ML16342D764
| ML16342D764 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 08/08/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D763 | List: |
| References | |
| 50-275-97-10, 50-323-97-10, NUDOCS 9708190259 | |
| Download: ML16342D764 (48) | |
See also: IR 05000275/1997010
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
50-275
50-323
DPR-82
50-275/97-1 0
50-323/97-10
Pacific Gas and Electric Company
Diablo Canyon Nuclear Power Plant, Units
1 and 2
7 1/2 miles NW of Avila Beach
Avila Beach, California
June 8 through July 19, 1997
M. Tschiltz, Senior Resident Inspector
D. Allen, Resident Inspector
B. OIson, Project inspector
W. Ang, Reactor Inspector
Approved By:
H. Worg, Chief, Reactor Projects Branch
E
ATTACHMENT:
Supplemental
Information
970829'025'P
970808
ADOCK 05000275
8
EXECUTIVE SUMMARy
Diablo Canyon Nuclear Power Plant, Units
1 and 2
NRC Inspection Report 50-275/97-10; 50-323/97-10
~Oerations
Control room operator's actions in response
to the condensate/feedwater
and subsequent
Unit 2 trip on July 2 were timely and appeared
to mitigate the
effect of the toss of both main feedwater pumps (MFPs) on other plant parameters.
The evaluation of the event and plant response
was thorough.
Subsequent
corrective actions taken to improve the unit's ability to w'ithstand similar transients
were based upon
a thorough investigation of the event.
The subsequent
power
ascension
was cautious and involved several verifications of condensate
and
feedwater system operation prior to returning to 'IOO percent power (Section 01.2).
I
O
A violation was identified when inspectors noted that the licensee's procedures for
alignment of a vital 480V power source to an instrument panel had not been
followed during the restoration from maintenance
that deenergized
the normal
power supply to the panel. Walkdowns of the power supply alignment verified that
normal power had been properly aligned; however,
a sealed component checklist
had not been completed for the transfer switch and the backup power supply
breaker was not positioned in accordance
with procedural requirements
(Section 01.4).
Maintenance
Postmodification testing for replacement of engineered
safety feature timers for
Containment
Fan Cooler Unit (CFCU) 2-3 was thorough and demonstrated
the
acceptable
performance of the design change.
The test participants performed the
test cautiously, with good coordination with operations
(Section M1.1).
Good test coordination occurred between reactor engineering
and operations
during
performance of Nuclear Power Range Incore/Excore Multiple-point Calibration
surveillance.
Additionally, the control operator made good use of plant process
computer to monitor plant parameters
and control core reactivity to obtain accurate
data in support of the test (Section M1.2).
A violation eras identified involving a containment isolation valve in an instrument
line that was not included in the monthly surveillance and had not been verified
closed at least once per 31 days (Section M1.3).
(
A noncited violation was identified when the licensee noted that Mode 3 had been
entered with an inoperable centrifugal charging pump (CCP)
~
CCP 1-1 was
determined to have been inoperable,
due to total pump flow in excess of that
allowed by Technical Specifications
(TSs), as a result of erosion of the miniflow
restriction orifice (Section M8.1).
-2-
Review'of the licensee's
control of RTV-732 caulking material revealed that the
licensee allowed its use in containment without administrative controls.
Tests of
the RTV-732 sealant conducted
by the licensee demonstrated
that the sealant was
not qualified for use in a harsh environment (Section M8.2).
~
Temporary modification/Jumper 97-017, which installed instrumentation
and
recorders to assist in troubleshooting
the cause of the July 2 trip, was well planned
and properly implemented.
However, the inspectors
noted several errors in the
documentation
of the jumper indicating a lack of attention to detail (Section 01.3).
~En ineerin
~
The design change for the replacement of the CFCU engineered
safety feature
timers effectively coordinated
the activities from initial design planning to final
implementation.
Cross-discipline engineering reviews, probabilistic risk analysis
assessment
and a licensing basis impact evaluation (LBIE) evaluation were
appropriately performed.
Affected procedures
and drawings were identified and
revised (Section E1.2) ~
In the control room several drawings and schematics
issued by engineering were
noted to have portions that were illegible. After identifying this situation to the
licensee,
an extensive review was performed which identified numerous drawings
and schematics that also had portions that were illegible.
Based upon the number
of discrepancies
noted, the inspectors concluded that the licensee's
program for
maintaining drawings and schematics
in the control room tailed to ensure that the
drawings were legible (Section 01.1).
Plant Su
ort
o
During the performance of the reactor coolant sample, the chemistry technician was
noted to be knowledgeable
of primary sampling procedures,
equipment use, and
radiological controls.
Primary samples were obtained satisfactorily (Section R4.1).
Re ort Details
Summar
of Plant Status
Unit
1 began this inspection period at 100 percent power.
The unit remained at
100 percent power throughout the inspection period.
Unit 2 began this inspection period at 100 percent power.
On July 2, the unit was
manually tripped by control room operators when a loss of suction pressure to the MFPs
resulted in the pumps tripping on overspeed.
The unit was returned to 100 percent power
on July 10.
Unit 2 completed the inspection period at 100 percent power.
I. 0 erations
01
Conduct of Operations
01.1
General Comments
71707
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations.
In general, the conduct of operations was professional
and safety conscious.
Review of drawings and schematics
issued by engineering
in the,control room
revealed that on some drawings there were areas which were illegible. After
inspectors
raised the concern, the licensee performed
a review of all control room
drawings and schematics.
The review identified numerous drawings and
schematics that had portions that were illegible and needed
replacem
nt. The
licensee issued
an action request
(AR) to document the problem and initiated
actions to replace drawings that were not completely legible. The inspectors found
that the actions taken by the licensee were responsive to the concerns.
Based upon the number of discrepancies
noted the inspectors concluded that the
licensee's
program for maintaining up-to-date drawings in the control room failed to
ensure that the drawings were completely legible.
