impact upon the integrity and
functional performance of the secondary
containment
and its
associated filtration systems
should
an instrument line
failure occur, the bypass
valves
are periodically verified
to be closed."
Conclusion
Technical Specification 4.6.1. l.b required that all non-automatic
containment isolation valves that are required to be closed during
an accident
be checked monthly to demonstrate
integrity.
Licensee
procedure
PPH 7.4.6. 1. 1, "Primary Containment
Integrity Verification," implemented
the surveillance
requirement
of TS 4.6.). l.b.
The inspector
found that the manual
bypass
valves for 115 excess
flow check valves identified in Table 3.6.3-
1 were not included in the Surveillance
Procedure
PPH 7.4.6.1. 1.
The failure to verify that the manual
bypass
valves for the
115
excess
flow check valves specified in Technical Specification
Table 3.6.3-1
were closed or locked in their closed position is
a
violation of Technical Specification 4.6.1. 1.b. (Violation 50-
397/94-02-02)
4.1.2.4
Incorrect Orifice Size
The inspector identified .another
problem regarding
improper
instrument line orifice sizes
as
a result of the review of the BMR,
backfill modification.
The inspector
found that the Haster
Equipment List (HEL) identified that 0.375-inch diameter orifices
were installed in the instrument lines for the water level
instrumentation.
However,
FSAR Chapter 15.6.2,
"Instrument Line
Break Analysis," indicated that the blowdown analysis for a
rupture of an instrument line was based
on )/4-inch diameter
orifices.
The licensee
subsequently
determined that the larger
orifices had been .installed during original construction
and
potentially affected all
115 instrument lines.
The licensee identified that
an orifice was installed in each
instrument line per Regulatory
Guide 1. 11 to limit releases
in the
event of a break of the instrument line to 10 CFR Part 100 limits.
Regulatory
Guide 1.11 stated that the combination of an orifice
and excess
flow check valve was
an acceptable
alternative
design
for two automatic isolation valves for the containment isolation.
In addition, the licensee
indicated that their
FSAR safety
analysis calculations for offsite releases
had
been
based
on the
1/4-inch orifice sizes.
The licensee initiated
a problem evaluation request
(PER)
on
January
27,
1994, to resolve the issue.
Their initial analysis
indicated that the larger size orifice would be acceptable
and not
significantly change
the
FSAR Chapter
15.6.2 analysis.
The
-18-
licensee
also stated that they considered that they would be able
to justify the adequacy of the larger orifices, recognizing the
fourfold increase
in the blowdown into the secondary
containment
and the dose
consequences.
The inspector considered that the initial licensee
actions
were
adequate.
However, this item is considered
an unresolved
item
pending review of the licensee's
evaluation of the radiological
consequence,
and the root cause of the discrepancy
between
the
as
.
built orifice sizes
and the
FSAR description.
(Unresolved
item 50-397/94-02-03)
1
4.1.3 Conclusions
4.2
The inspector concluded that engineering
appeared
to be actively
involved in ongoing modifications.
For example,
they were actively
involved in the identification and resolution of a longstanding
technical
issue involving leaking containment
supply
and exhaust
isolation valves.
The inspector also observed that engineering
had
been
actively involved in the development of the reactor vessel backfill
modification.
Their activities included involvement with the
BWROG in
the development of the modification,
as well as close coordination with
operations
and maintenance.
The inspector
concluded that the licensee
performance
in the
impl.ementation of the reactor vessel backfill modification could have
been
improved.
Specifically, the inspector identified unresolved
items
regarding,
(1) the credibility of initiating an unanalyzed
event through
the blockage of a single instrumentation line; (2) the adequacy of the
licensee's
10 CFR 50.59 review and safety analysis;
and
(3) improper
instrument line orifice sizes.
The inspector also identified a
violation involving the licensee's
failure to periodically verify that
the manual
bypass
valves for the
115 excess
flow check valves were
closed
o) locked in their closed position.
Completed Nodifications
4.2.1
Sample
and Criteria
The inspector performed
a limited review of completed modifications.
In
addition,
NRC Inspection
Report 50-397/93-25,
issued
August 13,
1993,
examined six design
changes for conformance to regulatory criteria.
That inspection
found that the design
changes
generally
met the
regulatory criteria.
However, the inspection
also identified one
violation for failure to update preventative
maintenance
records
pursuant to the modification.
During this inspection,
the inspector
reviewed several
modifications
including Plant Modification Request
(PHR) 91-0309-0,
"Diesel Generator
Heat Exchanger Service
Water
Flow Balance."
The objective of the review
was to assess
whether the modification package
was well-organized,
the
-19-
4.3
modification was clearly described,
the design calculations
were
correct, the
10 CFR 50.59 evaluations
were adequate,
and the post-
modification test requirements
and acceptance
criteria were accurately
specified.
4.2.2 Findings
The inspector found that the modification met the regulatory
requirements.
However, the inspector
noted
one minor discrepancy
wherein the modification description
was not clear.
Specifically, the
modification description stated that, "It is the intent of this
modification to distribute at least
45K of the total service water flow
to the two heat exchangers
in each loop to any one heat exchanger....
Additionally, the ability to achieve
a combined flow rate of 1650
gpm
for both heat exchangers
in each loop must
be confirmed."
The inspector
noted that 45 percent of 1650
gpm is 742.5
gpm, which was less than the
825
gpm described
in the reason for the modification.
The licensee
agreed that the reference
to 825
gpm in the modification package
was
misleading.
The inspector's
observation
did not constitute
a safety
concern,
and was provided to the licensee
as
an observation.
4;2.3 Conclusions
Based
on the results of Inspection Report 50-397/93-25
and this
inspection,
the completed modifications generally
appear to meet
regulatory requirements.
Temporary
and Minor Modifications
The inspector reviewed the licensee's
overall program for control of
Temporary Hodifications
(THODs).
The purpose of the review was to
determine
how well the licensee
was managing the
number of THODs and the
level of involvement by operations
and engineering
personnel
in the
THOD
process.
4.3.1
Sample
and Criteria
The inspector reviewed the licensee's list of active
THODs and selected
two safety-related
modifications for review.
This review included
discussions
with the system engineer
and operators
concerning the
modification,
and
a field verification of the modification installation.
The purpose of the review was to determine if: (1) the
THOD was
developed,
reviewed,
and implemented
per plant procedure
manual
(PPH)
1.3.9,
"Temporary Hodification Control," (2)
a proper
evaluation
was conducted,
(3) plans to restore
the
THOD or install
a
permanent
design
change existed,
and (4) all necessary
technical
and
regulatory requirements
were addressed
in the
THOD.
4.3.2 Findings
4.3.2. 1
Overall
Program
Review
The inspector
noted that the number of active
THODs was reduced
from 34 in April 1993 to 15 with a goal of 10 after the next
refueling outage.
One shift manager
was assigned
to ensure that
operations
personnel
played
an active role in the
THOD process.
Participation in the process
was evident
by the knowledge the
operators
had concerning .the status of the active
THODs,
and also
by routine audits of the
THOD log.
,Several of these audits
identified administrative errors in some of the
THODs,
and the
shift managers
were holding the system engineers
accountable
to
correct the errors.
Although this type of management
oversight
was not evident earlier in 1993
(see
NRC Inspection
Report 50-
397/93-24),
the inspector
concluded that the licensee
had improved
their oversight of THODs.
4.3.2.2
Hain Steam Isolation Valve (HSIV) Modification
The inspector
reviewed Temporary Modification Request
(THR) 93-
004.
This
TMOD installed resistance
temperature
detectors
(RTDs)
on the main steam isolation valve (HSIV) limit switches in the
steam tunnel to establish
an accurate
temperature profile for the
limit switches.
The limit switches
were moved in 1990
as part of
a design
change
so that they were further from the steam lines.
The
TMOD was installed to quantify the actual
temperature profile
so that the equipment qualification (Eg) life of the limit
switches could be validated.
The limit switches
had
a calculated
Eg life of 2.7 years,
and were replaced
every two years.
"
The inspector
concluded that the
THOD was properly processed
and
installed per 'the licensee's
procedures.
Additionally, the
10 CFR 50.59 safety evaluation
was thorough.
For example,
the effect of
the additional weight of the
RTDs on the seismic design
requirements
was included in the evaluation.
