ML17333A577
| ML17333A577 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 09/19/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17333A574 | List: |
| References | |
| 50-315-96-06, 50-315-96-6, 50-316-96-06, 50-316-96-6, NUDOCS 9609270037 | |
| Download: ML17333A577 (50) | |
See also: IR 05000315/1996006
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
License
Nos:
Report
No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
50-315,
50-316
50-315/96006;
50-316/96006
Company
Donald C.
Cook Nuclear Generating
Plant
1 Cook Place
May 26
July 13,
1996
B. L. Bartlett, Senior Resident
Inspector
D. J. Hartland,
Resident
Inspector
C.
N. Orsini, Resident
Inspector
R. Lerch, Reactor Inspector, RIII
Approved by:
W. J.
Kropp, Chief
Reactor Projects
Branch
3
9609270037
960919
ADOCK 05000315
8
l
0
Executive
Summar
D. C.
Cook Units
1 and
2
NRC Inspection
Report 50-315/96006,
50-316/96006
This integrated
inspection included aspects
of licensee
operations,
maintenance,
engineering,
and plant support.
The report covers
a 6-week
period of resident
inspection;
in addition, it includes the results of
announced
inspections
and the follow-up to issues identified during an
Integrated
Performance
Assessment
documented
in inspection report 50-315/316-
96003.
0 erations
~
Operator performance
at the controls was observed to be good, with
excellent shift turnover,
good communications,
and professional
performance.
One exception
was noted in the identification of a
degraded
condition that did not receive
a timely operability evaluation
(Section 01.2).
~
The inspectors
observed
licensed operator performance
during the failure
of a controller and determined that there
was
a prompt and professional
response.
Good attention to the boards identified the event early,
resulting in additional operator
response
time (Section 04. 1).
~
Weaknesses
were identified in the timeliness of identification and the
quality of evaluations
regarding operability of plant equipment
~
~
~
~
~
~
(Sections El.l and El.2)
Maintenance
~
The inspectors
found the work performed under these activities to be
generally professional
and thorough.
One exception
was the self-
identified improperly performed replacement of a fuel rack arm on the
Unit
1
CD D/G (Section Ml.l).
~
The licensee
exhibited
a conservative
approach
by deciding to replace
a
degraded
but operable Unit 2 train A Reactor Trip Breaker
(RTB).
The
inspectors
also noted that the licensee's
planning, coordination,
and
communications
between the different departments
was very thorough
(Hl.2) .
En ineerin
0
Three examples of failure to follow procedure
were identified for not
performing
an operability evaluation of degraded
and potentially non-
conforming conditions in a timely manner
( Sections
El. l.b. 1 and E1.2).
The inspectors
review of the licensee's
operability evaluations
determined that they were generally
weak and
some were lacking in detail
in
a number of areas
( Section El. l.b.2).
The inspectors identified one example of a licensee corrective action
program that
had
been initiated prior to
GL 91-18 whose operability
determination
process
had not been modified after
GL 91-18 (the Large
Bore Piping Reconstitution
Program)
and this appeared
to affect the
evaluation of degraded
pipe supports identified through other mechanisms
(Section El.l.b.3) .
The inspectors
reviewed the 0.
C.
Cook Integrated
Performance
Assessment
(IPAP)
Final Analysis (inspection report 50-315/316-96003),
and
identified inspection
issues
documented
by the
IPAP team.
Various
paragraphs
and comments
were given individual item numbers.
Those item
numbers
which rose to the level of violations, unresolved
items, or
inspector follow up =items are
so identified in this report (Section
E8.2).
Re ort Details
Summar
of Plant Status
Unit
1
Unit
1 began this inspection period at
100 percent
power.
Reactor
power was
decreased
to 57 percent
Reactor Thermal
Power
(RTP) June
6,
1996 to remove the
West Main Feed
Pump from service to facilitate steam supply leak repairs.
Reactor
power was restored to 100 percent
RTP June 8,
1996.
Reactor
power
was decreased
to 93 percent
RTP June
29,
1996,
due to wain
transformer thermal limitations as
a result of increasing
ambient temperature
conditions.
Reactor
power was restored to 100 percent
RTP on June 30,
1996.
Unit 2
Unit 2 entered
and exited this reporting period in Mode
1 at
100 percent
RTP.
There were no unit shutdowns or significant power reductions.
Ol
Conduct of Operations
01. 1
General
Comments
71707
IIOI
Using Inspection
Procedure
71707, the inspectors
conducted
frequent
reviews of ongoing plant operations.
In general,
the conduct of
operations
was professional
and safety-conscious;
specific events
and
noteworthy observations
are detailed in the sections
below.
In
particular,
the inspectors
noted the good operator
performance
during
the loss of a pressure controller.
Good operator turnover for a relief
occurred
and good attention to the unit enabled
an early identification
of the instrument failure.
01.2
Control
Room Observations
a.
Ins ection
Sco
e
71707
I
The inspectors
performed routine observations
of control
room
activities, shift relief and turnover, procedural
usage
and adherence,
response
to alarms
and plant conditions,
and supervisory
command
and
control including compliance with the following procedures:
~
Operations
Department
Head Instruction
(OHI) 2000,
"Operations
Department
Guidance Policy".
b.
~
OHI - 2211,
"Haintenance of Operations
Department
Logs".
~
OHI 4011,
"Conduct of Operations
(Shift Staffing)".
~
OHI 4012,
"Conduct of Operations
(Shift Turnover)".
Observations
and Findin
s
C.
The turnovers
were conducted
in a professional
manner
and included log
reviews,
panel
walkdowns, discussions
of maintenance
and surveillance
activities in progress
or planned,
and associated
LCO time restraints,
as applicable.
Procedural
usage
and adherence
was noted to be good with
appropriate
questioning of the adequacy of the procedures
for use during
plant evolutions.
The operators
exhibited good teamwork within the shift and were observed
to communicate
when necessary
with other departments
to resolve
equipment problems.
An exception to this good communications is
discussed
further in paragraph El.l and concerned
the untimely
initiation of an operability evaluation for the leaking Unit 2 West
Essential
(ESW) strainer discharge'check
valve.
A leaking
check valve was properly identified by an auxiliary equipment operator
and
an action request
was issued,
however,
an operability evaluation
was
not requested
of engineering.
Conclusions
Operators
acted
and reacted to various plant evolutions in a prompt
and
professional
manner.
One example
was identified where
a degraded
condition was not evaluated for operability in a timely manner.
This
issue is discussed
further in section El.l.
04
04.1
Operator
Knowledge and Performance
Prom t 0 erator
Res
onse
To A Pressure
Controller Failure
Unit 2
a 0
Ins ection
Sco
e
93702
The inspectors
assessed
the performance of the licensed operators
during
the failure of main steam
pressure controller 2-UPC-101.
This
controller affected the operation of the main feedwater
pumps
and prompt
operator actions
were necessary
to prevent the unnecessary
shutdown of
Unit 2.
b.
Observations
and Findin s
On June
13,
1996, Unit 2 was stable at
100 percent
RTP.
Pressure
controller 2-UPC-101 failed low without any warning.
This caused
the
secondary
control system to sense
a false low steam pressure.
As a
'esult
a separate
controller which compared
pressure
to steam
pressure
then indicate
a high differential pressure.
This controller
I
sent
a demand signal to the two main feedwater
pumps to reduce
speed in
order to reduce the indicated high differential pressure.
As speed
was
reduced,
feedwater flow was reduce resulting in lowering steam generator
water levels.
The balance of plant reactor operator
had requested
a break from the
controls
and
a relief operator took over after
a brief turnover.
The
relief operator
observed
the drop in steam generator levels prior to the
level deviation annunciators
actuating.
He announced
the unexpected
indications to the rest of the contt ol room operators
and
began checking his panels for possible
causes.
The unit supervisor
directed the operator to take manual control
and
then
he requested
additional assistance
from the Unit
1 control
room
personnel.
