ML16342D729
| ML16342D729 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 07/09/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D728 | List: |
| References | |
| 50-275-97-06, 50-275-97-6, 50-323-97-06, 50-323-97-6, NUDOCS 9707110200 | |
| Download: ML16342D729 (74) | |
See also: IR 05000275/1997006
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
50-275/97006
50-323/97006
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
April 27 through June 7, 1997
M. Tschiltz, Senior Resident Inspector
D. Allen, Resident Inspector
R. Huey, Technical Assistant, Walnut Creek Field Office
J. Kramer, Resident Inspector, San Onofre
S. Boynton, Resident Inspector
Approved By:
H. Wong, Chief, Reactor Projects Branch
E
ATTACHMENT:
Supplemental
Information
9707ii0200 970709
ADQCK 05000275
6
EXECUTIVE SUMMARY
Diablo Canyon Nuclear Power Plant, Units
1 and 2
NRC Inspection Report 50-275/97-06; 50-323/97-06
~Oerations
Operators were not observant to tagging discrepancies
identified by the inspectors
and when brought to the licensee's
attention personnel failed to initiate trending
records.
This was not in keeping with operations management
expectations
(Section 01.1).
A violation was identified when, for a brief time (3 minutes) in Unit 2, a licensed
reactor operator was not present
in the operator-at-the-controls
area.
Informal
communications
resulted in the relief operator not assuming the at-the-controls
duties for the Unit 2 control operator (Section 01.2).
Operators responding to a Steam Generator
(SG) 1-3 nozzle dam alarm took
approximately 30 minutes to enter containment to investigate and correct the cause
of the alarm.
This response
was considered
untimely and was determined not to be
in accordance
with management
expectations
(Section 01.3).
Preparations
for reducing the reactor coolant system inventory to mid-loop to
facilitate removal of SG nozzle dams were thorough.
Operators were provided with
time to review and discuss the applicable procedures
prior to performance.
Control
room activities were reduced to limit the potential for distraction and appropriate
attention was given to the evolution by Operations management
(Section 01.4).
The inspectors identified a violation when three of the four seismic restraining bolts
on the breaker cubicle for Safety Injection (Sl) Pump 2-2 were found not to be
properly installed as specified in procedures.
This condition was different than the
seismic analysis for breaker qualification.
Inadequately tightened bolts had been
a
problem found by inspectors
in the past.
Subsequent
analysis showed that the
breaker remained operable with the loose fasteners
(Section 01.5).
~
The Operations shift supervisor and shift foreman demonstrated
good command and
control during preparations for return-to-power operation at the end of Refueling
Outage 1R8.
Operator peer checking was consistently implemented
and was
effective in identifying and correcting minor problems before they occurred
(Section 01.8).
~
Operator training on major changes to the equipment clearance
process prior to
Refueling Outage
1R8 did not appear to have fully covered all appropriate aspects of
new responsibilities for each individual involved in the new process.
Also,
additional training on the bases for significant clearance
process changes
appeared
warranted (Section 01.8).
-2-
Maintenance
~
Outage scheduling
and planning were accomplished with a specific emphasis
on
safety and maintaining equipment operable
or available as required by the outage
safety plan.
Communications
between organizations
regarding changes
in the
schedule
appropriately addressed
changes
in the outage safety plan. The outage
safety plan and schedule were clearly communicated to the organization in meetings
and daily status reports that were published and distributed to workers
(Section M6.1).
For the maintenance. activities observed,
both technical maintenance
and
mechanical maintenance
personnel
were knowledgeable
of the assigned
tasks.
Appropriate authorization had been obtained for the work and the work package
instructions were closely followed (Section M1.1).
A non-cited violation was identified when the licensee noted that residual heat
removal (RHR) and excess letdown heat exchanger
seismic supports surveillances
were not performed as required by Technical Specification (TS) 4.05 and Section XI
of the ASME code (Section M8.1).
A non-cited violation was identified when the licensee found that procedures
failed
to provide adequate
instructions for installation of the power supply to the
containment source range audio count rate/scalcr timer. As a result, after
unintentionally de-energizing the power source to the sealer timer, the TS required
continuous audible count indication was not available in containment for
approximately
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> during core alterations (Section 08.1).
Nuclear Quality Services (NQS) assessments
of performance
during Refueling
Outage
1R8 were effective in identifying performance
problems to plant
management.
Assessments
were issued in a timely manner and provided
management
with the information needed to focus attention on problem areas
(Section M7.1).
Encnineering
A violation was identified involving the spray shields for the reactor coolant
pump (RCP) oil collection system,
Although the licensee determined that
inspections
should be performed in response
to Information Notice (IN) 94-58, no
inspections of the Unit 1 RCP oil collection system had been performed.
There had
been several opportunities to do so and, in addition, an assessment
of Unit 2 did
not identify the spray shield discrepancy
(Section E1.1).
A non-cited violation was identified when a Quality Assurance
engineer alerted
cognizant system engineers that an action request
(AR) that identified the need to
test main feed pump (MFP) turbine stop valves had incorrectly been closed without
initiating actions to accomplish the testing.
This demonstrated
competerice
in the
-3-
NQS organization, but was also indicative of a lack of appropriate follow through
and review of corrective actions within the Engineering organization (Section E8.1).
~
During reviews of the licensee's
disposition of Updated Final Safety Analysis
Report (UFSAR) discrepancies,
the inspector determined that changes to the Final
Safety Analysis Report (FSAR) had been included in Revision 11 without the
required safety evaluations
(Section E8.2).
Plant Su
ort
~
Operations personnel failed to establish adequate
controls to ensure Valve SFS-50
remained closed during hydrolasing of the lower reactor cavity. As a result, due to
the combination of an incorrect status board and inadequate
verification of
Valve SFS-50 valve position, hydrolasing was conducted with the valve open,
which resulted in the spread of contamination into the fuel handling building (FHB)
(Section
R1
~ 1).
Re ort Details
Summar
of Plant Status
Unit
1 began this inspection period in Mode 6 (performing fuel offload) for the unit's eighth
refueling outage
(1RS).
The unit entered Mode
1 on June
1, 1997,
and returned to
100 percent power on June 7.
Unit 2 began this inspection period at 100 percent power.
On June
1, power was reduced
to 75 percent to perform turbine stop valve testing and maintenance
on the MFP 2-1 speed
control system.
Subsequently,
the unit power was reduced to 50 percent to perform
additional MFP stop valve testing.
Unit 2 returned to 100 percent power on June
1 and
operated
at that level for the remainder of the inspection period.
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.
The Senior Resident Inspector and Reactor Projects Branch
Chief conducted
a review of the Institute of Nuclear Power Operations evaluation
completed during this inspection period (conducted
March 3-10, 1997).
The
Institute of Nuclear Power Operations results were consistent with NRC's views of
licensee performance.
No additional followup actions are considered warranted.
Control room activities during the 1RS outage appeared to be well coordinated
and
controlled.
The inspector noted that the additional licensed operators put in the
control room for the outage allowed the control room.workload to be more evenly
distributed among the operators.
In particular, the addition of a second shift
supervisor,
a shift foreman's assistant,
and an additional reactor operator was seen
as a significant commitment by licensee management
to better manage outage
activities.
During the inspection period, inspectors noted several instances where caution tag
stickers were incorrectly placed on the Unit 1 control room control panels, and an
AR sticker that was left on the control board after the AR had been closed.
After
the inspector pointed out the discrepancies,
the caution tag stickers were moved to
the correct components
and the AR sticker was removed; however, the
discrepancies
were not documented.
After discussion with the operations director,
the inspector noted that it was management's
expectation that these types of
performance
errors be documented
by writing event trend. records.
After the
inspector discussed this with the operations director, these discrepancies
were
documented.
0
-2-
01.2
Failure to Maintain an 0 erator-at-the-Controls
at all Times
Ins ection Sco
e 71707
The inspectors reviewed an incident in which the licensee identified that the Unit 1
senior control operator (SCO) left the control room after assuming the duties of the
Unit 2 operator-at-the-controls.
At the time, Unit 2 was at 100 percent power.
As
a result, there was no one assigned
to monitor Unit 2 control room indications and
alarms for a period of approximately 3 minutes.
The following documents
were
reviewed:
~
AR A0435466, Violation of Procedure
OP1.DC12
~
Procedure
OP1.DC12, "Conduct of Routine Operations"
b.
Observations
and Findin
s
In reviewing this occurrence,
the inspector discussed
the sequence
of events with
the shift foreman (SFM) on duty for Unit 2 during this time.