01.2
Unit 2 Manual Reactor Tri
on Loss of MFPs
a.
Ins ection Sco
e 71707
On July 2, at 4:56 a.m. PDT, Unit 2 operators initiated a manual reactor trip after
the overspeed
trip of both MFPs.
The plant response
after the trip was
unccmplicated.
The inspectors reviewed the operator's
response
to the event, the
investigation of the cause,
and corrective actions prior to the return to power.
b.
Observations
and Findin
s
Unit 2 was at 100 percent power when operators observed
a decrease
in generator
output, followed by indications of loss of
uction pressure to the MFPs.
The speed
of both MFPs inc-eased
in response
to <he decreased
flow to tl e steam generators
-2-
and the MFPs tripped on overspeed.
The operators
responded
to the secondary
plant transient by decreasing
reactor power and manually tripped the reactor when
the MFPs tripped.
The unit was stabilized in Mode 3 with the reactor coolant
system
(RCS) at normal no-load temperature
and normal operating pressure.
Emergency
Diesel Generator
(EDG) 2-2 had started on the electrical power transfer
from auxiliary power to startup power (as had occurred
in past reactor trips).
Main
Regulating Valve 2-2 had shifted to manual during the transient (due to
controller setpoints for limiting plant response
to out-of-range parameters).
Soth of
these automatic actions were considered to be expected responses
to the transient.
The licensee developed
a plan to evaluate the cause of the loss of suction pressure
to the MFPs, reviewed the plant response
to the transient, evaluated the EDG and
main feedwater regulating valve response,
and implemented their 2-day outage plan.
The review of the transient identified that the interaction of several control valves in
the condensate
system, and their associated
controllers, caused the flow to the
suction of the MFPs to decrease
below that required to maintain adequate
feedwater flow to the steam generators.
A recent throttling of a manual valve in
parallel with these control valves is believed to have contributed to the plant's
inability to recover from this condensate
flow transient.
The licensee fully opened
.
the manual valve and adjusted the controllers for the control valves to slow the
valve response
to system transients.
The unit was returned to power operation,
with holdpoints at several power levels to obtain condensate,
and feedwater system
data and evaluate the plant's response to normal steady state conditions and
planned transients.
The evaluation of the trip indicated that the initiating event was a sudden
loss of
condenser
vacuum.
The licensee identified all known causes for a loss of vacuum
and by review of recorder", inspection of equipment,
and questioning of personnel
eliminated each as the initiator for this plant trip. After the initial loss of vacuum,
the response
of other plant parameters
and equipment operation appeared to have
been adequately
evaluated.
Conclusions
The operators
actions in response
to the transient and subsequent
unit trip
mitigated the effect of the loss of both MFPs on other plant parameters.
The
licensee performed an exhaustive evaluation of the trip and the plant response.
Although the initiating cause for the loss of vacuum had not been identified,
corrective actions were taken to improve the unit's ability to withstand
a similar
transient without a plant trip. The corrective actions have also been implemented
in
Unit 1 where applicable.
The subsequent
return to power was performed cautiously
with prudent testing and adjustments
made at appropriate power levels.
~
~
-3-
01.3
Review of Tem orar
Modifications Jum
er Lo
a.
Ins ection Sco
e 71707
'The inspectors reviewed the jumper log and walked down the jumpers (Unit 2
Jumper Log 97-017) associated
with monitoring the condensate
system parameters
in troubleshooting
the cause of the Unit 2 trip on July 2.
The applicable
Administrative Procedure,
CF4.ID7, "Temporary Modifications - Plant Jumpers
and
M8cTE", Revision 5, was also reviewed.
b.
Observations
and Findin
s
The jumpers did not result in inoperability of safety-related
equipment and had
appropriate
evaluations
and actions implemented.
No conflicts with TS or the
Updated Final Safety Analysis Report were identified.
The jumpers and
instrumentation
associated
with the condensate
system monitoring were installed as
described on the jumper log, with adequate
restraints to prevent becoming
a hazard
to plant equipment.
A combustible loading permit had been obtained and was
located at the job site.
Information tags were attached to the jumpers as required
by the administrative procedure.
Data f.om the instrumentation
divas being recorded
periodically and the strip charts were routinely collected and evaluated.
The jumper
Iog was reviewed and contained the necessary
information, licensing basis impact
screening,
and approvals
as required by the administrative procedure.
Several
administrative errors were noted in the jumper log including:
an error in annotating
the screening for the LBIE; inappropriate
line out of the signatures for installation
and verification of two jumpers; and an attached drawing had an incorrect markup.
These administrative discrepancies
were identified to the licensee
and were
corrected.
c.
Conclusions
The temporary modification for monitoring the condensate
system after the July 2
transient had been adequately
planned
and reviewed, and the jumpers were properly
installed as described
in the jumper Iog.
In general, the jumper logs were properly
maintained.
The errors noted in Jumper Log 97-017 indicated
a lack of attention to
detail and failed to meet management
expectations.
01.4
Walkdown of Unit
1 480V Switch ear
a ~
Ins ection Sco
e 71707
The inspector performed
a routine walkdown of the Unit
1 480 volt switchgear on
July 1, 1997, and reviewed the following procedures:
~
OP J-10:IV, Revision 19, Instrument AC System
- Transfer of Panel
Power Supply
~
Switching Order dated 5/24/97
OP 0-13, Revision 9, Transferring Equipment to/from Alternate Power
Source
~
OP1. DC20, Revision 6, Sealed Components
b.
Observations
and findin s
During a walkdown of the Unit 1 480V Bus F,switchgear, the inspector noted that
Breaker 52-1F-27 was closed, although it's normal position is open.
The breaker
supplies backup power to 120V instrument Panels PY-15, PY-16, and PY-17.
PY-
15 and PY-16 are normally powered from the vital 480V Busses
G and H,
respectively, while PY-17 is normally powered from a nonvital 480 volt bus.
