ML16342E077
| ML16342E077 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 04/22/1998 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342E075 | List: |
| References | |
| 50-275-98-07, 50-275-98-7, 50-323-98-07, 50-323-98-7, NUDOCS 9804280121 | |
| Download: ML16342E077 (70) | |
See also: IR 05000275/1998007
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORYCOMMISSION
REGION IV .
Docket Nos.:
50-275
50-323
License Nos.:
DPR-82
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspector(s):
50-275/98-07
50-323/98-07
Pacific Gas and Electric Company
Diablo Canyon Nuclear Power Plant, Units 1 and 2
7 '/~ miles NW of Avila Beach
Avila Beach, California
February 15 through March 28, 1998
D. L. Proulx, Senior Resident Inspector
D. B. Allen, Resident Inspector
D. G. Acker, Project Inspector
T. R. Meadows, Licensing Examiner
W. M. McNeill, Reactor Inspector
B. J. Olson, Project Inspector
Approved By:
H. J. Wong, Chief, Reactor Projects Branch E
Attachment:
Supplemental Information
9804280121
980422
ADQCK 05000275
-2-
EXECUTIVE
UMMARY
Diablo Canyon Nuclear Power Plant, Units 1 and 2
NRC Inspection Report 50-275/98-07; 50-323/98-07
This inspection included aspects of licensee operations, maintenance,
engineering, and plant
support.
The report covers a 6-week period of resident inspection.
~Oera ions
Shutdown and startup evolutions were conducted in a professional manner, in
accordance with procedures and a focus on safety (Section 01.1).
A noncited violation, per Section VII.B.Iof the NRC Enforcement Policy, was identified
for failure to provide a procedure appropriate to the circumstances for switching of
power supplies between the units. The switching of the power supply without clearly
understanding the outcome resulted in unexpected alarms, loss of power to equipment
required by Technical Specifications, and unnecessary
disruption in both control rooms.
The immediate response of the Unit 1 control room operators was very good, with timely
and appropriate response to each alarm (Section 01.2).
A violation was identified for failure to provide a midloop procedure appropriate to the
circumstances that required proper stowage of a nonseismically qualified hoist. The
hoist was left in an unstowed condition above the operating residual heat removal pump
during a reduced inventory condition (Section 01.3).
Several significant operator evolutions were performed well. Shutdown and startup
evolutions were conducted well, in a professional manner, in accordance with
procedures,
and with a focus on safety.
Licensee preparations and implementation,
including the operations pre-evolution briefings for early midloop operations, were
conservative and reflected a focus on safety.
The reflood of the emergency core cooling
systems evolution was well coordinated and controlled, with each participant aware of
their responsibilities. The pre-evolution briefing w'as comprehensive,
with emphasis on
safe, cautious performance and the necessity for good communications
(Sections 01.3 and 01.4).
A violation was identified for failure to restore the "High Flux at Shutdown" annunciator
when the required number of fuel assemblies was installed in the core. The
responsibility to perform the actions was not clearly assigned prior to the evolution
(Section 01.5).
The control of refueling activities lacked clear procedural guidance and management
expectations.
The lack of procedural guidance for performing signal-to-noise ratio
calculation, the lack of acceptance
criteria in the procedure for fuel assembly
clearances,
and the confusing procedure format were weaknesses
in the procedure.
The method used to calculate inverse count rate ratio and the method used to perform
-3-
the post core load verification were inconsistent with the methods described in the
procedure.
The lack of separate signatures in the controlled copy of the procedure for
verifying that the signal-to-noise ratio was greater than two was an example of poor
documentation of procedurally required activities (Section 01.5).
Aviolation was identified for several examples of failure to properly implement the
clearance procedure.
However, the number and significance of clearance errors in
Refueling Outage 2R8 were improved from the previous outage.
Several significant
errors were not found or prevented by the clearance process and resulted in the
potential for work to be performed without the required isolation from sources of energy
to allow safe work (Section 01.6).
A violation was identified for failure to translate the design of the reactor vessel refueling
level indication system into abnormal operating procedures.
The licensee exhibited
good attention to detail in identifying this issue during simulator training. Documented
corrective actions at the end of the inspection period for this violation failed to address
deficiencies in the procedure preparation and approval process (Section 03.1).
The training provided for Unit 2 outage preparation was implemented well and provided
valuable lessons learned and necessary
procedural changes.
The inspectors noted, in
particular, that the simulator training was professional, well executed, and identified a
vulnerability in the abnormal operating procedures (Section 05.1).
aine
ance
Maintenance personnel did not exercise appropriate care during penetration seal work
and stepped on a valve, that when repositioned, challenged operators by causing a leak
in the chemical and volume control system (Section 02.1).
A number of maintenance activities were observed and were performed in accordance
with the procedural requirements.
Good coordination between technical maintenance,
mechanical maintenance,
and radiation protection was obser ved in performing several
maintenance tasks concurrently on the containment spray pump, thereby reducing the
time the pump was inoperable due to maintenance (Section M1.1).
The inspectors observed a number of surveillance tests and found that the surveillances
observed were performed in a cautious manner with self-checking and proper
communications employed.
The procedures governing the surveillance tests were
technically adequate
and personnel performing the surveillances demonstrated
an
adequate
level of knowledge.
The inspectors noted that test results appeared to have
been appropriately dispositioned (Section M1.2).
The containment cleanup and closeout activities were appropriately controlled, and the
material condition of containment areas was satisfactory for restart. of Unit 2
(Section M1.3).
The license's approach to the inspection of part length control rod drive mechanism
welds was sound and aggressive. The inspectors found the ultrasonic testing showed
the seven motor tubes'pper and lower transition welds were free of the type of defect
found at Prairie Island on the G-9 motor tube (Section M2.1).
'
A noncited violation was identified for failure to provide a procedure appropriate to the
circumstances for ground buggy installation. The improper ground buggy installation
had the potential to have caused significant damage to safety-related equipment and
injure workers (Section M4.1).
The inspectors concluded that the corrective actions for Violation 50-275;323/96014-03
were sufficiently directed towards ensuring that control board action request stickers
were removed when the work was complete, but did not appear to fullyaddress the
need to closely control these deficiency tags. The inspectors found six additional
deficiencies concerning control board action requests.
Therefore, the licensee's
programs to ensure that the control board action requests stickers reflected the
licensee's tracking list and the up-to-date plant configuration warranted further licensee
attention (Section M8.1).
~En ineerin
The inspectors concluded that the design change package and associated safety
evaluation for replacement of the Unit 2 recirculation sump screens was comprehensive,
and the conclusions were reasonable.
The design change was effective in improving
the containment sump's ability to screen out debris that could block safety injection flow
paths (Section E2.1).
Plan Su
ort
~
Licensee management's
efforts to keep exposures as low as reasonably achievable
during Refueling Outage 2R8 appeared to be successful in that total outage exposure
was improved from previous outages.
The licensee's cleanup of the reactor coolant
system following shutdown of Unit 2, and the use of mock-up training for several outage
tasks contributed to the lower exposure (Section R1.1).
Re ort Details
Sum
a
of Plan
S a us
Unit 1 began this inspection period at 100 percent power.
On March 21 1998, reactor power,
was reduced to 50 percent to conduct main feedwater pump control and stop valve testing, and
Unit 1 was returned to 100 percent power later that day.
Unit 1 continued to operate at
essentially 100 percent power until the end of this inspection period.
Unit 2 began this inspection period in Mode 4 (Hot Shutdown) for Refueling Outage 2R8.
On
March 24, on completion of outage activities as of that point, Unit 2 entered Mode 2 (Startup).
On March 25, Unit 2 entered Mode 1 (Power Operation).
Later on March 25, the turbine tripped
prior to synchronizing to the grid, and Unit 2 was returned to Mode 3 (Hot Standby) to
investigate a turbine lube oil system problem.
After completing repairs in the lube oil system,
the reactor was returned to Mode 2 on March 27 and entered Mode 1 later that day. On
March 28, Unit 2 was synchronized to the grid, ending Refueling Outage 2R8. Unit 2 was at
30 percent power at the end of this inspection period.
i. ~0erations
01
Conduct of Operations
01.1
General Commen s
1707
The inspectors observed control room operations and toured the plant on a frequent
basis, including frequent backshift inspections.
In general, the performance of plant
operators was professional and reflected a focus on safety.
Operators continued to
perform well, utilizing three way communications and self-checking techniques.
Operator response to alarms were observed to be prompt and appropriate to the
circumstarices.
Operations shift management were frequently present in the control
room and were aware of plant conditions. All crew members interviewed by the
inspectors were aware of plant conditions and system configurations.
Limiting
conditions for operations were properly entered when required.
During this period the
inspectors observed several crews for each unit, including backshifts.
The inspectors
noted increase operations department management presence
in the control room during
the Unit 2 shutdown.
The inspectors observed portions of reactor startup activities
between March 25-March 28. The inspectors noted that these startup activities were
conducted in a professional manner, in acc'ordance with procedures,
and with a focus
on safety.