The situation arose
when the Unit 2 control operator (CO) sought
a relief to allow him to leave the
"operator-at-the-controls"
area to go to the rest room.
The rest room, although
within the control room envelo'pe,
is outside of that area in which an operator-at-
the-controls is required to be stationed at all times.
At the time, the Unit 2 SCO was in containment performing a routine inspection and
the balance of plant CO, who is also a licensed reactor operator, was out of the
control room performing rounds.
As a result, the Unit 2 CO requested
relief and
was relieved by the Unit 1 SCO.
As provided by licensee procedures,
no formal
turnover is required for reliefs of this nature.
The Unit
1 SCO was on the phone
when the Unit 2 CO requested
the relief. Although the Unit 1 SCO apparently
acknowledged
the request,
he later left the control room after assuming the duties
of operator-at-the-controls.
Approximately 3 minutes later, when the Unit 2 SFM
stood up from his desk, he noted that there was not a licensed operator in the
designated
operator-at-the-controls
area.
At that point, the SFM assumed
the
operator-at-the-control
duties until another licensed operator was summoned to
assume the operator-at-the-controls
position.
The operations director noted that during the time there was no licensed operator
assigned
as the operator-at-the-controls,
the SFM was at his desk on the edge of
the operator-at-the-controls
area as defined in Attachment 7.5 of
Procedure
OP1.DC12.
The SFM was located where he would have heard and been
able to respond to control room annunciators.
In reviewing the information provided
by the licensee, the inspector determined that it was reasonable
to conclude that
the SFM was knowledgeable
of plant conditions and work in progress
and that he
was positioned in a way that he would have heard and responded
to any control
board al'arms,
It should also be noted that during this same time period there were
-3-
more than the TS minimum number of licensed senior reactor operators
and reactor
operators
in the control room.
Procedure
OP1.DC12, Section 5.11.3, allows the operator-at-the-controls
to enter
other areas within the control room envelope outside of that designated
as the
"operator-at-the-controls"
area provided the SCO or another cognizant licensed
operator is stationed such that he is attentive to control room indications and
alarms.
Procedure
OP1.DC12 also notes the operator preferably would be
positioned at the CO's desk or in front of the vertical boards.
TS 6.8.1 states,
in
part, that written procedures
shall be established,
implemented and maintained
covering the applicable procedures
in Appendix A of Regulatory Guide 1.33,
Revision 2.
NRC Regulatory Guide 1.33, Appendix A, requires implementing
procedures
for maintenance
of minimum shift complement.
The failure to have a
licensed operator in the operator-at-the-controls
area who was dedicated to being
attentive to control room indications and alarms and the associated
restrictions in
mobility is a violation of Procedure
OP1.DC12, "Conduct of Routine Operations"
(VIO 50-323/97006-01).
Conclusions
Informal communications
between the Unit 2 CO and the Unit 1 SCO combined
with other ongoing activities distracted the Unit 1 SCO when assuming the Unit 2
operator-at-the-controls
position.
As a result, the SCO left the control room during
the time he was the designated
operator-at-the-controls
for Unit 2. Consequently,
for a time period of approximately 3 minutes, there was no operator-at-the-controls
for Unit 2.
Untimet
0 erator Res
onse to SG Nozzle Dam Alarm
Ins ection Sco
e 71707
On May 15, 1996, while touring containment, the inspector noted that the alarm
and control panel associated
with the nozzle dams installed in SG 1-3 was alarming.
Discussion with the radiation protection (RP) technician stationed nearby indicated
that the panel had been alarming for approximately 30 minutes without a response
from operators.
After notifying the SFM of the alarm, the inspector observed that
operators
had arrived at the panel and were responding to the alarm.
The inspector reviewed the licensee's procedure for monitoring SG nozzle dams,
Procedure
OP A-5:III, Revision 0, the annunciator response
to a SG nozzle dam
trouble alarm, AR PK06-10A, Revision 0, the operator training lesson plan on SG
nozzle dams (lesson R956C4), and the Westinghouse
nuclear safety evaluation
checklist applicable to Busitech SG nozzle dams.
Observations
and Findin s
4-
The nozzle dam control panel for SG 1-3 was located outside the bioshield wall on
the 117-foot elevation in containment.
The panel alarmed both locally and remotely
in the control room; however, operators
in the control room were unable to
determine the cause or condition that resulted in the alarm until they respond to the
local control panel in containment.
Discussion with the cognizant engineer for the nozzle dams indicated that numerous
nozzle dam control panel alarms were occurring foi SG 1-3 due to air leakage past
the mechanical seal
~ This resulted in a buildup of air pressure
between the nozzle
dam wet and dry seals, which caused the alarm.
This pressure
is monitored and
alarmed because
a buildup of pressure
in this volume could be indicative of an air
leak in either the wet or dry seal.
AR A0433176 documented
the occurrence of
multiple nozzle dam alarms during Outage
1R8.
Procedure
OP A-5:IIIrequires that nozzle dam alarms be promptly investigated
and
resolved,
and that a failure of either the wet or dry seal may require that the reactor
vessel level be lowered to mid-loop to make repairs.
No other guidance
is provided
regarding the time frame for operator response.
Discussions with the director of
operations indicated that taking 30 minutes to respond to SG nozzle dam alarm was
not considered
prompt and was not in keeping with management
expectations,
especially if the alarm was a valid indication of a nozzle dam air leak.
A review of training records showed operators
have received training on SG nozzle
dams prior to Outage 1R8.
The training covered the basic construction and
operation of the nozzle dam as well as the operator response
upon receipt of an
alarm.
The training referenced the annunciator response
procedure
and the
operations procedure for the nozzle dams.
The annunciator response
procedure was
noted to be incomplete in that it only listed the conditions that would cause
an
alarm, but it did not provide operators with any guidance
on alarm response
or
reference other procedures.
Other than the problem noted with the annunciator
response
procedure,
the SG nozzle dam training and procedures
appeared
adequate.
The operations director indicated that different alternatives were being considered to
ensure more timely response
to SG nozzle dam alarms during the next outage.
Conclusions
The procedure for response to SG nozzle dam alarms specified that nozzle dam
alarms shall be promptly investigated
and resolved, yet operators took
approximately 30 minutes to respond to an alarming condition.
This was
considered to'be untimely response to the alarming condition by operations
management
and the inspector.
-5-
01 A
Pre arations for the Conduct of Mid-Loo 0 erations
a.
Ins ection Sco
e 71707
The inspector reviewed the licensee's
procedures
and 'preparations for conducting
midloop operations following the completion of core reload and SG inspections.
The
inspector observed tailboards conducted
by the operations services manager and
SFM prior to commencing reduced inventory operations.
b.
Observations
and Findin
s
Preparations
and controls for performing mid-loop operations were observed
by the
inspectors
and determined to adequately
ensure that the appropriate conditions
were established
and maintained during the time the reactor coolant system was in
reduced inventory.
Briefings conducted
prior to the evolution were comprehensive
and thorough.
Questions raised during the briefings were resolved prior to
continuing.
Operators were, provided time to review the procedure
prior to the commencement
of the draindown.
Control room activities were limited during the preparations
in
order to prevent distractions to the operators.
Contingencies
were discussed,
as
well as the actions that would be taken in the event that RHR pump suction was
lost.
These discussions
included the time frames that operators would have to
respond
and the time to boil when at reduced inventory conditions.
The inspector questioned
the fact that not all of the RCPs were re-coupled and off
of their backseat prior to draining to mid-loop.
This appeared to create the potential
for a cold leg vent path that would inhibit the restoration of RHR flow in the event
that pump suction was lost.
The licensee explained that the hot leg vent path, via
the reactor vessel head, would be established
at approximately 20 psig pressure
in
An analysis that had been performed by Westinghouse
determined that the RCP would not liftoff it's backseat until reactor coolant system
pressure was greater than 20 psig; therefore, the uncoupled and backseated
did not create
a credible cold leg vent path.
The inspector determined that this
engineered
pressure
boundary had been determined through engineering
analysis,
undergone
a detailed review by the licensee and appeared
acceptable.
C.
Conclusions
Preparations
by the licensee for the conduct of mid-loop operations were methodical
and thorough.
Operators were given an appropriate amount of time to review and
resolve questions
about the procedure.
Operations management
provided adequate
oversight of the activity and limited unrelated activities in the control room.
-6-
01.5
Seismic Qualification of the 4160V Switch ear
a.
Ins ection Sco
e 71707
The inspectors conducted
routine walkdowns of safety-related
equipment to verify
both availability and proper alignment of components
required for the current
operating mode.
b.
