ML20199B822
| ML20199B822 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 11/03/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20199B804 | List: |
| References | |
| 50-321-97-09, 50-321-97-9, 50-366-97-09, 50-366-97-9, NUDOCS 9711190107 | |
| Download: ML20199B822 (38) | |
See also: IR 05000321/1997009
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
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Docket Nos: 50 321.50-36t
Report No: 50-321/97-09, 53-366/97-09
Licensee: Southern Nuclear Operating Company, Inc. (SNC)
Facility: E. I. Hatch Units 1 & 2
Location: P. O. Box 439
Baxley, Georgia 31513
Dates- Augue.t 17 - October 4. 1997
Inspectors: B. Holbrook. Senior Resident Inspector
J. Canady, Resident Inspector
Accompanying Inspector: T. Fredette
Approved by: P. Skinner Chief. Projects Branch 2
Division of Reactor Projects
Enclosure 2
9711190107 971103
0 ADOCK 05000321
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EXECUTIVE SUMMARY. ;
I -Plant Hatch. Units 1 and 2-
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s -NRC-Inspection Report 50 321/97-09 50-366/97-09 ;
This integrated inspection includeo aspects-of licensee ' operations
engineering, maintenance, and-plant-support. The report covers a 7-week-
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_ period _of resident inspection activities.
Ooerations
Le During Unit 2 startup activities on September 18,_' operator 4
procedure usage, communications, control of activities, and
supervisory oversight during these activities were excellent.
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Equipment problems such as control rods that were difficult to I
withdraw - turbine vibration problems during turbine roll, and main
generator automatic voltage regulator problems challenged 4
operators-(Section 01.1).
e- Equipment al'gnment, component _o)erability, and material
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conditions observed-during a wal(down of the Unit 1 Standby Gas !
Treatment System were good in all areas inspected. Housekeeping
L conditions in the filter train room adjacent to Unit 1 Heating
Ventilation and Air Conditioning room were excellent
(Section 02.1).
e Unit I systems responded properly following a trip of the
1A Reactor Feed Pump Turbine (RFPT) and subsequent Reactor '
Recirculation Runback on September 6. Operator response to the
plant transient was good (Section 04.1).
. o Operations supervision failed to llow applicable procedures to
- correctly generate a-Maintenance Work Order (MWO) package for a
Reactor Manual Control system relay replacement. Operations
supervision authorized work and maintenance personnel performed
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work using the incorrectly completed work package. This was
identified as an example of Violation (VIO) 50-321, 366/97-09-01,
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Fai',ure to Follow Procedure - Multiple Examples -(Section 04.2).
e The inspectors concluded that the operating crew's performance
resulted in additional- challenges during a normal reactor manual scram. Operations management prompt actions to correct an
operating crew's weaknesses following a routine manual scram on
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-Unit 2 was good (Section 04.3).
o Operations demonstrated poor oversight and coordination of the
battery charger transfer activity. A plant equipment operator
failed to properly follow arocedures governing continuous
activities- that affected tie operability of Emergency Diesel
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-Generator 2A and 2C 125-volt direct current subsystems. This
failure to follow procedures was' identified-as an example of- >
VIO 50-321. 366/97-09-01, Failure to Follow Procedure - Multiple
Examples (Section_08.2).
tialptenance
o Routine maintenance activities were generally completed in a
thorough and professional manner. No deficiencies were identified
by the inspectors for the maintenance activities observed
(Section M1.1). ,
o Maintenance department response to the Rod Position Indicating .. '
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System (RPIS) problem on Unit I was timely 'and engineering support-
of the maintenance ac.tivity was excellent. Operator actions for
the failed RPIS were appropriate (Section M1.2).
- Maintenance and engineering support following the 1A Emergency
Diesel Generator failure to start on September 4 was excellent.
- The review of past performance and repair history for the failed
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fuel oil check valves that resulted in additional check valve
replacements. demonstrated conservative decision making by the
licensee (Section M1.3;
e- Management's oversight and pre-job planning for the forced outage
on the Unit 1 main steam isolation valve limit switch adjustment
was good. Craft personnel performed the work activity in a
professional and timely manner. Health Physics personnel
demonstrated a pro-active attitude by identifying the Low Pressure
Coolant Injection check valve leak and notifying maintenance
(Section M1.4).
e Maintenance personnel's attention-to-detail during a walkdown
which discovered broken 31eces of the Unit 2 High Pressure Coolant
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Injection (HPCI) flange Jushing was superior. Engineering support
of maintenance was excellent. Foreign Material Exclusion control
measures were satisfactory (Section M2.1).
e- Maintenance and engineering oversight of the intake structure
dredging activities was excellent. Foreign material exclusion and'
security control measures were appropriate. Communications and
departmental-coordination was good (Section M2.2).
e For the surveillances observed all-data met the recuired
acceptance criteria-and the equipment performed sat";factorily,
i The-performance of the personnel conducting the surveillances was
generally professional and-competent (Section M3.1).
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e The American Society of Mechanical Engineers (ASME)Section XI
code requirements for visual inspections were met for the strap
welding on the Unit 2 Safety Relief Valves. A procedurally
required VT-1 inspection was not com)leted following work on the B
fecdwater check valve hinge pin for Jnit 2. This was identified
as an example of VIO 50-321, 366/97-09-01. Failure to Follow
Procedure - Multiple Examples (Section M3.2).
e The licensee had taken appropriate actions to correct the TIP
System ASME code. Class 2 issues. The GE Code requirements of the
TIP equipment installed were equivalent to those of the ASME Code.
The proposed UFSAR revision was appropriate (Section M3.3).
e The inspectors concluded that Safety Audit and Engineering Review
(SAER) audit 97-SA-3. Technical Specification Administrative
Control Implementation, was conducted by trained and qualified
personnel. The audit was thorough and detailed. The corrective
actions and proposed completion dates were appropriate for the
findings (Section M7.1).
Enaineerina
e The inspectors concluded that the licensee was making progress in
resolving the divisional cable separation issues for both units
(Section E1.1).
e The inspectors concluded that new fuel receipt. inspection, and
storage were completed with appropriate oversight and control, and
in accordance with applicable plant procedures. Engineering.
Health Physics. and security personnel support for the activity
was satisfactory (Section E4.1).
Plant Supoort
e The inspectors concluded that a contract Health Physics
technician who left the plant site after receiving an alarm on the
exit portal monitor presented minimal safety significance to the
individual or to the public. The actions taken by the licensee
were a)propriate and no further NRC actions are planned. Based
upon t1e fact that the individual is no longer employed at the
site and site access was immediately terminated (Section R1.2).
e Management personnel had placed special emphasis for improved
Health Physics and general radiation worker activities. The stop
work meetino, plant tours for new contractors, and radiation
worker ex]ectations list were identified as a strength
(Section R1.3).
