ML17290B122
| ML17290B122 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 04/22/1994 |
| From: | Kirsch D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17290B120 | List: |
| References | |
| 50-397-94-12, NUDOCS 9405020176 | |
| Download: ML17290B122 (27) | |
See also: IR 05000397/1994012
Text
APPENDIX B
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection
Report:
50-397/94-12
Operating
License:
Licensee:
Washington Public Power Supply System
P.O.
Box 968
Richland,
WA
99352
Facility Name:
Washington Nuclear Project
2
(WNP-2)
Inspection At:
WNP-2 site near Richland,
Inspection
Conducted:
February
22 through April 2,
1994
Inspectors:
R.
C. Barr, Senior Resident
Inspector
D. L. Proulx, Resident
Inspector
S.
P. Sjnchez,
Resident
NRR Intern
Approved by
D. F. ir
, Ch'
Project
Branch
a e Si
ne
Ins ection
Summar
~Al<<d:
R tf,
dt
d tt
by
td tt*d t
f
control
room operations,
licensee
action
on previous inspection findings,
operational
safety verification, surveillance
program,
maintenance
program,
licensee
event reports,
special
inspection, topics,
and procedural
adherence.
During this inspection,
Inspection
Procedures
61726,
62702,
62703,
71707,
71710,
92700,
92701,
92702,
and 93702 were used.
Results:
Strenqths:
The licensee
has developed
a thorough,
comprehensive
Refueling Outage
9 plan.
Weaknesses:
~
Interorganizational
communications
were weak in making decisions with
respect to extending
Cycle
9 operations
(paragraph
2.2).
~
Work quality was poor during the overhaul of fuel pool Cooling
Pump
FPC-
P-lA (paragraph
5).
940S020l76
940422
ADOCK 05000397
Q
~
Long-standing deficiencies
were not promptly corrected
on the control
room emergency chillers that rendered
the chillers inoperable for over
1 year (paragraph 6.2).
~
The licensee's
review of NRC Information Notice (IN) 89-44 was incomplete
because
the review did not consider that potential control
room
habitability problems could occur due to the location of nitrogen storage
tanks
(paragraph
6.3).
~
Plant Procedures
Hanual
(PPH) 2. 10.3,
Revision 21, "Control Cable
and
Critical Switchgear
Rooms
HVAC," was inadequate
in that the wrong gage
was referenced for system adjustments
and the electrical
breaker
lineup
prescribed
the wrong position for several
breakers
(paragraph
6.4).
~
Operators failed to follow the procedure for the control
room ventilation
systems
in that several
controllers
were set improperly (paragraph
6.5).
~
A number of material deficiencies
and drawing errors existed.
These
items indicated that the system
management
program
and the system
engineer
walkdowns were not of sufficient detail
(paragraphs
6.6 and
6.7).
~
Implementation of the outage planning process
was weak (paragraph
8).
Summar
of Ins ection Findin s:
~
Violations 397/9412-01,
and 397/9412-02
were opened
(paragraphs
6.2, 6.4,
and 6.5).
~
Violations 397/9318-01,
397/9318-10,
397/9318-12,
and 397/9324-02
were
closed
(paragraph
7).
Attachment:
~
Persons
Contacted
and Exit Heeting
DETAILS
1
PLANT STATUS
At the start of the inspection period, the plant was operating at
100 percent
power.
During the inspection period,
the plant went into and out of final
feed water temperature
reduction,
as operating conditions permitted.
Throughout this period,
the plant operated
at, full power (except for momentary
power reductions to support weekly bypass
valve testing
and control rod
exercises).
On Harch 26,
1994, with the reactor at
75 percent
power, Control Rod 06-39 failed to insert
when operators initiated
a scram signal locally
during control rod scram time testing.
Operators
reduced
power and manually
inserted this control rod.
The operators
then tested
the scram times of the
remaining
184 control rods to assess
their short-term operability.
The
licensee
conc'luded that degraded
in the control rod's
solenoid pilot valves
(SSPV) contributed to the cause of the rod's failure to
insert.
At the
end of this inspection period, the plant was operating at 64
percent
power with control rod
SSPV refurbishment
in progress.
2
ONSITE FOLLOWUP TO EVENTS (93702,
92701)
2.1
Failure of Control Rod 06-39 to Insert Durin
2. l. 1
S stem Descri tion and Desi
n Basis
One of the reactivity control systems for the
WNP-2 reactor is the control rod
system.
The
WNP-2 reactor control rods are positioned
by hydraulics.
The
hydraulics
are controlled
by electro-pneumatics.
The electro-pneumatics
use
a
number of Automatic Switch Company solenoid operated
valves to perform the
rapid insertion
(scram) function of the
185 control rods.
The rod control
electro-pneumatic
system
has the three following means of rapidly inserting
(scramming) control rods into the reactor core:
(1) the
SSPVs which are
guality Class
1 components;
(2) the backup
scram pilot air solenoid valves,
which are guality Class
2 components;
or (3) the anticipated transient without
scram automatic rod insertion
blowdown valves,
which are
guality Class
2 components.
The design basis of the reactivity control system is to provide sufficient
nuclear reactivity control devices
(control rods) to control the excess
reactivity in the core
and to provide for adjustments
of the control rods to
permit power generation.
The safety functions of the reactivity control
system,
that apply to this event,
are to provide sufficient excess
negative
reactivity to keep the reactor
shutdown,
thereby preventing fuel damage,
and
to provide sufficient rapid insertion of control rods
so that no fuel
damage
results
from any abnormal
operating transient.
2. 1.2
Event Descri tion
At 1:43 p.m.
(PST), Saturday,
March 26,
1994, with the reactor at 75 percent
power
and
WNP-2 licensed operators
conducting Control
Rod scram time testing
on
a
10 percent
sampling of control rods, control rod 06-39 failed to insert
when operators initiated
a scram signal locally.