The control
room operators
then restored levels
and after
the pressure
controller was repaired,
automatic control
was re-
established.
The inspectors
entered
the control
room and began observations
of the
operating
crew approximately half-way through this event.
The
inspectors
observed:
Effective command
and control
was being effected
by shift
supervision.
None of the
SROs were at the panel
but instead the
unit supervisor
(US) was several
feet behind the
ROs providing
guidance.
The shift supervisor
(SS)
and the assistant shift
supervisor
(ASS) were at the US's desk maintaining
a broad
overview and ensuring that the reactor operators
were not
distracted.
Two of the four steam generators
did eventually
have level
deviation alarms annunciate.
As directed
by the
US, the
ROs took
manual control of the feedwater regulating valves
and restored
level.
This action was promptly and efficiently performed.
The
US and the
SS held
a crew briefing immediately following the
restoration of the level controllers in automatic.
The briefing
covered:
Mhy two of the steam generators
received level deviation
alarms
and the other
two steam generators
levels
had smaller
swings.
It was determined that
a feedwater regulating valve
was operating slowly.
An action request
was written and
subsequently
a valve's controller was tuned.
The operators
discussed
any additional actions which might
be needed,
applicable technical specifications
and the
sequence
of events.
+
A plan of repair was discussed
and each
crew member
was
asked for input concerning the event.
c.
Conclusions
The operating
crew and supervision
reacted
promptly and professionally
to the failure of main steam header
pressure controller. Effective
monitoring of control panels
and good relief turnover were also
demonstrated
by the operators.
Ml
Conduct of Naintenance
M1.1
Gener al
Comments
II. Maintenance
a.
Ins ection
Sco
e
62703
The inspectors
observed all or portions of the following work
activities:
~
1-IHP 4030.SMP. Ill
~
2-IHP 4030.SNP.120
~
2-OHP 4030.STP.018
Pressurizer
Pressure
Set
1 Surveillance
Test
2
& 4 Mismatch Channel II
Surveillance Test
Stop Valve Dump Valve
Surveillance Test
~
2-IHP 4030.STP.510
Train "A" Reactor Protection
System
and
Engineered
Safety Features
Breaker
and Solid State Protection
System
Automatic Trip/Actuation Logic Functional
Test.
~
JO C0036842
~
JO R0059010
~
JO R0059013
~
2-IHP. SP. C36477
0
Replace Solenoid for 2-MRV-232
Replace
a fuel injection pump on the
1
CD
D/G
Replace
a fuel injection
pump
on the
1
CD
D/G
Administrative Control Procedure for
Replacement of 2-52-RTA (Unit 2, train A
reactor trip breaker).
Unit 2 West
ESW pump strainer discharge
check valve sticking open.
Observations
and Findin
s
The inspectors
found the work performed under these activities to be
generally professional
and thorough.
One exception
was the self-
identified improperly performed replacement of a fuel rack arm on the
1
CD D/G.
This resulted in the inability of the D/G to take the
100
percent load requirement.
This was self-identified during the post
maintenance
testing prior to the restoration of the
D/G to operable.
The worker error was documented
in a condition report
and the licensee's
corrective action will depend
on the results of the
CR assessment.
c.
Conclusions
Haintenance activities were generally completed thoroughly and
professionally with the proper procedures
at the work site
and in active
use.
One exception
was the improper replacement of a fuel rack arm on
the
1
CD D/G that prevented
the
D/G from reaching
100 percent load.
M1.2
Reactor Tri
Breaker
RTB
Re lacement
Unit 2
a
~
Ins ection
Sco
e
62703
and
61726
b.
On June,
10,
1996 while per forming monthly surveillance
procedure
2-IHP
4030.STP.510,
"Train 'A'PS
and
ESF Reactor Trip Breaker
and
SSPS
Automatic Trip/Actuation Logic Functional Test," the licensee
was unable
to close
RTB A from the control
room.
The licensee
determined that the
inability to close the breaker remotely did not affect breaker
operability.
The breaker
was manually closed
and remained in service
until June
22,
1996,
when the breaker
was replaced.
The inspectors
reviewed the licensee's
basis for operability and
observed
the initial troubleshooting efforts including the breaker
replacement.
Observations
and Findin
s
During performance of STP.510,
the unit was in a two hour action
statement for TS 3.3.2.1 while the reactor trip bypass
breaker
was
closed.
When
RTB A would not close,
the licensee
needed to quickly
determine the extent of the problem, the effect on breaker operability,
and whether or not repairs
could be made without exceeding
the action
statement
time limits.
The inspectors verified the licensee's
conclusion that the RTB's only
safety function was to open
on
a reactor trip signal.
The licensee
determined that the problem was limited to the closing circuit, which
was electrically isolated
from the opening circuit.
The breaker
was
manually closed
and verified to open
as required.
The breaker
was then
declared
and the
LCO was exited.
The inspectors
observed
troubleshooting activities,
assessed
the licensee's
basis for
operability and did not identify any concerns.
Although
RTB A remained
the licensee
wanted to replace the
breaker
as
a conservative
measure
because
the root cause of the problem
had not been identified.
Due to the time constraints
involved with the
LCO, and the coordination of several
work groups,
(Operations,
ILC,
electrical
maintenance,
and engineering)
the licensee
wrote
a special
procedure,
2-IHP.SP.C36477,
"Administrative Control
Procedure for
Replacement
of 2-52-RTA," specifically for this evolution.
The inspectors
observed
the replacement
and associated
troubleshooting
efforts on June
22,
1996.
At this time the problem could not be
repeated,
and during testing the breaker
was successfully
closed
from
the control room.
The licensee
proceeded
with the installation
and
testing of the replacement
breaker within the time constraints of the
LCO.
Following removal, the licensee
conducted further testing
on the
malfunctioning breaker
to determine the root cause.
The inability to
close
was repeated
on an intermittent basis during bench testing.
The
problem was isolated to the closing control relay which did not fully
close
on each
demand.
The relay was scheduled
to be replaced
and the
breaker will be utilized as
a spare.
The licensee
also determined that the malfunction of the closing control
relay was not a generic concern 'as:
~
This particular breaker
had
been in service since
1982 without
exhibiting problems
and
~
No other breakers
on site had'xhibited this problem.
~
A review of industry experience with similar breakers
DB-50) did not identify similar concerns.
Conclusions
The licensee
exhibited
a conservative
approach
by deciding to replace
RTB A with it degraded
but operable.
The inspectors
also noted that the
licensee
s planning, coordination,
and communications
between the
different departments
was very thorough.
This was important due to
concerns with TS time constraints
and personnel
safety,
involved with
working on the reactor trip equipment.
III. En ineerin
El
Conduct of Engineering
El. 1
Assessment
of 0 erabilit
Evaluations
a.
Ins ection
Sco
e
37551
The inspectors
reviewed procedures,
condition reports
(CR),
and action
requests
(AR) to assess
the licensee's
capability to evaluate
degraded
and potentially non-conforming conditions.
The inspectors
intent was to
verify that the licensee
could ensure that appropriate operability
requirements
were satisfied.
b.
Observations
and Findin s
The inspectors
observed that generally the licensee
was able to properly
assess
identified conditions against license
and regulatory requirements
to ensure that the licensing basis
and operability requirements
were
maintained.
The inspectors
also determined that the licensee's
timeliness
in performing these
assessments
and the quality of these
assessments
appeared
contrary to
NRC Generic Letter (GL) 91-18,
"Information To Licensees
Regarding
Two NRC Manual Sections
On
Resolution Of Degraded
and Nonconforming Conditions
And On Operability".
In addition to the guidance contained within GL 91-18 the licensee's
procedure for documenting
and addressing
degraded
and potentially non-
conforming conditions gives requirements
for the timeliness
and quality
for performing operability evaluations
(Plant Managers Instruction
(PMI)
7030, "Corrective Action").