Enclosure 2
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e Overall performance during the annual emergency preparedness
exercise was good. Event classifications during the exercise were
correct. Operator performance in the simulator and overall
performance in the operations support center was excellent
(Section P4.1).
e The areas of security inspected met the applicable requirements
(Section S2).
Enclosure 2
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ReDort Details
Summary of Plant Status
Unit 1 began the report period at 100% Rated Thermal Power (RTP). End-
of-cycle coast down began on September 2, On September 6. the 1A
reactor feedwater pump turbine tripped during a weekly turbine test and
resulted in a power reduction to 66% RTP. The unit was returned to
98% RTP. the maximum achievable povci , the same day. Power was reduced
on September 15 to remove the 1A feedwater pump from service due to a
oil cooler leak. The unit was increased to the maximum achievable coast
down power on September 17. Later on September 17, power was reduced
slightly to verify turbine control valve functions. Power was returned
to maximum rated the same day. The unit remained in coast down for the
remainder of the report period except for routine testing activities.
Unit 2 began the report period at 100% RTP. On September 15. power w s
reduced to approximately 75% RTP for main steam isolation valve (MSIV)
testing and was subsequently brounht to Hot Shutdown due to MSIV limit
switch problems. Unit startup began on September 18. and reached 100%
RTP on September 22. The unit operated at this power level for the
remainder of the report period, except for routine testing activities.
I. ODerations
01 Conduct of Operations
01.1 General Comments (71707)
The inspectors conducted frequent reviews of ongoing plant
operations. In general, the conduct of operations was
professional and safety-conscious: specific events and
observations are detailed in the section below. In particular, the
inspectors observed that during the Unit 2 startup activities on
September 18. equipment problems such as control rods that were
difficult to withdraw, turbine vibration problems during turbine
roll, and main generator automatic voltage regulator problems
challenged operators. Operator procedure usage, communications,
control of activities, and supervisory oversight during these
activities was excellent.
Enclosure 2
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02- (Operational Status of Facility _and Equipment- !
02.1- Enaineered Safety Feature (ESF) System Walkdown -
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a. Insoection Scoce (71707)
Thel ins)ectors-performed an inspection of the accessible portions
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of the Jnit I standby gas treatment (SBGT) system. This-included-
verification of valve alignment, instrumentation, condition of -
-components in service, and general housekeeping for both trains of
the system,
b. Observations and Findinos
-The inspectors reviewed applicable Piping and Instrumentation
Diagrams (P& ids) and filter train operability verification
procedures in use for the Unit 1 SBGT system. System control
switches, valves and dampers were verified to be in the correct
positions. Proper operation of control room flow recorders and
indications were confirmed following routine atmospheric venting
of the primary containment using the "A" SBGT filter train,
c. Conclusions
Equipment alignment, component opertbility, and material condition
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were good in all-areas inspected. _ Housekeeping conditions in the
filter train room adjacent to Unit 1 Heating Ventilation and Air
Conditioning room were excellent.
04.0 Operator Knowledge and Performance
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04.1 1A Reactor Feedoumo Turbine (RFPT) Trio Durina Routine Turbine
Testina
a. Inspection 5 ooe (71707) (92901)
- The insSectors reviewed procedure 34IT-N21-003-1S, "RFPT Weekly
Test". Revision (Rev.) 4. and operator performance and plant-
response following a 1A RFPT trip on September 6.
b. Observations and Findinos
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Licensee management-had deferred routine RFPT_ testing during hot
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- weather conditions and times of peak load demand. 0n' September 6.
the 1A RFPT trip. test was scheduled. This was one of the first
weekly turbine tests performed following resumption of the-RFPT
testing. While performing section 7.3. "RFPT 011 Trip Test " the
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operator stated that when he released the Overs)eed Trip Test
Lockout Switch, the RFPT immediately tripped. Other than the RFPT
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trip. there were no indications of abnormal system resp
RFPf trip caused a Reactor Recirculation Systa runbac . (onse.
The inspectors reviewed plant data and discussed the RFPT trip
with operations and management personnel. The inspectors observed
that all systems responded correctly. The Reactor water level
decreased to about 15 inches and a Reactor Recirculation System
Runback occurred as expected. Reactor power stabilized at about
66% Rated Thermal Power (RTP). The region of potential
instability of the power to flow map was never entered.
Operations personnel discussed the pump trip and later
successfully completed the turbine testing on the 1A and 1B RFPT.
During subsequent testing. the operators did not release the
Overspeed Trip Test Lockout Switch until a few seconds had passed
after receiving the green reset permissive light. Operations
personnel told the inspectors that they believe that holding the
Overspeed Trip Test Lockout Switch depressed for a few seconds
longer may have prevented the initial trip. Reactor power was
increased to maximum rated within about 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> following the
RFPT trip and subsequent testing.
The licensee initiated a review of the procedure and system
response to determine if possible procedure problems existed or if
improvements could be made to ensure that no future RFPi trips
occurred. A temporary change to clarify some procedure steps for
both units was completed. The licensee concluded that the root
cause of the RFPT trip was mechanical linkage not being in the
proper position when the overspeed lockout switch was released.
The procedure revision addressed this problem.
The inspectors observed that the testing procedure had been used
numerous times in the past and no known previous problem or RFPT
trips had been identified. The inspectors reviewed the procedure
in detail and walked through the procedure at the local panels to
ensure switch nomenclature and procedure wording were clear. No
procedure deficiencies were observea.
c. Conclusions
Unit 1 systems responded properly following the tri) of the
1A RFPT and subsequent Reactor Recirculation Runbacc on
September 6. Operator response to the trip and runback'was good.
Enclosure 2
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04.2 Unit 1 Reactor Manual Control System (RMCS) Relay ReDlacement
a. Insoection Scoce (71707) (62707)
On August 15. Operations supervision prepared a maintenance work
order (MWO) for the re)lacement of a failed relay associated with
the RMCS on Unit 1. T1e MWO was provided to maintenance personnel
as guidance for component replacement. The inspectors reviewed
applicable procedures and otler documentation associated with the
work activity,
b. Observationsandfindinas
On August 15, while performing surveillance procedure
34SV-C11-003-IS. " Control Rod Weekly Exercise." Rev. 10. Edition
(ED) 1. the control rods in row 34 could be selected but would not
actuate the RMCS for manual insertion. Troubleshooting activities
by maintenance personnel revealed that relay 1C11-K033 had failed
and required replacement.
Operations supervision on shift 3repared MWO 1-97-1979 and grantec
approval for the maintenance tec1nician to replace the relay. Tht
MWO prepared and approved was not properly completed. The MWO dic
not'have any work instructions or procedural references, and other
items of importance were not indicated. The inspectors reviewed
the MWO that was used by the maintenance technician and observed
that the technician documented the work performed on the MWO. The
technician documented that the K033 relay was defective, had been
replaced with a new one, and the RMCS operated satisfactorily.