Overall, the
inspector concluded that the installation of the
THOD was
a good
initiative by engineering.
4.3.2.3
Disabled Control
Room Annunciator
t
The inspector reviewed
THDD 92-012,
which was installed in 1989.
This
THOD disabled
a continuous
alarm input caused
by
the abnormal position of the switch in the fire remote transfer
panel
(FRTP) for Fan WA-53B, the recirculation fan for the
Division 2 switchgear
room.
The switch was purposely kept in the
abnormal
emergency position to ensure that the control for this
fan was maintained at the
FRTP.
This was necessary
as
a temporary
remedial
action
due to
a licensee-discovered
condition where
a
degraded
voltage condition would prevent starting the fan from the
control
room.
The fan operation
would be satisfactory if the fan
-21-
were started
from the
FRTP.
This problem with the degraded
voltage condition was documented
in LER 89-013,
Plant Engineering
Request
(PER) 2-89-0323,
and Nonconformance
Report 289-0322.
By
disabling this particular annunciator,,an
alarm would be received
if any of the other remote transfer switches
were placed in the
emergency position.
The inspector
observed that the appropriate
plant procedure
manual
(PPH)
had been
changed to allow control of
the fan from the
FRTP.
Additionally, the inspector
noted that the
10 CFR 50.59 screening
process
at the time of the change (i.e.,
1989) did not require
an
evaluation or justification of the abnormal condition since the
normal location of fan control
was not described
in the Final
Safety Analysis Report.
However, the inspector
noted that the
licensee
had recently improved their 10 CFR 50.59 process
due to
weaknesses
identified in NRC Inspection
Report 50-397/93-36.
The
licensee's
new procedure for 10 CFR 50.59 evaluations
would have
required. an evaluation of the condition.
The inspector further
concluded that,
even though
an evaluation
was not performed,
normal operation of the fan from the
FRTP did not adversely
impact
overall plant safety.
The inspector
concluded that
a permanent solution for the problem
had not been aggressively
pursued
by the licensee.
Even though
the licensee
stated in LER 89-013 that the operation of the fan
from the
FRTP was
a "temporary solution", the licensee
allowed the
abnormal situation to exist for almost five years.
The inspector
noted that
a plant modification request
(PHR) was initiated to
correct the problem by installing
a voltage regulator in the
control
room starting circuit; but the
PHR was continually
deferred
due to higher priorities.
The inspector also noted that
the licensee's
current efforts to identify and reduce the number
of old THODS also identified this particular delay in implementing
a correction to the situation.
As
a result,
PHR 92-083
was
approved
and scheduled for refueling, outage
R-9.
Inadvertent
Design
Changes
The inspector
reviewed completed valve lineup sheets
and the
Component Status
Change Order
(CSCO) log to determine if any
inadvertent
design
changes
had
been introduced
by the changes
to
the valve lineups.
The inspector identified one inadvertent
design
change
and
a valve lineup discrepancy.
Post Accident
Sam le
S stem
Demineralized
Mater
valves
The inspector noted that valves
DW-757 and DW-758, which are
supply isolation valves for the residual
heat
removal
(RHR)
sample flush lines,
had
been cautioned-tagged
shut since
1987.
The valves were originally shut in 1987 due to leakage
past
two
isolation valves
and
a check valve which caused
contamination of
-22-
the
DW system
from the
RHR system.
One of the isolation va')ves
and the check valve were repaired;
however,
DW-757 and
DW-758
remained
shut
as
a precaution to preclude further
contamination.
The primary isolation valves,
PSR-Y-003A and
PSR-
V003B, were not repaired.
There
was
an
open work order for
these valves,
but it continued to be deferred.
The inspector
observed
a chem'istry technician simulate taking
a
PASS sample
from the
RHR system
and noted that the procedure
being
used could not be completed
as written since the sample lines
could not be remotely flushed per the procedure's
requirements.
Entry into high radiation
areas
would have
been required to
manually open the isolated valves.
The inspector
concluded that
keeping the
DW valves shut for seven years
was
an inadvertent
design
change in that the ability to remotely flush the sample
lines was removed.
Although
PER 293-317
had
been written, it only
documented
the problem with the system leakage.
The licensee
had
not evaluated
the effect of not being able to flush the sample
lines
on general
area radiation levels if a sample
was required
during
an accident.
The inspector concluded that the safety significance of the
inability to remotely flush the
PASS sample lines after
an
accident
sample
was minimal because
operability of the
PASS system
was not affected
and there
was
no requirement to perform the
flush.
However, the inspector
noted that the flush was
a prudent
measure to reduce general
area radiation levels.
PASS Valve Lineu
Discre
anc
During a review of the
CSCO log in the control room, the inspector
noted that manual isolation valves
RHR-746 and
RHR-747 were listed
as shut.
The valves were
on
PASS sample lines from the
system.
The normal position of the valves
was open to allow
obtaining
a remote
PASS sample of the
RHR system using other
solenoid-operated
valves.
The date of the
CSCO sheet
was Hay 1,
1993.
Further
review identified another record,
the master
system
valve lineup, which indicated that the valves were opened
on
June
10,
1993.
The licensee
conducted
a field .verification and
determined that the valves were opened
as
shown
on the master
system valve lineup.
The licensee
then corrected
the
CSCO entry.
The inspector
noted
a procedure
weakness,
in that the
administrative
procedures
for controlling the
CSCO log did not
provide any instructions to review the
CSCO for necessary
updates
after performing the master
system valve lineups.
-23-
Corrective Actions
The licensee
conducted
an audit of the
CSCO log and the master
valve lineup data sheets
and identified several
other
discrepancies
between the valve lineups
and the
CSCO log.
None of
these
errors were safety significant.
In response
to this
concern,
the Operations
Hanager instituted
a new administrative
requirement to audit the
CSCO logs every 28 days.
In addition,
the license initiated
a change to
PPH 3.1. 1, "Haster Valve
Lineup," to require shift managers
to review the
CSCO when
a
master lineup was completed.
The inspector concluded that the
licensee's
actions
were appropriate.
4.3.3 Conclusions
The inspector
concluded that the licensee
had initiated programs
which
significantly improved their oversight
and management
of the
THOD
program.
Additionally, program oversight
appeared
to be effective, in
that the age
and number of temporary modifications were being
significantly reduced.
Although the inspection identified one minor problem regarding
a
longstanding
temporary modification involving an abnormal position of
the switch on the fire remote transfer
panel for the recirculation fan
for the Division 2 switchgear, this problem had
been previously
identified by the licensee's
program
and corrective action
had already
been scheduled for the next outage.
Two minor problems were identified in the area of temporary
modifications.
One problem involved an inadvertent
design
change to the
PASS system
caused
by closing normally-open,
manually-operated,
demineralized
water valves.
As
a result,
the ability to remotely flush
portions of the
PASS to reduce
area radiation levels
was removed.
A
second
problem involved
a weakness
in the administrative
procedures
for
control,ling valve lineup exceptions.
The licensee
took appropriate
corrective action for these
problems.
No violations or deviations of NRC requirements
were identified.
5.0
5.1
Engineering
Involvement in'lant Problems
Nonconformance
Review
5.1.1
Sample
and Criteria
The inspector reviewed the Quality Assurance
(QA) procedures
addressing
the identification and processing of plant problems to verify
conformance with regulatory requirements.
The inspector selected
15
Nonconformance
Reports
(NCRs) out of a total of 64 issued in 1993.
These
15
NCRs were reviewed for evidence of engineering
involvement with
the resolution.
-24-
5.1.2 Findings
NCR Review
The inspector found that
11 of the
15
NCRs required,
and received,
engineering
support in resolving the technical
issues
affecting the
plant.
Engineering
support
was evident in the form of design
changes,
design calculations,
evaluations of proper set points,
performance of
probabilistic risk analysis
(PRA),
and root cause analysis.
The
remaining four NCRs required
no engineering
input.
Lack of Overview of PERs
The inspector
observed that Plant Procedures
Hanual
(PPH) 1.3. 12,
"Problem Evaluation
Request
(PER)," described
the method for initiation
of a
PER to report potential
or actual
conditions adverse
to quality.
PPH 1.3. 12, Section 6.0, required that
an individual discovering
a
condition adverse
to quality document the condition by initiating a
PER.
However, not all potential plant problems
were required to be logged in.