Observations
and Findin s
On April 30, during a walkdown of the Unit 2 4160V switchgear, the inspector
noted that three of the four seismic restraining bolts on the front of breaker
Cubicle 52-HH-15 were only finger-tight (bolt heads were able to be turned freely by
hand).
Breaker Cubicle 52-HH-'l5 houses the breaker for the Sl Pump 2-2 motor.
Due to the potential impact on the seismic qualification of the breaker cubicle, the
inspector immediately notified the unit SFM. An operator was dispatched
and the
bolts were properly tightened.
On May 6, the operations director identified a loose restraining bolt on the upper
door of breaker Cubicle 52-HH-13 in Unit 1.
Breaker Cubicle 52-HH-13 houses the
auxiliary feeder breaker for 4160V Bus H. The identified condition impacted the
seismic qualification of the breaker cubicle and the operability of one of the two
offsite power sources to Bus H. The condition was immediately corrected at the
direction of the of the Unit 2 SFM.
Operations Department Policy B-24, Revision 8, "Vital 4kV Switchgear Operability,"
provides specific guidance to operations
personnel
regarding the seismic
qualification requirements of the 4160V switchgear.
Policy 8-24 states that:
"If any bolt is missing or not properly installed in the upper front door of a
cubicle, the component fed by that breaker must be declared inoperable.
"Iftwo or more bolts are missing or not properly installed in the lower front
door of a cubicle, the component fed by that breaker must be declared
These criteria are based upon the licensee's
seismic analysis for qualification of the
4160V vital busses.
Applying these criteria to the circumstances
noted above
results in the conclusion that Sl Pump 2-2 arid auxiliary power to Unit 1 4kV Bus H
were inoperable until operators tightened the bolts in question.
Subsequently,
the
licensee performed
a detailed analysis of the as-found conditions and determined
that the Sl pump breaker was operable.
A review of the maintenance
history associated
with Sl Pump 2-2 noted that the
pump. was in a maintenance
outage window during the second week of April.
Following the maintenance,
the breaker was racked in'and the cubicle doors secured
-7-
on April 10.
The rack-in of Breaker 52-HH-15 was documented
on Attachment 9.1
of Procedure
OPJ-6A:IV, Revision 15, "4160 Volt Breaker Code Order."
Step 5.3
of Procedure
OP J-6A:IV requires all breaker cubicle panels and doors to be fully
bolted closed to ensure structural integrity of the bus housing for postulated
seismic
events.
To meet this requirement, Attachment 9.1 provides
a specific step to
tighten the bolts on the cubicle doors until the split ring washer is flat and then an
additional 1/8 to 1/4 turn.
This step was initialed as completed by the operators
who racked in Breaker 52-HH-15 on April 10.
The licensee has not identified any
additional records to indicate that the cubicle doors for Breaker 52-HH-15 had been
opened after April 10.
A review of the activities associated
with the auxiliary feeder breaker to Unit 1 4kV
Bus H, found that the auxiliary transformer feeding the breaker was re-energized
during the nightshift on May 5 (restoring the operability of auxiliary power to the
unit}. Since the operations director identified the loose bolt on the breaker cubicle
early in the dayshift on May 6, auxiliary power to Bus H was inoperable for
approximately an additional 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> following the re-energization of the
transformer.
Unit 1 was defueled during this event and the operability of auxiliary
power to Bus H was not required by plant TS.
Unit
1 4kV Busses
F and G were
operable during that period.
The licensee's self assessment
from 2R7 noted that multiple breaker cubictes on a
vital bus were found with missing or loose bolts which rendered the bus inoperable
when it was required by the outage safety plan.
This additional failure to properly secure fasteners
as required to ensure the
operability of the power source for SI Pump 2-2 in accordance
with approved
procedures,
therefore,
is a violation of 10 CFR Part 50, Appendix B, Criterion V,
which requires, in part, that activities affecting quality shall be accomplished
in
accordance
with these instructions, procedures,
or drawings (VIO 50-323/97006-
02).
The licensee has initiated actions to perform periodic checks of vital bus fasteners
to ensure that they have been properly tightened in order to detect and correct the
improper installation of fasteners.
Conclusions
A violation was identified in that controls established to ensure vital breaker cubicle
seismic restraints were ineffective in ensuring the proper installation of the
fasteners.
Subsequent
analysis showed the breaker to be operable with the loose
fasteners.
Similar problems occurred during Outage 2R7 and corrective actions had
not been fully effective in preventing additional instances.
-8-
01.6
Return to Service of the Main and Auxiliar Transformers
a.
Ins ection Sco
e 71707
The inspectors observed the operators return the main and auxiliary transformers to
service in accordance with Procedure
OPJ-2:I, Revision 7, "Main and Aux
Transformer Return to Service."
b.
Observations
and Findin
s
The energizing of the main transformer was performed as part of an electrical
system realignment to support replacement of Startup Transformer
1-1 during the
Outage 1R8.
The coordination of several procedures
including a temporary
procedure to energize the 12kV startup bus from the auxiliary power was necessary
to support the startup transformer replacement.
The personnel performing the
procedure
used good three way communications,
self-checking and peer checking
as applicable.
The activities included verifying the status of ground buggies, racking
in 12kV and 4kV breakers,
and fuse installation.
The personnel were observed
using appropriate safety equipment, including "flash suits" and a high voltage "hot
stick."
C.
Conclusions
Energizing the main and auxiliary transformers was performed well, with good
coordination of several procedures.
The personnel
involved were knowledgeable
of
the plant equipment and the procedure requirements
and performed the activities in
accordance
with the applicable procedure
and appropriate safety precautions.
01.7
Fill and Vent of the RHR S stem
Char in
Pum
s and Char
in
Flow Path
a.
Ins ection Sco
e 71707
The inspectors observed the operators filland vent the RHR system and portions of
the chemical and volume control system (CVCS) in accordance
with
Procedure OPA-2:Vll, Revision 6, "Core Offload Window Systems Restoration."
b.
Observations
and Findin s
A SFM was coordinating the activities of several teams in different areas of the
plant to perform this evolution.
The evolution included fillingthe piping systems
from the refueling water storage tank.
When the charging injection lines were filled,
the operators noted an increasing level in the reactor coolant drain tank.
The
operators closed valve CVCS-1-8108, isolating the flow path through the
regenerative
heat exchanger
and successfully terminating the flow to the reactor
'oolant drain tank; This expedited the identification and isolation of the leak path:
Further investigation revealed that the drain valves from the charging line
-9-
downstream of the regenerative
heat exchanger
(CVCS-1-91 and CVCS-1-566)
were
open.
These valves had been documented
as closed 2 days earlier.
Throughout this evolution, this portion of the CVCS was not required to be operable
or in operation.
The licensee wrote an AR to document this problem.
Subsequent
evaluation by the
licensee was inconclusive as to the cause of the out-of-position valves; however,
the licensee concluded that the most'ikely cause was operator error during valve
repositioning.
During the evolution, the operators were observed to be very knowledgeable of the
equipment, the procedure,
and activities being performed.
They were aware of
plant conditions and properly factored those conditions into their performance of the
procedure.
Communications
were clear with the use of three way dialogue.
The
SFM and CO were informed of the evolution progress, with frequent updates.
These
activities were generally well coordinated, with the exception of unblocking of
spring cans, which delayed the start of the RHR pump.
This problem involved
operators
needing to request unblocking supports twice from the maintenance
organization.
c.
Conclusions
The evolution had been well planned and was accomplished
in a cautious and
deliberate manner.
The operators demonstrated
excellent knowledge of the
equipment operation and interactions,
The actions taken to identify and isolate the
leak were sound and effective.
The regulatory and safety significance of the valve
mis-alignment was minimal since the system was not required to be operable.
Coordination between operations
and maintenance
were less effective and resulted
in delays but did not significantly impact the evolution.
01.8
Observation of 0 erations Activities Durin
Refuelin
Outa
e 1RS
a.
Ins ection Sco
e 71715
The inspector observed control room activities toward the end of Refueling
Outage
1R8, in order to evaluate operator performance
under the higher stress and
activity conditions associated
with preparations for unit return to power operation.
Observations
were conducted from May 20 through May 22, 1997, and focused
into the following areas:
~
Observation of equipment clearance activities, with emphasis
on how
effectively each individual involved in the process fulfilled their
responsibilities
as defined in the newly revised clearance
procedure.
Field walkdown of several clearances to confirm compliance with procedure
requirement's.
-10-
Observation of operator performance of control room activities associated
with outage completion, and operations interaction with other plant
organizations
disciplines involved in outage completion.
b.
Observation
and Findin s
Operations command and control was good during a period of a high work
activity and problem challenges.