Procedure
OP J-10:IV, Section 6.21, specifies the procedure for transfer of PY-16
from backup to normal power.
Procedure
OP J-10:IV, Step 6.21.4, requires that
the backup 480V supply Breaker 52-1F-27 be opened following realignment of the
normal power supply.
Additionally, Note
'l in Section 6.21 specifies that the use of
a transfer change form per OP1.DC20 is required.
Procedure
OP1.DC20,
paragraph 4.2.6 requires that removal and replacement
of seals shall be
documented
and that a transfer switch change form shall be issued and approved
prior to the component seals being broken.
Following completion of the sealed
component
change form it is required to be filed in the control room.
During
1 R8, the 480V Bus G was deenergized
to perform inspections of 4 kV
breakers.
During the time that Bus G was deenergized,
the power supplying PY-16
was realigned to its alternate power source.
Following completion of the
maintenance,
after reenergizing
Bus G, the licensee aligned the normal power supply
to PY-16.
During the restoration, breaker 52-1F-27 was left closed contrary to
procedural requirements.
Additionally, there was no record of the removal and
reinstallation of the seal installed on the power transfer switch, contrary to
procedural requirements.
A walkdown of the other power supplies was performed and revealed that all three
of the PY panels were powered from their normal power supply.
Breaker 52-1F-27
being closed and out of its normal position did not adversely impact the operability
of any components
since the normal power supplies were properly aligned;
however, the lack of documentation
and the fact that breaker 52-1F-27 was not
properly restored to the open position, indicated that applicable procedures
were not
followed when performing the restoration of normal power to the instrument panel.
The failure to follow procedures
for sealed components
and for realignment of
instrument Panel PY-16 is a violation of 10 CFR Part 50, Appendix B, Criterion V
(VIO 50-275/971 C-01).
-5-
c.
Concl'ions
Operators failed to follow procedures
for aligning 480 vital power to instrument
Panel PY-16.
08
Miscellaneous Operations Issues (92700)
08.1
Closed
Licensee Event Re ort
LER 50-275 95014 Revision 0: diesel generators
started and loaded as designed
upon failure of Auxiliary Transformer
1-1 due to
inadequate/ineffective
procedures
relating to the control of grounding devices.
e
This LER was written to document the loss of all offsite power following the failure
of Auxiliary Transformer 1-1 while the startup bus was deenergized
for
'maintenance'.
Following this event the NRC conducted
a special inspection, the
results of which are documented
in NRC Inspection Report 50-275;323/95-017.
Following review of the LER, the inspector determined that no new violations were
documented
and that the violations issued in the inspection report documented
the
pertinent issues pertaining to the event.
The associated
corrective actions for this
event are documented
in the response
to the violations and the NRC's review and
closure of the violations, therefore, no additional review is necessary to close this.
LER.
II. Maintenance
IVI1
Conduct of Maintenance
M1.1
Maintenance
Observations
ine ection Sco
e (~62707
The inspectors observed
all or portions of the following work activities:
C0152981
Remove and replace TM-3 and POT-32 components
in the
TCV-23 control circuitry
R0162375
Inspect auxiliary saltwater (ASW) Pump 1-'I vault drain line
check Valve SW-1-987
M1.2
CFCU Timer Re lacement Postmodification Testin
a.
Ins ection Sco
e 62707
'he inspectors observed
portions of postmodification Procedure PMT-23.26,
"CFCU 2-3 Time Delay Relays Replacement Test", Revision 0.
-6-
Observations
and Findings
The Design Control and Test Group performed the postrnodification test for the
replacement of the auto transfer timer and safety injection (Sl) timer for CFCU 2-3,
in accordance
with Procedure PMT-23.26.
The initial section of the procedure
tested the control circuit while electrically isolated from the motor electrical power.
This allowed a thorough checkout of the interlocks and seal-in paths without undue
cycling of the CFCU.
Later sections of the procedure
simulated autotransfer
signals
and Sl signals to the control logic and verified by actual operation of the CFCU that
the design modification had been properly designed
and implemented.
The test briefings covered the necessary
information (including test conditions,
organizational interfaces, test requisites, expected
alarms, expected component
changes
of state, ar.d test connections)
and the operators
and other test
participants clearly understood
their tasks and responsibilities.
The instrumentation
was within calibration and appropriate for the test.
Electrical safety precautions
were used when connecting
and disconnecting
from energized equipment.
Three-way communications
were used by the operators and test personnel.
Electrical schematic and connection drawings were available in the field and used to
ensure the actions in the procedure
and the plant response
were understood
before
proceeding.
The personnel performing the test were knowledgeable
of the equipment operation
and the intent of the design change.
The test procedure was performed and signed
as written, with-several minor on-the-spot-changes
(OTSC).
One OTSC was due to
the procedure
specifying incorrect fuse ratings.
Another was due to a procedure
error that verified a rel.y deenergized
when in fact it did not change state.
Both of
these errors should have been noted and corrected prior to starting the test by a
review of the tests performed on the Unit 1 CFCUs.
During the autotransfer part of the test, CFCU 2-5 was expected to stop and restart
in slow speed; however, it initially remained running in fast speed
and then shifted
to slow speed.
The test personnel
and operators worked well together to stop the
test and return plant equipment
and test jumpers to a normal and safe configuration.
The response
of the CFCU was documented
in an AR and evaluated before
proceeding with the remainder of the test.
The evaluation concluded
CFCU 2-5 has
performed as designed.
Conclusions
The personnel were well prepared
and knowledgeable
about the test.
The test
demonstrated
the design modification had been implemented properly and satisfied
the intent of .he design change.
!n general, the procedure was thorough and
properly used.
Procedural deficiencies that required an OTSC should have been
identified prior to the start of the test from lesson learned from the Unit
1
-7-
performance of the equivalent tests.
Involved personnel
responded
cautiously and
appropriately to the unexpected
performance of CFCU 2-5.