Because
the positions of
Control Rod 06-39 switches
and valves
had
been verified as correct,
licensed
operators
concluded that the control rod had malfunctioned.
At 1:52 p.m., the
operators
manually inserted
Control Rod 06-39, de-energized
that rod's
electrical
components,
and declared
the rod inoperable
per
WNP-2 Technical
Specification
(TS) 3. 1.3. l.a. l.a.
The Shift Hanager notified supply system
management
of the malfunction;
however,
he did not notify the resident staff
of this failure or the entry into the Limiting Condition for Operation.
The Shift Hanager
documented
the failure of Control Rod 06-39 to insert in
Problem Evaluation
Request
(PER) 294-0235.
At 3 p.m., licensee
management
decided to perform scram time testing
on selected
Later that
day, the Plant Hanager
(PH) concluded that scram testing of all
185 control,,
rods
was necessary
to gather data to assess
control rod operability.
Based
on that testing,
the
PH considered all the control rods operable,
with
the exception of Control Rods 54-47,
54-15,
30-31,
and 10-15, which were out-
of-specification slow on start of initial rod motion and
had
been fully
inserted.
Operators
had also fully inserted
which could
not be scram time tested
due to a failed transponder
card located in the
testing circuitry.
The licensee
wrote emergency
work order
HS 28 to remove,
disassemble,
and rebuild
CRD-Y-117 and CRD-V-118 For Control Rod 06-39.
By approximately 6:00 p.m., the system engineer
determined that Control Rod 06-39 had failed to insert because
the Buna-N rubber diaphragms,
environmentally qualified components of SSPV CRD-V-118,
had thermally aged
and
failed due to embrittlement.
The system engineer characterized
the failure as
brittle cracking of the diaphragm with the crack going approximately
180 degrees
around the interior circumference of the diaphragm.
He noted that
the diaphragms of SSPV CRD-V-117 were flexible.
At 8 p.m., the licensee
concluded that the failure of the diaphragm could have caused
the rod not to
by not exhausting
the air on the exhaust
diaphragm at
a rate greater
than the leakage of air into the diaphragm area.
At 3:58 p.m.,
on Harch 27,
1994, the repair of SSPV 'CRD-Y-117 and CRD-V-118
were completed
and the operators
declared
At
6: 17 p.m., operators
increased
reactor
power to 88 percent
and, at 8: 16 p.m.,
operators
completed
the scram time testing of all
185 control rods.
This issue will,be followed up in a special
inspection
(NRC Inspection
Report 50-397/94-15).
2.2
Core Fuel
Reload
Desi
n for 0 eratin
C cle
10
During routine inspection
associated
with outage preparations,
on February
25,
1994,
the resident
inspectors
learned that the licensee
was considering
changing the previously finalized batch size
(number of fuel assemblies)
and
reload design (fuel arrangement
and rod patterns)
for the next operating
cycle,
Cycle 10, which was scheduled
to begin in July 1994.
The inspectors
assessed
this activity to understand
the causes
and potential
impact
on
operation.
The following is
a chronology of the issues that led to the apparent late
decision making in the finalization of the Cycle
10 reload design:
In July 1993, the
PH had
begun to question the supply system designing
core reloads,
assuming
a capacity factor of 60 percent,
when it appeared
that for WNP-2 power production to be economical
the plant
had to operate
at
a capacity factor of about
73 percent.
In October
1993, the licensee
received the fuel vendor's
recommended
fuel
design for Cycle 10.
This design
assumed
a 60 percent capacity factor
and the implementation of the reactor
power up-rate
(RPU) modification
which enabled
the generation of approximately
50 additional
megawatts of
electrical
power.
In November
1993, the licensee's
senior management
requested
authorization
from the Bonneville Power Administration
(BPA) to extend
Cycle 9 operation
from approximately April 16 to May 15,
1994,
because:
(I) some long lead time repair parts
may not be available for Refueling
Outage 9; (2) the
RPU license
change
had been submitted late
and
may not
be approved
by the
NRC within the current operating
schedule;
and (3) the
Refueling Outage
9 preparations
were
somewhat
behind schedule.
Also in
November
1993, at
a senior management
review group meeting
(SHRG), the
group questioned
the licensee's
fuel designers
about the adequacy of the
Cycle
10 design projecting that
WNP-2 would operate
at
a capacity factor
substantially greater
than the
assumed
73 percent,
which appeared
possible
since the plant had
been operating well.
The designers
subsequently
informed the
PN that the reload design
was adequate.
However, the fuel designer s were not cognizant that management
had
requested
an extension to Cycle 9 operation.
On January
15,
1994,
WNP-2 fuel designers
again determined that the
Cycle
10 reload design
was adequate.
~
On January
17,
1994, the
WNP-2 fuel designers
learned that management
had
requested
an extension to Cycle 9 operation.
~
On January
26,
1994, the
BPA authorized the licensee to extend
WNP-2
Cycle
9 operation to April 29,
1994.
On February
2,
1994, the licensee
announced that
BPA had requested
the
supply system operate
WNP-2 until April 29,
)994, to support regional
power needs.
On February
14,
1994, the supply system fuel engineers
determined that
the hot excess reactivity for Cycle 10, reload design,
was
a concern,
after having been
informed by the fuel vendor on approximately
-6-
February 7,
1994, that the hot excess reactivity for Cycle
11 was
a
concern.
~
On February
17,
1994, the supply system
met with the fuel vendor to
establish
a plan to address
these
concerns.
The plan included increasing
batch size from 156 to 164 assemblies,
delaying the delivery of 32 fuel
assemblies
scheduled
for delivery on February
23,
1994,
and revising the
previously submitted final energy notice.
Also,
on February
17,
1994,
licensee
senior
management
decided to defer the implementation of the
RPU
until Refueling Outage
11.
~
On Parch 4,
1994, the licensee
again
met with the fue'Is vendor
and
discussed
four reload design options that were being considered.
Each of
the four design options reverted to the original design
of, 156 fuel
assembles,
due in part to the deferral of the
RPU.