01.2
Transferrin
Power Su
I
For Ins rument Dis ribution Panel PYNM
a.
Ins ection Sco
e 71707
On February 10, the inspectors observed control room activities while systems and
equipment with unit cross-ties were being realigned to Unit 1 prior to the Unit 2 refueling
outage (2R8).
-2-
Observa io s and Findi
s
While transferring the power supply for Panel PYNM (a 208/120 volt instrument
distribution panel) from Unit 2 to Unit 1, a number of unexpected alarms were received
in both Unit 1 and Unit 2 control rooms. The operator performing the switching had not
expected the alarms and had informed the Unit 2 shift foreman that there would be no
alarms in the control room during the switching. The drawing the operator had
referenced did not have sufficient information to identify the effects of the transfer.
Had
the correct drawings been used, each alarm would have been anticipated or actions
taken to prevent the alarms from occurring. Action Request A0452798 was initiated to
document this occurrence
The alarms received included: fire detection, component cooling surge tank pressure
high and low, seismic trip undervoltage, post accident sample room radiation monitor
failure, and low flow to Radiation Monitors RM-11 and RM-12. The seismic trip system
provided an input to reactor trip at Diablo Canyon.
Radiation Monitor RM-11 was the
containment air particulate monitor and RM-12 was the containment radioactive gas
monitor. Technical Specification 3.4.6.1, "Reactor Coolant System Leakage Detection
Systems" requires that with both Radiation Monitors RM-11 and RM-12 inoperable, the
containment fan cooler collection monitoring system and the containment structure
sumps and reactor cavity sump level and flow monitoring systems must be operable.
The inspector observed the Unit 1 control room operators respond to these alarms.
The
control operator immediately evaluated and prioritized the alarms by importance. The
Unit 1 shift foreman questioned the Unit 2 shift foreman and learned that the alarms
could have been caused by the switching of power to Panel PYNM, and relayed this
information to the control operator.
Follow up actions to return equipment and alarms to
normal was appropriate and timely. Both units entered Technical Specifications action
statements for loss of Radiation Monitors RM-11 and RM-12.
The switching of power was performed under the direction of an Operations Section
Policy DP, "Preoutage System Alignments For Systems With Unit Crossties,"
Revision 1. There was not a procedure available to perform this switching. For six
other activities addressed
by the policy, specific procedures were referenced to perform
the transfer.
The policy document was not a procedure and provided no guidance as to
the expected results.
The procedures referenced
in the policy did not provide the
necessary directions.
As corrective actions, the licensee committed to revise Operations Section Policy D-4
and the applicable procedures referenced in the policy such that clear procedural
guidance would be provided for future power switching operations.
In addition, the
licensee placed a permanent operator aide near Panel PYNM to alert the operators of
the multiple inputs to the panel.
Failure to provide a procedure appropriate to the circumstances for switching power
supplies is a violation of 10 CFR Part 50, Appendix B, Criterion V. However, this
-3-
nonwillful, self-revealing, and corrected violation is being treated as a noncited violation,
consistent with Section VII.B.1 of the NRC Enforcement Policy (50-275;323/98007-01).
c.
Conclusions
A noncited violation was identified for failure to provide a procedure appropriate to the
circumstances for switching of power supplies between the units. The switching of the
power supply without clearly understanding the outcome resulted in unexpected alarms,
loss of power to equipment required by Technical Specifications, and unnecessary
disruption in both control rooms. The immediate response of the Unit 1 control room
operators was very good, with timely'and appropriate response to each alarm.
01.3
Midloo
era 'ons
Unit 2
a.
ns ec ion Sco
e 71707)
b.
The inspectors verified the prerequisites and witnessed the performance of midloop
operations, when Unit 2 was in a reduced inventory condition.
In addition, the
inspectors witnessed training in preparation for this evolution. The inspectors performed
these inspections on February 19 and March 9, 1998, each time the licensee entered
the reduced inventory condition.
Observa ions a d Fin in s
a
I
Midloo
On February 19, 1998, prior to entering midloop operations early in the outage with a
high decay heat load, the inspectors verified the prerequisites for the evolution. This
included plant tours to verify that personnel and equipment were staged to permit
venting of the residual heat removal pumps in the event of pump vortexing. The
inspectors also ensured that no ongoing evolutions that could affect midloop operations
were in progress.
The inspectors concluded that the prerequisites for entering hot
midloop were satisfied.
The inspectors observed the operations briefing for entering midloop. The briefing was
organized, detailed, and focused on safety.
Licensee management was present and
emphasized expectations with respect to safe operations.
On February 19, with Unit 2 in Mode 5, the inspectors observed the control room crew
drain the reactor vessel water level down to 107 feet, midlevel of the reactor vessel
hotlegs, in preparation for steam generator maintenance.
The evolution was conducted
without incident, in a very professional manner.
The inspectors monitored the following
special reactor vessel
refueling level indications and other, special instrumentation:
~
Reactor Vessel Refueling Level Indicating System wide and narrow range
~
LT-954 8 LT-953 normal level indicators
0
~
LI-561 normal level indicator
~
Chart recorders wide and narrow range indicators
~
Chart recorders for pressure relief tank pressure and volume control tank level
The inspectors compared these indications throughout the evolution and they appeared
to be accurate.
Allranges and trends were consistent.
The inspectors also witnessed
the maintenance of midloop conditions and the refillfollowing completion of installation
of the steam generator nozzle dams.
These activities were also conducted
satisfactorily.
'
La e Midloo
On'March 10, 1997, following completion of the steam generator tube inspection and
tube plugging, the licensee reentered midloop operations to remove the steam
generatornozzle
dams.
The inspectors reverified the prerequisites were met. The
inspectors provided continuous coverage during the entire evolution and ensured that
the precautions, limitations, and prerequisites,remained
in effect. The inspectors
observed the control room crew drain the reactor vessel down to 107 feet, which was
completed without incident. The inspectors monitored instrumentation, which appeared
to be tracking satisfactorily.
With the reactor at midloop conditions, the inspectors toured the facilityto assess
the
material condition of the systems used for this evolution.
In the room for residual heat
removal Pump 2-2, the operating pump, the inspectors noted that the overhead trolley
hoist for the pump was not in its normally stowed position and was above the residual
heat removal pump and piping. The inspectors were concerned because the overhead
trolley hoist in the pump room was not seismically qualified, and could possibly impact
the operating residual heat removal pump, instrument tubing, or system piping while in
a reduced inventory condition. The inspectors contacted the shift supervisor, who
directed maintenance personnel to stow and lock the hoist in its proper position.
Engineering determined that the failure to stow the overhead hoist was not a significant
concern because
it was unlikely for a seismic event to result in the hoist chains or hoist
to impact residual heat removal components
in such a way that the system could not
perform its intended safety function. The licensee did not document the
inspectors'oncern
on an action request until March 25, after the inspector continued to question
the licensee on the cause and safety significance of this problem.
Procedure MP M-10.2, "Residual Heat Removal Pump Motor and Impeller Handling,"
Revision 5, Section 7.6.9, required the hoist and trolleys in the residual heat removal
pump rooms to be placed in their normally stowed positions with the chains secured
in
place following maintenance.
Although the licensee believed that this procedure was
properly implemented, the hoist was not in its proper location when required.
On March 25, 1998, the licensee began investigating this problem. The licensee noted,
that although Section 7.6.9 of Procedure MP M-10.2 was not signed off as completed,
-5-
maintenance personnel stated that they had stowed the hoist as required.
The licensee
believed that subsequent
to mechanical maintenance personnel properly stowing the
hoist, other personnel removed the restraining bracket from the chain and moved the
hoist back over the pump. At the end of the inspection period, the licensee had not
determined the cause of the improper hoist location.
The inspectors discussed this issue with licensee engineering personnel.
The licensee
noted that although licensee procedures required plant walkdowns to identify seismic
concerns prior to operational mode changes,
no such requirement existed for entry into
midloop operations in the prerequisites of the midloop procedure.
Procedure OP A:2-III,
"Reactor Vessel - Draining to Half Loop/Half Loop Operations with Fuel in the Vessel,"
Revision 13, was not appropriate to the circumstances.
Specifically,
Procedure OP A:2-IIIdid not provide for verification that no seismic concerns existed
prior to entry into reduced inventory conditions. As a consequence,
the hoist and trolley
for residual heat removal Pump 2-2 was not in its seismically approved storage position
and the chains were not in the storage racks when residual heat removal Pump 2-2 was
being used for decay heat removal. The failure to provide a midloop procedure
appropriate to the circumstances
is a violation of 10 CFR Part 50, Appendix B,
Criterion V (50-323/98007-02).
Co cusions
A violation was identified for failure to provide a midloop procedure appropriate to the
circumstances that specified proper stowage of a nonseismically qualified hoist. The
hoist was left in an unstowed condition above the operating residual heat removal pump
during a reduced inventory condition. Licensee preparations and implementation,
including the operations pre-evolution briefing for early midloop operations, were
conservative and reflected a focus on safety.