Only those
problems
determined
by the supervisor
as being valid were
logged in and assigned
a
PER number.
Problems judged not to warrant
a
PER were returned to the originator with the reason
described
on the
form.
5.2
The inspector
concluded that
PPH 1.3. 12 did not provide strong
provisions for overview of non-valid
PERs.
The inspector
was concerned
that in the event of an error in judgement
on the part of the supervisor
potential plant problems
which might represent
actual
conditions
adverse
to quality would not receive
any oversight.
The licensee's
process
did
not provide for any additional
overview beyond the supervisor's
screening.
The inspector discussed
his concerns with the licensee.
The licensee
committed to revise
PPH 1.3. 12 to require non-validated
PERs to be
filed, and also to perform periodic quality assurance
audits of the
files.
The licensee's
actions will be reviewed in a future inspection.
{Followup It'em 50-397/94-02-04)
5.1.3 Conclusi.ons
The inspector
concluded that the sampled
nonconformances
indicated that
engineering
involvement was evident in the identification and resolution
of technical
issues
affecting the plant.
Engineering
Involvement in the Reactor
Pressure
Vessel
(RPV)
Nozzle/Safe-End
Stress
Improvement
Process
5.2.1 Sample
and Criteria
The inspector
assessed
engineering
involvement through
an examination of
the engineering
controls over
a planned,
complex,
maintenance activity
-25-
which involved the reduction of reactor pressure
vessel
{RPV) stresses.
The inspector
examined the selection of the contractor,
the review of
contractor procedures,
and the adequacy of contractor quality control.
The purpose of this review was to evaluate
the adequacy of engineering
involvement
and to ensure
compliance with regulatory requirements
and
industry codes
and standards.
5.2.2 Findings
In response
to
"NRC Position
on
IGSCC in
BMR
Austenitic Stainless
Steel Piping," dated January
25,
1988, the licensee
was planning to perform stress
improvement
on 44 weld joints of the
nozzles
and safe-ends.
The stress
improvement technique
planned
was the
use of the Mechanical
Stress
Improvement
Process
(HSIP).
NSIP was
considered
by the
NRC technical staff to be
a qualified process
for
~
providing resistance
to intergranular
stress
corrosion cracking
{IGSCC)
in
BWR austenitic stainless
steel piping.
The stress
improvement
was
scheduled
to be completed
in 11 days during the next refueling outage
in
April 1994.
The inspector reviewed the procurement
documents that qualified the
contractor,
AEA O'Donnell, Inc., to be placed
on the licensee's
Evaluated Supplier List (ESL).
The audit of the contractor
was
performed
by the Nuclear Procurement
Issues
Committee
(NUPIC),
an
external
organization
whose
members
represent
various nuclear utilities
and licensees.
The inspector
found that Procurement
Engineering's
evaluation of the
NUPIC audit appropriately
addressed
the licensee's
requirements
for the scope of work to be provided.
The inspector also
found that the contractor's
gA program included controls of their
subcontractors.
The inspector
reviewed Contract
Number
C30831,
dated
December
8,
1993,
for AEA O'Donnell, Inc.
The inspector verified that the contract
included
a provision that the supplier have
a documented guality
Assurance
(gA) program that:
(1) complied with the requirements of
10 CFR 50, Appendix B, and (2) extended
appropriate
gA requirements
to
sub-tier suppliers.
The inspector also confirmed that the contract
included supplier acknowledgement
for reportability pursuant to 10 CFR Part 21, "Reporting of Defects
and Noncompliance."
Contract
C30831,
Appendix A, "Statement of Mork," required the
contractor to provide the following to the Supply System .by January
14,
1994:
(1) procedures
that would be used for the stress
improvement
process,
and (2) information about
any special
equipment that would be
brought
on site.
The inspector
was informed by the licensee that both
these
requirements
were met by the required date.
Licensee responsibilities for the MSIP program were
shown in
Attachment
5 of Contract
C30831.
Specific responsibilities
included
approval of the
AEA O'Donnell, Inc., engineering
procedures,
training
program, field service procedures,
and nonconformance
reports.
Review
-26-
and approval of the contractor quality control
(gC) inspector's
qualifications
was specified in the contract
as
a licensee
responsibility.
During the inspection,
the licensee
was in process
of
revising the contractor's
HSIP traveler to include the licensee's
engineering
review and verification of process
acceptance.
5.2.3 Conclusions
5.3
The inspector
concluded that engineering
was actively involved in the
RPV nozzle
and safe-end
stress
improvement process
planned for the
upcoming outage.
This was evident
by the amount of engineering
oversight
and quality controls over the contractor's
mechanical
stress
improvement process.
Materhammer
Incidents in the Standby Service Mater System
(SSMS)
5.3. 1 Sample
and Criteria
The inspector reviewed engineering
involvement in waterhammer
incidents
in the Standby Service Water System
(SSWS).
The inspector reviewed the
completeness
and accuracy of the problem evaluation reports
(PERs)
including root cause
evaluations
and interim dispositions.
The
inspector also examined Engineering's
support to Systems
Engineering for
this problem.
5.3.2 Findings
The
SSWS
had experienced
waterhammer
problems for several
years.
The
problem occurred following pump starts
due to the fact that the system
piping drained
and emptied
when the system
was not in service.
The
licensee's
operational
strategy for avoiding these
waterhammer
events
was to automatically fill the system through
a time-sequenced,
controlled opening of Hotor-Operated
Valves
(HOV) SW-V-2A and
SW-V-2B
just downstream of SSWS
pumps
SW-P-1A and SW-P-18.
The valve opening
scenario
consisted of a 12-second
stroke time from full closure,
which
resulted in the valve opening approximately
20 percent;
followed by
a
50-second
hold period in the throttled position.
This sequence
allowed
flow to be gradually established
in the
SSWS,
and filled the system at
a
substantially
lower flow than full flow.
After the 50-second
hold
period, the valve resumed
opening to full-open position.
During a
previous inspection in February
1993, the inspectors
had examined the
waterhammer
problem,
discussed
the licensee's
operating strategy to
avoid waterhammer,
and witnessed
a test which demonstrated
the
satisfactory
system start without waterhammer.
The inspector discussed
the additional
waterhammers
that
had occurred
since the last team inspection
and examined the circumstances
surrounding the
new occurrences.
- 27
Valve 'Overstroke
Caused
Waterhammer
On November
15,
1993,
Loop
B of the
SSWS experienced
a waterhammer
event.
Problem Evaluation Request
(PER)
293-1319
was written to
investigate this event.
The licensee attributed the waterhammer
event
to the fact that butterfly valve SW-V-2B'ad overstroked its closed
position by 13 percent.
This condition was discovered after the valve
was
opened
and inspected.
At its closed position, the valve disk had
passed its central
stop position (i.e., the middle of the seating
surface).
This condition was possible with the particular butterfly
valves in use
because
of their large seating
surface.
As
a result of
the overstroked position, the licensee
determined that the valve had
opened only 3 to 5 percent
instead of the intended
20 percent during the
fitst
12 seconds of valve opening,
Consequently,
during the subsequent
50-second
hold period,
very little to no flow was provided to fill the
SSWS.
The licensee
confirmed this theory with plant computer data,
which indicated minimal to no flow had
been achieved.
During the
subsequent
stoke of the valve to the full-open position, flow entered
the almost empty
SSWS at substantial
flow rates
and caused
a
waterhammer.
Inade uate Guidance in Settin
Valve to Its Full
Closed Position
PER 293-1319 stated that the root cause for valve SW-V-2B overtravel
was
inadequate
guidance in the Motor-Operated
Valve
(MOV) Master
Data Sheet.
The Master
Data Sheet
contained
applicable information on the
MOV such
as switch setting
and stroke time requirements.
It did not contain
information which required the closed position to be checked for angle.
The overtravel condition was established
when
a closed limit switch
adjustment
was
made
on May 14,
1993, during
a baseline
MOV test.
The
licensee's
test procedure
required the Master Data Sheets
to be used
along with the maintenance
work request for setting
up the valve
parameters.
The licensee
stated that during the
MOV baseline test,
the
technicians
followed the standard practice of adjusting the closed limit
switch until an increase
in the torque required to close the valve was
detected.
This practice
had
been successful
previously
on butterfly
valves with small seating
areas,
but was apparently not appropriate
for
valve SW-V-2B, which had
a large seating
area
and needed to open to a
precise throttle position.