M1.2
Surveillance Observations
Ins ection Sco
e 61726
Selected surveillance tests required to be performed by TS were reviewed on a
sampling basis to verify that:
(1) the surveillance tests were correctly included on
the facility schedule;
(2) a technically adequate
procedure
existed for the
performance of,the surveillance tests; (3) the surveillance tests had been performed
at a frequency specified in the TS; and (4) test results satisfied acceptance
criteria
or were properly dispositioned.
The inspectors observed
all or portions of the following surveillances:
STP R-13
Nuclear Power Range Incore/Excore Multiple-Point Calibration,
Revision 98
STP R-41
STP M-9A
RCS Temperature
Instrumentation
Data, Revision 6
Diesel Engine Generator Routine Surveillance Test,
Revision 43A
b.
Observations
and Findin s
During the performance of STP R-13, the shift foreman, shift technical advisor and
reactor engineering
provided good support for the evolution.
The reactor engineers
clearly communicated the necessary
plant conditions for data collection and the
control operator made good use of the plant process computer and its displays to
monitor and control plant parameters
critical to obtaining high quality data for the
test.
c.
Conclusions
The inspectors found that the surveillances
observed were being scheduled
and
performed at the required frequency.
The procedures
governing the surveillance
tests were technically adequate
and personnel performing the surveillance
demonstrated
an adequate
level of knowledge.
The inspectors noted that test
results appeared
to have been appropriately dispositioned.
-8-
M1.3
Surveillance
Re uirements for Containment
Isolation Valve SI-1-8964
lns ection Sco
e 61726
The inspectors reviewed STP I-1D, "Routine Monthly Checks Required By Licenses",
Revision 48, for compliance with TS 4.6.1.1.a, whicl; requires containment isolation
valves to be verified closed every 31 days.
b.
Observations
and Findings
The operating valve identification diagram for the Sl system shows containment
518 with a line used to test check valve leakage and to fillthe Sl
A branch of this line, outside containment,
has
a pressure
Indicator,
1-PI-942, with a normally closed manual isolation Valve, Sl-1-8964.
Valve Sl-1-
8964 is therefore part of the containment isolation barrier for a penetration that is
required to be closed during accident conditions and should be verified to be in its
closed position at least once per 31 days as required by containment integrity TS
Surveillance Requirement 4.6.1.1.a.
This valve was not verified as part of STP I-1D
and was not verified closed every 31 days.
The licensee was informed and the
operating crew verified the valves on both units to be closed.
The licensee's
position was that this valve is not a containment isolation valve and
was not within the scope of Surveillance Requirement (SR) 4.6.1,1.a.
Containment
isolation valves operability is covered by TS 3/4.6.3 which clearly applies to active
valves.
The action statement for an inoperable isolation valve includes isolating the
affected penetration
by use of a deactivated
automatic valve secured
in the isolation
position, or isolation by use of a closed manual valve or blind flange.
The
surveillance requirement for containment integrity, SR 4.6.1.1.a, addresses
not capable of being closed by an operable containment automatic
isolation valve, and verifying closed valves, blind flanges, or deactivated automatic
valves secured
in their positions, except for valves that are open under
administrative controls as permitted by TS 3.6.3.
The licensee believed that these
requirements
applied to main process valves only, and not to test vents and drains,
or to instrumentation valves that might form part of the containment penetration
boundary.
The local leak rate test valves were included in Procedure
STP I-1D
because
Standard
Review Plan, Section 6.2.6, requires test, vent, and drain
connections that are used to facilitate local leak rate testing or the performance of
the containment integrated leak rate test should be administratively controlled and
should be subject to periodic surveillance.
The NRC's TS Branch interpretation
is that any valve associated
with a coritainment
no matter how small, is a containment isolation valve and the
requirements
of TS 3.6.1.1 apply.
-9-
Licensee's
Corrective Actions
'
Following discussions
with the NRC inspectors
and TSB, the licensee began
a
thorough review of the containment penetrations
to.identify any additional valves
that had not been included in Procedure
STP I-1D. The penetrations
to be reviewed
were prioritized, with those penetrations
most likely to have valves that were
excluded reviewed. first. Penetrations
which receive local leak rate testing were
reviewed last, since the valves associated
with them were already included in
Procedure
STP I-1D. The review also included valves inside containment, which are
excepted for the 31-day requirement of SR 4.6.1.1. if they are locked, sealed,
or
otherwise secured
in the closed position.
These valves inside containment
are
required to be verified closed during each cold shutdown except such verification
need not be performed more often than once per 92 days.
Those valves outside
containment
and accessible
valves inside containment that had not been verified
closed are being checked by operations
and verified closed, and where applicable,
downstream
pipe caps were verified to be in place.
Related Industr
Problems
In December 1992, Florida Power and Light Company was issued
a violation for
failure to maintain containment integrity by opening
a drain valve in the containment
spray system which was also a containment penetration boundary valve
(documented
in NRC Inspection Report 50-335;389/92-21).
The licensee stated
that they were not in TS 3.6.1.1 Action Statement
because
only valves identified
by number in the TS or the Updated Final Safety Analysis Report were containment
isolation valves.
The licensee specifically stated that vents, drain and test valves
were not within the scope of the TS 3.6.1.1.
The NRC Staff review concluded any
valve which isolates
a containment penetration,
no matter how small, is a
containment isolation valve and is required to be within the scope of TS 3.6.1.1.
In September
1996, NRC Reaion
II requested
NRR to evaluate
a Catawba site
document entitled "Catawba Nuclear Station Containment Integrity Review" for
consistence
with various regulations and cod'es.
The licensee's
document
contended
that ANSI N271-1976 clearly differentiated between test connection
vents and drains and containment isolation valves.
It further contended that the
Standard
Review Plan Sections 6.2.4 and 6.2.6 also distinguish between
containment isolation valves and test connections
vents and drains,
and, therefore,
do not consider test vent and drain connections to be containment isolation valves.