The licensee
subsequently notifi d the vendor of the selectioii of the final reload
design option and
had the remaining Cycle
10 reload fuel assemblies
shipped.
Based
on the above chronology, the inspectors identified that the causes
which
led to the licensee
considering
a change to the batch size
and reload design
for Cycle
10 were as follows:
senior management
failed to effectively
communicate their plans to the fuels engineers
to extend Cycle
9 operation;
the timeliness
and quality of the
RPU amendment to the facility operating
license
was lacking, which resulted
in the deferral of the modification and
potential for reanalysis;
the licensee
fuel engineers
did not perform a, timely
detailed analysis of the potential
impact of operating at substantially higher
capacity factors
and extending Cycle
9 operation;
and weak outage planning
implementation.
2.3
Conclusions
Poor communications
resulted in late decision
making with respect to core
reload design.
3
OPERATIONAL SAFETY VERIFICATION (71707)
3.1
Plant Tours
The inspectors
toured the following plant areas:
Reactor Building
Control
Room
Diesel
Generator Building
Radwaste
Building
Service Water Buildings
Technical
Support Center
Turbine Generator Building
Yard Area and Perimeter
k
3.2
Ins ector Tour Observations
3.2. I
0 eratin
Lo s
and Records
The inspectors
reviewed operating logs
and records
against
TS and
administrative control procedure
requirements.
3.2.2
Honitorin
Instrumentation
The inspectors
observed
process
instruments for correlation
between
channels
and for conformance with TS requirements.
3.2.3
f~lif
2
The inspectors
observed
control
room and shift manning for conformance with
TS,
and administrative procedures.
The inspectors
also
observed
the attentiveness
of the operators
in the execution of their duties,
and the control
room was observed to be free of distractions
such
as nonwork
related radios
and reading materials.
3.2.4
E ui ment Lineu s
The inspectors verified valves
and electrical
breakers
to be in the position
or condition required
by TS and administrative
procedures
for the applicable
plant mode.
This verification included routine control board indication
reviews
and conduct of partial
system lineups.
TS limiting conditions for
operation
were verified by direct observation.
3.2.5
E ui ment Ta
in
The inspectors
observed
selected
equipment, for which tagging requests
had
been initiated, to verify that tags were in place
and the equipment
was in the
condition specified.
3.2.6
General
Plant
E ui ment Conditions
The inspectors
observed plant equipment for indications of system leakage,
improper lubrication, or other conditions that would prevent the system from
fulfillingits functional requirements.
were observed to
ascertain their status
and operability.
3.2.7
Fire Protection
The inspectors
observed firefighting equipment
and controls for conformance
with administrative procedures.
3.2.8
Plant Chemistr
The inspectors
reviewed chemical
analyses
and trend results for conformance
with TS and administrative control procedures.
The licensee
continued to
operate with elevated
reactor water conductivity.
The licensee controlled
reactor conductivity at less
than 0.15 micro Siemens
by frequent condensate
filter demineralizer
changeouts.
3.2e9
Radiation Protection Controls
The inspectors periodically observed radiological protection practices to
determine whether the licensee's
program was being implemented
in conformance
with facility policies
and procedures
and in compliance with regulatory
requirements.
The inspectors
also observed
compliance with radiation work
permits,
proper wearing of protective
equipment
and personnel
monitoring
devices,
and personnel
frisking practices.
Radiation monitoring equipment
was
frequently monitored to verify operability and adherence
to calibration
frequency.
3.2. 10
Plant Housekee
in
The inspectors
observed plant conditions
and material
and equipment
storage to
determine the general
state of cleanliness
and housekeeping.
Housekeeping
in
the radiologically controlled area
was evaluated
with respect to controlling
the spread of surface
and airborne contamination.
3.2.11
~Securit
The inspectors periodically observed security practices to ascertain that the
licensee's
implementation of the security plan was in accordance
with site
procedures,
that the search
equipment at the access
control points was opera-
tional, that the vital area, portals were kept locked
and alarmed, that
personnel
allowed access
to the protected
area
were
badged
and monitored,
and
the monitoring equipment
was functional.
3.3
En ineered
Safet
Features
Malkdown
The inspectors
walked
down selected
engineered
safety features
(and systems
important to safety) to confirm that the systems
were aligned in accordance
with plant procedures.
During the walkdown of the systems,
items such
as
hangers,
supports,
electrical
power supplies,
cabinets,
and cables
were
inspected
to determine that they were operable
and in a condition to perform
their required functions.
Proper lubrication and cooling of major components
were also observed for adequacy.
The inspectors
also verified that certain
system valves were in the required position by both local
and remote position
indication,
as applicable.
The inspectors
walked down accessible
portions of the following systems
on the
indicated dates:
~Sstem
Diesel Generator
Systems,
Divisions 1, 2,
and 3.
Dates
Harch
24
0
-9-
Hydrogen Recombiners
Low Pressure
Coolant Injection
Trains "A," "B," and
"C"
Low Pressure
High Pressure
0
Reactor
Core Isolation Cooling
Residual
Heat
Removal
(RHR),
Trains "A" and
"B"
March 24
March 8,
24
March 8,
24
March 8,
24
March 8,
24
March 8,
24
Standby
Gas Treatment
Standby Service
Water
125V
DC Electrical Distribution,
Divisions
1 and
2
March 24
March 24
March 25
February
23,
March 8
250V
DC Electrical Distribution
3.4
Conclusion
February
23,
March 8
The inspectors
concluded that the systems
were in good order
and aligned in
accordance
with plant procedures.
4
SURVEILLANCE TESTING (61726)
The inspectors
reviewed surveillance tests
required to be performed
by the
TS
on
a sampling basis to verify that:
(1)
a technically adequate
procedure
existed for performance of the surveillance tests;
(2) the surveillance tests
had
been
performed at the frequency specified in the
TS and in accordance
with
the
TS surveillance
requirements;
and (3) test results satisfied
acceptance
criteria or were properly dispositioned.