The wide seating
surface
introduced
a
substantial
error in the opening
angle to initiate flow.
The licensee
stated that they planned corrective action .to revise the
Master Data Sheet to specify that valve SW-V-2B was fully closed
when
the stem keyway was directly in line with the
SW pipe centerline,
thus
eliminating the angular error.
The inspector considered
the licensee's
action appropriate.
A
arent Differences in Valve 0 enin
Times
In examining the event data,
the inspector
noted
an inconsistency
in the
opening time data recorded for valve SW-Y-2B.
The data taken
on May 13,
-28-
1993, for ASHE inservice testing
(IST) stroke time trending
and data
taken
on May 16,
1993, for a special test for Generic Letter 89-10
testing of motor-operated
valves differed by 12 seconds.
The inspector
noted that the timing of the valve's
opening
was controlled by an
Agastat time delay relay,
SW-RLY-V/2B5.
Consequently,
the inspector
also
examined
the periodic relay calibration records
and found that the
Agastat relay had
an as-found setting of 62 seconds,
which was proper
and consistent with the expected results.
However, the inspector
noted
that the motor-operated
valve test data recorded for the Generic Letter,
special test using
a diagnostic
computer
had recorded
a stroke time of
50 seconds;
even though the
IST test data
showed
a 62-second
timeout.
The licensee
had not investigated
the cause of this
12 second difference
between the apparent
valve stroke times for SW-V-2B.
This difference
was mentioned in the
PER 293-1319,
but had not been
pursued
by the
licensee.
During the inspection,
the licensee
prepared
PER 294-0051 to
address
the cause of the apparent difference.
The inspector
concluded that the licensee's
actions in response
to the
inspector-identified
problem appeared
to be appropriate.
Furthermore,
the inspector concluded that the licensee
should
have independently
noted
and responded
to the differences
in stroke time data.
I
Abandonment of the
SSWS
Kee -full S stem
The inspector
observed that in October
1993, the licensee
had abandoned
a nonsafety-related,
keep-full system which had served the
SSMS.
Although the system
had not been fully effective in keeping the
SSWS
full due to excessive
valve leakage,
the system
abandonment
appeared
to
coincide with the reappearance
of system waterhammer.
The assessment
performed
by the licensee
in mid-1993 concluded that the keep-full
system
was not needed for the prevention of waterhammer.
The inspector
noted that
PER 293-1319 did not address
the abandonment
of the keep-full
system in its assessment
of the recurrence of SSWS waterhammer.
The
inspector also noted that no waterhammer
events
had been recorded
from
Hay 16,
1993, until the shutdown of the keep-full system.
The licensee
stated that they would reassess
the keep-full system's
role in causing
waterhammers.
The inspector considered
the licensee's
actions to be appropriate
in
response
to the inspector's
question.
Ina
ro riate Interim PER Dis osition
In review of the event records,
the inspector noted
an interim
disposition of PER 293-1319 which did not appear
to have
a sound
technical
basis.
The interim disposition
by Systems
Engineering
compensated
for the overtraveled position of valve SW-V-2B by adjusting
the time-delay relay setting to add approximately
17 seconds
to the
original 12-second partial stroke time.
The inspector
calculated that
this would result in approximately
a 30 percent
valve opening.
This was
-29-
substantially larger than the previously successful
20 percent
opening
associated
with the 12-second
The inspector
was concerned that
a 30 percent
opening would
substantially
increase
flow and the chances for a waterhammer in the
SSMS.
Although, the licensee
indicated that post-modification testing
following the timing adjustment
on November 30,
1993, did not result in
a waterhammer,
the inspector
noted'that
another
waterhammer
occurred
on
December
2,
1993.
An assessment
performed
by Design Engineering after
this second
event confirmed that "...at roughly 30 to 35 percent of full
open position,
SM-V-2B can have full flow through the valve, which is
what the [plant computer] printout indicated."
The inspector
concluded
that System Engineering's
interim fix of a 17-second
opening stroke
was
not adequately
evaluated,
in that it did not prevent another
waterhammer
event.
Materhammer
Anal sis
Ca abilities
The inspector reviewed Design Engineering's
modelling of the last
waterhammer incident.
The licensee
used
a commercially-available,
computer program, "LI(T".
The program predicted
some general
trends;
however,
LI(T had not been validated for safety-related
applications
and
did not have the capability to calculate the dynamic loadings
due to
waterhammer
events.
The inspector
concluded that Design Engineering
had
developed
some capabilities to address
waterhammer,
but that the
capabilities
had not been developed to the degree that could predict
.
system performance
during
a waterhammer
event under various scenarios.
5.3.3 Conclusions
5.4
The inspector
concluded that the licensee's
examination of the
recurrence
of waterhammer in the
SSMS was not as thorough
as would be
expected
for
a repetitive problem.
The licensee
actions
appear ed to
stop short of a thorough examination
and the evaluation
appeared
to stop
at the first viable explanation of the event..
Additionally, the
licensee's
interim disposition to increase
the time of the initial valve
opening
was not adequately
evaluated
and
may have contributed to another
waterhammer
event.
Suspected
HPCS Materhammer
Event
5.4.1
Sample
and Criteria
The inspector reviewed engineering's
involvement in an event,
which
occurred at MNP-2 during the inspection,
to assess
the involvement
and
effectiveness
of engineering
support of plant activities.
Specifically,
the inspectot
reviewed
an event that was noted in the control
room log
on January ll, 1994, involving the performance of the quarterly High
Pressure
Core Spray System
(HPCS) Surveillance Test,
PPH 7.4.5. 11,
Revision
14.
-30-
5.4.2 Findings
The log entry documented
a noise the operators
had heard
and
characterized
as
a waterhammer.
The noise
was also heard in the
Radwaste
Control
Room.
The noise
was reported to have occurred
when
valves
HPCS V-10 and V-ll, in the flow test return line to the
Condensate
Storage
Tank, were closed
and the minimum flow valve,
HPCS V-
12, started to open.
The log further noted that the system
was walked
down and
no damage
was reported.
The test
was completed satisfactorily
and the system
was determined to be operable
since it met all the
requirements
of the test procedure
and
no system
damage
was evident.
Operations initiated Problem Evaluation Report
(PER)
294-0021
and
requested
that System Engineering resolve the deficiency.
The inspector reviewed the initial issue of the
PER and followed up on
engineering's
involvement in the investigation
and evaluation of the
event.
In addition, the inspector discussed
the event with the
Operations
Manager
and was briefed
by a plant support engineer,
who was
assisting
the system engineer.
5.4.3 Conclusion
5.5
The inspector
concluded that engineering
involvement during this event
was prompt, thorough,
and responsive
to the needs of the plant.
Engineering assistance
was evident,
and the appropriate
degree of
analysis
and root cause
determination
was performed.
Spray
Pond Icing
5.5.1
Sample
and Criteria
The inspector
examined the actions
taken
by the licensee
in response
to
questions
regarding
pond icing.
These questions
had
been raised
by the
NRC service water
team inspection
conducted
in February
1993,
and
documented
in NRC Inspection
Report 50-397/93-201.
~Back coood
In February
1993, the
NRC inspectors
had observed five inches of ice
covering the service water spray
ponds
and questioned
the operability of
the ponds from the standpoint of structural
adequacy
in an earthquake.
The ice had formed across
the pond
and was around the pipe supports
which supported
the spray nozzle piping rings.
It appeared
that the
weight of ice attached
to the supports
might be excessive
in a dynamic
seismic event.
The licensee
wrote Problem Evaluation
Request
(PER) 293-
140, dated February
5,
1993.
- The licensee
judged the condition to be
acceptable
and stated that
an evaluation
would be completed
by
November
1,
1993.
-'31-
5.5.2 Findings
The licensee
had closed the
PER on February
19,
1993,
based
on the
preparation of Request
For Technical
Services
(RFTS) 93-02-057 to
perform
a calculation.
The calculation
was recorded
on Calculation
Modification Record
(CMR) 93-0896,
dated October
21,
1993.
The
inspector reviewed the calculation with the cognizant structural
engineer.
The Supply System contra'cted with an outside consultant to
evaluate
the ice loading
on the pond structures.
The consultant's
report was
E(E International
Report,
"The Effect of Ice on the Support
Structures
Inside
WHP-2 Spray Ponds,"
dated October
1993.