PHI-7030 is the licensee's
primary
mechanism
by which degraded
and potentially non-conforming conditions
are evaluated.
PHI-7030 requires the originator to initiate a condition
report
(CR) for known or suspected
adverse
conditions or events
(step
6.9.a).
PHI-7030 also defines
an adverse condition/event
as
"A non-
conformance,
deficiency, deviation, discrepancy,
or adverse
trend of
items, services
and/or administrative
systems that, if left uncorrected,
could adversely
impact safety, quality, or operability" (step 5. 1).
In
step 5.31,
PMI-7030 states,
in part,
"Prompt Operability Determination
This determination
must
be made expeditiously following identification
of a potentially degraded
condition that has the potential to impact
operability."
Unfortunately these
requirements
while strong for timeliness
were not
specific
and did not give guidance for the quality of the evaluations.
For example the requirements for timeliness
were "promptly" or
"expeditiously".
This can
be clear for major issues
but was less clear
for more subtle problems.
The licensee
had recognized this due to
previous inspector
comments
and was in the process of revising the
ambiguous
procedure to add more specific requirements
and to give
additional
guidance for the quality of the operability evaluations.
This procedure
had not been
issued at the close of this inspection.
During this assessment
period, the licensee
gave additional
temporary
10
0
guidance to plant personnel
in form of a standing
order in response
to
the issues
identified below
(Standing
Order 173,
issued July 16,
1996).
1)
Timeliness
Issues
GL 91-18 contained
recommendations
as to the timeliness of performing
prompt operability determinations
and for the performance of backup
The recommended
time for performing
an
operability determination in GL 91-18 was about
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with a few
exceptional
cases
taking longer.
In addition,
a recommended
timeliness
of the technical specification
(TS) allowed outage times
(AOT) was given
for those
components
covered
by the TS.
The following list gives
examples of where the licensee
exceeded
those
recommended
guidelines:
The Unit 2 West Essential
(ESW) discharge
check
valve was leaking-by sufficient to cause
reverse
pump rotation.
The West
ESW pump was running
and the licensee
swapped to the East
ESW pump.
During the
swap over the motor driven discharge
valves
of the West
pump were momentarily open while the East
ESW pump was
running.
During this time an auxiliary equipment operator
observed
the West
pump reverse rotation, which indicated excessive
discharge
valve leakage
and wrote
an action request
(AR).
This was identified on May 3,
1996,
however
an operability
evaluation
was not performed.
This was identified when the
inspectors
requested
a copy of the evaluation
on July 9,
1996 and
it couldn't be located.
The licensee
subsequently
performed
an
evaluation
and the evaluation determined that the
ESW system
was
After a review of the data
and discussions
with plant
personnel,
the
NRC inspectors
agreed with the licensee's
determination.
The failure to perform
a prompt operability assessment
expeditiously following the identification of a potentially
degraded
condition that had the potential to impact Structure
System
Component
(SSC) operability is
a violation of TS 6.8.1.
This failure to follow a required procedure is example
(b) of
Notice of Violation 50-315/316-96006-01.
CR 96-0022
The Unit
1
CD emergency diesel
generator
(D/G) neutral
grounding
resistor
was identified by licensee
personnel
to be incorrectly
configured (nominally 6 ohms but it was wired such that it was
actually 2.3 ohms).
The problem was identified on December
27,
1995, the
CR and
subsequent
prompt operability evaluation
were not written until
January
5,
1996.
The backup operability evaluation
was written
January
8,
1996.
The timeliness of the prompt evaluation
was
inadequate
to meet licensee
procedures.
The evaluation
which was
subsequently
performed determined that the
D/G was still operable.
The inspectors
review of the quality of the evaluation did not
identify any concerns.
The failure to perform a prompt operability assessment
expeditiously following the identification of a potentially
degraded
condition that had the potential to impact Structure
System
Component
(SSC) operability is
a violation of TS 6.8. 1.
This failure to follow a required procedure is example
(c) of
Notice of Violation 50-315/316-96006-01.
CR 96-0335
With the reactor at full power, hydraulic fluid from the Unit 2
containment jib crane spilled into the reactor cavity during
testing.
An evaluation
was performed which determined that the
fluid did not affect the operability of emergency
core cooling
system.
The spill occurred
on March 8,
1996
and the prompt operability
evaluation
was performed
on March 9,
1996.
The backup operability
evaluation
was performed
on March 13,
1996.
The licensee's
procedures
for the performance of operability evaluations
did not
clearly address
the timeliness
requirements
of the backup
operability requirements.
In the inspectors'pinion
the delay
until March 13,
1996, to perform the backup operability assessment
was excessive
but was not
a violation.
CR 96-0622
D/G Cam Follower springs
were discovered failed during testing of
the Unit 2
CD D/G.
The licensee
determined that the potential
failure was applicable to both units.
An evaluation
was performed
which determined that all four D/Gs were operable.
The event occurred
on Unit 2 on April 13,
1996.
In response
to
inspector questioning
an operability evaluation
was again
performed
and documented
on June
25,
1996.
Additional inspector
questioning resulted
in the licensee
supplementing
the evaluation
on June
26,
1996.
This issue is discussed
in more detail in
paragraph
E1.2.
The Failure to perform
a prompt operability assessment
expeditiously following the identification of a potentially
degraded
condition that
had the potential to impact Structure
12
System
Component
(SSC) operability is a violation of TS 6.8.1.
This failure to follow a required procedure is example
(a) of
Notice of Violation 50-315/316-96006-01.
2)
ualit
Of Evaluations
V
The inspectors
review of the licensee's
operability evaluations
determined that they were generally
weak and
some were lacking detail in
a number of areas.
CR 96-1097
Uni,t 2 West Essential
Service
Water
(ESW) discharge
leaking-by sufficient to cause the
pump to rotate backwards
referenced
above
as
After the inspector s brought this
issue to the licensee's
attention
CR 96-1097
was written and
a
prompt oper ability was performed.
The inspector s reviewed the prompt operability determination
contained
in the
CR and agreed with the licensee's
decision that
the
ES'W system
was still operable.
However,
one of the arguments
used
by the licensee
took credit for manual
operator action.
Specifically the evaluation stated that if the check valve stuck
open
enough to divert a large
amount of flow, the determination
took credit for the operators
manually closing the train cross-tie
valves
upon
low pressure
annunciation.
This. credit for prompt manual
operator action in order to restore
was inappropriate
in that it had not been
previously established
as part of the licensing review of the
plant.
The rest of the evaluation supplied appropriate
justification that operability was established
without taking
credit for manual action.
CR 96-0127
With the reactor at full power, the Unit 2 containment jib crane
spilled hydraulic fluid into the reactor cavity during testing.
The prompt operability determination relied upon
a valid
engineering
judgement
argument,
however the backup operability
determination
also relied upon engineering
judgement.
Several
weeks after the backup operability was performed the licensee
performed
a reportability determination.
The reportability
determination
was more technical
in nature
and supported
the
prompt
and backup operability determinations.
A lack of engineering rigor was demonstrated
through the reliance
on engineering
judgement for both the prompt and backup
operabil'ity evaluations.
13
CR 96-0472
The Unit
1
AB D/G before
and after lube oil pump was found to have
its discharge
check valve improperly installed
such that it would
not have closed
when needed to prevent reverse flow.
This
condition was identified while the D/G was inoperable
and
corrected prior to restoring the D/G to operable.
No operability
determination
was required for operating
under this condition,
however
was required in order to
determine
past operability and thus reportability.
The licensee's
prompt operability determination
was
based strictly
on engineering
judgement.
Normally the backup operability
determination
would be expected to provide more engineering rigor,
however
none
was performed.
There
was
a reportability
determination
performed with much more detail than the prompt
concerning the lube oil pump check valve
and failure modes,
however it too only contained
engineering
judgement.