The inspectors
observed
portions of the following surveillances
on the dates
shown:
Procedure
Descri tion
Dates
Performed
7.0.0
Shift and Daily Instrument
March
11
Checks
7.4.1.3.2
'ontrol
Rod Drive Scram Time
Harch 28-30
Test with Auto Scram Timer
-10-
The inspectors
concluded that the surveillances
were performed
and documented
properly.
5
PLANT MAINTENANCE (62703)
During the inspection period,
the inspectors
observed
and reviewed
documentation
associated
with maintenance
and problem investigation activities
to verify compliance with regulatory requirements
and with administrative
and
maintenance
procedures,
required quality assurance/quality
control
involvement,
proper use of clearance
tags,
proper equipment alignment
and use
of jumpers,
personnel
qualifications,
and proper retesting.
The inspectors
verified that reportability for these
maintenance activities was correct.
The inspectors
witnessed
portions of the following maintenance activities:
Descri tion
Dates
Performed
DH-3901,
Replace
Fire Damper
ROA-FD-7
February
22
EF-3501
Install Strain
Gages
and Perform
March
16
MOVATS Testing for SW-V-75A
DV-0901, Repair
and Overhaul
HT-1601,
Replace
Diaphragms for Scram
Pilot Valve Solenoids
March 28
Narch 29-31
In addition to the above maintenance
observations,
the inspector reviewed the
in-process
and completed
work package for fuel pool Cooling
Pump FPC-P-lA per
Haintenance
Work Order FL-9801.
The inspectors
noted that this work was
originally scoped to replace the leaking mechanical
seal.
The inspectors
reviewed the past work history to ascertain
the quality of work that was
performed.
The inspectors
noted that in April 1993
Work Order AR6375 was performed
on
this
pump to replace
the existing
pump seals
and
add
a vent to the
pump
casing.
This procedure
also aligned the
pump.
However,
2 months after this
work was complete,
the
pump exhibited excessive
seal
leakage
again
and was
caution tagged "for emergency
use only."
Upon disassembly of FPC-P-1A per
Maintenance
Work Order FL-9801 in March of
1994, the licensee
noted that the bushing
was broken,
the seal
was
worn, the mating ring was worn (indicating contact with the bushing),
foreign
material deposits
were found on the mating ring,
and the drive bands
and
retainer of the seal
had
become grooved.
The licensee
determined that these
deficiencies
should not have occurred after only 2 months of operation.
The
licensee
replaced
each of the failed components
under the supervision of the
system engineer
and
a vendor representative.
The licensee preliminarily
indicated that improper assembly
and alignment of the
pump resulted
in the
premature failure of the sealing
components.
The licensee
had not yet
determined
the root cause of this failure.
The inspectors will evaluate
the
root cause
when completed
by the licensee.
No violations or deviations
were identified.
6
ENGINEERED SAFETY FEATURES
WALKDOWN (71710)
The inspectors
performed
a detailed
walkdown of control
room heating,
ventilation,
and air conditioning
(HVAC).
This walkdown included both trains
of the emergency control
room chillers and detailed reviews of the low
pressure
core spray system
and Train A of the
RHR system.
The inspectors
examined
the system lineup procedures
to ascertain
whether they
matched plant drawings
and the as-built configuration.
The inspectors
verified that:
hangers
and supports
were
made
up properly, aligned correctly,
and
had sufficient hydraulic fluid levels;
housekeeping
was adequate;
insulation
and lagging was in-place
and maintained;
valves were installed
correctly, properly maintained,
locked
as appropriate,
and that local
and
remote position indications
were functional
and indicated the
same values;
flammable materials
were properly stored;
major system
components
were
properly labeled,
lubricated,
cooled,
and
no leakage existed;
instrumentation
was properly installed
and functioning; instrument calibration dates
were
current;
support
systems
were operational;
and breaker positions at local
electrical
boards
and indications
on control boards
were consistent.
With the
assistance
of licensee
personnel,
the inspectors
examined the interior of
breakers
and electrical cabinets.
In addition, the inspectors
assessed
licensee
procedure
PPH 2. 10.3,
Revision 21, "Control Cable
and Critical
Switchgear
Rooms
HVAC," to ascertain
whether the procedure
was adequate for
the system to perform its intended safety function.
The
inspectors'bservations
and findings are discussed
in the following paragraphs.
6. 1
Back round
LER 93-31 identified that the safety related control
room
HVAC would not
prevent temperature
in the control
room from exceeding
104 F.
The licensee
event report
(LER) states
that
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> into a design basis
event,
the control
room temperature
would reach approximately 107'F.
This concern
appeared
to
raise environmental qualification and control
room habitability questions.
The
LER primarily addressed
inadequate
cooling due to the degraded
cooling
capability of the service water system.
Because of the concerns
raised in the
LER, the inspectors
concluded that the control
room
HVAC required closer
scrutiny.
In addition, the inspectors
reviewed previous
NRC inspection reports to
determine if previous
commitments
and problems
had
been satisfactorily
implemented.
NRC Inspection
Report {IR) 50-397/90-05
(Haintenance
Team
Inspection)
indicated that the control
room chillers had been disassembled
and
inoperable for a period of 27 months.
The inspectors
had noted that redundant
seismic category I and environmentally qualified control
room emergency
chillers were required to be operable
per license condition
21 of the
WNP-2
-12-
operating license.
However,
IR 50-397/90-05 states
that the licensee
initially rationalized that corrective actions for the inoperable
equipment
"should not be pursued
at the crisis level" because
they were not specifically
addressed
in the TS.
The inspectors
were also concerned
because
in
IR 50-397/90-05,
neither
a justification for continued operation
(JCO) nor an
OA were performed for the degraded chillers.
The
licensee's
response
to the inspection report indicated that
a JCO and
an
OA
had
been performed.