The staff's response
was that test vents and drains (TVDs) are containment
isolation valves (CIVs}. The fact that ANSI N271-1976 has
a definition for TVDs
does not mean the TVDs cannot also be CIVs. The staff's position was that the
TVDs should meet the 31-day SR 4.6.1.1.a for CIVs.
ln November 1996, the resident inspector for Braidwood Station requested
NRR's
assistance
in interpreting TS 3/4.6, "P:imary Containment"
SR 4.6.1.1.a on a vent
and drain valve on a SI test line local pressure
indicator.
The licensee believed that
-10-
SR 4.6.1."..a, which requires the licensee to verify that all penetrations
are secured
every 31 days, applies orMy to penetrations
that are not capable of being
automatically isolated.
They stated that because
the penetration attached to these
valves is capable of being closed by an operable containment automatic isolation
valve, SR 4.6.1.1.a does not apply to these drain and vent valves.
NRR's TS
Branch reviewed the request
and concluded that these drain and vent valves should
be included in the SR testing.
The staff considers
any valve associated
with a
containment penetration
no matter how small to be a CIV and therefore the
requirements of TS 3.6.1.1 apply to them.
Part of the basis for the applicable
general design criteria is that a single failure will not prevent or degrade containment
integrity.
C.
Conclusions
l
The licensee's implementation of TS SR 4.6.1.1.a was inadequate
in that it failed to
verify that Valve Sl-1(2)-8964 was closed at least once per 31 days.
This is a
violation of TSs (VIO 50-275;323/9710-02).
M8
IVliscellaneous Nlaintenance Issues (92700)
M8.1
Closed
LER 50-275 94-023-00:
TS 3.0.4 was not met when Unit 1 entered
Mode 3 on May 4, 1994 with CCP 1-1 inoperable.
CCP 1-1 was inoperable
because
the total pump flow was greater than the TS 4.5.2h.1(d) limit.
The excessive
CCP 1-1 flow was caused
by erosion of the CCP miniflow restricting
orifices and leakage through flow control bypass Valves 83878 and C. The
excessive
erosion of the restricting orifices is believed to have been caused
by
extended
use of the CCPs for normal charging.
The licensee's corrective actions
included verifying the current flow balance satisfies the TS requirements,
replacement of the restricting orifices and adding flow measurement
equipment
in
the mini-flow path, and the use of the positive displacement
pump as the normal
supply for charging flow. The equipment modifications were completed
in Unit 1
during the 1R8 outage, and are scheduled
to he implemented
in Unit 2 during the
2R8 outage.
The review of the LER by the inspector revealed
no new information.
This licensee-identified
and corrected violation is being treated as a noncited
violation, consistent with Section VII.B.1 of the NRC Enforcement
Policy (50-275/97010-03).
M8.2
Use of Dow Cornin
RTV-732 in Containment
a.
Ins ection Sco
e 92902
As documented
in NRC Inspection Report 50-275;323/97-06
the appropriateness
of
the use of RTV-732 sealant to fillin gaps between the base of the reactor coolant
pumps and the lubricating oil collection pans was questioned
by the inspectors.
The inspectors performed additional reviews of the actions taken by the licensee
following identification of this issue.
I
Observations
and Findin s
Following the initial identification of the concern, the licensee determined that
RTV-732 sealant had not been qualified for use in containment
and would be
replaced with a qualified caulking material.
Testing performed by the licensee
determined
under harsh environmental conditions, that could be encounter
d in
cer.ain areas of containment during accident conditions, that the RTV-732
ealant
material may not adhere to the surface that it had been applied.
A.search was
performed to'determine the work orders which specified the use,of the RTV-732
sealant stock code for work performed in containmerit.
This search identified that
the use of the RTV-732 sealant had been specified on the CFCU 2-2 fan housing.
The licensee subsequently
reviewed the calculation for debris clogging the
containment sump and determined that the additional caulking material, if
transported to the containment sump during an accident, would not significantly
reduce the margin to safety in the calculation for adequate
emergency core cooling
system suction from the sump.
8ased upon the remaining margin in the calculation
this conclusion appeared
reasonable.
A prompt operability assessment
was written
based upon this information.
The licensee's
assessment
was questioned
by the inspector, since the work order
search did not identify ail of the reactor coolant pump oil collection trays as having
had RTV-732 applied.
Further review by the licensee revealed that RTV-732 had
been available for use in the tool crib in containment during outages.
Specifically,
during 1RS, six tubes of RTV-732 sealant had been used in containment based upon
tool crib inventory records.
The licensee was unable to identify where the RTV-732
sealant had been used.
8ased upon the previous analysis, the inspector agreed
with the licensee's conclusion that this did not change the validity of the licensee's
initial conclusion regarding the potential for clogging the containment sump.
However, the use of unauthorized
material in containment
is being considered
as an
inspection folfowup item pending the licensee'eview
of the impact of RTV use
during the outage to assure environmental qualification requirements continue to be
met {IFI 50-275;323/9710-04).
Conclusions
The licensee's
initial assessment
of the effect of the use of RTV-732 sealant in
containment was incomplete in that it failed to identify the total quantity of the
sealant used and the locations where it had been applied.
-1 2-
III. En ineerin
El
Conduct of Engineering
E1.1
Calculation in Su
ort of Com onent Coolin
Water
CCW Flow Balance
37551)
The licensee identified an error in a calculation for the CCW system.
Calculation M-916 specified instructions to be incorporated into test
Procedure
STP V-13A, "CCW Flow Balancing", to establish the CFCU outlet valve
positions to maintain CCW system hydraulic flow balance.
The instructions
included a correction for a difference in elevation of pressure
indicators.
This
correction was subtracted
from the measured
values; however, the correction
should have been added.
The licensee performed
a prompt operability assessment
and concluded that the CCW and CFCU systems remained operable.
The licensee
indicated that both the calculation and the surveillance procedures
were being
revised to correct this error.