Reflood of the Unit 2 Emer enc
Core Coolin
S s ems followin Core Offload Outa
e
Period
Ins ection Sco
e 71707
On March 2, the inspectors observed control room activities while preparations were
made to refill the residual heat removal and other emergency core cooling systems.
On
March 3, the inspectors observed operations venting emergency core cooling systems
using Procedure OP A 2:Vll, "Core Offload Window Systems Restoration," Revision 6.
Observa ions and Findin s
The pretask briefing performed by the shift foreman covered the precautions and
limitations, prerequisites, major steps, individual responsibilities and communications
between organizations.
The personnel attending the briefing included the operators
assigned to perform the venting, operators in the control room, radiation protection
personnel assisting with the venting, and technical maintenance
personnel assigned to
~ 1
-6-
backfill and place into service the reactor vessel refueling level instrumentation system.
Special attention was given in the briefing to maintaining vessel level to avoid cavitation
of the residual heat removal pump. The required positions of the newly installed throttle
valves also received additional attention and were verified to be addressed
by the
procedure.
The control room operators closely monitored reactor vessel level indications and
residual heat removal system parameters
and were cognizant of the field activities
during the filland vent. Good two-part and three-part communications, self checking
and peer checking was observed in the control room throughout the evolution. Venting
of high point vents within controlled surface contamination areas was observed.
The
operators and radiation protection personnel worked well together,to contain the vented
liquid and demonstrated
good radiological practices in entering and exiting controlled
areas and monitoring for contamination.
onctu ions
The reflood of the emergency core cooling systems evolution was well coordinated and
controlled, with the participants aware of their responsibilities. The pre-evolution briefing
was comprehensive, with emphasis on safe, cautious performance and the necessity for
good communications.
~Rf
i Alii
lns ection Sco
e 6071
On March 4 and 5, the inspectors observed refueling activities in the control room, fuel
building and containment.
These activities included handling and movement of the fuel
assemblies
from the spent fuel pool to the upender and from the upender to the final
core location, control room monitoring of required parameters,
and reactor engineering
calculations of inverse count rate ratio and monitoring of fuel location for accountability
requirements.
The inspectors reviewed Operating Procedure OP B-8DS2, "Core
Loading Sequence,"
Revision 20, which contained the procedural requirements for these
activities.
Observatio
s and Findin s
The inspectors observed the refueling senior reactor operator directing the fuel handling
operations in containment.
He was observed to maintain good supervision over the
activities, maintaining communications with the control room and the personnel in the
fuel building, giving directions to the crane operator and other observers, verifying the
correct core location as specified in the fuel movement tracking sheets, monitoring the
load on the manipulator crane as the fuel assembly was raised or lowered, and
confirming the proper indicating lights and Z-Z tape position. The fuel assemblies were
inserted off index as described in the procedure. The inspectors observed the insertion
of an assembly against the baffle and into a three-sided box, which resulted in a rapid
e
-7-
load fluctuation when the assembly bottom nozzle hung on the baNe.
The senior
reactor operator immediately stopped the loading and performed the steps required in
the procedure to protect the assembly and achieve a successful installation. Reactor
engineers were monitoring and video taping the fuel movement with cameras installed
on the upper internals guide pins.
Fuel Handlin
The inspectors observed the movement of the fuel assemblies
in the fuel handling
building. This activity was coordinated with the senior reactor operator to ensure an
assembly was not raised out of the spent fuel racks until the upender was unloaded in
the containment.
The crane operators were observed to followthe procedural
requirements, including observing limitations on crane motion, load, and speeds.
The
fuel assembly location and identification was independently verified against the fuel
movement tracking sheets prior to being removed from the racks.
Reactor engineers
used an underwater camera to monitor and record the fuel assemblies
as they were
moved to the upender.
The inspectors also observed that the foreign material exclusion
area controls around the reactor cavity and the spent fuel pool were effective.
ConroIRoomA
iviies oSu
o
FueILoad
The inspectors observed control room activities in support of fuel load. On March 5,
while inspecting the switch lineup on the nuclear instrumentation panels, the inspectors
noted that the "High Flux at Shutdown" alarm switch for source range Channel N-32 was
in the blocked position, rather than the normal position required for the current step in
the core loading procedure.
This was immediately brought to the attention of the control
operator and reactor engineer in the control room. Operations placed the switch in the
normal position and documented on Action Request A0455551 that OP B-8DS2,
Attachment 9.8, "Fuel Movement Tracking Sheet," required the "High Flux at Shutdown"
alarm for N-32 be restored at Step 21B and this action had been overlooked.
Approximately eight additional assemblies
had been loaded after Step 21B and before
the alarm was returned to normal.
During this time, both channels of source range
nuclear instruments were operable and monitored continuously by the control operator
and reactor engineer.
In addition, one channel of source range was audible in both the
control room and containment, and the "High Flux at Shutdown" alarm for Channel N-31
was in normal.
The failure to restore the "High Flux at Shutdown" alarm at the specified step in the core
loading procedure, Step 21B, is a violation of Technical Specification 6.8.1.a.
(50-323/98007-03).
A contributing cause of the failure to restore the "High Flux at Shutdown" alarm
appeared to be the format of the fuel movement tracking sheets
in that: the applicable
step contained three actions, the actions were to be performed by two different groups,
the step did not have a separate step number (step numbering was used to designate
the number of assemblies
loaded), and the place for date, time, and initials was covered
0
-8-
by the text of the step. Another contributing cause was that the responsibility to perform
the actions was not clearly assigned prior to the evolution.
Reac or En ineerin
Activiies Durin
Fuel Lo d
Step 21B of OP 8-8DS2, Attachment 9.8, contained several actions, including verifying
that the signal-to-noise ratio for source Range N-32 was greater than 2. The procedure
provided no directions for determining signaI to noise ratio. The completion of this
activity was not documented
in the procedure by a separate signature or initials,
although the reactor engineer stated that he had performed the verification. The step
was not signed until after the missed'action of restoring the alarm was brought to the
control operator's attention.
Step 6.17 of OP B-8DS2 stated, in part, that a calculated prediction of critical
assemblies was required to be performed after the first 13 assemblies
had been loaded
adjacent to a detector., The reactor engineers used a computer program to calculate
inverse count rate ratio (ICRR). This program also calculated the predicted ICRR if 12
additional assemblies were loaded based on extrapolation of the most recent ICRR data
points.
Ifthis predicted ICRR were greater than zero, it indicated core load could
continue.
This method satisfied the intent of performing ICRR, but appeared
inconsistent with the procedure in that the number of assemblies
predicted to cause
criticality was not calculated.
Step 6.25 of OP B-8DS2 stated that a fuel accountability audit and a foreign materials
scan at the completion of core loading be performed, prior to placement of the upper
internals in the vessel.
This was to consist of either producing a video tape of the core
and reviewing it for foreign objects, coupled with a verification of proper loading from the
tape, or visual (camera and monitor) verification with two signatures to document the
inspection.
Inspection and verification of nozzle-to-nozzle and nozzle-to-baffle
clearances was also required.
Reactor engineering satisfied the fuel accountability
requirement by reviewing the video tapes made in the spent fuel pool and in the reactor
cavity during fuel loading. Afterthe core was loaded, a video tape was made with a
camera scan to inspect for foreign material and clearances
between the assemblies
and
between the assemblies
and the baNe plate. Although the methods used were
technically adequate,
they did not appear to be entirely consistent with the procedure
(although vague) in that the tape of the core produced during the post core load scan
was not used to verify proper loading, nor was a visual (camera and monitor) verification
with two signatures to document the inspection performed.
The procedure did not
provide guidance nor acceptance
criteria for the size of the gaps between the
assemblies or between each assembly and the baffle. The inspectors also noted minor
documentation discrepancies
in the closeout of the paperwork.
Conclusions
A violation was identified for failure to restore the "High Flux at Shutdown" annunciator
when the required number of fuel assemblies was installed in,the core. The
responsibility to perform the actions was not clearly assigned prior to the evolution. The,
lack of formality in performance of control room refueling activities contributed to the
failure to restore this alarm.
The control of safety activities lacked clear procedural guidance and clear management
expectations.
The lack of procedural guidance for performing signal to noise ratio
calculation, the lack of acceptance
criteria in the procedure for assembly to assembly
and assembly to baNe clearances,
and the confusing procedure format which
contributed to the missed action of restoring the "High Flux at Shutdown," were
weaknesses
in the procedure.
The method used to calculate inverse count rate ratio
and the method used to perform the post core load verification appeared to be
inconsistent with the methods described in the procedure, although the procedure was
vague.
The lack of separate signatures in the controlled copy of the procedure for
verifying that the signal-to-noise ratio was greater than 2 was an example of poor
,
documentation of procedurally required activities.
The necessary
coordination between
the fuel handlers in containment, the fuel handlers in the refueling building, the reactor
engineer, and the control operator's observation of plant conditions were otherwise
performed well.