In addition, the licensee
stated that, in the future,
JCOs
and
OAs would be performed for degraded
equipment
and that, for
safety-related
equipment,
that
was not addressed
in the TS, reasonable
allowed
outage times
(AOT) would be determined.
The control
room emergency chillers
were returned to service in January of 1991.
6.2
Control
Room Chiller 0 erabilit
During the inspector's
walkdown of the control
room emerg
ncy chillers,
two
deficiency tags
were observed
on the chiller s which appeared
to indicate
excessive
delays
in repairing Chiller CCH-CR-18.
One deficiency tag dated
February 4,
1993,
stated that the motor trips
on overload.
The other tag,
dated April 19,
1993, stated that the temperature controller indicates
zero
and that it will not control cooling properly.
The inspectors
were concerned
that the control
room chiller may have
been
inoperable for 13 months.
The inspectors
discussed
these deficiencies with the system engineer
(SE), his
supervisor,
and the systems
engineering
manager.
The licensee
indicated that
they were aware of these deficiencies;
however, their repair
had
been deferred
several
times.
The inspectors
asked if a prompt
OA (POA) was issued for
either of these deficiencies.
The licensee
stated that
a formal
POA had not
been performed,
but would now be completed.
The inspectors
also questioned
whether
a JCO had been developed for the degraded
condition.
The licensee
replied that
a
JCO had
been developed.
However,
when the inspectors
requested
a copy of this JCO, the licensee
presented
the inspectors
with a copy of the
JCO written in Hay 1990 that addressed
the previous inoperability of the
chillers discussed
in paragraph
6. 1 of this inspection report.
No specific
AOT appeared
to be addressed.
The licensee's
POA determined that Chiller CCH-CR-18 would trip off and not
perform its intended function under the present
degraded
condition if service
water temperature
was less
than
55~F.
On Harch 23,
1994, the licensee
immediately
noted that service water temperature
was at 52~F and declared
Chiller CCH-CR-18 inoperable.
Due to the licensee's
POA, the inspectors
concluded that Chiller CCH-CR-18 had
been inoperable for many months.
This
condition appears
to indicate
a repeat of the untimely correction of the
degraded
condition of the chillers
and poor management
oversight in pursuing
corrective actions similar to that discussed
in paragraph
6. 1.
Appendix 8, Criterion XVI, requires
measures
to be established
to assure that
conditions
adverse
to quality such
as failures, malfunctions, deficiencies,
deviations,
defective material
and equipment,
and nonconformances
are promptly
identified and corrected.
Contrary to this requirement,
conditions
adverse to
quality concerning control
room Chiller CCH-CR-18, which is safety related
and
-13-
required
by the
WNP-2 operating license,
were not promptly corrected.
Because
deficiency tags dated
February 4,
1993,
and April 19,
1993, indicated that
Chiller CCH-CR-1B was in a degraded
condition for over
1 year,
the failure to
provide prompt corrective actions is
a violation of 10 CFR 50, Appendix B,
Criterion XVI (Violation 397/9412-01).
6.3
Potential for Nitro en Introduction into the Control
Room
A control
room operator aid identified that the liquid nitrogen tank, that is
used for safety relief valve operation
and inerting of the drywell, is located
near
one of the control
room ventilation intake structures.
The plant was
presently configured for intake from near this location.
The operator aid
also stated that the control
room may have
an oxygen deficient atmosphere
during
a design basis accident.
The nitrogen tank is not
a quality Class
I
category
component.
The licensee
postulated
the failure of this nitrogen tank
and intake of large
amounts of nitrogen into the control
room.
The inspectors
noted that
"Hydrogen Storage
on the Roof of the Control
Room,"
alerted the Supply System of the concerns for having nonoxygen
gas supplies in
close proximity of the control
room intakes.
The licensee
had previously evaluated this condition
and determined that
control'oom habitability problems
due to a failure of the nitrogen tank was
highly unlikely.
The licensee
concluded that this potential
was not
reportable
and
was not outside the design basis of the plant.
The inspectors
walked down the control
room intake structure
and noted that the closest
intake to the nitrogen tank was approximately
100 feet away.
Based
on this
observation
and the licensee's
evaluation,
the inspectors
accepted
the
licensee's
conclusions.
The inspectors
noted that the licensee's
review of IN 89-44 appeared
to be
cursory.
The supply system's
operating
experience
review of the information
notice only addressed
the location of hydrogen tanks
and required
no further
action.
The supply system's
review did not recognize the significance of
improperly located nitrogen tanks,
nor its consequences.
Although the
previous paragraphs
indicate that this poor review had
no safety significance,
this item emphasizes
the need for improved reviews of industry experience.
6.4
Procedural
Inade uacies of PPH 2. 10.3
During the inspectors'alkdown
of the control
room
HVAC system,
the
inspectors
used
PPM 2.10.3 to determine if adequate
direction for controlling
this system existed
and if personnel
adhered to the procedure.
The inspectors
noted the following apparent
problems with the procedure:
~
Final Safety Analysis Report,
Section 9.4. 1.5. 1, indicates that the only
operator action necessary
to operate Train
B of the control
room chillers
is to take the Chiller CCR-P-1B switch in the control
room to AUTO, at
which point the system will operate
automatically.
It further states
that
some
manual
valve manipulation is necessary
to operate Train A of
the emergency chillers.
The inspectors
were concerned that the latest
-14-
deviation to
PPM 2. 10.3 directed
manual manipulation of valves for
operation of Chiller B and that
a safety evaluation per
had
not been performed for this change.
The inspectors
discussed
this
concern with the SE.
The
SE stated that the manual
valve manipulation
was not needed for system operability,,but
was needed for "fine tuning"
of the system during routine operations.
~
Step 4.5 of PPM 2. 10.3 states
that the chillers must
be run for at least
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before checking the oil.
LER 93-31 states
that the control
room
will exceed
104'F
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> into an accident.
The inspectors
were
concerned that checking for proper lubrication
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the highest
heat load
may not be adequate
to ensure operability of the system during
accident conditions.