A lack of engineering rigor was demonstrated
through the reliance
on engineering
judgement for both the prompt and backup
operability evaluations.
CR 96-0335
With the reactor at full power, the Unit 2 containment jib crane
spilled hydraulic fluid into the reactor cavity during testing.
Both the prompt and backup operability evaluations utilized only
engineering
judgement to assess
the acceptability of the oil in
reactor cavity or the reactor coolant system.
The backup
oper ability evaluation
assessed
post accident
environmental
conditions but did not address
the oil's interaction with nuclear
fuel or other internal reactor vessel
components.
Following the initiation of the refueling outage
several
weeks
later, the licensee realized that the operability determinations
did not address
the oil's affects
on refueling operations.
Another determination
was performed which did address
refueling
operations
but it too only relied upon engineering
judgement
and
did not specifically address
the oil's affect upon the fuel
bundles.
Again,
a lack of engineering rigor was demonstrated
through the
reliance
on engineering
judgement for both the prompt and backup
operability evaluations.
3)
Lar e Bore P'n
Reconstitution
Pro ram
LBPRP
and The
Identification of De raded
Pi
e
Su
orts
The inspectors identified one example of a licensee corrective action
program that had
been initiated prior to
GL 91-18 whose operability
determination
process
had not been modified after
GL 91-18 (the
LBPRP)
and this appeared
to affect the evaluation of degraded
pipe supports
identified through other mechanisms.
In the late 1980's licensee
and
NRC personnel
identified situations
where as-found piping and piping supports did not meet the original
design requirements.
This was documented
in NRC inspection reports
and
licensee
documents.
The licensee
began
a program to identify, assess,
and where appropriate to correct these deficiencies.
The program was
committed to and documented
in correspondence
to the
NRC.
In licensee letter AEP:NRC: llOOA, issued
February
16,
1990, the licensee
committed that
"When these or similar reviews reveal
discrepancies
between
the as-found
and the as-designed
condition,
an evaluation of the
acceptability
and reportability of the condition is conducted."
The inspectors
determined that the licensee
was not in fact performing
specific calculations
on each identified discrepancy
or relying upon
bounding calculations
but was instead relying upon the results of series
of walkdowns in order to assess
operability of the supports.
The
walkdowns
had
been
performed
on
a sampling basis
and any identified
discrepancies
were evaluated
using interim acceptance criteria.
The
results of these
walkdowns were used to justify the operability of
safety related piping systems
in their existing configurations.
In teleconferences
with resident
inspectors
and Region III personnel,
the licensee
stated that licensee letter AEP:NRC:1100C,
dated
March 20,
1995,
documented this practice, that
NRC had been
a party to
teleconferences
in which this operability practice
had
been discussed
and that
NRC inspection reports
had accepted this practice.
A detailed
review of the referenced letter by the resident staff and
NRC region III
personnel
cognizant of this issue identified a reference to results of
the sample walkdowns being acceptable,
but no statement
could be found
which stated the licensee's
practice of only relying upon the walkdowns
for operability determinations
of discrepancies.
Interviews with NRC
piping exper ts
and their management
determined that none
remembered
any
such discussions.
A review of inspection report (50-315/316-91028)
showed that
a review of two systems
was indeed performed
and the
licensee's
were found to be acceptable.
However, the review was limited to just those
two systems
and the
acceptability
was also limited to just the discrepancies
identified on
those
two systems.
No blanket acceptability of the practice of relying
upon the walkdown samples
was meant or implied.
This was confirmed
during interviews with the lead
NRC inspector for the referenced
inspection report.
15
The
LBPRP was discussed
previously in inspection report 315/316-95012
and
an inspector follow-up item was issued
regarding resolution of the
licensee's
commitment to perform specific reviews
(50-315/316-95012-
02(DRP)).
This item will remain
open pending the assessment
of the
licensee's
response
to the request for information discussed
in the
cover letter.
Examples of piping support discrepancy
whose operability evaluation
appeared
not to meet
GL 91-18 are discussed
below:
CR 96-0395
During a walkdown on March 20,
1996,
a U-Bolt on 2-AFW-L944 was
found to not conform to the design drawing.
The prompt
operability determination relied upon
AEPSC Guideline 5700-13
which documents
the licensee's
operability determination practice
as discussed
above.
CR 94-1124
During an examination of a pipe support for an unrelated
reason,
on June 6,
1994, support
number 2-GC-R39 was found to not conform
to the design sketch.
The criteria contained within AEPSC
Guideline 5700-13
was relied upon for a prompt operability
determination.
CR 96-0180
During a walkdown with licensee
personnel
of the plant,
NRC
inspectors identified 14 discrepancies
on piping supports for
various safety related
and non-safety related
systems.
The
inspection
was documented in report 50-315/316-96003
(IPAP).
The
LBPRP was not intended
by the licensee to address
non-safety
related
systems,
but for those safety related support
discrepancies
identified by the inspectors
the licensee relied
upon the guidance
contained with AEPSC 5700-13.
The separate
issue of the timeliness of initiating CR 96-0180 is addressed
elsewhere
in this report
as
We were concerned that the operability assessments
performed
as
a part
of the
LBPRP and support discrepancies
identified through other
mechanisms
did not appear to comply with NRC Generic Letter 91-18.
A
request for a response
concerning the licensee's
for pipe supports
was discussed
on the front cover of this report.
c.
Conclusions
The licensee
generally failed to implement the timeliness guidelines of
GL 91-18 for performing operability evaluations.
In addition,
examples
of the quality of the operability evaluations
not meeting
GL 91-18 were
identified concerning piping support discrepancies.
A Notice of
Violation with three
examples
was issued for failing to meet licensee
16
procedural
requirements for timeliness.
A request for information
concerning the apparent
lack of piping supports to meet
Gl 91-18
requirements
was issued.
Issuance of A Re ort
Re uired
b
10 CFR Part 21 - Both Units
Ins ection
Sco
e
37551
The inspectors
performed routine followup activities in response
to
a
licensee
issued report required
by 10 CFR Part 21.
The inspectors
independently
assessed
the licensee's
for the
emergency diesel
generators
and the details contained within the Part
21
report.
Observations
and Findin s
Initial Identificati on of Failed
Com onent
On June
20,
1996, at 9:45
am
EDT the licensee called the
NRC
Headquarters
Operations Officer via the Emergency Notification System
and
made
a report
as required
by 10 CFR Part 21.
The licensee
reported
that
a failure of the, emergency diesel
generator
(D/G) cam follower
spring which occurred
on April 13,
1996, represented
a substantial
safety defect
and was reportable
under
On April 13,
1996, Unit 2 was in a refueling outage with the reactor
defueled.
While troubleshooting for a speed control problem on the
2
CD
engine
a loud knocking was heard.
During followup to that knocking the
licensee
discovered that one cylinder had
a failure of its cam follower
spring.
The licensee
performed appropriate
followup activities and
identified one other broken spring on the
2
CD D/G.
One of the two broken springs resulted in its associated
cylinder in not
being able to produce
power.
The other broken spring was not as
severely
damaged
and its cylinder was still able to produce
power.
Licensee's Initial Root Cause
Anal sis
and Corrective Actions
The licensee
performed acoustic monitoring of the cylinders
on the other
three
D/Gs (two on Unit
1 and the other one
on Unit 2)
and did not
identify any other failed springs.
One spring
on the
2 AB D/G was
removed
and inspected
in response
to noise
on one cylinder,
however,
no
problems
were identified.
The licensee
had also observed that the set screws for the spring cover
plate
had
been
found loose
on the spring first identified as failed and
ensured that the other three
D/Gs had tight setscrews.
Licensee
management
had discussed
with the inspectors their bases for
three
D/Gs being operable following the April 13,
1996, failure.
This
basis for oper ability included all the information discussed
previously
in this section.
The
2
CD D/G was repaired
and tested prior to being
17
declared
The inspectbrs
had no significant concerns with the
licensee's
discussion
on their basis for operability.