01.6
Clearance Rela
d
rrors Durin
R8 Refue in
Outa
e
ns
e
ion
co
7 707
The inspectors reviewed the licensee's self-assessment
of operations clearance
performance during 2R8, and 27 action requests initiated to document errors related to
clearances.
b.
Observation
and Findin s
Operations performed a self-assessment
of their performance during 2R8 and
concluded there was a reduction in clearance errors and a reduction in the severity of
these errors compared to 1R8. The licensee categorized the errors by significance. A
level 1 (high significance) error was one that caused or could have caused personnel
injury or equipment damage or all clearance process barriers were breached.
A level 2
(moderate significance) error was one where some clearance process barriers were
breached,
but others prevented placing personnel or equipment in jeopardy. A level 3
(low significance) error was an inconsequential error related to some phase of the
clearance process.
In comparing the performance in 2R8 to 1R8, the licensee
determined there were 3 high significance errors in 2R8 as compared to 8 in 1R8, there
were 15 moderate errors in 2R8 compared to 33 in 1R8, and there were 45 low
significance errors in 2R8 compared to?3 in 1R8.
During 2R8, none of the errors
resulted in personnel injury or equipment damage.
The licensee identified some recurring themes in the clearance errors.
Most of these
themes had minimal significance.
Tags becoming unsecured or becoming illegible but
none of the cleared equipment were operated as a result, and minor administrative
~
~
-10-
errors such as missing a set of initials were considered minor. Errors of most
significance were generally caused by lack of proper self verification and independent
verificatIon.
The most significant clearance errors during 2R8 were related to clearing tags to
perform testing and resulted in tags being removed from the wrong components or
allowing work to be performed without a clearance,
as follows:
On February 25, while attempting to remove a clearance tag from 52-2F-02R.to
allow testing of containment fan cooling Unit 21, an operator mistakenly removed
a tag from 52-2F-01R and attempted to close the breaker, which jammed and did
not close.
The operator rec'ognized his mistake while showing the technical
maintenance technicians the jammed breaker (AR A0454479):
~
On February 26, while processing a partial removal of a clearance to perform
testing, a senior control operator marked the desired return to service position on
two incorrect clearance points. As a result, an operator removed tags and
closed two incorrect breakers.
The problem was identified and the breakers
reopened and retagged (AR A0454548).
~
On March 17, after testing of a control rod drive mechanism fan for proper
rotation identified the fan motor leads needed to be swapped; the power supply
breaker was opened and technical maintenance swapped the leads without
clearing the breaker (AR A0457998).
Other clearance errors had the potential to be cause equipment damage or personnel
injury, but were identified outside the clearance process.
For example,
On March 4, while removing tags following work, a senior control operator
discovered a caution tag hanging over the fuse holders for fuses that had been
removed for Valve RCS-2-PCV-474.
This tag should have removed the fuses for
Valve RCS-2-PCV-472 (AR A0455485). This error was not identified in the
clearance process.
On February 17, Clearance 57169 was hung prior to the proper plant conditions
being established,
isolating reactor coolant pump seal injection while the reactor
coolant system pressure was approximately 350 psig. Operating procedure
OP A-6:II, "Reactor Coolant Pumps - Shutdown and Clearing," Precautions and
Limitations 5.2, specified that seal injection should remain in service as long as
the reactor coolant system is pressurized to prevent introduction of crud from the
reactor coolant system into the seals.
The control room operators, responding to
the loss of seal injection, contacted the operator in the field, and the seal
injection flow was reestablished
(AR A0455670). This clearance error was not
found in the clearance process, but by alarms in the control room.
-11-
On March 3, workers detected voltage on a cathodic protection circuit prior to
performing work. The clearance, 56570, did not clear an alternate source of
power from Unit 1's power supply 52-P J18-1-33 (AR A0455394).
Other clearance errors were considered moderately significant by the licensee because
not all barriers were broken, such as the errors were identified during walkdown by
maintenance prior to starting work. These errors indicated that improvement in self-
verification in the operations organization required improvement, because
more than
one barrier failed. For example:
On February 16, during the'maintenance
walkdown, Breaker 52-23J-08 was
found closed with a man-on-line tag hanging requiring the breaker to be open
(AR A0453258).
On March 6, during a clearance walkdown prior to starting work a man-on-line
tag was found hanging on the wrong fuse. The tag was hanging on the fuse
holder for lYFW21, but it should have been hung on the fuse holder for lYFW22,
which was the cross feed power from the relay scheme for lYFW21
(AR A0455669).
Several other less significant errors existed that were identified by the independent
verifier, thus indicating a failure of only one barrier.
The inspectors noted that, fortuitously, none of these examples of clearance errors
resulted in personnel injury or equipment damage; however, the potential existed.
Multiple failures of operations personnel to properly implement the clearance procedure
is a violation of Technical Specification 6.8.1.a (50-275;323/98007-04).
c.
Conclusions
'
violation was identified for several examples of failure to properly implement the
clearance procedure.
Several significant errors were not found or prevented by the
clearance process and resulted in work being performed or had the potential for work to
be performed without the required isolation from sources of energy to allow safe work.
However, the number and significance of clearance errors in Refueling Outage 2R8
were improved over previous outages.
02
Operational Status of Facilities and Equipment
02.1
Chemical and Volume Con rol S stem Lea
a.
ns ectio
co
e 93702
On February 13, 1998, the inspectors responded to the control room and observed
operator response to a leak from the chemical and volume control system.
0
b.
Observa ionsa dFindin s
On February 13, 1998, while Unit 2 was operating at 100 percent power, the control
operator identified that volume control tank level was dropping at a rate of approximately
12 gallons per minute.
Operators implemented Procedure OP AP-17, "Charging Line
Leak at Power," Revision 19, and isolated the flowpath to the deborating demineralizer,
but volume control tank level continued to drop at the same rate.
Approximately 30
minutes later a nuclear equipment operator reported that the miscellaneous equipment
drain tank level was rising. The shift foreman directed that the nuclear equipment
operators check the flow sight glasse's
in the auxiliary building, which determined that
Flow Indicator Fl-276 had flow. The nuclear equipment operators verified the position of
check valves that drain through Flow Indicator Fl-276. A nuclear equipment operator
found that Valve CVCS-2-66 (the centrifugal charging pump recirculation drain line
isolation valve) was approximately 1-1/2 turns open.
The valve was closed, which
stabilized volume control tank level. The inspectors monitored the operator response to
the event and considered the operator resolution of the lowering of volume control tank
level to be timely and thorough.
Licensee investigation revealed that maintenance personnel performed penetration seal
work in the overhead area above Valve CVCS-2-66, and that the likely cause of the
event was that the handwheel for Valve CVCS-2-66 was bumped while using a ladder
adjacent to the valve. The inspectors noted that NRC Inspection
Report 50-275; 323/97019 discussed an event in which the root cause was similar. In
the previous event, maintenance personnel stepped on a main steam isolation valve
limitswitch when working overhead that resulted in a reactor trip and safety injection.
In response to this event, licensee management
issued a shift order to the crews
describing the event and directing operators to brief maintenance personnel on sensitive
equipment areas while working overhead.
In addition, licensee management issued a
memorandum to all employees that discussed the event and the need to exercise
vigilance in ensuring that care is taken not to disturb equipment while working in the
plant. The inspectors considered the licensee actions appropriate.
Conclusions
Maintenance personnel did not exercise appropriate care during penetration seal work
and stepped on a valve handwheel.
This challenged operators by causing a leak in the
chemical and volume control system.
Operator response to decreasing volume control
tank level was timely and thorough.
)
-13-
03
Operations Procedures and Documentation
03.1
idloo
Abnormal 0 era in
rocedures
a.
Ins
c ion Sco
71707)
The inspectors evaluated the licensee's response to Action Request A0451605, which
identified an inadequate pressure rating of the reactor vessel refueling level indicating
system.
b.
Observ
io s and Find'n
s
In 1993, the licensee upgraded their strategies for responding to abnormal events during
shutdown conditions.
This item was done with the help of the vendor. These strategies
were incorporated into Procedure OP AP SD-O,."Loss of, or Inadequate Decay Heat
Removal," Revision 3.
New strategies for combating casualties during shutdown and midloop operations
included the use of natural circulation cooling and reflux cooling. Each of these methods
required pressurizing the reactor coolant system to up to 400 psig and rejecting heat
through the secondary side of the steam generators.
However, on January 23, 1998, during simulator training in preparation for midloop
operations, the licensee noted that the reactor vessel refueling level indication system,
predominantly constructed from tygon and nylobraid tubing, was designed for a normal
operating pressure of 57 psig. The burst pressure of the reactor vessel refueling level
indicating system was 150 psig for temperatures
expected to be encountered during
these abnormal procedures.
Therefore, although Procedure OP AP SD-0 directed the
operators to pressurize the reactor coolant system to 400 psig in the event of a loss of
decay heat removal, the reactor vessel refueling level indication system was not
designed nor qualified for this pressure.