The
SE stated that the oil check after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of
operation only applied during routine operation or when the chiller was
being operated for preventive maintenance
purposes.
~
In two instances
Step 5.5(19) refers the operator to use indication
on
Gage
WCH-PI-6B to control pressure.
The licensee
stated that the
intention of this step
was to refer to Chiller CCH-PI-6B.
The licensee
revised
PPM 2. 10.3 to correct this error.
On page
39 of the breaker lineup sheet,
the position for Switch
WMA-
FN-52B indicates
"ON/OFF."
There is no amplifying instruction to
determine
when this breaker
should
be
ON or OFF.
The licensee
was
evaluating this item on the lineup sheet to determine if a change is
necessary.
~
Breaker lineups for WMA-EHC-51B, 52B,
and
53B listed the required
position
as
"ON/LOCKED OFF(+)."
The (+) or amplifying instruction at the
bottom of the page indicated that the position of these
breakers
should
be
"OFF" in May through
September
and
"ON" in October through April.
On
March 18,
1994,
the inspectors
noted that the actual position was
"LOCKED
OFF."
The inspectors
noted that Paragraph
5.9,
Step
1, states
that these
should
be
"LOCKED OFF" during Modes 1, 2,
and 3.
The local operator aid
also states this requirement.
The licensee
stated that the breaker
was
in the correct position but that the procedure
was in error.
The error
was introduced during the latest revision of the procedure.
The licensee
initiated
a procedure revision to correct this error.
~
On page
40 of the breaker lineup sheet,
the procedure lists the required
positions for Switches
WRA-EUH-52, 53,
54,
and
56 as
"ON/OFF(+)."
There
is no explanation of the (+) on this page.
The licensee
stated that
there should
have
been
an amplifying instruction stating that the breaker
should
be
"OFF" in May to September
and
"ON" in October through April.
The inspectors
noted that all of these
breakers
were in their correct
position.
Although none of the above procedure errors involved inoperability of the
system,
the inspectors
were concerned that the procedure
reviews were not
adequate.
The licensee
stated that each of the errors that the inspectors'
-15-
identified was introduced during the latest revision
and after each of the
breakers
had
been properly positioned.
The inspectors
noted,
however, that
PPH 2. 10.3
had recently
been verified and validated,
indicating that the
verification and validation process
was of poor quality.
The failure to
provide the appropriate
gage designation for Chiller CCH-PI-68 and the failure
to provide appropriate
breaker lineup sheets
in Revision
21 of PPH 2. 10.3 was
an example of a violation of 10 CFR 50, Appendix 8, Criterion
V
(Violation 397/9412-02).
6.5
Procedure
Com liance Issues
With PPM 2. 10.3
The inspectors
noted
a number of instances
in which the emergency chillers or
control
room ventilation components
were set improperly or misaligned
as
required in
PPM 2. 10.3:
~
Step 5.5(7)e requires
the operator to ensure that the Temperature
Control
Point, located
on the local panel called the temperature
control module,
is set
6 increments
from the
"RAISE" position.
The inspector
found that
the actual setting
was at
4 increments
from the "RAISE" position.
~
Step 5.5(7)e requires
the operators
to ensure that the Maximum Load
Adjustment (also located
on the local panel) is set at 69 percent.
The
inspectors
noted that the actual setting
was at 90 percent.
~
Step 5.5(8) requires
the operators
to ensure Chiller SW-TIC-118 is set at
75'F.
The inspectors
noted that the actual setting
was at 70OF.
~
Step 5.5(9) requires the operators
to ensure Chiller WMA-TIC-118 is set
between
744F and
76OF.
The inspectors
noted that the actual setting
was
at 69OF.
~
Paragraph
4.9, in the precautions
and limitations section of PPH 2. 10.3,
requires that the setpoints of the temperature
controllers of the control
room to be set
as follows to meet the Final Safety Analysis Report
commitments of normal control
room temperatures:
WMA-TIC-12Al
74 to 76 degrees
WMA-TIC-1281
74 to 76 degrees
WMA-TIC-12A2
WHA-TIC-1282
70 to 72 degrees
70 to 72 degrees
WHA-TS-12A
Knob A- 71 to 73 degrees,
Knob 8- 69 to 71 degrees
WHA-TS-128
Knob A- 71 to 73 degrees,
Knob 8- 69 to 71 degrees
Contrary to Paragraph
4.9, all of the setpoints for the above controllers were
set improperly,
some
by as
much
as
5 degrees.
The licensee
stated that
-16-
control
room operators
adjusted
these setpoints without,referring to the
procedure.
The operators initiated
PER 294-0236 to address this condition.
This
PER appeared
to indicate that the operators
did not consider precautions
and limitations to be mandatory steps
in a procedure.
The inspectors
noted
that licensee
administrative
procedures
did not support this conclusion.
The inspectors
discussed
all of the
above incorrect settings
and misalignments
of the
The
SE stated that the operators
mispositioned
these controllers
during various operations
on the system
apparently without regard to returning these
HVAC systems
to the required
standby or normal positions of PPM 2. 10.3.
Operations
management
discussed
the above items with the operations staff and posted operator aids to prevent
recurrence.
The failure to follow PPM 2. 10.3 in setting the setpoints for the
above listed controllers
was
an example of a violation of 10 CFR 50,
Appendix B, Criterion
V (Violation 397/9412-02).
6.6
Other Material Deficiencies
Deficiency Tag 0093789 dated
November 6,
1993, states
that
LOW REFRIG.
PRESS.
alarms at 1.5 psig.
The
SE stated that
a maintenance
work order had already
been
issued.
The inspectors
found oil leaks inside the local panel for the Control
Room
B chiller.
The
SE wrote
a deficiency tag
upon the
inspectors'otification.
Temperature
Gage TI-69B had
a broken glass
cover with a deficiency tag
dated October
19,
1993.
The licensee
had already initiated
a maintenance
work order.