Issuance
of A Re ort
Re uired
B
The licensee
determined that the D/G spring failure met Part
21
reporting requirements
on June
19,
1996.
The report was
made
on June
20,
1996.
This met the two day reporting requirements
of Part 21.
The
narrative
appeared
to meet the reporting requirements,
however it did
fail to supply important, pertinent information.
For example the
report:
~
Failed to discuss
the basis fot reportability (it represented
a
substantial
safety hazard).
~
Failed to discuss
the past
and current operability of the four
D/Gs in detail sufficient to inform the reader of the present
operability status of the D/Gs.
Failure to Document The Basis
For 0 erabilit
Following the issuance of the
10 'CFR Part
21 report discussed
above,, the
inspectors
attempted to review the licensee's
basis for operability for
the other three
D/Gs.
This review was to ensure that no new information
was revealed
in the Part
21 which invalidated the previous basis for
operability.
The licensee's
requirements
for performing operability
evaluations
was
implemented through Plant Hanagers
Instruction (PHI)-
7030, "Corrective Action" as
was discussed
in El.l.
CR 96-0622
was written on April 17,
1996, to document the failure of the
2
CD D/G cam follower springs.
This
CR did not contain
a prompt
operability determination required in PHI-7030
as it only addressed
2
CD
D/G and it had been declared
inoperable for maintenance
{thus it wasn'
required to be operable).
However the inspectors
could not locate
any
documented operability evaluation for the other D/Gs.
Subsequently
the
licensee
confirmed that no operability evaluation
had
been
documented.
The licensee
was required to perform and document
a prompt operability
evaluation for the remaining three
D/Gs following the spring failure on
April 13,
1996.
The licensee's
failure to comply with PHI-7030 is
a
violation {example {a) of 50-315/316-96006-01{DRP))
{this violation is
also discussed
in paragraph El.l.b. 1 above).
Conclusions
The licensee's
Part
21 report was accurate
but lacked certain desired
information.
The licensee failed to ensure that
an operability
evaluation
was documented
however this issue
was address
in El.l above.
18
E8
E8.1
Niscellaneous
Engineering
Issues
(92902)
Closed
I s ector Follow-u
Item 50-316 93020-02:
Loss of turbine
driven auxiliary feedwater
(TDAFW) pump flow retention
due to inaccurate
flow measurements.
This item concerned
the fact that the flow sensing
device which initiated a flow retention signal for the Unit 2 TDAFW pump
was reading only 78 percent of actual flow.
The instrument
inaccuracy
was corrected
by a modification, installed in 1994, which moved the flow
orifice to
a straight run of piping.
This modification eliminated
oscillations
and turbulence
across
the orifice which resulted in more
accurate
flow measurements.
The inspector reviewed the licensee's
post
modification tests to ensure that the flow instruments that initiated
a
flow retention signal
were accurately indicating actual
flow rates.
This item is closed.
E8.2
0 en
Inte rated
Pe formance Assessment
ro ram
IPAP
Issues
The inspectors
reviewed the
D. C. Cook Integrated
Performance
Assessment
(IPAP) Final Analysis
(NRC Inspection
Report Nos. 50-315/316-96003),
and identified inspection
issues
documented
by the
IPAP team.
Various
paragraphs
and
comments
were given individual item numbers.
Those item
numbers
which rose to the level of violations, unresolved
items, or
inspector follow up items are
so identified in the below list.
Some
items concerned
issues that were either the
same
item or were similar in
nature.
Those issues
are referenced
whenever possible in the list of
items below.
It should
be noted that the section
.numbers referenced
below are the section
numbers
from inspection report 50-315/316-96003
and are not from this inspection report.
Item No.
01
Condition reports
(CRs) were either not initiated or not done
so in a
timely manner.
(Section 1.1, "Safety Assessment
and Corrective Action")
Untimely identification and resolution of conditions adverse
to quality
is
a violation of 10 CFR 50, Appendix B, Criterion XVI "Corrective
Action."
(50-315/316-96006-02)
Specific examples
are addressed
in
other items below.
Three examples
were given; these
and others
are addressed
in more detail later
in the report:
01A
A CR was initiated 4 days after the team
and the system engineer
identified possible auxiliary feedwater
system piping support
deficiencies.
(Section 1.1)
See item 62.
01B
A CR was not initiated when licensee identified that boric acid
heat trace instrumentation,
used to verify compliance with TS
surveillance
requirements,
was not included in plant calibration
program.
(Section l. 1)
See
item 44.
19
02
03
04
05
" 06
07
08
09
10
12
01C
A CR was not initiated when foreign material
was found in interior
of feedwater heater level control valve 2-HRV-.651 during
maintenance
of the valve.
(Section
1. 1)
See item 60.
Documented operability determinations
were delayed.
(Section
1. 1)
See
paragraph
E. l.l.b.l of this report.
gA audits
and surveillance findings appeared
to be programmatic in
nature
and fairly narrow in scope.
(Section 1.1)
This issue
and item 12
are
an IFI. (50-315/316-96006-04)
CR causal
determinations
associated
with issues
not requiring
a formal
root cause
evaluation
were narrowly focused,
did not address
potential
generic aspects,
and contributed to inadequate
corrective actions.
(Section 1.2)
See
items 07 and 0&.
A large number of CRs were assigned
to generic root cause
categories,
which resulted in little trending value.
(Section 1.2)
This issue is
an
IF I. (50-315/316-96006-05)
Ferrography identified by lab analysis,
(EDG) governor oil sample
marginal
due to high particulate count. Subsequently,
the governor
failed due to contaminants
in oil.
(Section 1.2)
See item 77.
Corrective
actions taken in response
to identified plant problems
were
not always effective.
Problems recurred
due to inadequate
and/or timely
follow-up corrective actions.
(Section 1.3)
This is
a violation of 10 CFR 50 Appendix B, Criterion XVI, "Corrective Action." (50-315/316-
96006-02)
This includes item 08 below.
The specific examples
are
addressed
in other items.
Corrective actions
tended to be narrowly focused.
(Section 1.3)
This
is a portion of the issue identified in item 07.
Repeated
Component Cooling Water
pump discharge
check valve slamming
events
due to failure to install vendor recommended
stop plates.
(Section 1.3)
See item 48.
Unit 2 reactor/turbine trip due to actuation of moisture separator
reheater
high level switch.
Root cause
not determined.
(Section 1.3)
This issue
was reviewed in inspection report 50-315/316-95010.
Numerous foreign material exclusion control related
issues.
(Section
1.3 and 2.2)
The specific issues
were reviewed in inspections
reports.
See
item 75 for the general
issue.
Line organization
responses
to gA findings tended to be program oriented
and narrowly focused.
(Section 1.3)
See
item 03.
20
t
14
15
16
The team noted lack of programmatic controls that would preclude
subsequent
revision or elimination of the corrective actions
by the line
organization.'
(Section 1.3)
This issue is an IFI. (50-315/316-96006-
06).
Corrective actions associated
with rework CRs were narrow in scope.
Root cause
was not effectively determined
in several
cases
and
corrective actions to prevent recurrences
appeared
inadequate.
(Section
1.3)
See item 67.
Licensee's
response
to
NRC generic communications
were narrowly focused,
and relied upon actions already in place.
Licensee did not fully
address
the issues.
(Section 1.3)
This issue is an IFI. (50-315/316-
96006-07)
NRC Generic Letter 91-18 provided specific guidance for determining
operability of piping with degraded
supports.
The licensee did not
incorporate
any of the
GL 's specific guidance into existing programs.
(Section 1.3)
This issue is discussed
in section
E. 1. l.b.3 of this
report
and is being tracked
by IFI 50-315/316-95012-02.
OPERATIONS
17
19
20
21
Inconsistencies
between the functioning of the five operating
crews were
noted.