This condition existed for both Units 1 and 2,
and was of immediate concern for Unit 2 because of the forthcoming refueling outage.
The licensee initiated Action Request A0451605 to enter this item into the corrective
action system.
The licensee evaluated several options to address this condition. Options that were
initiallyconsidered included allowing the system to rupture and making up with safety
injection or entering containment and isolating the level indication system following a
loss of decay heat removal. The licensee determined that these solutions were
undesirable because each involved a loss of level indication during midloop operations
and would further complicate an event.
The licensee chose to upgrade the system to
withstand pressures
of up'to 250 psig by replacing the tubing with stainless steel and
installing valves with a high pressure rating. To accomplish this task, the licensee
initiated Design Change Package DCP J-50422 to upgrade the system.
In addition,
Procedure OP AP SD-0 was revised to limitpressurization of the reactor coolant system
t
-14-
to 250 psig. This modification was completed on February 17, and the system was
placed in service for midloop operations on February 19. The inspectors noted that the
upgraded reactor vessel refueling level indicated system performed satisfactorily during
both entries into midloop operations for Unit 2.
The inspectors noted that the apparent cause of this issue was the failure of operations
. procedure preparers and reviewers to recognize that the reactor vessel refueling level
indication system was not qualified for the pressures
specified in the proposed
strategies for mitigation of a loss of decay heat removal.
Both the preparer and the
reviewer of Procedure OP AP SD-0 were operations personnel that were not
knowledgeable of the system's design basis.
The licensee's quality assurance
plan only
required the licensee to make a determination ifa cross-disciplinary review was required
for any new procedures.
The licensee determined that such a review was not required
for Procedure OP AP SD-0. Therefore, Procedure OP AP SD-05 was not reviewed by
design or system engineers to ensure that the systems affected by the new procedure
were designed to withstand the referenced conditions.
This condition existed for
approximately 4 years and encompassed
several refueling outages for both units when
the conditions that could potentially use Procedure OP AP SD-0 were in place. This
issue was mitigated by the fact that a safety injection pump was available during
midloop operations and could have adequately made up coolant inventory to the core in
the event of a reactor vessel refueling level indication system rupture.
The inspectors reviewed the proposed corrective actions for AR A0451605 and noted
'hat
these actions included upgrading the reactor vessel refueling level indication
r
system, revising procedures and drawings to reflect the modification, and performing a
maintenance preventable functional failure evaluation.
These corrective actions were
proposed by February 27. At the end of the inspection period (Nlarch 28), no further
corrective actions were proposed.
Based on the above discussion of the apparent cause of the problem, the inspectors
concluded that corrective actions did not address the failure of the procedure
preparation and approval process to identify the need to upgrade the reactor vessel
refueling level indication system or the need to choose another mitigation strategy.
Because of the incompleteness
of the corrective actions, the exercise of discretion was
not considered warranted.
The failure to properly translate the design of the reactor vessel refueling level indication
system into Procedure AP SD-0 is a violation of 10 CFR Part 50, Appendix B, Criterion
III (50-275;323/9800?-05).
Conclusions
A violation was identified for failure to translate the design of the reactor vessel refueling
level indication system into abnormal operating procedures.
The licensee exhibited
good attention to detail in identifying this issue during simulator training. Corrective
actions for this violation failed to address deficiencies in the procedure preparation and
l
-15-
approval process.
05
Operator Training and Qualification
05.1
Uni 2 Ou
e Traini
s eci
Sco
e 7 707
The inspectors observed training in preparation for the shutdown and anticipated hot
midloop evolutions.
Observa ions
nd
indin s
From February 10 to 13, 1998, the inspectors observed both classroom training for the
Unit 2 shutdown and hot drain down to midloop evolutions. This training included both
classroom and simulator scenario sessions for the two expanded crews that were
anticipated to perform these evolutions.
System engineers that would be performing
tests during the evolutions were involved in order to anticipate any impact on plant
activities that the tests might have.
The inspectors noted valuable lessons learned and
procedural changes that were identified during the training and that, in particular, the
simulator training was professional and well executed.
The licensed operators and shift
engineers viewed their training to be valuable and would ensure successful performance
of the planned shutdown evolutions. The inspectors noted the actual observed
evolutions 'were implemented without major incident. The inspectors also determined
that the involvement of the test engineers with the crew training was a valuable
contribution to the outage and was an improvement over the training provided in the
past.
Evidence of the value of this training was exhibited by the identification that the
reactor vessel refueling level indication system was not designed for pressures
required
in the abnormal operating procedures.
Co cusions
The training provided for Unit 2 outage preparation was implemented well and provided
valuable lessons learned and necessary
procedural changes.
The inspectors noted, in
particular, that the simulator training was professional, well executed, and identified a
vulnerability in the abnormal operating procedures.
II. Maintenance
M1
Conduct of Nlaintenance
M1.1
Main enance Observa ions
a.
Ins ec ion Sco
e 62707
The inspectors observed portions of the following work activities:
b
-16-
MP M-7.53, Reactor Coolant Pump Motor Ten (10) Year Inspection for Reactor
Coolant Pump 2-1
. Replace Flow Element FE-974 in the Safety Injection to Loop 1 Cold Leg, Work
Order C0153639
Replace Flow Element FE-975 in the Safety Injection to Loop 2 Cold Leg, Work
Order C0153640
Replace Existing Grating at Residual Heat Removal Sump for 2R8, Work
Order C0154660
Install Ground Buggy in Cubicle for Component Cooling Water Pump 1-1.,
MP E-7.11B, Revision 17, for Clearance CL 00057211,
Preventative Maintenance on Auxiliary Feedwater Pump 1-2, Work
Orders R0161465 and R0170439
Remove and Replace Valve FW-2-1 83, Work Order C0144622
Remove and Replace Gasket on Piping Flange Downstream of Containment
Spray Pump 1-2 Vent Valve CS-1-24,
Work Order C0156657.
Sample Containment Spray Pump 1-2 Pump Bearing Oil, Work Order R0178536
Sample Containment Spray Pump 1-2 Motor Bearing Oil, Work Order R0170178
Perform Motor Preventative Maintenance on Containment Spray Pump 1-2,
Work Order R0162541
b.
Ob e
a ions and Findin s
On March 2, the inspectors observed portions of the 10-year inspection of the reactor
coolant Pump 2-1 motor. The technicians had the work package at the job site and
were performing the steps as written. The torque wrench used was calibrated and had
the proper range as specified in the procedure.
An alternating pattern was used to
tighten the bolts, performing three passes with increasing torque values.
The inspectors observed the replacement of Flow Elements FE-974 and -975 in the
safety injection lines to the Loop 1 and Loop 2 cold legs. A radiological catch bag, tube
and bottle were setup on each line to contain the contaminated water released when the
flanges were unbolted. This arrangement was effective in controlling the spread of
contamination.
Scaffolding to support the work was properly erected and had the
required inspection tags attached.
A nuclear quality services inspector was observed
verifying the gasket, all-thread, nuts, bolts, lubricant and new orifice plates were as
specified in the work package.
The nuclear quality services inspector also verified the
~
~
-17-
orientation of the new orifice plate was correct for the direction of flow and matched the
orientation of the old orifice plate.
The inspectors observed the modiTications made to the Unit 2 residual heat removal
containment recirculation sump and inspected the final configuration after the new
screens were installed.
Cutting, grinding, and welding on the structure were properly
controlled, with the required posting of permits for open flame and combustibles, and fire
watches in place.
The modifications appeared to be effective in closing all the paths for
small debris to enter the sump.
New flashing installed around the grating was effective
in closing the gaps between the grating and the sump housing.
The design change is
described in Section E2.1 of this repo'rt. During the inspection of the inside of the sump,
the inspectors noted no debris or peeling paint inside, the condition of the sump housing
appeared sound, with sufficient structural support, a secondary internal screen that
covered the inlets to the suction piping, and no visible unscreened
path into the sump.
On March 3, the inspectors observed the installation of a ground buggy in the cubicle for
component cooling water Pump 1-1 for maintenance.
The maintenance personnel
installing the ground buggy were knowledgeable of the equipment, and the correct
method and indications of proper alignment of the buggy in the cubicle. They were
aware of the required safety precautions,
using flash suits, ensuring all unnecessary
personnel were out of the room, ensuring the doors were posted to prevent entry, and
using a voltage tester to confirm the load side of the breaker cubicle was deenergized.
They inspected the ground buggy to verify correct configuration and current rating. An
operator was also present to verify the correct breaker cubicle, correct ground buggy
configuration (line side or load side), and correct current rating. Both the operator and
the maintenance personnel had their procedures at the job site and used them. The
ground buggy was installed without difficulty.
The inspectors observed the removal and replacement of flanged butterfly
Valve FW-2-183, auxiliary feedwater Pump 2-3 suction isolation valve. The alignment of
the auxiliary feedwater pump to its motor was monitored during the loosening of the
bolts and removal of the valve to ensure the suction pipe was not exerting excessive
load on the pump suction. The alignment was rechecked following installation of the
new valve. The maintenance personnel had the procedure at the job site and used it
correctly. The torque wrench was within its calibration. The clearance for the work,
C0144622, was verified by the inspector to be hung and to adequately protect the
equipment and personnel.