The licensee
utilized the results of that calculation in conjunction with their own
calculations to evaluate
the effects of a seismic event
and found the
effects acceptable.
The inspector noted that the licensee
had not assessed
the worst climate
conditions for ice
and
had
assumed
that the five inches
observed
in 1993
was the worst case.
The licensee
also limited the study to
a continuous
five-inch slab of ice from pond wall-to-wall versus
forming in the
middle of the pond first near the exposed-to-atmosphere
metal piping and
structure
heat sink.
Although the inspector did not consider these
assumptions
to be conservative,
the inspector
noted that the licensee's
study was based
on
an analysis of the weakest structure in the pond,
which was conservative.
In response
to the inspector's
concern,
the l.icensee
performed
a further
study,
contacted
other agencies for historical weather information,
and
performed Calculation
CMR-94-0080,
dated January
24,
1994.
The licensee
concluded that the formation of ice was acceptable
and that the maximum
credible ice thickness,
based
on historical weather records,
was
10
inches.
The study concluded that ice would form as
a sheet,
and that
the ice would act
as
a supporting diaphragm
and would provide lateral
support to the pond structures until the ice broke due to sloshing
effects.
The sloshing effects were
seen
as breaking the ice away from
the structure leaving. a small
mass of .ice attached to the structure.
Furthermore,
the licensee
concluded that:
(1) there would only be one
cycle of sloshing which would not produce significant lateral
movement;
(2) interaction of the broken ice with the support structures
would not
be significant;
(3) the weight of ice that remained
attached to the
structure after sloshing
broke the ice would be
231 lbs. with a maximum
allowable of 400 lbs;
(4) the inertia load of the ice did not need to be
combined with the structure uplift pullout loads
due to sloshing since
the uplift and inertial loads would not occur at the
same time;
and (5)
the melting of the ice will likely occur from the edges of the pond
leaving
a potentially larger mass of ice attached
to the structure for
the period of time it takes
the ice to melt.
The inspector noted that
the licensee did not specifically analyze this case
which they concluded
would only be applicable for brief periods of time.
In addition, the
inspector
noted that the licensee
did not have
any information regarding
the licensing basis for ice considerations.
-32-
5.5.3 Conclusions
The inspector
concluded that the acceptability of the licensee's
assumptions
concerning
pond icing required further
NRC review.
The
inspector considered
that the assumptions
of ice breakage
and movement
were crucial to the licensee's
conclusions
regarding the structural
integrity of the spray
pond piping.
This issue
has
been referred to the
Office of Nuclear Reactor Regulation for further evaluation
and will be
considered
a followup item pending the
NRC evaluation.
. {Followup item 50-397/94-02-05)
No violations or deviations
were identified.
6.0
Engineering
Communications
and Programs
The .inspector
assessed
the degree
and effectiveness
of the support provided by
the Engineering
and the System Engineering organizations
to plant operations.
The inspector also
examined the status
of implementation of the licensee's
programs for personnel
and equipment
performance.
6.1
Sample
and Criteria
The inspector selected
certain
systems
and components
which had exhibited
a
history of recurring problems during the past year
and conducted
the following
activities:
Examined the historical records for the past year of plant entries
by
the responsible
system engineers,
design
system engineers,
and their
supervision
and management
to assess
whether these
persons
were spending
time in the plant assessing
the state of the plant conditions.
Examined the licensee's
system for identifying equipment
performance
problems to engineering for resolution.
Examined the licensee's
expectations for system walkdowns
by the system
engineers,
design
system engineers,
and operations staff.
Examined the licensee's
expectations
for time-in-plant for key staff
members.
Assessed
the degree of understanding
of the management
expectations
and the degree of implementation of those expectations.
Assessed
the methods
used
by the licensee's
management
to monitor the
implementation of their guidance
and assess
the effectiveness
of the
plant walkdowns.
Examined the effectiveness
of the joint walkdowns of the selected
systems'y
Engineering,- System Engineering,
and Operations.
Examined the licensee's
program for equipment
and system performance
monitoring including collecting,
analyzing,
and trending performance
data.
Determined whether minimum acceptable
performance levels
and
-33-
criteria were specified.
Assessed
whether the program effectiveness
was
periodically evaluated
by management
for needed
improvements.
The inspector
conducted
the
above examinations
by interviewing plant
operators,
shift managers,
operations
supervision
and management,
system
engineers
and their supervision
and management,
and design engineers
and their
management.
The inspector
also reviewed the administrative control
documents
and technical
documentation.
6.2
Findings
6.2. 1 System Engineering
Performance
The inspector
found that the System Engineering
and Design Engineering
. organizations
were in a state of transition.
The System Engineering
Program
had
been significantly revised beginning in October
1993 in
order to correct inadequacies
identified in the program during 1992
and
early 1993.
The revised
program provided workload adjustments
to
provide more time for the system engineers
to focus
on system
performance
and problems.
Plant
Su
ort
En ineerin
The inspector
noted that the licensee
had implemented
a particularly
important initiative with the creation of a Plant Support Engineering
staff under Design Engineering to provide additional
support for
emerging plant issue resolution,
10 CFR 50.59 safety evaluations,
and
day-to-day communications with Operations
and System Engineering.
In
preparation for changing the old program, the licensee
attended
industry
counterpart
meetings
on the subject
and conducted
information gathering
visits to their counterpart utilities for selection of successful
practices
which might be applicable to MNP-2.
Res onsibilities
The inspector
examined the
new Administrative Control Procedure,
TI 2.1,
"System Engineering," for the System Engineering
Program.
The inspector
noted that the old system engineer's
responsibilities
had
been
completely listed in a letter,
dated
November 20,
1991;
however,
the
new
procedure did not provide
a clear,
complete listing of the system
engineer's
responsibilities.
Although the licensee
had proposed certain
workload adjustments
in a letter dated
November
15,
1993,
the inspector
concluded that the system engineer responsibilities
were not clearly
specified
and communicated
in the
new procedure.
Nevertheless,
discussions
with the system engineers
and their supervision,
indicated
that there
was
a good understanding
of the responsibilities for the
program implementation.
The lack of clear communication of the system engineer's
responsibilities
did not appear to be causing
a problem because
supervision
was
so closely involved in system engineer activities.
The
- 34-
licensee
pointed out that the performance
plan for each
engineer
contained
a more complete listing of the system engineer's
expectations.
Nevertheless,
the performance
plans did not contain
a complete listing
of responsibilities.
The licensee
observed that the program was still
under development
and that the administrative control procedure
would be
evaluated
regarding the desirability of providing
a complete identi-
fication of system engineer responsibilities.
S stem Walkdowns
The System Engineering
Program provided for routine tours of the systems
at
a frequency
agreed
upon by the supervisor
and the system engineer
and
for a quarterly wal kdown by the system engineer
and responsible
personnel
from the Operations,
Haintenance
and Design Engineering
Departments.
However, the inspector
noted that the licensee
was
experiencing start-up
problems with participation in the quarterly
walkdowns from the other organizations.
The inspector
also found that there were
some missed opportunities to
include the views of other interested
organizations
in the definition of
the System Engineering
Program.
The licensee
had rank ordered the
systems
according to perceived
importance.
Both the Operations
and
System Engineering staff participated in this process.
The inspector
pointed out that this process
apparently
missed the opportunity to have
risk management
organizations
participate in the rank ordering,
an
oversight which the licensee
agreed to correct.
In addition, the
inspector
noted that the System Engineering staff had defined tour
frequency expectations
and defined the parameters
which would be
monitored
and trended to assess
system performance.
The inspector
observed that the opinions of Operations
and the risk management
organization
were not solicited in the definition of tour frequency
and
parameters
to be monitored.
The licensee
also
agreed to solicit these
opinions.
The. inspector
examined
documentation of system engineering
tours
and
concluded that tours were being performed in accordance
with agreed
upon
frequencies,
that problems
were being identified,
and system performance
parameters
were being monitored
and trended.
The inspector noted that the licensee
had established
a program for
System Engineering
management
and supervision to participate in system
tours
and impart their expectations
to the responsible
system engineers.
Supervisors
were to accompany
the engineers
on one system tour per week
and management
was to accompany
the engineers
on one tour per month.
The inspector considered this to be
a well-conceived initiative to
assure that expectations
were communicated.