(Section 2.1)
This issue is an IFI. (50-315/316-96006-08)
Administrative activities were distracting shift supervision
from their
oversight responsibilities.
(Section 2. 1) This,issue is an IFI. (50-
315/316-96006-09)
Technical
operating guidance
was promulgated to shift supervisors
without indication that it had operations
management
approval for
implementation.
(Section 2.1)
This issue is an IFI. (50-315/316-96006-
10)
Lack of a questioning attitude
was observed
in some operators.
(Section
2. 1)
This was based
on limited observations
by the team,
and is an
element normally reviewed during routine operations
inspections.
No
further tracking is required.
Elevated
were identified in an August
1994
gA
audit, but had not been effectively corrected.
(Section 2. 1)
See item
03.
22
23
Cumbersome
nature of the work control
system did not facilitate
effective control of the status of other equipment.
(Section
2. 1)
This
issue is
an IFI. (50-315/316-96006-11)
See
items
34 and 55.
Operations
management
and supervision rarely used
gA assessment
or trend
results.
(Section 2.2)
See
items
03 and
05 regarding the weaknesses
in
gA assessments
and corrective action trending.
21
25
26
27
28
Correction of some longstanding deficiencies
such
as procedure
inadequacies,
work practices,
and equipment
clearance
errors
was
ineffective. 'Section 2.2)
The licensee's
action to address
these
concerns will be tracked under their response
to violation 50-315/316-
96006-02.
Specific examples
are addressed
in other items of this
report.
Despite procedure
changes,
performance
problems with inadequate
control
of Reactor Coolant System draining.
{Section 2.2) This issue is an IFI.
(50-315/316-96006-12)
Instances
of operators'ot
responding
promptly to alarms.
(Section
2.3)
This was
based
on limited observations
by the team,
and is an
element normally reviewed during routine operations
inspections.
No
further tracking is required.
Weaknesses
in system
knowledge in a few operators.
(Section 2.3)
This
issue
was addressed
in the inspection report reviews of specific events
and was
a comment
on minor discrepancies
observed
by the team.
Observation of new fuel receipt
and inspection revealed
instances
of
weak work practices.
(Section 2.3) This issue is an IFI. (50-315/316-
96006-13)
29
31
32
33
34
Recent inspection reports
and the team's
observations
indicated that
coordination
and communication with other site groups
was often
ineffective.
(Section 2.3)
This is an element normally reviewed during
routine operations
inspections.
No further tracking is required.
Many normal operating
and surveillance
procedures
were of lesser
quality.
(Section 2.4)
See
items
31
and 33.
The overall quality of administrative
procedures
also varied greatly.
(Section 2.4)
See
items 30 and 33.
Poor cor rective action was taken in response
to problems with poor
procedures.
(Section 2.4)
The role of specific procedures
in specific
events
was reviewed in inspection reports.
This issue is another
example of lack of adequate
corrective action which was
a violation of
10 CFR 50, Appendix B, Criterion XVI,
Corrective Action." addressed
with specific examples
in other items of this report.
Slowed implementation of procedural
improvements.
{Section 2.4)
Items
30, 31,
and
33 are
an IFI. (50-315/316-96006-14)
Both the work control
and the clearance
control processes
were
cumbersome,
imposing
a burden
on the unit supervisors.
(Section 2.4)
See
item 22.
35
Cryptic equipment
nomenclature
made work schedule readability difficult
(i.e., poor human factoring).
(Section 2.4)
See
item 22.
22
Scheduling
system did not easily support adjusting work activity
schedules if difficulties arose with a job.
(Section 2.4)
See item 22.
Unit supervisors'dministrative
burden
was increased
with multiple work
schedules
containing similar information.
(Section 2.4)
See
item 22.
ENGINEERING
38
39
40
41
Hanagement
involvement was not evident in the handling of deficiencies
identified by the "As Found Reportable"
(AFR) program.
(Section 3.1)
This issue is related to the effectiveness
of the corrective action
process
addressed
in item 07 and violation 50-315/316-96006-02.
Hanagement
involvement was not evident in the handling of
operability/reportability of the auxiliary feedwater
(AFW) pump
instantaneous
overcurrent trips.
(Section 3.1)
This issue is related
to the effectiveness
of corrective actions
addressed
in item 07 and
'iolation 50-315/316-96006-02.
The "As Found Reportable"
program was intended to identify Technical
Specifications related instruments
not in the calibration program. At
some date prior to January
1996, the licensee
had identified that TS-
related boric acid system temperature
instruments
were not in the
calibration program and,
as of February
5,
1996,
a condition report
(CR)
had not been written.
{Section 3.1)
Once this was noted
by inspectors,
a condition report
was not initiated until two days later.
Failure to
enter this deficiency in the corrective action program was
an example of
a violation of 10 CFR 50, Appendix B, criterion XVI. "Corrective
Action." which required that conditions adverse to quality promptly
identified and corrected.
= (example
(a) of 50-315/316-96006-02)
In two instances,
the Corrective Action Group
(CAG) incorrectly
designated
CR 95-1204 for the safety-related
motor-driven auxiliary
pump
{HDAFW) motor
as not safety related.
(Section 3.1)
This
issue is addressed
with item 42.
Inspection report 50-315/316-95010
section 3.5 identified that the Unit
1 west motor-driven auxiliary feedwater
pump
(HDAFWP) had
a history of
instantaneous
overcurrent trips.
The
IPAP team noted that the
overcurrent protection circuit tripped the
pump within the design
operating
range of the bus voltage,
thus there
was
a possibility for the
pump to trip at any time when required to start,
during normal operation
or an accident condition.
(Section 3.1)
Only one
pump of three
(another
50 percent capacity motor-driven
pump
and
a
IOOX capacity
turbine-driven
pump)
was affected
by the
pump trip point at
approximately
4285 volts on
a nominally rated
4160 volt bus.
The effect
of this condition on pump and system operability is
an unresolved
item
(50-315/96006-15)
pending further
NRC review.
23
Delayed
and narrow-focused
use of the condition reporting process to
identify/capture
problems
was considered
a weakness.
Example:CRs
relating to a
CCW system temporary modification (TM).
(Section 3.2)
See
items
07 and 51.
The licensee did not promptly initiate condition reports to document the
various problems,
(ie)
CRs written for boric acid system high
temperatures
and uncalibrated
instrumentation
were written two days
after the issue
were identified.
(Section 3.2)
The timeliness of
documented operability determinations
was also influencing and
influenced
by the timing of CR initiations. It appeared
that the
initiation of a
CR was being delayed until
a formal documented
could be prepared,
leaving the immediate
operability issue
unaddressed
in the interim.
Prompt identification of
a condition adverse to quality was
a requirement of 10 CFR 50, Appendix
B, Criterion XVI, "Corrective Action," which stated,
in part, that
conditions
adverse to quality are to be promptly identified and
corrected.
The failure to initiate corrective action in the past
and to
promptly initiate a condition report once these
issues
were identified
by the inspectors
were examples of a violation of 10 CFR 50 Appendix
B
(50-315/316-96006-02).
The issue of the uncalibrated boric acid system
temperature
instruments is 'addressed
in item 40.
The high temperature
issue is addressed
in item 45.
0
46
48
A condition report for the boric acid system high heat trace
temperatures
adverse
condition had not been written by operations
or
engineering until two days after inspectors
questioned
the system
status.
The high temperature
alarm condition of the temperature
instruments
could have
been identified on previous periodic operator
rounds.
(Section 3.2)
Failure to take prompt corrective action for a
condition adverse to quality was
an example of a violation of 10 CFR 50,
Appendix B, Criterion XVI, "Corrective Action," which required that
conditions adverse to quality be promptly identified and corrected.
(example (c) of 50-315/316-96006-02)
Unit
1
CCW flow balance surveillance did not meet the Updated Final
Safety Analysis Report
(UFSAR) 240
gpm minimum flows listed on
table 9.5-2 for sample coolers.