On March 19, the inspectors observe performance of routine maintenance
on
containment spray Pump 1-2 by technical maintenance and mechanical maintenance.
This work included obtaining samples of motor bearing oil and pump bearing oil,
replacing a gasket on a pipe flange downstream of the pump vent valve, and routine
cleaning, inspecting, and testing of the motor leads and junction boxes.
A radiation
protection technician assisted
a mechanic in removing and replacing the pipe flange
A catch bag, tubing, and bottle were erected prior to opening the flange to
contain any liquid. Good radiological practices were used to survey the parts and
0
-18-
equipment and to minimize the contamination released by the work. The survey
equipment and torque wrench were inspected arid found to be within calibration. The
new gasket material was verified to match that specified in the work package.
The
flange bolts were observed to be torqued to the value specified in
Procedure MP M-54.1.
The oil samples were obtained as specified in Procedure MP M-56.7, "Lubricant
Sampling." The oils used to refill the bearings were verified to agree with the lubricant
charts contained in Procedures
MP M-56.24 and E-56.1, and to agree with the
nameplates
mounted on the containment spray pump. The electricians cleaning and
inspecting the motor leads and junction boxes were thorough, and checked the torque
on the bolted connections using a torque wrench of the proper range and within its
calibration frequency.
One bolt that appeared to be corroded was removed, cleaned,
inspected, and reinstalled after its condition was determined to be acceptable.
The
clearance for this work, CL0057967, was reviewed and found to be adequate to protect
the work and each tag was hung in the correct location.
c.
Conclusions
A number of maintenance activities were observed and were performed in accordance
with the procedural requirements.
Good coordination between technical maintenance,
mechanical maintenance and radiation protection was observed in performing several,
maintenance tasks concurrently on the containment spray pump; thereby reducing the
time the pump was inoperable due to maintenance.
M1.2
S
eillance Observ
io s
s ec ion Sco
e
172
Selected surveillance tests required to be performed by the Technical Specifications
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 Technical Specifications; and (4) test results
satisfied acceptance
criteria or were properly dispositioned.
The inspectors observed all or portions of the following surveillances:
STP M-13F
4KV Bus F Non-Sl Auto -Transfer Test, Revision 22
STP M-15
Integrated Test of Engineered Safeguards
and Diesel Generators,
Revision 29
STP R-6
Low Power Reload Physics Tests,
Revision 7
STP R-30
Reload Cycle Initial Criticality, Revision 12
-19-
STP R-31
Rod Worth Measurements
Using the Rod Swap Method,
Revision 8
STP M-120
Firewater Availabilityto Centrifugal Charging Pump Coolers,
Revision 2
The inspectors also reviewed the results of the following surveillances:
STP R-17
Estimated Critical Position;
Revision 12A
STP G-8C
'perational Checkout of the Reactivity Computer, Revision 7
STP R-7A
Determination of Moderator Temperature Coefficient, Revision 10
b.
Observa ions and Findin s
On February 24, the inspectors observed the performance of surveillance test procedure
(STP) STP M-120, "Firewater Availabilityto Centrifugal Charging Pump Coolers,"
Revision 2, on the Unit 1 centrifugal charging pumps.
This test demonstrated
the ability
to flow cooling water through the hoses and manifold to provide. cooling to either
centrifugal charging pump using firewater. Firewater would be used in the event
component cooling water was lost to both centrifugal charging pumps.
The operators
had the procedure and signed offthe steps as they were performed.
Allof the hoses,
fittings and manifold worked as design with no observable leakage.
The test adequately
demonstrated that the equipment could be properly installed and would provide cooling
'ater
to the centrifugal charging pump cooling piping. The operators performed self
checking and independent verifications, by verifying the valve numbers on the tags
matched the procedure prior to operating the valves.
The operators were careful to
cleanup the small amount of water that spilled during the disconnection of the hoses.
On March 15, the inspectors observed the pretest briefing and performance of
surveillance test procedure STP M-13F, "4KVBus F Non-Sl Auto-Transfer Test." The
pretest briefing was comprehensive,
covering precautions and limitations, prerequisites,
communications and responsibilities, major test evolutions, and expected results.
The
performance of the test was well coordinated, with clear communications between the
test personnel and control operators, including 3-part communications.
During the test,
all equipment operated as expected and the test results satisfied the acceptance
criteria.
On March 17, the inspectors observed the pretest briefing and performance of
surveillance test procedure STP M-15, "Integrated Test of Engineered Safeguards
and
Diesel Generators."
The pretest briefing was comprehensive,
covering precautions and
limitations, prerequisites, communications and responsibilities, major test evolutions,
and expected results.
Several other surveillance requirements were satisfied
concurrently with this test, including STP V-11, "Containment Isolation Phase
B
0
-20-
Valves FCV-355, FCV-356, FCV-357, FCV-363, FCV-749, and FCV-750." The
inspectors observed good communications and coordination between test participants,
which was necessary to capture the starting time of the many different pumps and fans,
and to coordinate the recording of data from control board meters. During the test, the
newly installed load tap changer for the startup transformer was used per the operations
procedure to transfer the vital buses from startup to auxiliary power.
On March 24, the inspectors observed the preparations for and achievement of initial
criticality and performance of low power physics testing. A pretask briefing was
performed by the shift foreman and reactor engineer.
Management oversight was
provided during the briefing and evolution by the engineering services manager.
The
briefing covered responsibilities and communications, Technical Specification
requirements,
including the special test exceptions and related surveillances,
precautions and limitations, prerequisites,
and brief description of the physics tests.
The
prerequisites were verified by the inspectors.
Operations limited other plant activities
that could cause distractions to the control room or unnecessary
alarms during the
physics testing.
Communications between the reactor engineers and the control operators were clear
with 3-part communications consistently used.
The reactor engineers were
knowledgeable of the test requirements and test equipment.
They continually evaluated
the data against expected results and made conservative decisions in implementing the
procedures.
The approach to criticalitywas performed slowly and cautiously, with
criticality achieved well within the allowed deviation from the estimated critical
conditions.
The control operators maintained the plant stable to ensure good data for
the reactor physics tests.
The test results met both the acceptance
criteria and review
criteria.
Conclusions
The inspectors observed a number of surveillance tests and found that the surveillances
observed were performed in a cautious manner with self-checking and proper
communications employed.
The procedures governing the surveillance tests were
technically adequate and personnel performing the surveillances demonstrated
an
adequate
level of knowledge.
The inspectors noted that test results appeared to have
been appropriately dispositioned.
M1.3
Con ainment In
e
ion Prior
Close
u for Con ainment In e
ri
lns ection Sco
e
6 707
The inspectors toured containment during the period when containment work activities
were finishing and efforts to clean up in preparation for containment closure were in
progress.
-21-
Observa 'ons and Findin s
The cleanup effort was well organized with coordination between completion of the final.
work activities, surveying and decontamination of radiologically controlled areas,
removal of equipment, tools, and supplies, as well as cleaning to meet housekeeping
standards occurring simultaneously.
Loose insulation buckles had been a concern in
the previous outage and were addressed
early in the cleanup schedule.
The inspectors
found no unfastened,
broken or missing insulation buckles during their tour. The reactor
coolant pump oil collection system was inspected and found to be properly assembled.
The various sections were bolted or fastened into place.
The joints between the
sections were sealed with approved sealant.
The oil collection tank was inspected and
found to be clean and empty of oil. The inspectors noted several small bolts and nuts
and other debris.
These were identified to the licensee and removed.
The inside of
several mechanical panels were inspected and found to be in good materiel condition
with no housekeeping
problems.
Radiologically contaminated material was properly
separated from noncontaminated
material and appropriately labeled and posted.
Conclusions
The containment cleanup and closeout activities were appropriately controlled, and the
material condition of containment areas was satisfactory for restart of Unit 2.
Maintenance and Materiel Condition of Facilities and Equipment
eview of Pa
Len th Control Rod Drive Mechanis
s Transi ion Weld
Unit 2
Ins ection Sco
e 62707
The inspectors reviewed the ultrasonic examination of the transition welds on the part
length control rod dive mechanisms to find ifthe same problem found at Prairie Island
Unit 2 existed at Diablo Canyon.
Observa ions and Findin s
Prairie Island Unit 2 shut down on January 24, 1998, because of reactor coolant system
The licensee estimated the leak rate to be 0.2 gallons per
minute as measured
by mass balance calculations and radiation monitors.
On
February
27, 1998, Northern States Power reported to the NRC that one of four part
length control rod drive mechanisms,
G-9, had a leak in the lower transition weld of the
motor tube.
The part length control rod drive mechanism had, by design, a section of the pressure
boundary motor tube made of 403 stainless steel.