In particular, the operating crew worked
well together and properly evaluated
and responded
to a loss of cold
calibrated pressurizer level indication, and an unexpectedly
high volume of
reactor coolant degassing,
which impacted reactor vessel head venting
operations
and repair work on an RCP.
The SFM effectively identified, documented,
and resolved minor problems
.
associated
with an improperly signed clearance,
and an improperly validated
test procedure.
Control room personnel communicated
well throughout the observation
period.
Specifically, operator peer checking and repeat-back
identified and
corrected several problems during operational transitions.
Examples included
identification that an operator was at the wrong switch for a valve position
change
and an'perator was about to make an incorrect public address
announcement
for start of an RCP.
Field walkdown of numerous clearance points identified no discrepancies.
Considering the magnitude of change implemented to the clearance
process
prior to the outage, operator training on the new changes
did not appear to
be timely or comprehensive.
Most operators stated that they were not
comfortable with such significant changes
immediately prior to an outage,
and they did not consider that training appropriately emphasized
the specific
new responsibilities affecting each individual involved in the clearance
process.
For example, some operators stated that they were not aware of
additional requirements for redundant verification of individual clearance
points until pointed out by the individuals they were relieving at shift change.
As a group, operators did not appear to have fully "bought-in" to the revised
clearance
process.
Although operators clearly recognized the need for
additional controls to prevent recurrence of previous clearance problems,
some appeared to view the process
as overly-cumbersome,
and did not fully
accept the need for the magnitude of redundant over-checking involved in
the new procedure.
Some operators
also noted a sense of management
reluctance to appropriately consider operator opinion in developing the new
process.
Recognizing the major effort and careful consideration
involved in
the licensee's
revision of its clearance
process, the inspector considered that
0
-1 1-
more interactive training on the bases for the changes
would have benefitted
all involved.
c.
Conclusions
The operations shift supervisor and SFM demonstrated
good command and control
during preparations for return to power operation at the end of Refueling
Outage
1R8.
Operator peer checking was consistently implemented and was
effective in identifying and correcting minor problems before they occurred.
Operator training on major changes to the equipment clearance
process prior to the
outage did not appear to have fully covered all appropriate aspects of new
responsibilities for each individual involved in the new process.
Also, additional
training on the bases for significant clearance process changes
appeared
warranted
to ensure full operator understanding
and support of the need for implemented
changes,
08
Miscellaneous Operations Issues (92901)
08.1
Closed
Licensee Event Re ort
LER 50-323 96004:
fuel movement not
suspended
when source range audible indication stopped.
On May 4, 1996, an
engineer entered containment
and noted that the source range audible indication
was not present with core alterations in progress.
The refueling senior reactor
operator was notified, who in turn notified the control room. A control room
operator immediately re-established
the audible indication.
The licensee
subsequently
determined that audible indication had been lost for approximately
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
The licensee identified that the sealer timer, which had been powered from a
convenience
outlet, momentary lost power during a switching operation and
required resetting to reestablish count rate indication.
The licensee determined that
had the sealer timer been powered from the audio count rate drawer, the switching
operation would not have affected the component.
The licensee revised
Surveillance Test Procedure
(STP) I-4C, "Calibration of Audio Count Rate/Sealer
Timer Channel," to include a step to specify the exact location to plug in the sealer
timer.
In addition, the licensee initiated actions to provide an alarm to alert
operators of a loss of audible counts.
The inspectors noted that the alarm was
installed and used during the recent Unit 1 refueling outage and
Procedure
STP 1-4C was revised.
TS 3.9.2 requires, in part, that continuous
audible indication count be available in
the control room and containment,
or suspend
all operations involving core
alterations.
The inspectors determined that the licensee did not violate the
requirements
of TS 3.9.2 since audible count indication was immediately
reestablished
when discovered although audible indication had been lost for
approximately
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
-1 2-
The inspectors determined that Procedure
STP l-4C, Revision 3, did not contain
adequate
guidance
on installing the power supply to the sealer timer, and therefore,
was not appropriate to the circumstances,
constituting
a violation of 10 CFR Part 50, Appendix B, Criterion V, "Procedures."
This licensee-identified
and
corrected violation is being treated as a non-cited violation, consistent with
Section VII.B.1 of the NRC Enforcement Policy (NCV 50-323/97006-03).
The inspectors documented
a previous event on November 6, 1995, where the
operators failed to recognize that the audible count was not on when Unit 1 was in
Mode 6 (NRC Inspection Report 50-275;323/95016).
The inspectors concluded
that these two examples indicated
a lack of operator awareness
and sensitivity to
the requirement to maintain audible count indication in the control room and
containment.
II. Maintenance
M1
Conduct of Maintenance
M1.1
Maintenance
Observations
a.
Ins ection Sco
e 62707
The inspectors observed
all or portions of the following work activities:
~
C0152057, Replacement
of Pressurizer
Level Transmitter (LT-461)
~
C01488866, Installation of Component
Cooling Water Valve TCV-130
~
C0146604, Installation of Battery 1-3
b.
Observations
and Findin s
The inspectors found the work performed under these activities to be accomplished
in accordance
with procedures.
All work observed was performed with the work
package present and in active use.
QC personnel were at the work location as
required.
C.
Conclusions
For the maintenance
activities observed
both technical maintenance
and mechanical
maintenance
personnel were knowledgeable
of the assigned tasks; they had
appropriate authorization for the work and closely followed the work package
instructions.
-1 3-
M1.1.1
Installation of Ground Bu
a.
Ins ection Sco
e 62707
The inspectors observed
portions of Maintenance
Procedure
(MP) E-57.11B,
"Protective Grounding," Revision 15.
b.
Observations
and Findin s
Technical Maintenance
and Operations personnel installed a ground buggy in
electrical Cubicle 52-HG-5 (for 4160V. Diesel Generator
1-2) in accordance
with
Procedure
MP E-57.11B.
The personnel
used the required personnel safety
equipment; the test equipment was properly used to verify the bus, and line sides of
the breaker were de-energized.
The first ground buggy used was found to stick in
the elevating mechanism
due to interference between the rails. The personnel
identified the cause of the problem and stopped the activity in order to prevent
damage to the equipment.
The ground buggy was replaced and the installation was
completed.
C.
Conclusions
The installation of the ground buggy was performed in a safe and cautious manner.
M'l.1.2 Clean
Ins ect
and Test 480V Circuit Breakers
a.
Ins ection Sco
e 62707
The inspectors observed portions of the following surveillance and maintenance
procedures:
~
MP E-64.1A
AC and DC Molded Circuit Breaker Test Procedure,
Revision 28
STP IVI-83A
Penetration Overcurrent Protection, Revision 16
b.
Observations
and Findin s
Technical Maintenance
personnel cleaned, inspected,
and tested circuit breakers on
the Bus 1F 480 volt bus.
Two breakers failed the surveillance acceptance
criteria
established to protect containment electrical penetrations
from overcurrent.
Containment
Fan 1-2 backup overcurrent Breaker 52-1F-01R failed to trip in the
required time and the FCV-750 circuit Breaker 52-1F-23 failed to trip at less than
the penetration's
maximum current limit. In each case,
an additional 10 percent of
the same class breakers were tested,
as required by TS, and no additional failures
occurred.
Other breakers tested passed
the surveillance acceptance
criteria, but
failed the more stringent manufacturer's
tolerance and were replaced.
The test
-14-
equipment was observed to be within current calibration.
Proper safety precautions
were used, and procedures
were followed and signed as required.
The cognizant
system engineer'was
closely involved with the work and the resolution of problems
as they arose.
c
~
Conclusions
The inspectors found the work performed under these activities to be accomplished
in accordance
with procedures.
All work observed was performed with the work
package present
and in active use.
System engineers
closely monitored job
progress.
M1.1.3 Containment
Fan Cooler Unit CFCU
1-4 Motor Ali nment and Electrical
Terminations
a 0
Ins ection Sco
e 62707
The inspectors observed portions of the following work order C00152198 to
replace bearings
and inspect the motor for CFCU 1-4.
b.
Observations
and Findin
s
Mechanical Maintenance
personnel performed motor alignment per
Procedure
MP M-56.19 and Technical Maintenance
personnel
performed the
electrical termination per MP E-57.2B.
The test equipment was observed to be
within calibration.
The procedure was at the job site and the steps were signed as
they were performed.
The two activities were well coordinated
between the two
maintenance
organizations to minimize the time for transition between groups.
During the termination activity, the licensee identified that the Raychem material
installed on the motor lead butt splices was outside the required size for the
application.
These splices were believed to have been installed in 1985.
The
licensee inspected the other Unit 1 CFCUs and found similar discrepancies.