A later review by maintenance personnel identified several
discrepancies with the MWO and initiated a deficiency card. The
inspectors reviewed the deficiency card that identified the
discrepancies on the MWO used by the technician to re) lace the
failed relay. Also, reviewed was a second MWO with t1e same
control number that was prepared after the relay replacement. This
MWO corrected the discrepancies identified for the earlier MWO.
The inspectors reviewed MWO 1-97-1979 to determine if the
requirements of Administrative Control procedure 50AC-MNT-001-05.
" Maintenance Program." Rev. 25, were met for the maintenance work
activities. The following discrepancies were identified:
. Step 4.2.5 of the procedure required. in part that plant
maintenance be performed and controlled within the
boundaries of " work instructions" of MW0s and/or procedures.
Work instructions were not provided to replace a failed RMCS
relay.
Enclosure 2
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Section 8.2.2 and sub-step _8,2.1.2 required, in part, that
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block:23 of the MW0' state a specific sco)e of work using l
referenced material as ap)licabler The iWO failed to enter ,
the specific scope of. wort and references in block 23 of the
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MW0.
- -Step 8.5.-1 requires. in' part, that prior to the start of
. plant maintenance, the responsible personnel will perform a
-cursory review of the MWO package-to ensure the contents are'-
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adequate. Responsible operations and maintenance personnel- ,
.did not ensure that the contents of the MWO package were -
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adequate. -
-c- Conclusions a
The inspectors concluded that. operations supervision' failed to
- follow applicable procedures to correctly generate a MWO package' <
for a-RMCS relay replacement. - Additionally, operations 4
supervision authorized work and maintenance personnel performed
work'using the MW0. Operations'and maintenance personnel failed
-to ensure that the MWO package contents were adequate. This was
identified as an example of Violation (VIO) 50-321. 366/97-09-01,
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Failure to-Follow Procedure - Multiple Examples.
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04.3 Doerator Performance Durina Normal Plant Shutdown
a. Insoection Scoce (71707)
The inspectors reviewed an operating crew's performance and
management's corrective actions following deficiencies identified ,
during a forced outage of Unit 2-on September 15.
b. Observations and Findinas ,
-Unit 2 was being shut down to conduct a drywell entry to~ adjust
inboard main Steam Isolation Valve (MSIV) limit switches.
Maintenance activities associated with the limit switch
adjustments are discussed'in Section M1.4 of this Inspection
Report (IR), Following a manual scram from about 20% aower.
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reactor water level increased to about 88 inches, at w1ich time
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operators closed the HSIVs. About 36 inches is the normal reactor _ ~
water level. Maintaining an approximately normal reactor water
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-level is generally not a problem during a manual scram condition ,
from low )ower, and the MISVs are not normally closed during
routine slutdowns._ Closing the MSIVs isolated the RFPT (normal-
water control system) steam supply and the main condenser for
normal pressure control. These actions can complicate a routine -
manual scram and present additional challenges to the operating
" crew. The. operators stated that they. closed the MSIVs to prevent
-exceeding the reactor: vessel cooldown rate. The potential for
Enclosure 2
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exceeding the vessel cooldown rate was due to abnormally high
water level. Following the MSIV closure at 4:42 p.m. the Reactor-
Core Isolation Cooling System (RCIC) was manually placed in
service for reactor pressure control. The MSIVs were reopened at
6:40 p.m. and norml pressure control was established.
The inspectors-discussed the operating crews performance with
operations management. The inspectors were informed that the
perforinance of the operating crew did not meet managements
expectations. Operations management stated that the operators'
response to chcnging reactor water level was slow. Management
personnel also stated that operations )ersonnel were slow to reset
the reactor scram and this also contri)uted to the high reactor
water level.
Operations management and the operating crew conducted a critique
of the crew performance and unit response using unit chart
recorders and the safety parameter display system tape
information. Management stated the crew acknowledged that their
performance could be inproved. As part of the corrective actions,
simulator training was provided to the crew to practice similar
m&nual scram con itions. Additionally, low power reactor
shutdowns will be evaluated for inclusion into the regularly
scheduled operator license requalification training.
c. Conclusions
The inspectors concluded that the operating crew's performance
resulted in additional challenges durin9 a normal reactor manual scram. Operations management prompt actions to correct an
operating crew's weaknesses following a routine manual scre a on
Unit 2 was good.
04.4 Review of Unit 2 Emeraency Diesel Generator (EDG) Battery Charaer
Transfer
a. Insoection Scooe (71707) (92901) (62707)
The inspectors reviewed the circumstances associated with an
activity on September 11, when a plant equipment operator (PE0)
improperly transferred battery chargers for the 2A and 2C
Emergency Diesel Generator (EDG) 125-Volt Direct Current (VDC)
subsystems, rendering both subsystems inoperable. The inspectors
reviewed the ap)licable procedures, control room logs. TSs. rfi0s,
and discussed t11s problem with licensee management.
Enclosure 2
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b. Observations and Findinas
The control .roon -logs indicated that the unit shift supervisor had
authorized a maintenance electrician to conduct preventive
maintenance (PM) on battery charger feeder breakers in accordance
with MWO 29701339. In order to facilitate taking the battery
chargers out of service to perform the PM. the electrician
requested the assistance of the outside roving PE0 to transfer
battery chargers. The PE0 performed the transfer without using
)rocedure 34S0-R42-001-25. "125/250 VDC Station Service Charger
Rotation & Breaker Racking." and failed to connect the in-service
battery chargers to their respective 125 VDC cabinets. As a
result, both EDG 125-VDC subsystems were left misaligned with
control power being provided by the EDG batteries.
Control room operators subsequently received an annunciator for
" Battery Volts Low or Fuse Trouble" for both the 2A and 2C EDGs.
An operator was dispatched to investigate the problem. Normal
battery charger alignment was restored: however, the misaligned
battery chargers had rendered the 125-VDC subsystems inoperable
for a total of 36 minutes. Engineering conducted an analysis and
determined that a loss of function of the 2A and 2C 125-VDC
systems did not occur due to the fact that the total energy loss
from the batteries was only 2 amp-hours, compared to load profiles
of 66 amp-hours and 37 amp hours for the 2A and 2C DC subsystems,
respectively.
The inspectors reviewed procedure 34S0-R42-001-2S. Rev. 4, which
is classified as a " continuous use" procedure in accordance with
10AC-MGR-019 0S. " Procedure Use and Adherence." Rev. O.
Specifically MGR-01900S stated, in part, that a " continuous use"
procedure is required at work activities that affect safety-
related system operability, and that procedure steps will be
reviewed, read, and initialed during the activity. The inspectors
verified that the )rocedure was adequate to perform the DC system
transfers for the EDGs.