This design by the vendor allowed
motor coils to be located outside the pressure boundary because
magnetic fields can
penetrate 403 stainless steel.
The rest of the motor tube assembly consisted of 304
~
~
-22-
stainless steel.
To weld the two different stainless steels together, the manufacturer
layered or buttered the 403 stainless with 309 stainless steel. A final weld consisted of-
308 stainless steel and, normally, the stator shroud assembly covered these welds
during operation.
At Prairie Island, the G-9 motor tube had a manufacturing defect in
the buttering weld. The manufacturing defect was a circumferential crack with a high
temperature oxide layer and no evidence of operational extension.
The crack was
almost 360 degrees,
initiated on the inside diameter and opened to the outside diameter
for about /~ inch. Northern States Power concluded that this was a hot crack induced
during manufacturing welding with no sign of propagation during service.
Diablo Canyon had eight part length control rod drive mechanisms and was similar to
Prairie Island. The licensee modified one part length control rod drive mechanism at
Diablo Canyon to be a head vent. The vendor ultrasonically inspected the remaining
seven for the Diablo Canyon licensee.
The vendor completed a hot cell inspection of
G-9 plus other motor tubes from Prairie Island and used the same basic technique at
Diablo Canyon.
Diablo Canyon motor tubes contained the same heat of buttering
material as G-9. One motor tube (M-6) had been weld repaired during manufacturing
similar to the manufacturer repair of G-9. Just as the Prairie Island motor tubes, Diablo
Canyon welds were both penetrant and radiographically tested after buttering and also
final welding.
The ultrasonic testing of seven of the eight motor tubes done by the vendor was a
remote automated inspection with a customized clamp and track for the search unit and
bubbler to supply the water couplant.'he vendor did a '/~ vee inspection with a 1/4
inch, 4 MHZsearch unit using a 45 degree refracted longitudinal wave for the lower
transition weld where the thickness was approximately .400 inches.
A 45 degree
2.25 MHZ, shear wave inspection done on the lower transition weld was not as
informative as the 45 degree refracted longitudinal wave inspection.
The upper weld
where the thickness was approximately .490 inches, used a 60 degree, refracted
longitudinal wave. The technique and personnel were Electric Power Research
Institute
(EPRI) qualified for intergranular stress corrosion cracking ultrasonic testing, and were
in accordance with Procedure DC-800-001, and Field Change Notice Number 1. Also
the technique and equipment was reported to have been used for the "Performance
Demonstration Initiative."
The vendor calibrated the system on two mockups of the motor tube as calibration
blocks, one for the lower transition weld and one for the upper transition weld. Each
calibration block had 0.030 notches on the inside diameter placed at the location of the
buttering weld. These notches gave some measure of the minimum detection limitof
thesystem.
The vendorusedA,
B, and C-scandisplaystoanalyze
theresults.
The
scans showed low intensity noise reflectors from the grain structure of the weld metal,
but did not show any reflectors like that found in G-9.
The inspectors reviewed all the ultrasonic data collected on the lower and upper
transition welds of the seven motor tubes inspected and the manufacturing records.
The inspectors reviewed the calibration records of the lower transition welds. The
-23-
inspectors witnessed the calibration and inspection of four upper transition welds. The
tapered geometry and an outside diameter offset (.010 inches) on the motor tube in the
areas in question presented technique challenges.
The inspectors verified the
inspection of the areas in question.
The calibration notches of 0.30 inches were
discernable and the inspectors found no apparent defects.
Conclusio
s
The license's approach to the inspection of part length control rod welds was sound and
aggressive. The inspectors found the ultrasonic testing showed the seven motor
tubes'pper
and lower transition welds were free of the same kind of defect found at Prairie
Island on the G-9 motor tube.
M4
Maintenance Staff Knowledge and Performance
M4.1
Grou d'Bu
s alla ion Unit 2
The inspectors reviewed the circumstances
surrounding a failed attempt to install a
ground buggy in safety-related 4160 vac Cubicle 52HG5.
b.
erva ions and Find'n s
On February 24, 1998, two contract technicians attempted to install a ground buggy on
the deenergized
line side of a diesel generator load in safety-related 4160 vac
Cubicle 52HG5 in Unit 2 in accordance with Procedure MP E-57.11B, "Protective
Grounding," Revision 17. The bus side of Cubicle 52HG5 remained energized with
4160 vac to provide power to other loads.
Unit 2 was defueled at the time. When the
technicians installed the ground buggy, they inserted the buggy into the cubicle until it
was mechanically stopped.
However, the buggy was hitting an obstruction and was not
fullyinserted into the cubicle.
The technicians began raising the ground buggy to mate with the cubicle line side stabs,
however, because the ground buggy was not fully installed, it began to tiltforward. The
technicians attempted to stop the elevator motor, which continued to run. The
technicians then pulled the power plug to the motor, stopping the lift.
The ground buggy was found to have partially raised and tilted forward, opening the
switchgear shutters and exposing the cubicle bussing.
Because of the forward tilt of the
buggy, the ground buggy stabs were almost touching the energized bus side stabs,
which would have hard grounded the energized 4160 vac bus, challenged switchgear
protective devices, and could have caused significant damage to the switchgear and
injury to the technicians.
The licensee successfully lowered the ground buggy from its
improper position, and after inspection of the cubicle, installed another ground buggy.
-24;
The licensee found that the wheel runners on the original ground buggy were
misaligned, which allowed the buggy to jam inside the cubicle prior to being fully
inserted.
The licensee issued instructions to inspect and repair all 4160 vac ground
buggies for alignment and added this instruction to preventative maintenance
requirements for the ground buggies.
The inspectors noted that Procedure MP E-57.11B and other associated
licensee
procedures did not provide any instructions on how to rack in ground buggies or how to
verify proper installation prior to lifting. Licensee personnel stated that detailed ground
buggy installation instructions had been provided after a ground buggy error in 1995
= caused failure of the Unit 1 AuxiliaryTransformer 1-1, as discussed
in Inspection
Report 50-275; 323/95-017.
Subsequent
to that time, specific instructions for,ground
buggy installation had been removed from Procedure MP E-57.11B, because the
installation was considered by the licensee to be within the skill of the craft.
However, the inspectors noted that the improper installation was accomplished by
contract personnel.
The licensee stated that the two contract technicians were qualified
by licensee training procedures to install ground buggies.
The licensee provided the
training records to the inspectors.
The inspectors noted that these two contract
employees had been certified as having the required training during previous outages
and had received no additional training for this outage.
The licensee stated that the site
program for training of personnel for craft work, including ground bug'gy installation, did
not require periodic retraining for permanent or contract personnel.
In addition, the
licensee's craft procedures did not require that permanent personnel accompany
contract personnel during performance of any work the contract personnel were
qualified for.
The licensee issued additional instructions for installing ground buggies.
The inspectors
questioned whether it was appropriate to give contract personnel, who may have
recently worked at other sites with different hardware, permanent qualification for Diablo
Canyon.
The licensee's evaluation of the event, Quality Evaluation Q0012011, stated
that the corrective action for the installation problem would include a review of the
policy for permanent qualification of contract personnel.
This review willidentify specific
qualifications that willrequire remediation of contractor qualifications prior to performing
the task, based on criteria such as safety significance and frequency of prior use.
The
inspectors considered that the licensee's corrective actions were adequate.
The inspectors considered that Procedure MP E-57.11B was not appropriate to the
circumstance in that the licensee allowed permanent qualification of contract personnel,
allowed these contract personnel to work on safety-related equipment without
supervision, and these contract personnel did not have the necessary
successfully complete the work.
The inspectors reviewed the licensee's corrective actions for previous violations for
failure of maintenance
and operations personnel to follow procedures for removal of a
ground buggy in 1995, as discussed
in NRC Inspection Report 50-275; 323/95-017.
~
4
-25-
The inspectors considered that the February 24, 1998, installation problem did not result
from inadequate corrective actions for the previous violations.
In the February 1998
error, both operations and maintenance personnel had followed licensee procedures.
In addition, the inspectors considered none of the previous violations concerned
inadequate procedures or craft skills.
Therefore, since the improper installation of the ground buggy did not result from
inadequate corrective actions from previous violations, this self-revealing and corrected
violation is being treated as a noncited violation, consistent with Section VII.B.1 of the
NRC Enforcement Policy (50-323/98007-06).
Conclusions
A noncited violation was identified for failure to provide a procedure appropriate to the
circumstances for ground buggy installation. The improper ground buggy installation
had the potential to have caused significant damage to safety-related equipment and
injure workers.
Miscellaneous maintenance
Issues
0 en Viola ion 50-27
323/96014-03
failure to remove action request tags from the
control boards.
This violation involved five examples of failure to remove stickers from
the control boards following correction of the deficiencies.
The root cause of this
violation was that no formal program existed to control these action request stickers.