The inspectors
found that Valve SW-V-862 had
a loose handwheel.
The
stated that this would be corrected during the next routine walkdown.
The position indicator for Chiller CCH-V-3A did not indicate valve
position properly.
The
SE initiated a deficiency tag to document this
item.
The inspectors
noted that
a U-bolt nut was loose
on the drain connection
for Chiller CCH-RY-2A.
The
SE stated that maintenance
would correct this
deficiency.
The inspectors
noted that
a temperature
indicator (TI) and cap were
missing from the top of Chiller A.
However, this TI was found on
Chiller
B.
The
SE stated that the TI was necessary
only for
troubleshooting
and was left in place
on the chiller for which the
troubleshooting
had
been performed.
The
SE also stated that the cap for
the connection
needed to be replaced.
-17-
~
The inspectors
found damaged
and split electrical
conduit
on emergency
Chiller A.
The
SE wrote
a maintenance
work order to document
and correct
this deficiency.
~
The inspectors
found that Chiller CCH-V-43 had
a loose
handwheel.
The
stated that the handwheel
would be tightened during the next routine
system walkdown.
~
The inspectors
found that the end connection
downstream of Chiller
CCH-'-63
was not capped
as
shown
on the system print.
The licensee
determined that,
since the valve was shut
and
no leaks were apparent,
this item had
no safety significance.
The
SE stated that the cap would
be replaced.
6.7
Drawin
Oeficiencies
The inspectors
found that downstream of Valves
SW-V-8S6A and 865B, there are
two valves not shown
on the drawing,
one labeled
"instrument isolation valve
PSllA/B" and the other "isolation drain valve PSllA/B."
The
SE stated that
the
WNP-2 policy was not to show the details of drain
and isolation valves for
pressure
switch lines
on top tier drawings.
The inspectors
found that,
on page
36 of the valve lineup sheet,
Chiller CCH-
V-13A was listed
as closed;
however,
the drawing required the valve to be
open.
The
SE submitted
a drawing change
request to correct this problem.
6.7
Conclusions
The inspectors
concluded that the licensee did not monitor the control
room
HVAC systems
and procedures
in necessary
detail to ensure
long-term
operability and prompt corrective action of potential
problems.
Several
previous inspection reports
noted that system engineers,
and the licensee
as
a
whole, did not appear to perform walkdowns of the systems with the necessary
frequency or at the requisite level of detail to ensure
a quality. condition of
the safety systems.
The licensee
committed in their 1993 Systematic
Assessment
of Licensee
Performance
response
to perform system walkdowns with
teams,
which included the system engineer,
a design engineer,
an equipment
operator,
and
a maintenance
craftsman.
The licensee
stated that these
team
walkdowns
had
been
done for the control
room
HVAC systems,
but that these
teams did not look in sufficient detail to identify and correct the type of
problems identified by the inspectors.
Although many of the
inspectors'bservations
appeared
to be minor in nature,
the number of
inspectors'indings
appeared
to -indicate that strong
management
attention is required to
improve total
system performance.
The inspectors
discussed
these
conclusions
and all of the above observations
with the
PH,
who acknowledged
the
inspectors'omments.
-18-
7
FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
The inspectors
reviewed records,
interviewed personnel,
and inspected
plant
conditions relative to licensee
actions
in response
to previous violations:
7. 1
Closed
Violation
50-397 93-18-01
Control
Rod Drive
H draulic
Control Unit Accumulators
Re laced without a Substitution Evaluation
During
a previous inspection period, the inspector
noted that, during
replacement of the control rod drive hydraulic control unit accumulators,
the
mechanics
encountered
numerous
delays
and problems.
The inspector
then
questioned
the licensee's
planning process.
The inspector
noted that the
licensee
had treated this task
as
a one-for-one substitution rather than
a
design
change,
despite
the
new accumulators
being
made of stainless
steel
rather than the previously used
carbon steel,
having
a larger outside
diameter,
and having
a different operating pressure
and temperature.
The
inspector further noted that
a
SE was not performed per licensee
PPH 1. 17.2,
"Procurement
Engineering
Reviews."
Licensee corrective actions
included:
(1) properly performing
a substitution evaluation,
(2) reviewing
a
representative
sample of past work by the individuals involved in the
violation, (3) counseling of the individuals involved,
and
(4) performing
a
program review of the procurement
process.
The inspector
reviewed
documentation
associated
with the licensee's
corrective actions
and determined
them to be satisfactory.
7.2
C'losed
Violation
397 9318-10
As-Found Testin
not Performed for
Local
Leak Rate Testin
During a previous inspection period, the inspector
observed
portions of the
Type
C testing for the
LLRT of valves
RHR-Y-16B and
17B.
The inspector
questioned
whether as-found
LLRTs were performed prior to any adjustments
of
the valve.
The
LLRT coordinator informed the inspector that such testing
was
not required.
The licensee
determined that as-found
LLRTs were required
by
licensee
procedures.
Licensee corrective actions
included:
(1) counseling
individuals performing/planning/coordinating
LLRTs, (2) performing
as found
LLRTs for subsequent
valve repairs,
(3) and issuing directions for proper
verbal
communications.
The inspector
reviewed documentation
associated
with
the licensee's
corrective actions
and determined that the licensee's
actions
were satisfactory.
7.3
Closed
Violation
397 9318-12
Pressure
Test Performed with
Uncalibrated
Pressure
Ga
e
During a previous inspection period, the inspector
noted that the licensee
was
using
an uncalibrated
pressure
gage during performance of an air pressure test
of the
head gasket
assembly
on
a cy'linder of Diesel Generator
2.
The
licensee's
corrective actions
included revising
PPH 1.5.4,
"Control of
Heasuring
and Test Equipment
Transfer Standards,"
to more clearly delineate
the requirements
for use of calibrated
equipment.
In addition, the
maintenance craft personnel
were trained
on the
new requirements.
The
~
~
4
inspector
reviewed the licensee's
procedure revision
and training records
and
determined that the licensee's
corrective actions
were satisfactory.