The inspector's review indicated that at the pre-job briefing, the
Unit 2 shift supervisor had designated a performance team PE0 to
perform the battery charger transfers. This PE0 was never in
attendance at the pre-job briefing, nor was the PE0 who
subsequently performed the improper transfer.
In addition, a review of the operations logs revealed that the
shift supervisor documented the maintenance being performed under
MWO 29701339 as " Battery Charger Clean and Inspect." when the
actual maintenance was to clean and inspection of the battery
charger feeder breakers. The inspectors determined that
operations * oversight and coordination of the battery charger
transfer evolution was poor.
Enclosure 2
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c. Conclusions
Operations demonstrated poor oversight and coordination of the
battery charger transfer activity. A PE0 failed to pro >erly
follow procedures governing continuous use activities tlat affect
the operability of EDG 2A and 2C 125-VDC subsystems. This failure
to follow procedures was identified as an example of Violation
(VIO) 50-321. 366/97-09-01. Failure to Follow Procedure - Multiple
Examples.
08 Miscellaneous Operations Issues (92901) (82301)
08.1 (Closed) IFI 50-321. 366/96-13-04: Inability to Correctly
Classify Events. This IFI was initiated following
misclassification of events during simulator scenarios observed
during a licensed operator requalification program assessment. The
licensee revised procedure 73EP-EIP-001-05. " Emergency
Classification and Initial Actions." to improve usability and
increase training emphasis on event classifications. Based upon
the inspectors' review of licensee actions and demonstrated
improvements in simulated event classifications this item is
closed.
08.2 (Closed) LER 50-366/97-09: Removal of DG Battery Chargers From
Service Results in Inoperability of Both the 2A and 2C DG DC
Electrical Power Subsystems. This LER is discussed in
Section 04.4 of this IR. Based upon the inspectors review of
licensee actions, this item is closed.
II. Maintenance
M1 Conduct of Mcintenance
M1.1 General Coments
a. Jnsoection Scoce (62707)
The inspectors observed or reviewed all or portions of the
following work activities:
. MWO 1-97-2223: realace RPIS 28 volt power supply
. MWO 1-96-2099: re) lock 1B EDG generater winding at next
outage
. MWO 1-96-3225: inspect 1B EDG engine per applicable
6-year PM procedures
. MWO 1-97-1998: perform inspection of 18 EDG jacket
, coolant pump in accordance with procedure
l . MWO 1-96-4145: Jerform 18-month grease inspection on
iPCI CST suction valve 1E41-F004
Enclosure 2
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-b. Observations and Findinas
The inspectors found that the work was performed with the work
packages present and being actively used.
c. Conclusions
Maintenance activities were generally completed in a thorough and
professional manner. No deficiencies were identified by the
inspectors for the maintenance activities observed.
M1.2 Rod Position Indicatina System (RPIS) and Drywell-to-Torus Vacuun
3reaker Problems on Unit 1
a. Insoection Scope (62707) (37551) (71707)
The inspectors observed portions of the work activities associated
with the re)lacement of the 28-volt RPIS power sup)ly and
discussed tie activity with the system engineer. )iscussions were
also conducted with operations' management concerning the opening
of a drywell-to-torus vacuum breaker during drywell venting
activities. Additionally the inspectors reviewed the Technical
Specifications (TSs). Technical Requirenent Manual (TRM). abnormal
operating procedure. MWO 1-97-2223. and applicable work packages
associated with the problems.
b. Qbservations and Findinas
Unit 1 entered TRM Action Statement. Section T3.3.3. on
September 16. due to an inoperable RPIS. The TRM Action Statement
required that the unit be in Mode 3 (Hot Shutdown) within 12
hours. The RPIS became inoperable due to a failed 28-volt power
supply. The operators lost a portion of the full core display
panel. Operators were able to determine control rod positions
using the process computer. The manual and automatic shutdown
functions of the control rods were still operable.
Similar RPIS and drywell-to-torus vacuum breaker (DW/ torus)
3roblems occurred on June 30 and July 20. The 5-volt power supply
lad failed for the RPIS system and the 1T48-F323F DW/ torus vacuum
breaker had failed to close due to mechanical binding. Details of
these problems are documented in section 01.3 of Inspection Report
(IR) 50-321, 366/97-07.
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The inspectors observed a portion of the RPIS power supply
replacement activity and its return to service. The system
indicating lights operated properly and the RPIS functioned
properly.
Enclosure 2
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Engineering personnel informed the inspectors thai; the current i
5 volt and 28-volt RPIS power supplies are obsolete and a design
change to realace the existing power sup) lies ds being prepared.
The design clange will be installed in tie future.
On Seatember 15 during drywell (DW) venting activities, the
IT48 323A DW to torus vacuum breaker openec and would not close.
Operations >'ersonnel entered the correct TS Required Action
Statement ( RS) 3.6.1.8. Suparession Chamber-to-Drywell Vacuum i
Breakers. This TS requires tlat the vacuum breaker ce closed
within two hours. The operating crew aligned the SBGT system to
take suction from the torus as allowed by procedure and the vacuum
breaker closed within the required two hours. The TS RAS for the
opened vacuum breaker was terminated.
Operations management informed the inspectors that the operating
crew allowed the DW-to-torus differential pressure (DP) to become
lower than desired during DW venting activities. The F323A vacuum
breaker has a history of opening sooner than the other vacuum
breakers, and it o]ened at the higher DP. Operations management
further informed t1e inspectors that a night order was written for
the operators to use during drywell venting activities. The night
order instructed the operators to keep the DW-to-torus DP greater
than 0.2 pounds per square inch differential (psid). The TS
opening setpoint is less than or equal to 0.5 psid. The
inspectors reviewed the night order and system operating procedure
3450-T48-002-15. " Containment Atmospheric Control and Dilution,"
Rev.1.6. and no deficiencies were identified.
The inspectors also reviewed Section T3.3.3 of the TRM and
abnormal operating procedure 34AB-C11-002-1S. "RPIS Failure."
Rev.1. Edition (ED) 1. to verify that the appropriate actions
were taken by the o)erating crew. The inspectors reviewed
MWO 1-97-2223 whic1 provided instruction for the replacement of
the 28-volt RPIS power supply. No deficiencies were identified.
c. Conclusions
Maintenance's response to the RPIS problem was timely; engineering
support of the maintenance activity was excellent: and operations
personnel took the appropriate actions for the RPIS failure.
Enclosure 2
_
.
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15
M1.3 LA Emeraency Diesel Generator Failure To Start Durina Surveillance
M ,
xa. -Insoection Scone (61726) (92902)
.
The inspectors reviewed applicable maintenance procedures,
associated MW0s,_and work packa9es associated with the repair of >
the 1A EDG following a: failure to start on September 4, 1997-.- The
inspectors discussed the EDG failure with operations, maintenance. ,
and engineering personnel.
b, l Observations and Findinas'
,
% ring the performance of surveillance test 34SV-R43-001-1S.