The surveillance procedure was reviewed by the inspector and an additional error in
correcting for elevation of the test pressure
indicators was identified.
The elevation
of each indicator was determined
in reference to the floor elevations which were
incorrectly specified in the procedure.
This was identified to the licensee for
incorpo.ation into the procedure
revision.
and corrective
actions adequately
addressed
these errors.
E1.2
CFCU Auto Bus Transfer and Sl Timer Re lacement Desi
n Chan
e
a.
lns ection Sco
e 37551
rhe inspector reviewed the Design Change
Package
E-049344, Revision 1, and
Design Change Notice 1-EE-049355, Revision 1, to a sess the design control and
installation ot plant modification processes.
b.
Observations
and Findin s
Design Change
Package E-049344 replaces
all Unit 1 existing 10 CFCU timers
(5 Sl and 5 auto bus transfer timers) with more accurate digital Agastat DSC timers.
The wiring changes
use existing 42X relays as auxiliary relays to meet seismic
requirements
and facilitate installation, as well as change the CFCU start logic such
that an autotransfer signal will start the CFCU in slow speed regardless of the
High/Low speed switch position.
The design change was the result of Quality
Evaluation Q0010264, which identified the existing Agastat 7000 series auto bus
tiansfer timers drift outside the range allowed by TS.
The effect on plant operation was addressed
by the design change package,
including changes
to operating, surveillance and administrative procedures.
The
engineering
evaluations
included seismic and environmental considerations
as well
-1 3-
as electrical calculations for loading of the EDGs and dropout voltages of the timers.
The probabilistic risk assessment
concluded that the change would be beneficial
since it does not introduce any new failure modes and the new timers are more
reliable.
The design change package specified the functional tests to be performed and the
acceptance
crite'ria to be satisfied to demonstrate
the modification functions as
intended.
The design was reviewed by appropriate interface organizations,
including operations,
maintenance
and other engineering
disciplines.
An LBIE screen
was performed and determined the need for a LBiE. The LBIE was performed, but
was not properly annotated
as to whether an unreviewed safety question was
involved or whether a TS change was required.
It appeared
from the LBIE that
neither was involved.
The discrepancy was pointed out to the licensee and
corrected.
A Final Safety Analysis Report (FSAR) 'change was identified and the
FSAR Update change request was submitted.
Revisions to Design Criteria
Memorandum S-23, heating, ventilation and air condition, and S-63, 4KV Systems,
have been submitted but not yet incorporated.
Design Change Notice 1-EE-049355, Revision 'I, contained the installation
requirements to implement the above plant modification.
It specified the necessary
sequence
of installation and the system lineup, and identified the TS requirements
applicable during installation.
The postmodification/functional tests and applicable
acceptance
criteria were specified.
The associated
field change forms, were
reviewed and found to correct a "neak circuit, clarify instructions, allow use of new
wire or existing spare wire and to correct minor errors.
The identified procedure changes
were reviewed and found to have been
implemented.
Control room dra;vings were reviewed and contained thri applicable
cnarkups.
c ~
Conclusions
The desigr control process effectively coordirated the necessary
activities from the
initial design planning to final implementation.
Interfaces between various
organizations
were controlled to ensure supporting activities were completed to ful/y
implement the plant modification.
The number of field changes
was not excessive,
but does indicate improvement could be made in the planning of the installation.
The design change appeared
to accomplish its intended function.
E8
Miscellaneous Engineering Issues (92903)
ES."
Closed
IFI 50-275/96006-04:
licensee long-term corrective actions to improve
source range instrument reliability. The control console startup rate meter for
source range Inst-ument Nl-32 stuck on its bottom peg on several occasior.s.
The
licensee had previously identified that the source and intermediate rar.ge startup
rate meters were the wrong current range (-0.1 to 0.9 made verses the correct
-1 4-
range of -0.1 to 1.0 made) and were procuring replacements.
The wrong range
meters were calibrated and oerformed the required function, and therefore were
acceptable
until the new meters could be installed.
During 1R8 outage,
the startup
rate meters for source and intermediate instruments were replaced with new
meters.
The applicable calibration Procedure,
STP I-37-N46 NIS Comparator and
Rate N46/N37 Calibration, was performed and the meters were observed
prior to
startup to operate properly without sticking.
The Unit 2 meters are scheduled for
replacement
during the next refueling outaoe.
Closed
URI 50-275 323 96021-06:
ASW TS interpretation more restrictive than
TS.
The inspector reviewed the unresolved
item (JRI) that was written after noting that
the TS 3.7.4.1 ACTION statement,
as written, no longer specified the lowest
functional capability or performance
levels for the ASW system.
Current TS 3.7.4.1
Re uirements
The TS limiting condition for operation, requires two operable ASW trains, with an
ACTION statement that with only one ASW train operable the second train must be
restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in HOT STANDBY within the
following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
Licensee TS 3.7.4.1 Inter retation
The TS interpretation 95-08, implemented by the licensee, imposed more restrictive
requirements for ASW pumps and CCW heat exchangers
in order to ensure that
adequate
equipment was available to prevent overheating the CCAV system.
Although this was different than originally stated in the FSAR, the licensee had
performed
a 10 CFR 50.59 evaluation and revised the FSAR to reflect the system
configuration requirements.
Issues identified durin
revious NRC ins ections
During the review of this issue, the inspector determined that the NRC had
reviewed related issues in a safety system fur ctional inspection
in Sanuary 1989
(see NRC Inspection Rreport 50-275/89-01) and later during the review of the LER
submitted by the licensee following the inspection
(LER 50-275/84-40, see NRC
Inspection Report 50-275;323/89-013).
Following these inspections,
the NRC
determined that the licensee had not adequately translated
plant system
configuration design assumptions
into procedures.
Consequently,
operating
procedures
or instructions did not provide adequate
guidance for system operation
under certain design basis conditions.