7.4
Closed
Violation
397 9324-02
Uncontrolled Combustible
Li uids Left
in Vital Area
During
a previous inspection period, the inspector
noted that, following a
repair of an oil leak in the
RHR A pump, licensee
personnel left a 5-gallon
bucket of oil in the
pump room but had not obtained
a Transient Combustible
Permit
as required
by
PPM 1.3. 10, "Fire Protection
Program."
This was
a
violation of Technical Specification 6.8. l.g.
In addition, the inspector
noted that
a number of licensee
personnel
performed fire tours in this area
prior to the arrival of the inspector.
The inspector determined that fire
tours
may not have
been thorough.
Licensee corrective actions
included:
(1) counseling of the craft personnel
involved,
(2) performing training of the
appropriate craft personnel,
and (3) revising fire tour procedures
to more
clearly communicate
management's
expectations
for ensuring
proper
administrative controls for hot wor k, fire impairments,
and combustible
material.
The inspector reviewed documentation
associated
with the licensee's
corrective actions.
In addition,
the inspector
has performed frequent tours
of vital areas
over the last several
inspection periods
and
no further
violations were noted.
The inspector considered
that the licensee's
corrective actions
were satisfactory.
8
REFUELING OUTAGE 9 PLANNING AND OUTAGE PLANNING IMPLEMENTATION (62703)
The supply system
had originally scheduled
Refueling Outage
9 to begin
April 15,
1994;
however,
at the licensee's
request
the
BPA approved deferral
of the outage until April 29,
1994.
Some of the major wor k scheduled for
Refueling Outage
9 includes mechanical
stress
improvement of selected
reactor
vessel
nozzles,
the 10-year
ASME hydrostatic test of the reactor vessel,
an
integrated
leak rate test of the primary containment,
replacement
of selected
containment
supply and exhaust
purge valves,
core shroud weld inspection,
and
jet pump
beam replacement.
The inspector
assessed
the licensee's
procedures for outage planning, the
outage planning requirements
established
in these
procedures,
the outage
plan
and the licensee's
status of readiness
for Refueling Outage
9.
To assess
the
status of readiness
the inspector
reviewed selected
work packages
and the
status of work package
planning.
The inspectors
review of PPM 1. 16.8,
"Outage Management,"
which describes
the
structure
and functions of the
WNP-2 outage
management
process
used during the
annual refueling and maintenance
outage,
identified several
strengths
and
a
weakness.
The strengths
of this
PPM include effectively describing the
responsibilities of each
member of the outage organization,
establishing
criteria for the minimum numbers of operable
safety systems
for all aspects
of
planning
and scheduling
work during the outage,
and establishing
an outage
critique.
This
PPM appeared
weak because
is does not identify specific
guidelines
in which elements of outage
planning must
be completed.
The
-20-
failure to establish
these guidelines
could lead to poor outage planning
implementation.
For example,
the
PPH states
that the outage
manager will
develop
and implement
an outage
plan prior to the next major outage
and,
several
months prior to the start of the outage,
the site will be notified of
the scope freeze date.
Also, this
PPH does not establish
goals for
completing work packages
prior to the outage.
The inspector's
review of outage status
information provided by the licensee
on Harch 31,
1994,
noted the following:
approximately
415 of 3800 outage
tasks
(which did not include preventive
maintenance
tasks)
were ready to work;
the ready to work packages
appeared
adequate
in quality; approximately
725 of
the 3800 outage
tasks
were in the final stage, craft walkdown, of the planning
process;
approximately
125 of the 3800 tasks
had
been
added to the outage
scope
since January
3,
1994;
approximately
1000 of the
2000 work tasks
scheduled
to start during the first 2 weeks of the outage
were either ready to
work or in the final stage of the planning process;
and approximately
200 of
the 2000 work tasks
planned to start during the first 2 weeks of the outage
were missing
some of the repair parts.
The inspector
concluded
from the review of this information that the
licensee's
plan for the outage
had
been thoroughly developed;
however,
the
implementation of the plan warranted significant strengthening.
Less than
approximately
25 percent of the tasks for the outage
were planned
or in the
final stage of planning,
and
some parts
were not yet available
3 weeks prior
to the beginning of the outage.
The inspector considered
that
PPH 1. 16.8
omission of clearly defined implementation goals contributed to the
implementation
weaknesses.
'
ATTACHMENT 1
1
PERSONS
CONTACTED
- V. Parrish, Assistant
Managing Director for Operations
- H. Flasch,
Engineering Director
- J. Swailes,
Plant Manager
G. Smith, Operations
Division Manager
- H. Reddemann,
Technical
Services Division Manager
- H. Honopoli, Maintenance Division Manager
- J. Sampson,
Maintenance
Production
Manager
- P. Bemis, Regulatory
Programs
Manager
- H. Kook, Licensing Manager
D. Larkin, Engineering
Services
Manager
D. Whitcomb, Nuclear Engineering
Manager
J.
Benjamin,
equality Assessments
Manager
- J. McDonald, guality Support
Manager
R. Barbee,
System Engineering
Manager
- S. Washington,
Nuclear Safety Assurance
Division Manager
- C. Noyes,
Engineering
Programs
Manager
- J. Huth, Plant Assessments
Manager
- B. Hugo, Licensing Engineer
D. Williams, Bonneville
Power Administration
- H. Davidson,
Licensing Support
Counsel
The inspectors
also interviewed various control
room operators, shift
supervisors
and shift managers,
maintenance,
engineering,
quality assurance,
and management
personnel.
- Denotes attendance
at the exit meeting
on April 8,
1994.
2
EXIT MEETING
An exit meeting
was conducted
on April 8,
1994.
During this meeting,
the
inspectors
reviewed the scope
and findings of the report.
The licensee
acknowledged
the inspectors'indings.
The licensee
did not identify as
proprietary any of the information provided to, or reviewed by, the
inspectors.