The
splices were all replaced prior to the restart of the unit.
Unit 2 was evaluated for
operability and found acceptable with plans for inspection and repair during a later
outage.
C.
Conclusions
The composite maintenance
crew worked well together.
Work activities were
performed in accordance
with the procedural requirements,
and were well
coordinated to minimize the time necessary to complete this critical path
maintenance.
The licensee's identification and response to the undersize
Raychem
splicing appeared to'orrect the deficiencies.
0
-1 5-
M1.1.4
Removal
Ins ection
and Installation of RCP Mechanical Seal
a.
Ins ection Sco
e 62707
The inspectors observed
performance of portions of Procedure
MP M-7.43,
"Removal, Inspection, and Installation of Mechanical Seat-RCP (Motor In Place),"
Revision 14.
b.
Observations
and Findin
s
Following planned outage maintenance
on the RCP 1-4 seal assembly, the number
one seal leaked when filling the reactor coolant system.
Mechanical Maintenance
personnel
removed and inspected the mechanical seal, in accordance
with
Procedure
MP M-7A3. To minimize the radiation exposure to personnel, the
individual in the motor support stand wore a camera with the image displayed in a
nearby low-dose area and recorded
on videotape.
The inspection revealed several
paint chips on the seal in the area of the suspected
leak, including one paint chip
that appeared
to interfere with the o-ring seal.
The seals were cleaned,
a new
o-ring installed, and the seals reassembled.
f
Involved maintenance
personnel were knowledgeable
of the procedure,
tools, and
equipment and demonstrated
good teamwork.
They used good radiological
practices to minimize the spread of contaminatior., stopping to wipe up water and
clean the exposed
surfaces
as they worked.
Weakness
in foreign material exclusion was evident from the paint chips found in
the seal area.
Although the workers continually cleaned
as they worked, the
methods used did not prevent the introduction of foreign material. At the time of
the seal disassembly,
the inspectors noted that persorrnel were carrying hoses and
outage material across the open grating above the RCP.
Additionally, chain-falls
used in the disassembly
and reassembly of the seals had apparently chipped the
paint on the inside of the motor support stand, which may have been the source of
the foreign material that caused the unacceptable
seal leakage.
C.
Conclusions
The activities related to the removal, inspection, and repair of the RCP 1-4 seals
were observed to have been performed in accordance
with the procedure.
The use
of the camera and monitor was effective in reducing radiation exposure for the task.
However, the previous efforts to prevent foreign material from entering the seals
were ineffective, which resulted in the need for the rework of the RCP seal.
-1 6-
M1.2
Surveillance Observations
Ins ection Sco
e 61726
Selected surveillance tests required to be performed by the 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 M-16T
Slave Relay Test of K615A/8, K612A, and K614B (Sl
and Phase A Isolation), Revision 3
~
STP P-23A
Acceleration Timing of Safety-Related
Pumps Actuated
By Solid State Protection System Train A, Revision 5
~
STP P-23B
Acceleration Timing of Safety-Related
Pumps Actuated
By Solid State Protection System Train B, Revision 6
~
STP P-23C
Acceleration Timing of Turbine Driven Auxiliary
Feedwater Pump, Revision 12
~
STP V-5C
Emergency
Core Cooling System Hot Leg Check Valve
Leak Test, Revision
11
~
STP R-1B
~
STP R-31
Rod Drop Measurement,
Revision 17
Rod Worth Measurements
Using Rod Swap Method,
Revision 7
b..
Observations
and Findin s
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 engineering test directors were
well versed on the technical requirements
of the testing and closely monitored test
performance
and scrutinized test results.
The inspectors noted that test results
appeared to have been apprcpriately dispositioned.
0
-1 7-
M1.2.1
Manual and AUTO Transfer of 4KV Vital Busses Off-site Power Sources
a.
Ins ection Sco
e 61726
The inspector observed the performance of Procedure
STP M-13A, "Manual and
Auto Transfer of 4kV Vital Busses Off-site Power Sources,"
Revision 6, to
determine whether the procedure was technically adequate
and the test results
satisfied acceptance
criteria or were properly dispositioned.
b.
Observations
and Findin s
While performing the manual transfer of 4KV vital Bus H from the auxiliary
transformer to the startup transformer,
in accordance
with Procedure
STP M-13A,
Revision 6, the operators noted that the incoming bus voltage was 10 volts higher
than the running bus voltage.
A design change
had been installed during
Outage IRS which provided
a variable tap transformer and added the ability to
change the startup bus voltage from the control room.
Operations normal operating
procedure for this transfer, Procedure
OP J-6 A:II, had been updated with
instructions to match voltages within indicated 3 volts; however, the surveillance
procedure
had not been updated.
As a result, operators stopped the surveillance
test in order to resolve the difference in voltage by revising the procedure to include
the necessary
instructions.
The test was then completed satisfactorily.
Conclusions
Operators proceeded with caution after revising Procedure
STP M-13A to provide
instructions for utilizing the newly installed variable tap transformer for adjusting
startup bus voltage.
Surveillance procedure reviews performed prior to
implementation of the design change failed to identify the need for the change.
M1.2.2 Containment
Ins ection Prior to Establishin
Containment Inte rit
a.
Ins ection Sco
e 61726
The inspectors observed portions of Procedure
STP M-45A, "Containment
Inspection Prior to Establishing Containment Integrity," Revision 6.
b.
Observations
and Findin s
The conditions in the containment were noted to be in compliance with the criteria
of Procedure
STP M-45A. All noted exceptions to the closeout were documented
and tracked by the licensee.
A minimal amount of debris including tape, a sheet
metal screw, paper clips, a test fitting cap, and plastic mounting tabs were
identified to the licensee
and corrected.
The general area containment cleanup 'was
complete, with the exception of several last maintenance
activities.
Some
-1 8-
insulation fasteners
on the SGs and reactor coolant system piping were noted to be
loose or broken.
The licensee corrected these discrepancies.
c.
Conclusions
Containment closeout activities were appropriately controlled.
Several minor
discrepancies
were noted by inspectors
and corrected by the licensee.
M1.2.3 Resettin
Hi h Flux Bistables
Unit
1
a.
Ins ection Sco
e 61726
On June 6, 1997, the inspectors observed Technical Maintenance technicians
perform portions of Procedure
STP l-2U, "Resetting High Flux Bistables for Power
Range Channels,"
Revision 9A.
b.
Observations
and Findin s
The technicians
used good communication techniques
between themselves
and
with the operators.
In addition, the technicians proceeded
cautiously when opening
the power range drawers to avoid component damage
and used good procedure
adherence throughout'he surveillance test.
c.
Conclusions
The inspector concluded that the technicians displayed an overall strong
performance during the surveillance test.
M6
Maintenance Organization and Administration
M6.1
Outa
e 1RS Safet
Plan and Schedule
a.
Ins ection Sco
e 62707
The inspector reviewed the licensee's
Outage Safety plan and schedule
and
attended
Outage Coordination Center meetings during the course of the outage.
b.
Observations
and Findin s
Significant effort was put forth by the licensee in the development of the outage
safety plan and schedule.
Efforts in this area appeared to be focused on
maintaining multiple sources of power and core cooling capabilities during the
different phases of the outage.
Particular emphasis was placed on communicating
these requirements to all personnel
in the organization on a daily basis.
Changes
in-
the schedule
and scope of work were carefully evaluated as to the potential impact
-19-
on the outage safety plan.
Changes
were made when required and approved
by the
Plant Staff Review Committee (PSRC).
The outage safety plan also placed emphasis
on maintaining the availability of the
containment sump at different stages of the outage.
The inspector noted during
tours of containment tnat there were materials and plastic on the 91-foot elevation
of containment that had the potential to partially block the sump.
After questioning
the licensee on the control of material, the licensee acknowledged that a review of
the control and storage of material on the 91-foot level of containment was
warranted.
One discrepancy was noted and corrected by the licensee where work was
conducted
contrary to the outage safety plan.
Turbine building siding work was
allowed to continue above the Unit 2 startup transformers during the time that
startup power was being relied upon as the single source of offsite power.
The
siding work posed
a threat to the Unit 1 offsite power.
Review of the situation
revealed that, while the siding work had been approved
early in the outage, the
licensee had not established
adequate
subsequent
controls to assure that personnel
understood the actions required when plant conditions changed.
As a result, the
licensee failed to ensure that the work being performed did not threaten the single
source of offsite power.
C.
Conclusions
The outage safety plan and schedule were focused on maintaining a safe plant
configuration in order to ensure availability of emergency power sources
and core
cooling throughout the outage when there was fuel in the reactor vessel.