A recent review of the associated
procedures
determined that the licensee had completed revisions to the procedures
which
appeared
to provide adequate
guidance.
-1 5-
CCW S stem Desi
n Chan
e Raised Maximum Allowed Tem erature
The licensee recently issued
a design change which raised the design temperature
of the CCW system to allow a temperature
transient in the system to 140'F for a
period not to exceed
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Based upon the increase
in the maximum allowable
system temperature,
the additional restrictions implemented by the TS interpretation
are no longer required; however, in order to ensure maximum heat removal
capability during emergencies
operators
are instructed to place a second CCW heat
exchanger
in service early in the emergency operating procedures.
Additionally, the
licensee has submitted
a license amendment,
based upon the new analysis, which
require"., only one ASW pump and one CCW heat exchanger,
as assumed
in the
safety analysis, in order to provide sufficient heat removal to mitigate a design basis
accident.
Based upon the analyses, this unresolved
item is closed.
E8.3
(Closed
Violation 50-323/96023-05:
failure to initiate an AR to address
loose
fasteners.
On November 19, 1996, during a routine tour of the Unit 2 480V vital
switchgear rooms, the resident inspectors identified a number of loose fasteners
associated
with the breaker front panels.
These findings were discussed with the
system engineer and the onsite mechanical engineer responsible for seismic
qualification and evaluation of plant equipment.
On Noverr,ber 22, 1996, the
system engineer provided the resident inspectors
a technical evaluation regarding
the seismic qualifications of the affected breaker panels with the observed
loose
fasteners
and resolved the resident inspectors'oncerns
regarding the impact of the
observed
loose fasteners.
However, the resident inspectors determined
that as of
December 2, 1996, an AR had not been initiated to address
and document the
quality problem associated
with the loose fasteners contrary to Procedure AD4.ID8,
Revision 1, "Identification and Resolution of Loose, Missing or Damaged Fasteners."
On February
14, 1997, the licensee responded'to
the Notice of Violation by means
gf PGSE letter DCL-97-024 and agreed with the violation.
The licensee stated that
the following corrective actions had been taken:
~
An AR was written to document the observed fastener deficiencies and the
corrective actions that were taken.
The system engineer was trained regarding the need to document quality
problems as required by Procedure AD4.1D8.
A case study was written and distributed to plant personnel to provide
lessons
learned regarding the event.
Electrical and instrumentation
and controls system engineers
were given
specific training regarding the requirements
of Procedure AD4.1D8.
During the current inspection period, the inspectors reviewed the licensee corrective
actions for the violation as stated in the licensee response.
The inspectors
determined the following:
-1 6-
The licensee issued AR AO418696 on December 3, 1996, to document the
observed
loose fast. ners and the. corrective actions for'the fasteners.
The
'R
also addressed
the procedure violation regarding the failure to write the
AR.
AR AO4'l8696 also documented
the preparation
and issuance of a case
study regarding the violation on February 28, 1997.
The inspectors
reviewed case study 63 dated February 27, 1997, regarding the violation.
The inspectors noted that the case study provided a good description of,:he
problems identified and lesson learned.
The case study appropriately
discussed
the need to comply with procedural requirements
and the need to
document identified fastener problems.
AR AO418696 also documented
the completion of training of all electrical
and instrumentation
and controls system engineers
on March 21, 1997.
The
inspectors discussed
the training with the original system engineer involved
with the problem.
The inspectors noted that the system engineer was also
the individual who prepared the case study and was now fully aware of the
procedural requirement associated
with documenting fastener problems.
The inspectors concluded that the licensee had performed reasonable
corrective
actions for the identified violation. Additional problems noted with the control of
4 kV breakers werc documented
in a violation (VIO 50-275;323/97-06-02).
Corrective actions for those specific instances will be evaluated
during the review of
the licensee's
response
to the violation and willconsider the adequacy of the
ccrrective actions for previous similar violations.
Based on the above,
Violation 50-323/96023-05
was closed.
IV. Plant Su
ort
R4
Staff Knowledge and Performance
in Radiological Protection and'Chemistry Controls
R4.1
Primar
Coolant Sam
le Procedure
a.
Ins ection Sco
e l71750
On June 12, the inspector observed the drawing of RCS daily samples at Units
1
and 2 primary sample sinks.
Procedure
CAP E-', Revision 17A, "Sampling cf
Primary Systems," was also reviewed.
b.
Observations
and Findin s
The chemistry technician was knowledgeable
of the sampling procedure
and the
configuration and operation of valves at the primary sample sinks.
The chemistry
technician was sensitive to potent)ally contaminated
areas
and demonstrated
proper
f
-1 7-
radiological controls while working in the sample sink. A sufficient volume of
coolant was purged through the sample lines to ensure that representative
samples
were drawn.
The inspector verified that the" issued-for-use"
copy of Procedure
CAP E-1 located
in the primary sample room for each unit was the latest revision.
After the samples
were drawn, the inspector observed
portions of the sample analysis.
The inspector
observed that the chemistry technician was knowledgeable
of the required analysis
and use of the analytical equipment.
C.
Conclusions
The primary samples were obtained satisfactorily.
The chemistry technician was
knowledgeable
of the sampling procedure,
equipm'ent use, and radiological controls.
P1
Conduct of Emergency Preparedness
Activities
P1.1
Licensee
Pre
a'redness
for Criticalit Accidents
a.
lns ection Sco
e 71750
The inspectors
examined the implementation of 10 CFR 70.24, "Criticality Accident
Requirements."
b.
Observations
and Findin s
The licensee did not have an exemption from the requirements
of 10 CFR 70.24 in
the operating license.
However, on April 3, 1997, the licensee submitted a request
fear exemption from the requirements
of 10 CFR 70.24.
Currently, the licensee has
procedures
and equipment in place that appear to meet the requirements
of
The inspectors verified that Diablo Canyon has two area radiation monitors
positioned near the fuel storage
and handling areas which are intended for the
monitoring of potential criticality events.