" Diesel Generator 1A Monthly Test." Rev. 17. ED1. the-1A EDG
failed to start. Operations personnel contacted maintenance for' ,
their assistance in troubleshooting activities. Operations
declared the EDG inoperable and initiated the correct TS RAS. The
maintenance investigation revealed that the fuel oil check valve
had stuck in the open position. This check valve is on the down-
stream: side of the injectors and allowed the fuel oil to drain
from the fuel oil header back into the clean fuel oil drain tank.
As a result an inadequate supply of fuel oil existed for the EDG ,
-
-start.
'
Maintenance replaced the-check valve and the EDG surveillance was
successfully completed. Hintenance and engineering personnel
o conducted a review of pa~ nerformance and repair history for the
check valves and issued at e Mneering evaluation to document the
results of the review. The mspectors reviewed the engineering
evaluation and other licensee documentation and observed the
following:
. .In 1987, all check valves (one for each of the five EDGs)
were replaced due to suspected problems.
, e From the total of five valves, two valves had 10 years or
more of service life with no problems. Check valves for
~
EDGs 2A and 2C were replaced in 1987 and in March 1997.
-respectively, with no problems observed.
. One valve had five years of service life with no problems.
The check valve for-EDG 1B was replaced in October 1992 and .
<
August 1997-, with.no problems observed.
L. One valve had less than five years of service life with one
failure.
. - The check-valve for EDG 1A was replaced in April 1993 and -
had failed in September 1997.
Enclosure 2
<
% - +e . . - . . - ---,e % .v -' ;m,- n.-m..y , r,-. , - - - , - -
..
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16
Maintenance personnel inspected the check valve installed in the
1C EDG and discovered that it was also open. The check valve was
replaced, and post maintenance testing was successfully performed.
The check valve had been replaced in March 1993.
The engineering evaluation recommended that the check valves be
replaced every five years, however, maintenance management was
evaluating whether or not the frequency snould be every 18 me hs.
The inspectors were informed that the check valve was suspected of
causing sluggish EDG start times in 1987. The inspectors were not
aware of any recent operability concerns or sluggish EDG start
proi>lems .
c. Conclusions
Maintenance and engineering support following the 1A Emergency
Diesel Generator failure to start on September 4 was excellent.
The review of past performance and repair history for the failed
fuel oil check valves that resulted in additional check valve
replacements demonstrated conservative decision making.
M1.4 Unit 2 Forced Outaae
a. Insoection Scooe (6270171
The inspectors reviewed applicable procedures and MW0s associated
with the main steam isolation valve (MSIV) limit switches on
Unit 2. Limit switch adjustments were discussed with maintenance,
engineering, and operations personnel. Additionally, the
inspectors reviewed procederes applicable to the repairs performed
on the low pressure coolant injection (LPCI) check valve during
the forced outage and discussed the re pairs with maintenance
management and engineering personnel
b. Observations and Findinas
On September 14. While performing quarterly MSIV surveillance
)rocedure 345V-B21-001-25. "MSIV Exercise and Closure Instrument
r unctional Test." Rev. 5. ED 1: the 2C71-K3G and 2C71-K3H relays
failed to re-energize when the 'O' inboard MSIV was returned to
its fully opened position. Because a s-imilar relay associated
with the 'B' MSIV was already de-energized due to a similar
failure during the previous surveillance a half scram resulted
which the operators were unable to reset. The failure of the
relay associated with the 'B' inboard MSIV is documented in
Section M1.3 of IR 50-321. 366/97-07.
The licensee decided to bring the unit to Hot Shutdown for entry
into the drywell to ins)ect and/or adjust the limit switches that
provide the signal to t1e relays that failed to re-energize.
Enclostre 2
.
. .. ~ - - . . - - - - - . . -. . .. . - - ~ . - . . - .
n +
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li .
Maintenance work was completed for limit switch adjustments and-
-
unit startup was commenced on September 18. The unit achieved
100% RTP on September 22.
Due to the failure of the relays to reset on September 14 and on
June 22,1the licensee initiated a root- cause investigation of the ,
MSIV limit switch problems. The licensee root cause investigation: !
concluded that the limit switch setup methodology was a-possible- ,
contributor to the problem.-.The-limit switch reset positions '
i criteria was not specified by procedure and was left to the *
judgement of the electrician performing the work. A new type of i
-
limit switch was installed during the-last unit refueling outage
and craft judgement-was again used to set the limit switch reset
positions. However, small changes in valve stroke length (due to
unknown causes) when steam flowed through the MSIV may have
prevented the' limit switches from resetting'when the MSIV-was very
close to the valve full-open position. Maintenance personnel also
determined that the new limit switch reset position was not :
consistent and predictable like the previous limit switches. The 4
4 root cause investigation report-recomnended that the maintenance
department revise applicable procedures to include specific
instructions on limit switch reset positions.
The inspectors reviewed surveillance procedure 52SV-B21-001-0S.
"MSIV Limit Switch Inspection," P.ev. 4. The revision of the
-
procedure included an addition which required a confirmation that
. the MSIV limit switch resets when the MSIV is taken back to the
fully opened )osition. Other procedure steps were either deleted
or added to t1e preventive maintenance procedure.
Health Physics personnel identified a leak on the Low Pressure
Coolant Injection (LPCI) check valve 2E11-F050B upon initial entry
-
into the drywell for the MSIV limit switch adjustment work
activity. The valve was leaking steam from the hinge pin area.
Maintenance attempted to stop the leak by torquing the hinge pin.
The valve was_ repacked after the torquing failed to stop the leak.
c. . Conclusions
l:
Management's oversight and pre-job plconing for forced outage
act'vities on the MSIV limit switch adjustment was good. Craft
<
personnel performed the work activity in a professional and timely
manner. Health Physics personnel demonstrated a aro-active-
attitude by identifying the LPCI check valve leac and notifying
maintenance.
,
L Enclosure 2
L
1-
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p
18
M2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Inocerable Unit 2 Hiah Pressure Coolant In.iection (HPCI) Pumo
a. Inspection Scone (62707)
On August 18 the Unit 2 HPCI pump was declared inoperable due to
a broken flange bushing that was discovered by maintenance
personnel. The inspectors reviewed a)plicable drawings.
3rocedures. TS. MW0s. Licensee Event Re] orts (LER), and the
Jpdated Final Safety Analysis Report (U SAR) associated with
repairs of the pump. The inspectors also held discussions with .
involved maintenance, engineering, and vendor personnel,
b. Observations and Findinas
On August 18. during a routine housekeeping wal!:down of the HPCI
system. maintenance personnel discovered pieces of metal in the
shaft drain casing of the HPCI main pump. The metal pieces were
from the pump shaft flange bushing (six pieces) and one of the
shaft's split rings. The flangt bushing is designed to limit the
water flow from the shaft of the pump in the event of a
catastrophic failure of the mechanical seal. The split ring is
one of two semicircular rings that assists in maintaining the
shaft sleeve in proper alignment.