As
corrective action, the licensee: (1) performed an audit of both Units 1 and 2 control
boards to ensure that all control board action request stickers were in place and those
that were resolved had been removed, (2) reprogrammed the plant's computer work
management system such that the status of installation and removal of the control board
action request stickers was tracked and such that the work order could not be closed out
without removal of the stickers, (3) revised procedures for controlling control room action
request stickers to clarify management's
expectations,
and (4) issued a memorandum
that indicated its expectations for supervisory personnel and its intention to hold
personnel accountable.
The inspectors reviewed documentation that verified that these items were completed.
The inspectors noted that Procedure OP2.ID2 "Problem Identification and Resolution-
Action Requests" was revised to state that personnel
~ma
enter "Y" in the action
request sticker removal block in the licensee's plant computer to signify that the stickers
were removed from the control boards.
The inspectors concluded that this procedure
revision did not fullyaddress the corrective actions because
it did not appear to
proceduralize the committed actions such that personnel could be held accountable.
On March 19, 1998, the inspectors performed an audit of existing control board action
request stickers to verify the effectiveness of corrective actions.
The inspectors
identified a total of six discrepancies
between the licensee's existing list of control board
action requests and the stickers on the panels, as listed below:
-26-
The inspectors identified three control board action request stickers on the
panels that were not being tracked in the licensee's computer data base as
control board deficiencies.
The inspectors noted that the existing process in the
licensee's computer data base would remove these stickers.
The inspectors identified one control board action request sticker that was left on
the panels for completed work and was faded such that the problem described
on the stickers was illegible.
The inspectors identified that the computer status block for removal of the control
board sticker for Action Request A0437900 was changed to "Y,"despite the fact
that the sticker was still in place and the problem was not corrected.
The inspectors identified one instance in which an action request was open for a
control board action request, the work was not complete, yet the sticker was
removed.
The inspectors informed the technical maintenance foreman, who corrected the
discrepancies
in the licensee's control board action request tracking system.
The inspectors concluded that the corrective actions for Violation 50-275;323/96014-03
were specifically directed to ensuring that control board action request stickers were
removed when the work was complete, but did not appear to fullyaddress the need to
closely control these deficiency tags. The licensee's programs to ensure that the control
board action requests stickers reflected the licensee's tracking list and the up-to-date
plant configuration warranted further licensee attention. The licensee implemented the
control board action request program to inform operators of equipment that was
deficient, and with inaccuracies
in the program, the operators could be misled.
'ecause
of the additional deficiencies identified with the program,
Violation 50-275;323/96014-03 willremain open for further inspector review of licensee
improvements to the control of control board action requests.
E2
Engineering Support of Facilities and Equipment
E2.1
Residual Heat Removal Recircula ion Containment Sum
Gratin /Scree
M difica ions
a.
lns ec ion Sco
e 37551
The inspectors reviewed Design Change Package DCN N-050317, Revision 0, and the
related licensing basis impact evaluation and screens,
Final Safety Analysis Report
Update Change Request, and field changes.
The inspectors also observed the
modification work in progress and inspected the sump upon completion of the
modiTication..
Nl
4
-27-
b.
Observations a
d Findin s
As the result of the potential to pass debris through the previously installed containment
sump screen and grating that could cause blockage of flowthrough the safety injection
lines, modifications were made in refueling outage 2R8 to reduce the size of the screen
openings from 3/16 inch to 1/8 inch. This modification was made in addition to
emergency core cooling system injection line modifications (DCP N-50286) that
increased the minimum openings in the flow paths.
These modifications removed the
physical'possibility of debris entering the emergency core cooling system that could
block the throttle/runout valves in the safety injection flow paths.
The design change evaluation identified the applicable design bases and design inputs
affected by the modification. The technical review portion of the evaluation confirmed
the sump would meet its design function following implementation of the modification.
This review addressed
the impact of: performing the modification during the refueling
outage with fuel in the vessel, on routine operation, on the high energy line break study,
on pump available net positive suction head, on hydraulic design considerations,
on the
seismic interaction evaluation, on consistency with Regulatory Guide 1.82, "Sumps for
Emergency Core Cooling and Containment Spray Systems," material compatibility and
consistency with licensing documents,
in addition to other design considerations.
The 10 CFR 50.59 safety evaluation concluded that an unreviewed safety question
was'ot
involved, nor was a change to the Technical Specifications involved. The proposed
Final Safety Analysis Report Update change and revision to Design Criteria
Memorandum T-16, "Containment Function," were consistent with the modification. The
design change package was prepared
in accordance with the applicable
Procedure, CF33.ID9, "Design Change Package Development." The inspectors
identified no concerns with these reviews.
Following the completion of modification, the sump was inspected for openings in the
structure or potential flow paths that could bypass the screens.
No openings greater
than that specified in the design were found. Potential openings around piping or
supports that penetrated the sump structure were effectively closed.
Joints between
sections of grating and between the edges of the screen and the supporting structure
were effective closed by the design and installation of the modification.
c.
Conclusions
, The inspectors concluded that the design change package and associated
safety
evaluation for replacement of the Unit 2 recirculation sump screens was comprehensive,
and the conclusions were reasonable.
The design change was effective in improving
the containment sump's ability to screen out debris that could block safety injection flow
paths.
~ t
-28-
Miscellaneous Engineering Issues (92901)
E8.1
Closed
Violation 96016-06
failure to perform prompt operability assessment.
The
inspectors identified that following documentation of degraded conditions in the diesel
generator voltage regulator boards, the licensee failed to perform a prompt operability
assessment.
For corrective actions, the licensee:
(1) replaced the voltage regulator
boards, (2) established
a daily action request review team that screens each new action
request for operability issues, (3) trained nuclear technical services personnel in the
license procedures for operability assessments,
(4) revised Procedure OM7.ID12
"Prompt Operability Assessments"
to'require shift supervisor notification of all degraded
conditions, (5) briefed all shift supervisors on the responsibility for maintaining
operability, (6) issued an all employee letter emphasizing management expectations
with respect to operability assessments,
(7) initiated an engineering directors meeting to
discuss emergent issues that may have operability concerns, and (8) performed a case
study on lessons learned from the violation. The inspectors reviewed documentation
that established that these items have been completed satisfactorily. This item is
closed.
.P
R1
Radiological Protection and Chemistry Controls
R1.1
General Comments
During this inspection period, the inspectors observed radiation protection controls.
The
inspectors noted that licensee personnel followed basic radiation practices such as
proper wearing of dosimetry and observance of radiation protection boundaries.
Licensee management's
efforts to keep exposures as low as reasonably achievable
during Refueling Outage 2R8 appeared to be successful in that total outage exposure
was 147 person-rem, while the outage exposure goal was 160 person-rem. The
licensee's cleanup of the reactor coolant system following shutdown of Unit 2, and the
use of mock-up training for several outage tasks, contributed to the lower exposure.
This was an improvement over previous refueling outages.
S1
Conduct of Security and Safeguards Activities
S1.1
General Comments
71750
During routine tours, the inspectors noted that the security officers were alert at their
posts, security boundaries were being maintained properly, and screening processes
at
the Primary Access Point were performed well. During backshift inspections, the
inspectors noted that the protected area was properly illuminated, especially in areas
where temporary equipment was brought in.
0
-29-
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 April7, 1998. 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.
t
0
TT CHMENT
SUPPLEMENT
L INFORMATIO
PARTIALLIST OF PERSONS CONTACTED
Licensee
W. G. Crockett, Manager, Nuclear Quality Services
R. D. Gray, Director, Radiation Protection
T. L. Grebel, Director, Regulatory Services
S. A. Hiett, Director, Operations
D. B. Miklush, Manager, Engineering Services
J. E. Molden, Manager, Operations
Services'.
H. Oatley, Manager, Maintenance Servi'ces
R. P. Powers, Vice President and Plant Manager
L. F. Womack, Vice President, Nuclear Technical Services
INSPECTION PROCEDURES (IP) USED
IP 60710
IP 62707
IP 71750
IP 92903
Onsite Engineering
Refueling Activities
Surveillance Observations
Maintenance Observation
Plant Operations
Plant Support Activities
Followup - Maintenance
Followup - Engineering
Prompt Onsite Response to Events at Operating Power Reactors
/s
0
-2-
0~coed
ITEMS OPENED AND CLOSED
50-323/
98007-02
50-323/
98007-03
50-275;323/
98007-04
50-275;323/
98007-05
C~los
d
VIO
VIO
Failure to provide appropriate procedure for nonseismic
hoist stowage (Section 01.3)
Failure to restore high flux alarm during core reload
(Section 01.5)
Multiple failures to implement clearance procedure
(Section 01.6)
Failure to implement design of level indicating system into
abnormal procedures (Section 03.1)
50-275;323/
96016-06
Failure to perform prompt operability assessment
(Section E8.1)
ened and Closed
50-275;323/
98007-01
Failure to provide an appropriate procedure for switching
power supplies (Section 01.2)
50-27;323/
98007-06
Inadequate ground buggy installation procedure
(Section M4.1)
.
Discussed
50-275;323/
96014-03
Failure to remove action request tags from the control
boards (Section M8.1).
(
e
0
'I