Area Radiation Monitor (RM)-59 was
positioned near the new fuel storage vault and area RM-58 was positioned near the
'pent fuel pool.
ln addition, licensee procedures
specified the placement of portable
criticality monitors near the new fuel storage vault and cask washdown areas,
as
applicable, during fuel handling activities.
Licensee personnel indicated that the
radiation monitors were capable of meeting the requirements
The monitors energized
local audible alarm signals if setpoints
are reached,
and
RM-58 and RM-59 energize control room annunciators
upon alarm.
The alarm response
procedures
for the remote alarm feature in the control room
have instructions that speci-y the actions to be taken and the requirements
for
initiating the emergency response
plan.
The actions include the evacuation
of
A
-18-
personnel from the fuel handling areas.
Procedure
OP B-SH, "Nonrefueling Fuel
Handling Instructions," also specifies the actions to be taken if any of the criticality
monitors alarm.
Licensee procedures
specify the performance of an on-station evacuation drill prior
to receiving fuel for each operating cycle.
Licensee procedures
also specify preshift
briefings of actions to be taken in the event of a radiation alarm or portable
criticality monitor alarm.
Conclusions
The licensee currently meets the requirements
of 10 CFR 70.24 for criticality
accidents.
PS
Miscellaneous Security and Safeguards
Issues (92904)
P8.1
Closed
Violation 50-275 9103-04:
inattentiveness
to duties.
This violation was issued after a security officer, assigned
as a compensatory
measure watch, was observed to be inattentive.
The licensee acknowledged
the
violation and described corrective actions in a letter to the NRC dated May 3, 1991.
Due to an oversight, this item remained open in NRC records.
However, the
inspector was onsite at the time of the violation, recalls the licensee's immediate
corrective actions and actions to prevent recurrence,
and recalls that those actions
were appropriate
and effective.
The inspector confirmed that the licensee's
actions
were as described
in their May 3, 1991, letter, and concludes that no additional
action is warranted for this matter.
V. Mana ement Meetin
s
X1
Exit Meeting Summary
The inspectors presented
the inspection results to members of licensee management
at the
conclusion of the inspection on July 25, 1997.
In the meeting the licensee acknowledged
the findings presented.
The inspectors
asked the licensee whether any materials examined during the inspection
should be considered
proprietary.
No proprietary information was identified.
I
ATTACHMENT
PARTIAL LIST OF PERSONS CONTACTED
Licensee
W. E. Coley, Engineer,
Regulatory Services
W. G. Crockett, Manager, Nuclear Quality Services
T. F. Fetterman,
Director, Instrumentation
and Control Engineering
T. L. Grebel, Director, Regulatory Services
J. A. Gregerson,
Engineer, Engineer, Engineering Services
D. J. Hampshire, Senior Engineer,
Balance of Plant Engineering
M. J. Jacobson,
Manager, Nuclear Quality Services
S. C. Ketelsen, Senior Engineer, Regulatory Services
S. D. LaForce, Engineer Regulatory Services
J. E. Molden, Manager, Operations Services
M. G. Mosher,'Acting Director OSSP, Nuclear Quality Services
D. H. Oatley, Manager, Maintenance
Services
H, J. Phillips, Director, Engineering Services
R. P. Powers, Manager, Vice President
DCPP and Plant Manager
J. A. Shoulders,
Director, Support Engineering
R. L. Thierry, Engineer, Nuclear Technical Services
D. A. Vosburg, Director, NSSS Engineering Services
R. A. Waltos, Director, Engineering Services
R. C. Whitsell, Director, Nuclear Quality Services
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62707: Maintenance
Observations
IP 71707: Plant Operations
IP 71750: Plant Support
IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IP 92904: Followup - Plant Support
t
i
-2-
ITEMS OPENED, CLOSED, AND DISCUSSED
~Oened
50-275/97010-01
Failure to follow procedures
for alignment of 480V
power supply to instrument pan
I PY-16
50-275;323/97010-02
Failure to verify CIV SI-1(2}-8964 closed at least once
per 31 days
50-275/9701 0-03
Mode 3 entry with CCP inoperable due to total pump
flow exceeding
TS limit
50-275;323/9710-04
IFI
Unco trolled use of Dow Corning RTV-732 sealant in
containment
Closed
50-275/94023-00
LER
CCP flow greater than TS due to erosion of mini-flow
restricting orifice
50-275;323/9701 0-03
Mode 3 entry with CCP inoperable due to total pump
flow exceeding
TS limit
50-275/9506-02
IFI
'ASW vault drain calculation for medium energy line
break did not address
the limited capacity of the intake
structure sump pumps
50-275/96006-04
IFI
Licensee long-term corrective actions to improve source
range instrument reliability
50-275/9501 4-00
LER
Diesel Generators
started and loaded as designed
upon
failure of auxiliary transformer
1-1 due to
inadequate/Ineffective
procedures
relating to the control
of grounding devices
50-275;323/96021-06
ASW TS interpretation more restrictive than TS
50-323/96023-05
50-275/9 'I 03-04
Failure to initiate an AR to address
loose fasteners
Inattentiveness
to Duties
Discussed
50-275;323/97-06-02
loose fasteners
on 4kV breaker cubicle
t
t
C
-3-
LIST OF ACRONYIVIS USED
ASW
CFCU
IFI
LBIE
LER
OP
OTSC
SR
TS
TVD
1R8
action request
auxiliary saltwater
centrifugal charging pump
component cooling water
containment fan cooler unit
containment isolation valve
Diablo Canyon Power Plant
final safety analysis report
inspection followup item
licensing basis impact evaluation
Licensee Event Report
main feedwater pumps
noncited violation
Office of Nuclear Reactor Regulation
Operations Procedure
on-the-spot-change
Public Document Room
safety injection
surveillance requirement
Technical Specification
test, vents, and drains
unresolved
item
Unit 1 eighth refueling
I
0-