Operations personnel declared the HPCI system inoperable after
being informed of the damage. The RAS of TS 3.5.1. Condition C,
was entered. The required 10 CFR 50.72 notification was made to
the NRC.
housing and
The inspectors
removal of pum) observed the disassembly
shaft components of the bearir.g/ repair
during the inspection
activities. T1e inspectors observed that the lubricant piping
removed was not immediately sealed for foreign material exclusion
(FME) control. The inspectors observed that sawing activitias of
metal components were in progress in the immediate area and had
the potential of FME contamination. Maintenance personnel
eventually taped the lubricant piping for FME protection. The
inspectors were later informed that the piping and components were
flushed and cleaned prior to installation.
The inspectors observed the recovered pieces of the bushing
flange. It was noted by the inspectors that all pieces necessary
to reconstruct the flange bushing were not present. The
inspectors were informed by maintenance personnel that six pieces
of the flange bushing were recovered and the remaining missing
part or parts were not found. A search of the immediate area was
conducted but did not locate the missing parts.
Enclosure 2
. . . _ _ _ . _ _ .. _ -- _ _ . . ~ _ - _ _ . . _ _
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d
1
-t
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19-
The licensee contacted the aump vendor to assist with the failure L '
mechanism determination. Tle inspectors discussed the possible
-
cause of the flang,e bushing failure with-the vendor
~
representative. nie vendor representative informed the inspectors
that he suspected that shaft movement caused by the bearing-
failure cn the-shaft between the main pump and the booster pump -
allowed the shaft to rub against'the flange bushing, thus causing ,
a: failure of the flange bushing.
The licensee suspected that the bearing failed due to a small
amount of particles that contaminated the main pump journal 1
2 earing housing. This caused damage to the bearing babbitt- .!
material which led to increased pump vibration sufficient in '
magnitude to cause the shaft-to impact, crack, and. break the-
flange bushing and displace the spl:t ring retainer. The licensee ;
indicated that the damage to the seal likely occurred during the
performance of the HPCI operability surveillance performed on
August 11, but was unable to determine the source and type of
.contamiration that caused the bearing damage.
The inspectors reviewed the data package for the most recently:
-performed o)erability surveillance procedure: 34SV-E41-002-2S, +
"HPCI Pump Operability." Rev. 26, and noted that the main pump
inboard horizontal vibration (point H03) was in the alert range.
This required the operability test to be performed at double the ,
normal frequency.
A review of MWO 2 96-0024 by the inspectors indicated that a small
i
water leak at the mechanical seals had been identified earlier.
Since the leak did not affect pump operability the work for the
mechanical seal repair / replacement was initially deferred until
>
the next Unit 2 refueling outage. The MWO was revised to include
the work scope for the replacement of the damaged bearing.' the
flange bushing and the split ring. All work was performed and the
HPCI-system was returned to an operable status-en August 24.
The inspectors reviewed LER 50 366/97-08, Main Pump Journal
> Bearing Damage Renders HPCI System Inoperable. As part of the
corrective actions, the licensee inspected and replaced the
i inboard and outboard main pump bearings and rebuilt the pump shaft
bearing. The damaged outboard main pump mechanical seal was
replaced and the bearing lubrication oil system was drained,
flushed, and cleaned. : The lubricating' oil system filters were
also replaced. Following-system repairs. maintenance engineering
personnel confirmed that vibration levels and alignment of the
l turbine and main' pump were within acceptable tolerances.
l Enclosure 2-
l
. - - _ - - .- - . - - . . - .. _- , , - _ . -.
. . . , - - --. -. - - ~ - - - - - - - - _ . . - _ --
,
,- ..- _;
-
1
.20-
The inspectors-reviewed vendor. drawings S-25084. "HPCI Pump he l
Sectional-GE VPF #3076-13." and the associated drawing for t
mechanical seals. Additior, ally. Unit 2 UFSAR Section 7.3.1.2.1. 1
'
High Pressure Coolant Injection System Instrumentation and
Centrol, was reviewed. No discrepancies were identified.
I
c. Conclusions--
Maintenance personnel's attention-to-detail during the walkdown
which discovered the broken pieces of the HFCI flange bushing was i
FME-
superior. Engineering support of maintenance was excellent.
control measures were satisfactory.
M2.2 Intake Structure Dredaina Activities
.
a. InsoectionScone(62727.1
The inspectors observed activities associated with the dredging
and cleaning of the intake structure water pit. The inspectors
also reviewed MWO 1-97-1453 and the data package of )rocedure
52PM-MME-006-05 " Intake Structure Pit Inspection." Rev. 6.
v Discussions were conducted with maintenance supervision and
engineering. A representative sampling of clearance tags was
verified,
b. Qbservations and Findinas
On September 26. the inspectors observed activities associated
with the preparation-to dredge and clean the intake structure pit.
The inspectors observed that a FME area boundary had been
established inside the intake structure on the ground level and
FME was properly controlled.
'
The inspectors verified that a representative sampling of the-
clearance tags associated with the work activity was properly-
placed.
The inspectors discussed communication aspects of this activity.
-with engineering and maintenance supervision. The inspectors
> observed that communications had been established with the divers.
the divers' attendant. the control room, and with a member of the
diving ~ team that--was located on the dredge platform.
The dredge platform was afloat-on the river with a suction hose.-
that ran through an opening in the travelling screens. The
opening was made by removing necessary sections of the traveling
e screen. The opening in the travelling screen was large enough to
insert an 8-inch diameter suction line into the pump suction pit
L
- area.
- Security personnel appropriately monitored the area.
Enclosure 2
!-
L
. _ , _ . - , . - . .,. - - _ ~ -
-
.
21
A review of MWO 1-97-1453 and the data package for procedure
52PM-MME-006-0S revealed that the intake pit dredging and cleaning
activity was completed by the divers on October 2. The divers had
cleaned the pit to an acceptable level per the requirements of
procedure 52PM-MME-006-0S.
c. Conclusions
The ins)ectors concluded that maintenance and engineering
oversialt of the activities was excellent. FME and security
control measures were appropriate. Communications and
departmental coordination was good.
H3 Maintenance Procedures and Documentation
M3.1 Surveillance Observations
a. Inspection Scoce (61726)
The inspectors observed various surveillance activities. The
procedJres to accomplish the activities provided instructions for
demonstrating that the referenced safety-related equipment
functioned as required by TSs and the Inservice Testing procram,
b. Qbiervations and Fin.fdn_qi
The inspectors observed all or pcrtions of the following Unit 1
and Unit 2 surveillance activities:
. 345V-E11-001-1S: Residual Heat Removal Pump Operability.