However, the inspector
pointed out that it may have
been desirable for senior plant and utility
management
to have participated in the tour process to assure that the
broadest
possible perspectives
were effectively communicated
to the
system engineers.
The licensee
indicated that this comment would be
evaluated.
- 35-
Desi
n Basis
Document
Use
The inspector
asked
whether the system engineers
used the licensee's
design basis
documents
in the performance of their duties
and was
informed that the system engineers
made little use of these
documents.
The inspector noted that the documents
were not readily available
and
were only located in the supervisor's
office.
In addition, the system
engineers
and supervisor stated that the information in the documents
was not useful in the performance of their jobs.
It also
became
apparent that neither the system engineers,
nor the supervisors,
had
communicated theit
concerns
regarding the usefulness
of the information
to anyone in the engineering
organization responsible for producing the
design
documents.
The inspector considered this poor communication to
be
a missed opportunity to influence the preparation of the design
basis
documents.
Interface
Interviews of the operations staff indicated that system engineer
presence
in the pl.ant,
response
timeliness,
and credibility had
improved.
These interviews suggested
that problems regarding
System
Engineering staff stability had improved
and discussions
with System
Engineering supervision
and management
indicated that certain
initiatives were underway to improve plant presence
and stability.
These initiatives included items such
as presence
at
some shift
turnovers,
development of backup capability,
and development of a
replacement staff trainee
program for some positions.
The licensee's
program provides for performance of a joint design
system
engineer/operations/system
maintenance
engineer
walkdown, to be led by
the system engineer
nine weeks prior to the quarterly scheduled
system
outage for maintenance.
In addition, joint system walkdowns by the
same
team are conducted prior to return to power following a refueling
outage.
Status
Re orts
The licensee
had recently
begun producing
a system status report by
System Engineering
management
for Operations
and other senior
management.
The depth of system analysis
in this report was under
refinement.
~Staffin
Staffing levels in System Engineering
was discussed
with various
managers,
supervisors
and staff.
The licensee
stated that there
are
currently about
28 personnel
in the Systems
Engineering staff.
The
licensee
acknowledged that this staffing level
was at the low end of the
average for single large utility plants
and the licensee
planned to add
five-new positions in the near future to bring the staffing in line with
their current needs.
-36-
Conclusion
The inspector
concluded that the System Engineering
Program
appeared
to
have improved,
although certain oversights
in program definition were
observed.
Specifically, the inspector concluded that the procedure for
the System Engineering
Program did not provide
a clear,
complete listing
of the system engineer responsibilities,
and the expectations
of senior
management for the functions of a System Engineering
Pt ogram had not
been clearly communicated
to the mid-level managers
responsible for
developing the program
and implementing procedures.
The inspector
also
noted that additional staff needs
were being addressed,
and that
interviews with operators
indicated that system engineering
support of
plant operations
had improved.
6.2.2 Plant Performance
Monitoring and Trending Program
Performance
Monitorin
The licensee's
plant performance
monitoring program was described
in
Adminis'trative Control Procedure,
PPH 1.5.9,
Revision 5, "Plant
Performance
Monitoring Program,"
dated October
11,
1993.
The procedure
recognized
the use of the Technical Specification Testing
Program
and
the Reliability-Centered
Maintenance
Program in monitoring selected
plant systems
and equipment,
including the collection, evaluation,
and
reporting of data.
The inspector
found that this procedure did not
provide
a complete identification and coordination of all the various
parameter monitoring and trending activities performed
by the Supply
System.
For example,
the procedure
did not include the parameters
monitored
by the System Engineering
Department
and the Specialty
Programs
Group.
The inspector considered
that the lack of a well-defined program
procedure
indicated that management
had not ensured that their
expectations
had been
communicated.
Further,
the Specialty
Programs
Group was conducting
business
as specified
by informal, internally-
generated
guides without the benefit of a procedure.
The licensee
acknowledged that the performance
monitoring program would be further
assessed
and more formally integrated with the company goals
and
expectations
of management.
Reliabilit -Centered
Maintenance
Pro ram Status
The inspector discussed
the Reliability-Centered
Maintenance
(RCM)
Program with responsible
licensee
personnel.
The program consisted of
reliability-centered
maintenance
information analysis,
data obtained
from a variety of sources,
and equipment condition monitoring, (e.g.,
vibration, oil, lubricant,
and motor current signature
analyses).
The licensee
had contacted
industry counterparts
and
EPRI during the
development of the program.
The program
was
based
upon the
EPRI process
- 37-
regarding the selection of equipment
and the preventive maintenance
tasks
which may be done to improve performance.
The methodology for
program implementation
was chiefly determined
by those activities which
were applicable to the Supply System organizations
and the existing
organizational responsibilities.
The Supply System
had obtained
agreement
with the methodology
used to scope the program.
The licensee's
program monitored
abo'ut
1300 pieces of equipment
and
reported the results of the monitoring and trends to the System
Engineering organization for review.
The licensee
indicated that
130
systems
were scheduled
to be analyzed.
The licensee
also intended to
perform
a fault-tree analysis
on key plant equipment
and to build
component
basis files.
These files would include the kind of preventive
maintenance
done
on component
types
and
a description of the maintenance
necessary
as
a function of operating
environment
and other attributes.
The licensee
had completed
an analysis
on the Residual
Heat
Removal
and
Circulating Water
systems.
The results of these
analyses
recommended
changes
to the preventive maintenance
program
and other documents
and
programs.
The licensee
was working on methods to quickly extract
and
analyze
trended data.
Condition Honitorin
The licensee's
condition monitoring program
was specified
by
Administrative Procedure,
PPM 1.19.3,
"Condition Monitoring Program."
This program consists of process
parameter monitoring for safety-related
and balance-of-plant
(BOP) equipment.
Examples of equipment
included in
the program were safety-related
pumps,
valves, batteries,
and emergency
diesel
generators.
The
BOP monitoring included thermal-cycle monitoring
for the Service
Water, Circulating Water,
and Fuel
Pool Cooling systems.
The program also included heat exchanger monitoring (thermal
performance
and pressure
drop testing),
vibration monitoring, oil
analysis,
and motor current signature
analysis.
~Trendin
The trending program trended
almost all of the parameters
collected
by
the various organizations
in the conduct of the performance monitoring
program;
prepared
trend plots covering three
month or three year periods
depending
upon the frequency of data collection;
and distributed the
trended information to system engineers,
operations
and others.
Special
reports
on potential
problems
were issued
as warranted.
For example,
a
special
report described vibration anomalies
on Reactor Recirculation
Pump
1A, suggested
the possible existence of a small
pump shaft crack,
and provided recommendations
to avoid propagation
along with additional
monitoring suggestions.
Conclusions
Although the licensee's
plant performance monitoring and trending
programs
were generally developing
adequately,
the inspector
concluded
-38-
that they could have
been better defined
and did not fully reflect the
expectations
of management.
For example,
the program administrative
control document did not address
all of the various performance
monitoring activities being performed
and certain monitoring activities
were being performed without benefit of a approved
procedure.
6.2.3 Design Engineering Effectiveness
The inspector
held discussions
with the Director of Engineering,
the
Manager of Design Engineering,
.and several
of their staff.
The
inspector
found that Engineering
had
an extensive
number of improvement
initiatives in various stages
of completion
and concluded that
completion of these
could only improve the effectiveness
of engineering
support of operations.
Each initiative was assigned
a responsible
manager
and appeared
to be updated
in status regularly.
Plant Trackin
Lo
As an example of'mprovement,
in late October
1993,
Engineering
achieved
zero overdue
items
on the plant tracking log, indicating that emergent
work and backlogs
were being effectively managed.
In addition, the zero
overdue item condition had continued since achieving that milestone.
To better understand
what was in the plant tracking log (PTL) and
how it
was being used,
the inspector requested
a list of all the open
engineering
items in the
PTL and several
specific items representing
engineering
work that was due to be completed during the period of
January
17-28,
1994.
The inspector
used these lists in discussions
with
'various engineering
managers
and supervisors
to obtain
an understanding
as to how the
PTL was
used
and 'how various departments
tracked their
workloads
and determined their resource
requirements.
The inspector
determined that:
The
PTL was not very interactive or user friendly. It had not
been
used
as the primary tracking tool, nor had it been
used for
determining resource
needs.