(Section 3.2)
The Unit
1 flow balance
procedure
EHP 4030 ST0.248 completed
on 9/28/95 listed
an objective to
achieve
195 gpm flow to the sample coolers.
The recorded
combined flows
of sample coolers
and the blowdown cooler flow was
142 gpm.
This item
is an IFI (50-315/316-96006-03).
Weaknesses
were also noted in the area of problem resolution.
Several
recurring issues
were not resolved in a timely manner.
(Section 3.2)
The specific issues
have
been reviewed in previous inspection report 50-
315/316-95010.
No additional inspector follow-up action
was required.
CCW check valve slamming root cause
not addressed.
Failure to resolve
the slamming issue in a timely manner
and failure to address
the
implementation of vendor
recommendations
were considered
to be
a
weakness
with the licensee's
resolution of the check valve slamming
24
50
51
issue.
(Section 3.2)
This issue
was addressed
in NRC inspection report
50-315/316-95010.
Hotor Driven
AFW Pump instantaneous
over current trips narrowly
addressed.
The narrow scope of the corrective actions
was considered
a
weakness
in the resolution of this issue.
(Section 3.2)
See item 42.
The inspectors
reviewed the licensee's
high temperatures
on the boric acid system.
Based
on missing
temperature profile data,
missing
NPSH calculations,
a lack of basis for
adequate
pressure
in the line to prevent boiling and the lack of
discussion of the high temperature effect on the process fluid, the
was considered
to be inadequate.
(Section
3.3)
The inspectors
concluded that the system
was operable;
no further
inspector follow-up action is required.
The quality of the licensee's
is discussed
further in section E.l.l.b.2 of
this report.
Inspectors
reviewed the installation of a "Cosmos"
system analysis
apparatus
controlled by a
CCW system temporary modification (TH).
Several deficiencies
were identified with the TH.
(Section 3.3)
The safety evaluation failed to address
the effect of flow
through the equipment
on the overall
CCW flow balance.
Flow
balance
values
were listed in the
The TH redirected
approximately
10 gpm from the other sample coolers including post-
accident
sample stations.
The total
CCW flow to the sample
coolers
was already less than described
in the
See item
46.
The use of tygon tubing connections
was not specified in the
TH
and its design requirements
were not evaluated.
The licensee
initiated
CR 96-0179 for this issue.
The tubing was replaced with
tubing of a higher pressure/temperature
rating.
No further action
was required,
the safety evaluation did address
the potential
consequences
of a leak.
Review by the Plant Nuclear Safety Review Committee
(PNSRC)
was
marked
"N/A" although requirements
specified that when
a procedure
was initiated which had
a full safety evaluation,
PNSRC review was
required.
The licensee initiated condition report
CR 96-0210
and
issued revision
2 to procedure
PHP 1040.SES.001
to clarify the
requirements for PNSRC reviews.
No further action was required.
Following installation, but prior to placing
a TH in operation,
the completed
package
was required to be returned to the
control
room and placed in the
TH log.
The unit had been in
service for about 30 days,
however, the package
had not been
returned to the control
room,
and operators
were not aware that
the unit was in service.
This did not meet the requirements
of
the temporary modification procedure
PHP 5040 HOD.001;
however,
no
condition report was written to address this issue.
This was
25
52
53
another
example of a violation of 10
CFR Appendix
B for the prompt
identification and correction for a condition adverse to quality.
(50-315/316-96006-02)
Some weaknesses
were noted in that system engineers
were not reviewing
work requests.
(Section 3.4)
This was
a comment
on engineering
performance
which may be reviewed under normal inspection activities.
No further follow-up tracking required.
Other programs that warranted further review included post maintenance
testing which was to receive substantially
reduced
engineering
review
beginning in April 1996, fer rography (lube analysis)
program which was
not fully established
at the time of the onsite
assessment,
and the
backlog of modification package
indicated in the performance trend
report.
(Section 3.4)
Post maintenance
testing
was addressed
in
violation 50-315/95009-03.
The implementation of the ferrography
program was addressed
under IFI 50-315/94018-02.
The backlog of
modification packages
is an IFI (50-315/316-96006-16).
The team noted
few self assessment
activities were ongoing or planned in
the engineering
area.
(Section 3.4)
This was
a comment
on engineering
performance
which may be reviewed under normal inspection activities.
No further follow-up tracking required.
Boric Acid surveillance
procedure
12
OHP 4030.STP.023
was considered
weak because it did not provide acceptance criteria for maximum system
temperatures
or guidance
on what to do.
(Section 3.4)
This issue is
an
IFI. (50-315/316-96006-17)
CCM flow balance surveillance,
I-EHP 4030 STP.248
was considered
to be
weak because
the "Acceptance Criteria" data sheet did not contain the
sample coolers
and the data sheets
did not list acceptance criteria.
(Section 3.4)
See
item 46.
MAINTENANCE
57
58
59
Voluntary
LCO entries frequently exceeded their estimated
time for the
system to be returned to service.
(Section 4. 1)
This issue
was covered
under
URI 50-315/316-94022-02.
The corr ective maintenance
wor k backlog
had steadily risen
and
had
approximately doubled since
March 1995.
(Section 4. 1)
This was
a
comment
on the performance of maintenance
which may be reviewed under
normal inspection activities.
No further follow-up tracking required.
The time for "completion of a prio'rity 30" maintenance activity had
increased significantly.
(Section
4. 1)
This was
a comment
on the
performance of maintenance
which may be reviewed under normal inspection
activities.
No further follow-up tracking required.
26
61
62
63
The team was concerned with the licensee's
failure to recognize the need
to initiate a condition report to evaluate the as-found
damage of
secondary
valve 2-HRV-651 internals
and the presence
of foreign material
in the system.
(Section 4.2)
This is another
example of weakness
in
reporting conditions
as discussed
in item 44.
Equipment
had
been returned to service without an evaluation of the
foreign material
in the system.
(Section 4.2)
See item 75.
Piping support deficiencies.
The team considered
the licensee's
failure
to recognize
the need to promptly initiate condition reports to be
a
weakness.
(Section 4.2)
This issue is another
example of the issue
discussed
in item 44 and is considered
a violation of licensee
procedures
(example
(b) of 50-315/316-96006-02).
The team was concerned with the licensee's
timely completion of
oper ability determinations.
(Section 4.2)
This issue
was discussed
in
item 44.
The maintenance
department
was not effective at preventing the
recurrence of previously identified deficiencies.
(Section 4.2)
See
item 7.
The team identified a rework condition on the turbine room sump
pump,
12-PP-25-1,
that had not been identified by the licensee.
(Section 4.2)
See item 66.
67
Weaknesses
existed in the licensee's
process for identifying rework.
(Section 4.2)
This issue is an IFI. (50-315/316-96006-18)
The majority of condition reports written for rework were narrow in
scope
and were not effective at determining the root cause for the
rework or identifying appropriate
preventive actions.
(Section 4.2)
See item 66.
68
69
Maintenance
department self-evaluations
were programmatic
and were not
in-depth or critical.
(Section 4.2)
This was
a comment
on the
performance of maintenance
which may be reviewed under normal inspection
activities.
No further follow-up tracking required.
The team was concerned with the licensee's
apparently
high threshold for
the identification of material condition problems.
(Section 4.3)
See
item 44.
70
The team
was concerned with the licensee's
lack of timeliness with
initiating condition reports
when appropriate.
(Section 4.3)
See item
44.
71
U-1
W centrifugal charging
pump was found to be inoperable
from March
15,
1996 through September
12,
1995.
(Section 4.4)
This item was
addressed
in violation 50-315/95014-01.
27
~lt
?3
74
75
76
77
U-1 main transformer
was
damaged
on July 16,
1995,
due to the improper
installation of a main generator
voltage potentiometer.
(Section 4.4)
This issue
was previously discussed
in NRC inspection report 50-315/316-
95009.