Rev. 20. ED 1
. 345V-E41-002-1S: HPCI Pump Operability. Rev. 21
. 345V-R43-003-2S: Diesel Generator 2C Monthly Test. Rev. 18
. 34SV-SUV-018-1S: ECCS Status Checks. Rev, 6
. 57SV-N62-001-2S: Off Gas Hydrogen Analyzer FT&C. Rev. 10
The inspectors attended the pre-evolution briefing for all of the
surveillance activities. During the Unit 1 HPCI o)erability
briefing, appropriate precautions were emphasized )y the Unit 1
Shift Supervisor regarding torus temperature. Communications
between maintenance, engineering operations, and HP personnel
were excellent. The inspectors observed that, during the test.
operations personnel were very cognizant of monitoring suppression
pool temperature. Coordination between the test lead operator and
the shift operator when placing the RHR system in the suppression
pool cooling mode was good.
The inspectors observed that during the Unit 1 RHR operability
pre-evolution briefing, the lead operator appeared unfamiliar with
specific aspects of the test as they related to items on the
Enclosure 2
.
.
22
pre-evolution checklist. Specifically, the operator was unsure of
what permission was required to initiate this surveillance,
whether FME would be a concern, and whether or not a post-
evolution briefing would be conducted to discuss results of the
test. The inspectors discussed this observation with operations
management.
During the Unit 1 RHR pump operability test, the inspectors
observed that operations personnel collected in Service Testing
(IST) vibration readings at two )oints on the motor mounting
flange in the radial direction. )ut took no axial vibration
readings. Discussions with the licensee's IST engineer and a
review of the RHR pum) IST plan revealed that these pumps were not
equipped with thrust 3 earings, therefore axial vibration readings
were not required.
The inspectors examined the IST test data for the 1A RHR pump and
verified that reference parameters were correctly extracted from
the Unit 1 IST data book. No deficiencies were identified,
c. Conclusions
For the surveillance activities observed, all data met the
required acceptance criteria and equipment performed
satisfactorily. The surveillance tests were conducted in
accordance with procedures and with cversight from supervisors and
system engineers. With minor excepticns, all involved personnel
were knowledgeable of the tests and system performance
requirements. Overall, performance was professional and
competent.
M3.2 Review of The American Society of Mechanical Enaineers (ASME) Code
Visual Examinations for Unit 2
a. Insoection Scoce (62707) (929021
The inspectors reviewed the work packages for maintenance
activities performed during the Unit 2 Spring Outage of 1997.
This review was to ascertain whether applicable visual
examinations, as required by Section XI of the ASME code, were
met. The inspectors conducted discussions with Quality Control
(OC) supervision and engineering. Additionally, the inspectors
reviesed the following plant procedures:
. Engineering Service Procedure 42EN-ENG-014-05. "ASME
Section XI Repair / Replacement." Rev. 9.
- Quality Control Procedure 450C-0CX-009-0S. " Quality Control
Document Review and Inspection Point Assignment." Rev. 5.
Enclosure 2
1
- .
, ,
c
_
23
-
- - Administrative C6ntrol: Procedure-40AC-0CX-001-05.J" Quality
Control -Inspection Program." Rev 7.
b. .0bsersations and Findinas
IThe ins)ectors were informed by quality control (0C) supervision
that-a QC review of work packages for the recent Unit 2 outage
(Spring 1997) revealed that-some required Section XI ASME code~
visual inspections were not performed. The work packages in-
question were 2-96-0834. 2 96-0836, and 2-97-0686. The work
packages were identified on deficiency card (DC) C09703695.
The inspectors discussed the work packages with engineering
~
personnel assigned to perform the root cause determination for the
deficiencies. Engineering informed the inspectors that the ASME
Section XI Code-required visual inspections (VT-1 and VT-3) were
performed but some were not performed per.the guidance provided 'in
procedure 42EN-ENG-014-05.
The inspectors reviewed the three work packages listed on
DC-C09703695, the Root Cause Analysis Summary for the DC, and the
engineering evaluation for the vendor-performed VT-1 for the
feedwater check valve hinge pin installation. This review
indicated the following:
,
. Work packages 2-96-0834 and 2-96-00836 provided wark
instructions for outage re) air / replacement activities on
safety relief valves.2B21 :013E and 2B21-F013G.
respectively. The work activity in question was for the
welding of a strap onto the safety relief valve to support a
pilot sensing tube. The licensee treated the work activity
as an ASME Section XI repair / replacement activity, thus
requiring a VT-3 examination. However, the VT-3 post
maintenance requirement was not listed on the Section XI
, Examination Plan, attachment 4. of procedure
'
42EN-ENG-014-05, and the VT ' was not com)leted. However.
l ' credit was taken after the tag because t1e OC inspector
c assigned to the work cctivities was VT-3 qualified and had
'
performed other visual examinations-on the valves. A review
-
of the ASME Section XI code revealed that this work was not
required to be treated as ASME Section XI.
-
- - Work package 2-97-0686 provided work instructions-for outage
repair / replacement activities performed cn feedwater inboard
check: valve-2821-F0108. The work activity in question was
for the installation of a new u) graded hinge-pin assembly.
The Quality Control Ins)ection )oint Assignment Sheet of
procedure 450C-0CX-0094S (generic hold point sheet)
required a VT-1 based upon the repair / replacement program.
This generic hold sheet was in the work package. A , t
Enclosure 2 4
o
i:
L
>
.=
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, .-
24
documentation review revealed that an initial baseline VT-1
-
(prior to valve hinge pin work) was performed by site OC
Sersonnel in accordance with the repair / replacement program,
Jut was not performed on the replacement bolting after the
new hinge pin was returned to service. An engineering
evaluation of the VT-1 performed by the vendor was conducted
by the licensee. The evaluation concluded that the visual
examinations performed by the vendor met all the
requirements to fulfill the ASME Section XI pre-service
examinations of a VT-1.
'
Procedural enhancertents were recently implemented for the
Section XI Examination Plan of procedure 42EN ENG-014-0S and the
Quality Control Ins)ection Point Assignment Sheet of procedure
450C-0CX-009-0S. T1ese enhancements provide more clarity as to
when post repair / replacement inspections are required.
The inspectors reviewea administrative control procedure
40AC-0CX-001-05. Step 8.6.5 of the procedure required, in part,
that th? qualified OC inspector perform inspections in accordance
with an a> proved Quality Control Inspect.on Point Assignment Sheet
(generic lold point sheet). Site OC personnel did not perform a
VT-1 inspection for replacement work activities on feedwater check
valve F010B during the Unit 2 spring outage of 1997 per plant
procedures. Credit was taken, after an engineering evaluation,
for a vendor-performed VT-1.