The
safety plan and schedule were clearly communicated to the organization in meetings
and daily reports that were published and distributed to workers.
M7
Quality Assurance
in Maintenance Activities
M7.1
Licensee Qualit
Assessments
of 1RS Performance
a.
Ins ection Sco
e 40500
The inspector reviewed the licensee's
self assessments
of the first two outage
windows during Outage
1R8 as well as the overview assessment
of the previous
Refueling Outage 2R7.
b.
Observations
and Findin
s
The licensee assessments
covered operations,
maintenance
and engineering
services,
and areas common to all, which were considered
as cross functional
areas..'The
assessments
were issued within several days. after the completion of,
-20-
the assessment
periods.
This provided plant management
with timely feedback on
performance
and focused management's
attention on the problem areas, which
were of greatest significance.
The assessments
noted improvement in two of the three areas that were of concern
during the last outage.
Specifically, performance
in the areas of personnel safety
and foreign material exclusion had improved, while a significant number of
performance errors continued to occur with clearances.
Clearance
Errors Durin
Outa
e 1R8
Clearance discrepancies
were predominantly personnel performance
errors and did
not appear to be due to procedural inadequacies.
The inspector reviewed the types
of errors that were documented
and concluded that the causes for the errors were
mostly in the areas of inattention to detail, knowledge level exceeded,
and time
pressures.
The inspector noted that several significant clearance
errors occurred, including:
a
valve and a 480 volt breaker which had been tagged
in the incorrect position; work
performed without clearances
when a clearance was required; and reporting off
clearances
prior to the completion of work. These errors did not result in personal
injury or damage to equipment, but were viewed by the inspector as precursors to
potentially more significant events and, therefore, warranted additional attention
from licensee management.
Since problems with clearances
had been a problem
area during the last outage the licensee's
self assessment
concluded that corrective
actions to address
problems with clearances
were not comprehensive
and, thus,
partially ineffective.
The NQS assessment
noted that the actions taken by
management
during the first two outage windows had a p'ositive effect on clearance
performance for the remainder of the outage.
C.
Conclusions
NQS assessments
of performance during 1R8 were effective in identifying problem
areas to plant management.
Assessments
were issued in a timely manner and
provided management with the information needed to focus attention on problem
areas.
A significant number of clearance performance problems occurred during
Outage 1R8. The licensee's efforts to improve performance
in this area immediately
after Outage 2R7 appeared to have been not completely effective in preventing
similar problems.
M8
Miscellaneous Maintenance issues (92902)
M8.1
Closed
LER 50-275 83040:
missed inservice inspection (ISI) surveillance.
On
.
April 10, 1996, the licensee'identified that since the initial fuel loading in both units,
-21-
the RHR and excess letdown heat exchanger
seismic supports were not included in
the ISI'program plan or routinely inspected
as required by TS 4.0.5.
On April 11,
1996, the licensee inspected the seismic supports
and found them acceptable.
The licensee performed
a review of maintenance
records and noted no indication of
inoperability or required maintenance
during the period of the missed surveillance.
Therefore, the licensee concluded that while the seismic supports were technically
inoperable, they were available during that period of time to support the heat
exchangers
as required during a seismic event.
ISI and engineering
personnel
performed
a walkdown of components to ensure the
attached
seismic supports were properly identified and inspected.
The licensee
identified no additional missed surveillances.
The licensee revised the ISI program
plan and ISI surveillance schedule to include the RHR and excess letdown heat
exchanger
seismic supports.
The inspectors reviewed the ISI program plan and
observed that it included the heat exchanger supports.
The inspectors concluded
that the licensee's corrective actions were appropriate.
TS 4.0.5 requires,
in part, that tests and inspections
be performed in accordance
with periodic surveillance criteria of Section XI of the ASME Code.
The Section XI
for the RHR heat exchanger
and excess letdown heat exchanger
requires, in part, an
inspection in accordance
with the visual test criteria be performed prior to placing
the system in use and each 40 month period thereafter.
The failure to perform the
surveillance
is a violation of TS. This licensee-identified
and corrected violation is
being treated as a noncited violation, consistent with Section VII.B.1 of the NRC
Enforcement Policy (NCV 50-275;323/97006-04).
III. En ineerin
E1
Conduct of Engineering
E1.1
RCP Oil Collection S stem Discre ancies
a.
Ins ection Sco
e 37551
92903
The inspector reviewed the licensee's
actions to identify and resolve reactor coolant
lube oil collection system problems.
The NRC highlighted potential problems in
IN 94-58, "RCP Lube Oil Fire." During the course of the inspection, the following
documents were reviewed:
AR A0351025, Evaluation of IN 94-58
Operational Events Assessment
Log 94-330
~ '
1RB RCP Oil Collection System Inspection Results
-22-
Independent
Safety Engineering
Group (ISEG) Assessment
Report 961430034, Assessment
of RCP Oil Collection System to the
Requirements
Operability Evaluation 97-04, Revision 0, Operability of the RCP LiftOil
System with Missing Oil L'ift Pump Enclosures
(Unit 2)
b.
Observations
and Findin s
Ins ection of RCP Oil Collection S stem durin
1R8
On April 19, 1997, the licensee documented
the inspection results for Unit 1 RCP
oil collection piping on AR A0429325.
The AR noted that several of the RCP oil
collection systems
had missing or bent and broken tray sections
as well as tray
sections that were in need of adjustment.
During the inspection licensee personnel
noted that there was a small section of the
liftoil pump instrument tubing that was pressurized
during liftoil pump operation
that was not enclosed
by a sheet metal shield.
This was noted as not being in
accordance
with licensee procedures
which implement the requirements of the fire
protection program to confine a leak within the shield and to direct the oil.to
collection pans.
Following identification of this discrepancy,
the licensee made a 'l-
hour non-emergency
report to the NRC to report a condition
outside of the design
basis of the plant.
The licensee noted that the section of tubing was not normally
pressurized
during RCP operation and that the only time the line was pressurized
was during an RCP start.
Reviews determined that the RCP lift oil system had been modified to add the
additional section of tubing that was outside of the spray shield.
The licensee
determined that the modifications were most likely made sometime in 1977 or
1978; however, no records or documentation of the modification were found.
Licensee Determination of Acce tabilit for Continued 0 eration
The licensee issued
a prompt operability assessment
(POA) for Unit 2 since it was
not practical to correct the liftoil shield discrepancies
until the next outage due to
the radiation levels in the RCP cubicles where the unshielded instrument tubing is
located.
Unit 1 was not included in the evaluation since 1R8 was ongoing at the
time of discovery and the licensee planned to correct the discrepancies
prior to the
restart of Unit 1.
The POA was later replaced by an operability evaluation that was reviewed and
approved
by the PSRC.
The licensee's conclusion on operability was based on the
line being pressurized
only during pump starts and the ability to monitor for oil
~ losses.
'The licensee initiated compensatory
actions for observation of-piping leaks
during RCP starts.'he
inspector reviewed the assessment
and determined that it
.~
-23-
appeared
to be reasonable
and included adequate
compensatory
measures.
The
licensee intends to correct the Unit 2 deficiencies during the next Mode 3 entry, not
to exceed Outage 2R8.
Licensee Evaluation of IN 94-58
NRC IN 94-58, "RCP Lube Oil Fire," addressed
a number of discrepancies
associated
with the RCP oil collection systems
in which inadequately
designed,
installed, and maintained oil collection systems resulted in fire hazards.
The
inspectors performed
a walkdown of the system during Refueling Outage
1R8 and
at the end of the outage prior to restart.
The licensee received IN 94-58 in August 1994.
In September
1994, the licensee's
OEA log indicated that Diablo Canyon's
RCP oil collection system did not utilize
PVC piping as described
in IN 94-58.
Evaluation of other aspects of IN 94-58
involving oil on insulation and RCP oil collections system design adequacy,
installation, and maintenance
were not addressed
at that time.
AR A0351025 was later written by the licensee to track the evaluation of IN 94-58.
No inspections were performed by licensee personnel
until June 1996 for Unit 2 and
April 1997 for Unit 1, despite the fact that there had been several refueling outages
and forced shutdowns which had offered inspection opportunities.
As of April
1997, however,
IN 94-58 was still being evaluated
by the licensee.
Based upon the licensee's untimely evaluation of IN 94-58, the inspector questioned
their response to other NRC generic communications to the industry.
The licensee
provided a status of evaluations
and the inspector noted that there were nine other
issues in the time period from 1992 through 1994 that had not been fully
evaluated.
The licensee's
response
to these issues will oe reviewed to determine
adequacy
and timeliness.