Specific subsets
of open items,
which
were sorted
by name
and due dates,
were used.
In addition, other
status tools
had
been developed
by individual departments
for
their individual monitoring.
Engineering
managers
and supervisors
were keenly aware of open
action items for which they were responsible.
The inspector
noted that the Engineering
Improvements
Document,
which listed several
enhancements
and improvements
(either
planned,
in progress,
or completed)
included
a guality Action Team
(OAT) which had completed the development of an enhanced
action
item tracking system to replace the
PTL.
The licensee
stated that
the (AT results
were being reviewed
and
a plan was under
development to implement the proposed
changes.
39-
En ineerin
Backlo
The inspector
held discussions
with the Design Engineering
Manager
and
several
individuals who were closely involved with the request for
engineering technical
services
(RFTS) backlog reduction efforts.
The
inspector determined that,
as of July 1992, there were about
2500 items
in the backlog.
The licensee
had perfor'med
an initial comprehensive
review to define the content.
The inspector
examined the results of the
licensee's
comprehensive
review, the methods of accomplishment,
and the
documented results.
In summary,
the backlog
was determined to consist
of about
70 percent active tasks
and future work.
About 10 percent
were
items that were essentially
complete,
but needed
closure documentation.
About three percent
were abandoned
tasks
and required purging.
The
balance
consisted of drawings needing corrections,
unassigned
tasks,
and
long-range planning work.
The licensee
performed
a second
comprehensive
review in July 1993 of about
850 remaining
items that were set
up prior
to July 1991 using similar criteria.
About 50 percent
were drawing
corrections,
and the balance
were active work or candidates
for closure.
The inspector concluded that
a significant effort had
been
conducted to
manage the work backlog
and that Engineering
had been successful
in
reducing the backlog to the current level of about
1100
RFTS.
The
majority of the items closed
represented
real work, with relatively few
categorized
as
abandoned
or redundant
items.
The inspector also noted
that the reduction efforts did not result in stifling the generation of
new RFTS,
as is sometimes
experienced
in backlog reduction programs.
The inspector considered this indicative of a well-managed
program.
Benchmarkin
Initiatives
The inspector reviewed the results of the licensee's
Benchmarking
Initiatives Program,
which was
an effort to become
more aware of
industry initiatives and good practices
by visiting other sites that
have
been cited
as good performers in selected
areas,
such
as
system
engineering
and commitment tracking.
The licensee
used the information
from these
benchmarking trips to determine
a starting point for
developing
improved practices
both in the Engineering
Department
and in
other plant organizations.
The benchmarking trips were
made
by key
managers,
supervisors,
and staff.
The inspector also noted that there
had
been significant involvement by the licensee's
staff in outside
committee activities
and meetings.
An example of a recent
benchmarking
trip was
a December
1993 visit by the Hanager of Technical
Services to
the Monticello and Callaway nuclear
power plants to review their System
Engineering
Programs.
0 erations
Interface with Desi
n
En ineerin
Interviews with Operations
Department
personnel
indicated
a lower degree
of satisfaction with the effectiveness
of Design Engineering
support
than
had been
expressed
for System Engineering.
Improvement
-40-
opportunities
suggested
by the operations staff included getting more
and earlier operations
input into design
change
planning,
spending
more
time in the plant so
as to better preclude interference
problems,
improving communications with the operators
and operations staff,
and
speeding
up the minor modification process.
The licensee
had recently
embarked
upon
a program to speed
up the minor modification process.
The inspector's
discussions
with Engineering
personnel
indicated that
they were not aware that operations
did not view the efforts of the
Engineet ing organization in accordance
with their own opinion of the
effectiveness
of their operations
support.
The inspector
observed that
the expectations
of the licensee's
senior management
regarding
engineering
support for operations
were not clearly defined
and
communicated to the Engineering organization.
In some cases,
the
inspector
found that Engineering
Department
personnel
did not clearly
identify their support activities to the operations
management
and
staff.
These
two situations contributed to the disparity of views
regarding the effectiveness
of engineering
support for operations.
The
licensee
indicated that expectations
would be assessed
and communicated
to improve relationships
between
the two organizations.
Subsequent
to these discussions,
the inspector
was informed that the
licensee
began holding periodic staff lunches.
The purpose of these
lunches
was to provide the plant staff with information regarding the
role of Design Engineering
and their current activities.
A selected
cross section of plant personnel
were invited to the sessions,
and
opportunities
were provided for questions.
According to the licensee,
these
sessions
generated
good questions
and
a better understanding
of
the role of Design Engineering
and their activities.
The licensee
stated that they planned to continue the periodic lunches.
Conclusion
The inspector
concluded that the various Engineering
improvement
initiatives that were in progress
or planned
should
improve the
effectiveness
of engineering
support for the operation of the plant.
Specifically, the work that
had
been
done
on reducing the significant
backlog of RFTS and other work had already
had significant impact.
The
backlog reduction also demonstrated
Engineering's willingness to improve
their effectiveness
in response
to plant needs.
Furthermore,
the site's
benchmarking activities, which included visits to other sites with
successful
programs,
appeared
to be effective in improving performance
in key areas
such
as system engineering.
The licensee's
increased
involvement in external
committee activities appeared
to improve focus
on ongoing industry initiatives.
Nevertheless,
the inspector
concluded
that it was too early to assess
long term effectiveness
of these
initiatives, but encouraged
the licensee to continue their attention to
the improvement initiatives.
The inspector also noted that licensee
management
had not established
an agreed
upon set of expectations
to
assure
the effectiveness
of Design Engineering interface with Operations
or System Engineering.
6.2.4 Project Nanagement Activities
The licensee
had recently established
a group dedicated
to assuming
project management
responsibilities for plant modifications
and selected
major maintenance
tasks.
The group was called
"WNP-2 Projects",
and
reported to the Assistant
Hanaging Director for Operations.
The
licensee
stated
the group was formed to provide
an adjustment to the
system engineer
workload and to provide better
management
and
coordination of major plant work efforts.
A responsibility document
and
charter
had
been drafted
and agreed to by senior
management.
Daily
implementation of the charter
had
been the subject of informal table-top
guides,
describing
how the project management
functions were to be
accomplished.
The formal functional procedures
for the organization
had
not yet been issued.
The licensee
stated that the project management
team
had
been envisioned
to include system engineering,
maintenance,
health physics,
design
engineering,
operations,
outage
management,
work planners,
schedulers,
estimators,
and site support craft representatives.
The team output was
envisioned to be
a project proposal to the Plant Review Committee
(PRC)
for the
PRC to set priorities and approve
implementation.
The inspector
suggested
that, in addition to the normal Operations
Department
individual responsible for design
change interface,
the licensee
consider inclusion of the various Operations
Department individuals who
were expert in and responsible for the particular
system involved in a
particula} design
change
in order to improve the quality of the
Operations
Department contribution.
The licensee
stated that they
recognized
the potential
improvement
and would consider its
implementation.
6.2.5 Design Basis
The inspector reviewed the adequacy of the procedures for the generation
of Design Requirements
Documents
(DRDs),
sampled
DRDs to assess
the
accuracy
and completeness
of information they contained,
and assessed
the perceived
usefulness
of the
DRDs through interviews with licensee
personnel.
Validation and Verification of Desi
n
Re uirements
Documents
The licensee's
DRD program included
DRD preparation,
design
database
review and reconstitution,
DRD verification and validation,
and
documentation
and resolution of open items.
The procedure
which defined
the processes
to be followed in developing the Design Requirements
Documents
was
EDP 2.23,
"Preparation of Design Requirements
Documents,"
Revision I, dated October
1,
1993.
The inspector considered
that the
procedure satisfactorily addressed
all of the above items.
However, the
inspector
noted that prior to July 1,
1993,
Engineering
Standard
PDS-6,
"Design Requirements
Document
Program Description
and Writer's Guide,"
outlined the
DRD Program
Plan
and defined the structure
and format of
documents written to consolidate
the design
bases
and requirements
of
'
42
WNP-2 systems
and specialty subjects.
Since
DRDs are part of MNP-2
Design Specifications,
the relevant procedure
EI 2.3,
"Preparation
and
Revision of MNP-2 Design Specifications,"
which delineated
responsibilities,
was also applicable.
The inspector
was concerned
that procedure
PDS-6 (which was
no longer
applicable)
was weak in specifying the requirements for the licensee's
DRDs.