No further review is required.
U-1 East motor driven auxiliary feedwater
pump was damaged
on December
30,
1994,
as
a result of inadequate
maintenance.
(Section 4.4)
This
item was tracked
by LER 94015.
The team was concerned that licensee
management
appeared
not to have
recognized
commonalities
between
the causes for the events
discussed
in
items 71, 72,
and 73.
This issue will be addressed
in item 71, in
response
to violation 50-315/95014-01.(Section
4.4)
The foreign material exclusion practices
was considered
a weakness.
(Section 4.4)
This issue is an IFI. (50-315/316-96006-19)
See
item 61.
The licensee failed to replace
EDG quick exhaust
valve diaphragms
at the
scheduled interval.
(Section 4.5)
This issue is an IFI. (50-315/316-
96006-20)
The team considered
the ferrography program ineffective.4.5
This issue
was tracked
by URI 94-018-02 which is here re-designated
as
an IFI.
78
Procedural
adherence
or inadequate
maintenance
procedures
were
identified as contributing causes
to equipment failures by both the
NRC
and the licensee.
(Section 4.5)
This issue is an IFI. (50-315/316-
96006-21)
See item 74.
PLANT SUPPORT
79
80
81
Inadequate
management
involvement to address
the
number of unnecessary
alarms.
(Section
5. 1)
This issue
was reviewed in inspection report 50-
315/316-96004
under open item IFI 50-315/316-95012-03
The
PASS continued to have material condition deficiencies. (Section 5.2)
This issue
was reviewed further in inspection report 50-315/316-96004.
gC records
revealed significant weaknesses
in the program
implementation.
(Section 5.2)
This issue
was further reviewed in
inspection report 50-315/316-96004
and
a violation 50-315/316-96004-02
was issued.
82
83
Weaknesses
were evident in the chemistry staff's ability to identify and
resolve performance
issues.
(Section 5.2)
This issue
was further
reviewed in inspection report 50-315/316-96004
and
a violation 50-
315/316-96004-02
was issued.
1995 exercise
weakness
(verbal
communication).
Indicating
a lack of
issue resolution.
(Section 5.2)
This issue
was further reviewed in
inspection report 50-315/316-96004
under open item IFI 50-315/316-95007-
02.
28
ll
84
Improper donning of protective clothing.
(Section 5.3)
The report
identified isolated occurrences
noted
as
an indicator of level of
performance.
- Additional inspection of this area
was documented
in
inspection report 50-315/316-96004.
85
Chemistry technicians
(CTs) did not perform radiation surveys of reactor
coolant system
(RCS)
samples
or sample
areas
during routine sampling.
The reliance of an
ED as
a survey instrument
was considered
a weakness.
(Section 5.3)
This issue is an IFI. (50-315/316-96006-22)
86
Boron samples
(November
and December
1995) required
by
gC
procedures
were discarded
by the chemistry department
before their
analyses.
(Section 5.3)
This issue
was further reviewed
and violation
50-315/316-96004-02a
was issued.
87
Boron analytical
comparisons for September
1995 were not properly
documented.
(Section 5.3)
This issue
was further reviewed
and
violation 50-315/316-96004-02a
was issued.
88
The licensee failed to take required action when the acceptance
criteria
in 12 THP 6020
PAS.016 were not met.
(Section 5.3)
This issue
was
further reviewed
and violation 50-315/316-96004-02b
was issued.
29
A
Licensee
- A
- K
- D
- T
- f
- J
- B
- H
- p
- D
- J
- C
- H.
- l
"A.
- p
IP 61726
IP 71707
~oened
PARTIAL LIST OF
PERSONS
CONTACTED
Blind, Site Vice President
Baker, Assistant Plant Hanager
Noble, Radiation Protection Superintendent
Postlewait,
Site Engineering Support
Hanager
VanGinhoven, Haterial
Hanagement
Department
Allard, Haintenance
Superintendent
Gillespie, Operations
Superintendent
Hierau, Operations
Shift Technical Advisor Supervisor
Schoepf,
Supervisor,
Safety Related
Systems
Horey, Chemistry Superintendent
Kobyra, Hanager Nuclear Engineering
Freer,
Scheduling
Depuydt,
Licensing
guaka,
Project Hanagement
& Inst. Services
Barker, Plant Performance
Assurance
Russell,
Plant Protection
INSPECTION
PROCEDURES
USED
On-site Engineering
Surveillance Observations
Haintenance
Observation
Plant Operations
ITEHS OPENED,
CLOSED,
AND DISCUSSED
50-315/316-96006-01
50-315/316-96006-02.
50-315/316-96006-03
50-315/316-96006-04
50-315/316-96006-05
50-315/316-96006-06
Failure to perform a prompt operability
assessment
Failure to identify 10CFR50 Appendix
B Criterion
XVI "corrective actions" in a prompt manner.
IFI
No written 10 CFR 50.59 evaluation.
IFI
gA audit and surveillance findings appeared
to
be programmatic
and narrow in scope.
IFI
A large number of CR's were assigned
generic
root cause categories,
therefore of little
trending value.
IFI
No programmatic control to preclude revisions or
elimination of corrective actions.
I
30
0
50-315/316-96006-07
IFI
Responses
to
NRC generic communications
was
narrowly focused
and did not fully address
the
issues.
50-315/316-96006-08
50-315/316-96006-09
50-315/316-96006-10
50-315/316-96006-11
50-315/316-96006-12
50-315/316-96006-13
50-315/316-96006-14
50-315/316-96006-16
50-315/316-96006-17
50-315/316-96006-18
50-315/316-96006-19
50-315/316-96006-20
IFI
IFI
IFI
IFI
IFI
IFI
IFI
IFI
IFI
IFI
IFI
IFI
The operating
crews did not function the same.
Administrative activities were distracting shift
supervision
from their oversight
responsibilities.
Technical
operating guidance
was promulgated to
shift supervisors
without indication that it had
operations
management
approval for
implementation.
Cumbersome
nature of the work control
system did
not facilitate effective control of the status
of other equipment.
Despite procedure
changes,
performance
problems
with inadequate
control of Reactor Coolant
System draining.
Observation of new fuel receipt
and inspection
revealed
instances
of weak work practices.
Slowed implementation of procedural
improvements.
Post maintenance
testing which was to receive
substantially
reduced
engineering
review
beginning in April 1996, ferrogr aphy (lube
analysis)
program which was not fully
established
at the time of the onsite
assessment,
and the backlog of modification
packages
in the performance trend report.
Boric Acid surveillance
procedure
12
OHP
4030.STP.023
was considered
weak because it did
not provide acceptance criteria for maximum
system temperatures
or guidance
on what to do.
Weaknesses
existed in the licensee's
process for
identifying rework.
The foreign material
exclusion practices
was
considered
a weakness.
The licensee failed to replace
EDG quick exhaust
valve diaphragms
at the scheduled
interval.
31
G
~
'
50-315/316-96006-21
IFI
Procedural
adherence
or inadequate
maintenance
procedures
were identified as contributing
causes
to equipment failures by both the
NRC and
the licensee.
50-315/316-96006-22
IFI
The reliance of an
ED as
a survey instrument
was
considered
a weakness.
50-315/94-018-02
Closed
IFI
URI (same
number) re-designated
as
a IFI.
50-316/93020-02
IFI
Loss of turbine driven auxiliary
pump flow retention
due to
inaccurate
flow measurements.
DISCUSSED
50-315/96006-15
UDI
Inspection report 50-315/316-95010
section 3.5
identified that the Unit
1 west motor-driven
pump
(HDAFWP) had
a history
of instantaneous
overcurrent trips.
The
IPAP
team noted that the overcurrent protection
circuit tripped the
pump within the design
operating
range of the bus voltage,
thus there
was
a possibility for the
pump to trip at any
time when required to start,
during normal
operation or an accident condition.
32