This is being tracked as an inspection followup item
(IFI 50-275;323/97006-05).
ISEG Assessment
of RCP Oil Collection S stem to the Re uirements of 10 CFR Part 50 A
endix R
In June 1996, NQS performed an assessment
of the Unit 2 RCP oil collection
system.
During the assessment,
it was noted that the actual flash point of the
motor oil was 55 degrees lower than what was stated in the UFSAR and
Supplemental
Safety Evaluation Report 23. This discrepancy was identified as
requiring a 10 CFR 50.59 safety evaluation.
Following the inspectors'uestions,
the safety evaluation was completed and approved
by the PSRC in May.1997,
approximately
11 months after the discrepancy
and the need for an evaluation was
identified.
The safety evaluation concluded that the difference in flash point
temperature
did not create an unreviewed safety question.
-24-
As a part of the ISEG assessment,
a review of 10 CFR Part 50, Appendix R,
requirements
was performed and no discrepancies
were noted.
The assessment
included an observation that the RCP oil collection system was required to be
capable of collecting lube oil from all potential pressurized
and unpressurized
leakage sites.
The Unit 2 RCP oil collection system was inspected with this in mind
and compared the as-constructed
system to the as-designed
system.
No
discrepancies
were noted with regard to this capability during the assessment.
NRC Evaluation of Licensee
Res
onse
TS 6.8.1 requires that procedures
covering the fire protection program be
implemented.
The licensee is committed to implement a lube oil collection system
to contain system leaks through program directive Procedure
OM8, Revision 2, "Fire
Protection Program," and through references to provisions in the FSAR.
The licensee's
response
to IN 94-58 was reviewed and the following observations
were made:
IN 94-58 was issued in August 1994; however, as of April 1997 the licensee
had not perfo'rmed an inspection of the system
as recommended
in the initial
evaluation of the IN. Additionally, the IN remained in an "eval" status
meaning that it had not been determined if corrective action was necessary.
The licensee's
self-assessment
of the Unit 2 RCP oil collection system in
June 1996 incorrectly concluded that the system met the requirements of
10 CFR Part 50, Appendix R, and failed to identify modifications that were
made to the RCP lift oil pump instrument tubing.
Discrepancies
between the flash point temperature
in the UFSAR and the
actual flash point temperature were required to be evaluated to determine the
affect of the difference; however, an evaluation was not completed until the
NRC raised questions about the difference, approximately 10 months after
the initial identification of the discrepancy.
Inspections of the RCP oil collection system performed by the licensee at the
beginning of Outage 1R8 revealed numerous installation and maintenance
discrepancies
that were indicative of inadequate
attention to the system.
NRC Observations
of Plant Confi uration
The inspectors questioned
the use of sealant to fillin gaps between the base of the
RCPs and the collection pans.
The licensee responded that the sealant that had
been used was RTV 732 sealant and had not been qualified for use in containment
and would be replaced with a qualified caulking.
The licensee also reviewed the
calculation for debris clogging the containment sump and determined that the
-25-
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.
Conclusions
The inspectors determined that the RCP oil collection system spray shield deficiency
was a violation of licensee procedures.
There were opportunities to have identified
the spray shield deficiency and other maintenance
related deficiencies earlier.
This
constituted
a violation of TS 6.8.1 (VIO 50-275/97006-06).
The licensee was slow
to complete
a safety evaluation for a lowered lube oil flash point.
E8
IVliscellaneous Engineering Issues (92903)
E8.1
MFP Turbine Sto
Valve Time Res
onse Testin
Discre ancies
a.
Ins ection Sco
e 92903
A
The inspector reviewed the actions initiated by the licensee following discovery that
MFP turbine stop valves had not been periodically response
time tested.
During the
inspection the following documents
were reviewed.
b.
~
AR AO316782, Revise ISC Procedure
PEP-04
~
AR A0429696, MFP Turbine Stop Valve Testing
~
Quality Evaluation 0011951, MFP Turbine Stop Valve Testing
~
AR A0427518, AE 11, POA addressing
lack of time response
testing
~
TS 3.3.2 Interpretation 97-04, Revision 0
Observations
and Findin s
Identification of the Need to Test MFP Turbine Sto
Valves
The design of the main feedwater (MFW) system relies upon the rapid closure of the
MFW control and bypass valves to limitthe mass and energy release within
containment in various secondary
system rupture accidents.
The design class
II
MFP trip, which occurs concurrently with a MFW control and bypass valve closure
signal, provides the backup in the event that a MFW control valve or it's associated
bypass valve fails to close.
Following a Unit 2 reactor trip in March 1997, NQS initiated a review of past
problems associated
with MFP turbine stop valves.
During the review it was
recognized that no corrective actions had been taken following the previous
discovery of the need to response
time test MFP turbine stop valves.
AR A0316782, written in September
1993, identified that MFP turbine stop valves
and associated
control circuitry were not being periodically time response
tested.
The licensee recognized. that since the MFP trip feature was credited in the main
0
-26-
steam line break mass and energy release analysis, the testing was required and a
surveillance procedure was needed.
There is no TS requirement for response
time
testing of these valves.
Response
time testing of the MFW turbine stop valves had not been previously
accomplished.
The cognizant system engineer later closed out the AR in October
1995, in error, without a surveillance test procedure having been written to test the
valves, and as a result the required testing was not accomplished.
10 CFR Part 50, Appendix B, Criterion XI, "Test Control," requires that a test
program be established
by the licensee to assure that all testing required to
demonstrate
that structures, systems,
and components
will perform satisfactorily in
service is identified and performed in accordance
with written test procedures,
which incorporate the requirements
and acceptance
limits contained
in applicable
design documents.
These requirements
were not met by the licensee until testing
was performed to verify that the time response
of the MFP turbine stop valves and
associated
circuitry were verified.
Corrective Actions Followin
Identification of the Failure to Perform Re uired
~Testin
After recognizing that the initial corrective actions failed to address the need to
periodically verify the time response
of the MFP turbine stop valves the licensee
initiated the following actions:
A POA was written to address the lack of response
time testing of the MFP
trip feature.
I
A TS interpretation 97-04 was issued which determined that MFP turbine
stop valve time response
testing should be included in TS.
was written to track the actions needed to add this requirement to TSs.
STP V-3P7 was issued to perform the response
time testing of MFP turbine
stop valves on a refueling frequency.
Response
time testing was accomplished for both Units
1 and 2 MFP turbine
stop valves.
The inspector reviewed the corrective actions and determined that they appeared to
be appropriate
and if followed through would correct the discrepancies.
The licensee's failure to periodically verify the MFP turbine stop valves performed as
assumed
in the MSLB safety analysis is a violation of 10 CFR Part 50, Appendix B,
Criterion Xl, "Test Control."
This licensee-identified
and corrected violation is
being treated as a noncited violation; consistent with Section VII.B.1 of the NRC
Enforcement Policy (NCV 50-275;323/97006-07).
4
-27-
c.
Conclusions
The licensee's
response
following the identification of the need to response
time
test MFP turbine stop valves in September
1993 was untimely and failed to address
the identified testing discrepancy.
This problem is indicative of a previous lack of
attention to detail and deficient engineering
management
oversight and review of
corrective actions.
Detailed research
by an NQS engineer of past problems with MFP turbine stop
valves resulted in identification of the inappropriate
closure of AR A0316872.
This
is considered
to be noteworthy since these efforts resulted in the identification and
correction of a significant discrepancy.
E8.2
Chan
es Included in Revision
11 to the UFSAR Without Safet
Evaluations
a.
Ins ection Sco
e
37551
The inspector reviewed changes that were included in Revision
11 to the UFSAR
without having completed safety evaluations
in accordance
with 10 CFR 50.59.
The following FSAR Update change
requests,
which were included in Revision 11
were reviewed:
Sections 3.3, 5.1, 5.2, 5.4, 5.5, 5.6.2, 8.1, 8.2, 8.3, 9.5.2, 9.5.3,
and 9.3.
b.
Observations
and Findin s
The changes that were made to the UFSAR were reviewed by the inspector.
The
majority of the changes
appeared to be editorial or provide clarification to the
UFSAR for agreement with existing plant conditions and/or the associated
design
criteria memorandum.
None of the changes
appeared
to involve physical changes
to the plant and had originally been determined by the licensee not to require formal
safety evaluations.
However, these changes
did warrant safety evaluations to
determine whether or not they involved unreviewed safety questions.
The licensee
issued Revision
11 to the UFSAR in November 1996, which included these
changes,
without having completed the associated
safety evaluations.