This was of concern
because
the procedure
was
used to develop
a
majority of the
DRDs and the licensee
did not intend to revise these
older
DRDs to the requirements
of their current procedure.
An example
of the weakness
of the older
DRD procedure
was the validation
(comparison to the physical plant configuration)
and verification
(correct transfer of information from source
documents
into DRDs)
processes.
Although there
was
a requirement in PDS-6 for DRD
validation, the procedure
did not describe
the details of how such
a
validation should
have
been
accomplished.
The inspector
found that this
generally resulted in a lack of a detailed validation of approximately
90 percent of the
DRDs generated prior to implementing the
new
procedure,
EDP 2.23.
The licensee
had
an open issue regarding the
adequacy of the validation of the
DRDs produced
under
PDS-6 in their
Revised
DRD Program Plan,
dated
December
15,
1993.
The licensee's
action appeared
to be appropriate.
Omissions
Noted in Desi
n
Re uirement
Documents
The inspector identified some omissions in Design Requirement
Document
(DRD) 309,
"Standby Service Mater System."
For example,
DRD 309 did not
clearly refer to an important calculation for system design
(Calculation
HE-02-91-41) which calculated
SSWS flows and temperatures.
DRD 309 was
limited to referenced
Calculation HE-02-92-43,
which only computed
room
temperatures
based
on room heat loads.
In addition,
DRD 309 described
the requirement for the time-dependent
opening of valve SM-V-2A(2B) to
prevent
SSMS waterhammer.
However, the
DRD did not provide the basis
for the time dependent profile.
Conclusions
6.3
The inspector
found the license's
Design Requirement
Document
Program
.documents
did not contain information sufficient to make them useful to
plant users.
In addition, the validation
and verification process
used
for the DRD's resulted
in varying amounts
and types of validation
and
verification.
As discussed
in Section 6.2. 1 of this inspection report,
the inspector also found that the system engineers
made little use of
the design basis
documents primarily due to the lack of details in those
documents.
Conclusions
The inspector concluded that the degree
and effectiveness 'of the support
provided by the Engineering Directorate
and the System Engineering
organizations
for plant operations
was clearly improving.
This was evidenced
43
by obs'erved
improvements
in the implementation of the licensee's
programs for
personnel
and equipment
performance.
The inspector also concluded that System
Engineering
appeared
to have
improved although certain oversights
in program
definition were observed.
Additional staff needs
were being addressed,
and
interviews with operators
indicated that System Engineering support of plant
operations
had improved.
Also, the inspector
concluded that the licensee's
plant performance
monitoring
and trending programs
could have
been better
managed,
and that they did not
appear to have
had the benefit of the guidance
and expectations
of senior
management.
For example,
the program administrative control
document did not
address all of the various performance monitoring activities being performed
and certain monitoring activities were being performed without benefit of a
approved
procedure.
The inspector also considered
that the various Engineering
improvement
initiatives that were in progress
or planned
should
improve the effectiveness
of engineering
support for the operation of the plant.
Specifically, the work
that
had
been
done
on reducing the significant backlog of RFTS's
and other
work had already
had significant impact.
The backlog reduction also
demonstrated
Engineering's willingness to improve their effectiveness
in
response
to plant needs.
Furthermore,
the site's
benchmarking activities,
which included visits to other sites with successful
programs,
appeared
to be
effective in improving performance
in key areas
such
as system engineering.
The licensee's
increased
involvement in external
committee activities appeared
to improve focus
on ongoing industry initiatives.
Although the inspector
observed that it was too early to assess
long term effectiveness
of those
initiatives, the licensee
was encouraged
to continue their attention to the
improvement initiatives.
The inspecto'r also noted that licensee
management
had not'established
an agreed
upon set of expectations
to assure
the
effectiveness
of Design Engineering interface with Operations
or System
Engineering.
No violations or deviations
were identified.
7.0
Licensee Self Assessment
7.1
guality Assurance
Oversight
7.1.1
Sample
and Criteria
The inspector
examined the activities of the guality Assurance
(gA)
organization in the oversight of engineering
effectiveness.
The quality
assurance
organization
had performed
about
20 audits
and surveillances
during the past
18 to 20 months looking at the broad
area of engineering
support of operations.
7.1.2 Findings
The inspector
found that the
gA organization audits
had identified
several
penetrating
findings with a lower rate of findings during the
most recent time frame.
The licensee
stated that the recent lower rate
of findings was due to the 'fact that the last six-month period consisted
of mostly steady-state
power operation with little opportunity for
extensive engineering interface with operations.
The
gA activities
indicated that:
Design Engineering
had improved in their understanding
of Project Modification Request technical
requirements;
communications
with operations
had improved slightly; improvement
was needed
in
engineering participation in the de'finition of post-modification
testing;
and there
was
a lack of consistency
in the quality of the
engineering interface with operations
due, in part, to loosely defined
management
expectations
and administrative controls.
The inspector subsequently
conducted
an additional review of several
Technical
Assessments,
gA Surveillances
and
a gA Audit listed below:
TA 92-015,
Set Point Program
Review
TA 92-017,
MOV Program Implementation Yerification
TA 93-001,
Assessment
of Long Term Corrective Actions 'for Core
Instability Event.
TA 93-003,
Technical
Communication
between
Engineering
and
Operations.
TA-93-004, Design Review of Selected
R-8 Outage Modifications.
SR 292-0038,
SW Expansion Joint Adjustment
SR 292-0088,
Design
and Inst of ECCS
Pump
Room Seals
SR 293-0027,
Safety System Modification Adequacy for R-8
'R 293-0038,
8/93 Forced
Outage
and Startup Oversight Activities.
gA Audit 93-612, Corrective Action Program, Specifically
Procedural
Adherence.
En ineerin
Res onsibilit Clarification
The inspector reviewed Technical
Assessment
(TA) 93-04, in which the
gA
Department
performed
a review of selected
modifications scheduled for
implementation during the eighth refueling outage.
The assessment
found
that the design control process
was adequate
and, resulted
in acceptable
design
change
packages.
However,
the assessment
also stated that Design
Engineering's
input to post-modification testing
(PMT) requirements
was
minimal, and should
be increased.
(}uality Finding Report
((FR)
No. 93-
001 was issued to Engineering
on January
26,
1993, to document the
finding.
Design Engineering's
response
to the problem,
which was included in TA
93-04, stated that,
"Presently there is no requirement for Design
Engineering to specify or review normal
acceptance
criteria.
There is
a
perceived deficiency that Design Engineering
should document
and specify
all required Post-Modification Testing requirements."
Programs
and
Audits accepted
the Design Engineering
response.
They recorded their
rationale for acceptance
in the technical
assessment
which stated
the
response
was acceptable:
"...because
adequate
PMT was actually performed
even though Design Engineering's
involvement
was minimal
and
undocumented."
45-
The inspector noted that Engineering Instruction,
EI 2.8,
"Generating
Facility Design
Change
Process,"
Revision 7, dated
February 8,
1989,
required Design Engineering to provide post-modification test
requirements.
Specifically, Section 3.1, Action 16, stated that,
"Cognizant
and Participating Engineer... If installation, functional or
performance test requirements
need to be'considered,
prepares
a Test
Requirement
Summary in accordance
with Attachment 5.5 and includes
[Basic Design
Change]
BDC."
The Test Requirement
Summary is described
as requiring the inclusion of the test acceptance
criteria.
As
a result of this concern,
the licensee
determined that
a procedure
clarification was required to clearly specify what test
acceptance
criteria should
be provided by Design Engineering.
The licensee
also
stated that they intended to revise
EI 2.8 to clarify the test
requirements.
7.1.3 Conclusions
The inspector considered that the assessments,
surveillances
and audits
were thorough, insightful,
and contained
good findings and
recommendations.
The inspector also noted that the audits
had
been
responded
to in a generally timely manner
and that the responses
appeared
adequate.
The inspector
noted that completed actions
were
being reviewed
and verified by the
gA organization.
No violations or deviations
were identified.
8.0
Exit Neeting
On January
28; 1994, the inspector
met with licensee
representatives
(as noted
in Section 3.0) to discuss
the inspection findings.
The licensee
did not
identify as proprietary
any of the materials discussed
with or reviewed by the
inspectors
during this inspection.