The safety
evaluations for these changes
were not completed until approximately 6 months
later.
c,
Conclusions
The failure to perform safety evaluations when required by procedure prior to
implementation of the changes
in the UFSAR will be reviewed as a part of the
unresolved
item tracking UFSAR discrepancies
(URI 50-275;323/96006-06).
-28-
IV. Plant Su
ort
R1
Radiological Protection and Chemistry Controls
R1.1
Radiolo ical Controls Durin
the H drolasin
of Unit 2 Lower Reactor Cavit
a.
Ins ection Sco
e 71750
The inspectors reviewed the events leading up to, and the licensee's
response
following, the spread of radioactive contamination
in the FHB during the hydrolasing
of the Unit
1 lower reactor cavity.
The following documents
were reviewed:
Procedure
OP B-2:Vl, Revision 12, RHR - Draining the Refueling Cavity
Procedure
MP M-19.3, Revision 7, Fuel Transfer Tube Cover Removal and
Installation
Radiation Control Procedure
D-661, Revision 5, Decontamination of the
Reactor Cavity by Strippable Coatings
Procedure
OP L-6, Revision 26A, Refueling
Contamination Surveys 97-03912 and 03913, Unit 1 FHB (South)
AR A0434161, Spread of Significant Contamination Outside of. a Surface
Contamination Area (SCA)
b.
Observations
and Findin s
Events Resultin
in the S read of Contamination
On May 20, 1997, RP personnel
performed hydrolasing to decontaminate
the lower
reactor cavity surfaces.
Prior to commencing the hydrolasing,
RP personnel
had
contacted the Unit 1 control room to determine the status of the spent fuel
pool (SFP) transfer tube Valve SFS-50.
Operations personnel
relied upon an
abnormal status board to verify that Valve SFS-50 was closed.
RP was concerned
about the position of the valve since, if open, it provided a direct
pathway from the lower reactor cavity into the FHB. This was undesirable
since it
created the potential for the spread of contamination into the FHB during
hydrolasing.
Hydrolasing conducted
during a previous outage with Valve SFS-50
open had resulted in the spread of contamination
in the FHB.
Following the hydrolasing, an operator exiting the Auxiliary Building radiologically
controlled area alarmed the personnel contamination monitor.
Surveys showed
contamination levels as high as 3,500 counts per minute (cpm) on the operator's
-29-
shoes,
right upper arm and chest areas of his shirt.
RP investigation of the
contamination identified the spread of loose contamination adjacent to the Unit
1
SFP in the FHB. Subsequently,
it was determined that Valve SFS-50 was open
during the hydrolasing.
Contamination
Levels in the FHB
Surveys of the FHB showed contamination
levels of up to 30,000 cpm on large area
swipes.
Contamination was noted outside SCAs primarily in the areas adjacent to
the SFP with the highest levels being adjacent to the fuel transfer canal.
Survey
results showed contamination levels as high as 10,000 disintegrations
per minute
per 100 cm'
RP personnel
subsequently
decontaminated
the areas outside of the
SCAs to restore normal access to the FHB. The inspector noted that the levels of
contamination found during the surveys were not wide spread
and did not create
a
significant radiological hazard to workers who entered the area.
Procedural Controls for Refuelin
Procedure
OP L-6 provides the sequence
and procedures that are performed in
support of refueling.
Procedure
OP L-6, among other things', sequences
the draining
of the lower reactor cavity and the closing of Valve SFS-50.
Specifically,
Step 6.3.6 directs the'draining of the lower reactor cavity and transfer canal
utilizing Procedure
OP B-7:Vll, which opens Valve SFS-50.
Procedure
OP L-6,
Step 6.3.7, directs that Valve SFS-50 be closed when the spent fuel pool side of
the transfer canal is fully drained.
Hydrolasing was conducted after completion of
draining the lower reactor cavity and transfer canal, but prior to closing
Valve SFS-50.
Procedure
OP L-6 does not address the sequencing
of hydrolasing
activities in the lower reactor cavity.
Prior to the draindown of the cavity and transfer canal, operators
had hung a
clearance
(for the installation of the fuel transfer tube cover) which closed
Valve SFS-50.
Since Valve SFS-50 was required to be open for the draindown,
operators
had to remove the clearance
on Valve SFS-50 in order to accomplish the
draindown.
Following completion of the draindown, when RP personnel
called the
control room to determine the position of Valve SFS-50, the operator assumed that
the valve was shut since he had hung the clearance
on the valve earlier in the shift.
Additionally, the control room status board incorrectly showed Valve SFS-50 to be
closed.
Operations did not require a clearance to ensure that Valve SFS-50
remained closed for hydrolasing.
The licensee indicated that they planned to use a
clearance to assure that Valve SFS-50 is closed prior to future hydrolasing activities
in the reactor cavity.
Conclusions
Operations failed to establish positive controls to ensure Valve SFS-.50 was closed
during hydrolasing.
As a result, due to the combination of an incorrect control room
-30-
status board and inadequate
verification of Valve SFS-50 valve position, hydrolasing
was conducted with Valve SFS-50 open, which resulted in the spread of
contamination into the FHB.
V. IVlana 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 June 5, 1997.
A separate
exit meeting was held for the
control room observations
of Section 01.8 on May 22, 1997.
In both meetings 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.
ATTACHMENT
PARTIAL LIST OF PERSONS CONTACTED
Licensee
J. R. Becker, Director, Operations
W. G. Crockett, Manager, Nuclear Quality Services
T. L. Grebel, Director, Regulatory Services
T. F. Fetterman,
Director, Instrumentation
and Control Engineering
S. R. Fridley, Manager, Outage Services
D. J. Hampshire, Senior Engineer,
Balance of Plant Engineering
S. C. Ketelsen, Senior Engineer, Regulatory Services
D. B. Miklush, Manager, Engineering Services
J. E. Molden, Manager, Operations Services
D. H. Oatley, Manager, Maintenance
Services
R. P. Powers, Manager, Vice President
DCPP and Plant Manager
J. A. Shoulders,
Director, Support Engineering
D. A. Taggart, Director, Nuclear Quality Services Engineering
and Procurement
R. L. Thierry, Director, Balance of Plant Systems
R. A. Waltos, Director, Engineering Services
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
'P
40500: Effectiveness of Licensee Controls in Identifying, Resolving and Preventing
Problems
IP 61726: Surveillance Observations
IP 62707: Maintenance
Observations
IP 71707: Plant Operations
IP 71750: Plant Support
IP 92901: Followup - Plant Operations
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
~Oened
50-323/97006-0.1
Failure to maintain an operator-at-the-controls
as
required by procedure
-2-
50-323/97006-02
50-323/97006-03
Failure to properly install Sl breaker cubicle fasteners
Inadequate
procedure for installation of power supply to
sealer/timer audio count rate
50-275;323/97006-04
Failure to perform ASME required ISls
50.-275;323/97006-05
50-275/97006-06
IFI
Slow response
to industry information
Failure to assure spray shields enclose
RCP liftoil pump
lines
50-275;323/97006-07
Failure to time response test MFP turbine stop valves
Closed
50-323/96004-00
LER
Fuel movement not suspended
when source range
audible indication stopped
50-323/97006-03
Inadequate
procedure for installation of power supply to
sealer/timer audio count rate
50-275/83040-00
LER
Missed ISI surveillance
50-275;323/97006-04
Failure to perform ASME required ISls
50-275;323/97006-07
Failure to time response test MFP turbine stop valves
Discussed
50-275;323/96006-06
Failure to adequately review and update the FSAR
1
LIST OF ACRONYMS USED
CFCU
CO
FHB
IFI
IN
ISEG
LER
kv
NQS
OP
POA
PSRC
POA
SCA
SCO
SFM
TS
1R7
1RS
2R7
2RS
inspection followup item
Information Notice
inservice inspection
Independent
Safety Engineering
Licensee Event Report
kilovolt
main feedwater pump
main feedwater
Maintenance
Procedure
noncited violation
nuclear quality services
Operations
Procedure
prompt operability assessment
Group
Public Document Room
pounds per square inch gage
Plant Staff Review Committee
prompt operability assessment
reactor coolant pump
radiation protection
surface contamination
area
senior control operator
spent fuel pool
shift foreman
safety injection
surveillance test procedure
Technical Specification
Updated Final Safety Analysis Report
unresolved item
Unit 1 seventh refueling
Unit 1 eighth refueling
Unit 2 seventh refueling
Unit 2 eighth refueling
action request
American Society of Mechanical Engineers
containment fan cooler unit
counts per minute
chemical and volume control system
control operator
Diablo Canyon Power Plant
~
fuel handling building
final safety analysis report
l>>