The inspectors reviewed licensee performance for the past two
years with respect to Section XI ASME code VT inspections. A
violation was identified in Ins)ection Report 50-321. 366/96-11
for a failure to perform an ASME Code-required VT-3 inspection on
HPCI Valve 1E41-F006. The inspectors concluded that the
circumstances surrounding the missed VT-3 on the HPCI valve were
different and the corrective actions for that violation would not
have reasonably prevented the VT-1 problem with the feedwater
check valve hinge pin replacement.
c. Conclusions
ASME Section XI code requirements for visual inspections were met
for the strap welding on the SRVs and the hinge pin replacement on
the feedwater inboard check valve. The acceptance of credit for
-the VT-1 performed by the vendor for the feedwater check valve was
reasonable. The inspectors concluded that site OC personnel
failed to follow the requirements of plant procedures for the VT-1
listed on the generic hold inspection sheet for replacement work
on the feedwater check valve hinge pin. This was identified as an
example of VIO 50-321, 366/97-09-01, Failure to Follow Procedure -
Multiple Examples.
Enclosure 2
l
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,
.
.
.
,
25
Review of Traversina Incore Probe (TIP) Flance Reolacement On
-
M3.3
Jnit 2
a.' -Insoection Scoce (62707) .
The inspectors reviewad procedure 42EN-ENG 014-0S. "ASME
Se: tion XI Repair / Replacement." Rev 9.-and documentation
associated with ASME Code.Section III. Class 2. requirements for 4
i
the Unit 2 primary containment' TIP penetration flanges,
'
b.. Observations and Findinas
The inspectors were informed by Nuclear Safety and Compliance
(NSAC). personnel that they were conducting a review of whether or -
not the Unit-2 primary containment TIP penetration flanges meet :
ASME Code Section III. Class 2. requirements. Table 3.2-1 of the
' Unit 2 UFSAR lists the TIP piping as ASME Code Section III.
Class 2. This included the flange. TIP tubing, and tubing valves.
This review was initiated following a review of maintenance work
activities conducted during the last Unit 2 refueling outage.
~
The inspectors reviewed E.I. Hatch Nuclear Plant Unit 2 Safety
Assessment for Primary Containment TIP Penetrations, dated
September 10, 1997, and Hatch Project Support - Engineering
Operability-Evaluation - Unit 2 TIP Penetrations, dated .
September 16. 1997. The inspectors also reviewed Table 3.2-1 of
the Unit 2 UFSAR.
GE h'd verbally informed the licensee that, even though the TIP
systen flanges were not what the code s)ecified in the UFSAR,
there was no operability concern with t1e TIP system. The
licensee stated that GE informed it that other sites had
identified similar problems with respect to the TIP system and
that the components supplied by GE were equivalent to those
required by ASME. By letter dated October 21. 1997. entitled-
Hatch Tip System ASME Code Compliance Evaluation. GE concluded
that the portion of the TIP system that is considered part of the
primary containment supplied for Hatch Units 1 and 2 during
construction and as replacement parts meet the intent of ASME
Section III. Class 2. The licensee also informed the inspectors
that a proposed UFSAR change for table 3.2-1 was being reviewed
=for the next scheduled UFSAR submittal.
The inspectors reviewed applicable documentation and observed that
all applicable-inspection requirements of the ASME code were met
following the flange installations on Unit 2.
Enclosure 2
. _
__ _ _ ._ _ _ _._ . _ _ _ . _.__ _ _ _ _ _ _
. - -- . . , . - ~- . - - . - - -- - -
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-;
9
26
1
c. -Conclusions- a
r
- -
The licensee had taken appropriate actions-to correct the TIP .
_.
'
.-System ASME code, Class 2-issues. ,The GE Code requirements of the '
-"
TIP equipment installed were equivalent to those of the ASME Code.
The proposed UFSAR revision was appropriate.
- M7_ Quality Assurance in Maintenance Activities ,
M7.1 Review of Safety Audit end Enaineerina Review (SAER) Audit
ReDort 97-SA-3 (62707)
The-inspectors reviewed audit report 97-SA-3. Ventilation Filter
Train Testing, dated July 24, 1997. The audit included a review
of procedures, methodology, and employee performance of testing
activities for plant-ventilation systems described in the
'
Technical Specifications (TSs) and UFSARs for both units to ensure
that the ventilation filter testing program was being correctly
implemented. The audit included a detailed review of the TS and
UFSAR requirements and the testing requirements and methodology
outlined in Regulatory Guide 1.52 and ASME/ ANSI N510.
The inspectors concluded that the audit was conducted by trained '
and qualified personnel. The audit was thorough and detailed. The
inspectors observed that the audit findings identified were
submitted to appropriate management and department personnel.
Corrective actions were-identified and tracked in accordance with *
applicable plant procedures. The corrective actions and proposed
completion-dates were appropriate for the findings.
M8- Miscellaneous Maintenance-Issues (92700) (92902)
M8.1 (Closed) LER 50-366/97-08: Main Pump Journal Bearing Damage
Renders HPCI System inoperable. This item is discussed in
Section M2.1 of this re)crt. Based u
- -
licensee actions,- this _ER is closed.pon the inspectors' review of
,
M8,2_ (Closed) IFT 50-321. 366/96-14-02: Potential Single Failure
Vulnerability in the Freeze Protection System. This item was
opened'to review whether or not a loss of power from Unit 1 to the
freeze protection for the service water cooling plaing to the
IB Emergency Diesel Generator (EDG) could impact t1e EDG's
operability support to Unit 2. Corportte engineering reviewed the
issue and determined that a potential Ligle failure vulnerability
in the freeze protection heat tracing system does not exist.
Based upon the ins
-dated February 10.pectors* review
1997, this item of the engineering evaluation.
is closed.
-
r
n Enclosure 2
'
, ,_ .
, , - . . - = . - . - - - . - - . - - - , - ,. - - . -
.
.
,
27
M8.3 (Closed) IFl 50-321/96-15 04: Switchyard Maintencnce and Material
Condition. Ihis item was initiated following an inspection to
evaluate electrical maintenance in the switchyard as it relates to
the Maintenance Rule. The following completed or long term
planned corrective actions associated with the IFl were described
in documentation provided by central scheduling personnel during a
discussion:
- An independent review team performed a thorough housekeeping
inspection of the switchyard on January 19.1997. The
inspection identified the items listed in the IFl and a
determination was made that che housekeeping and material
conditions did not meet the expectations and standards of
plaat Hatch, but no items were identified that were
- detrimental to the proper operation of switchyard equipment.
. An evaluation of overdue PMs indicated that they were not
applicable to Plant Hatch. PMs (performed every eight
years), which are applicable to Hatch, were current.
. The following long-term process was developed to avoid
future concerns:
Southern Transmission Maintenance Center (STMC) will ensure
that adequate housekeeping standards are maintained in the
,
Dispatchers in central scheduling will function as the
primary contact for planning and performing switchyard
maintenance.
STMC and central scheduling agreed that the policy and
practice will be that there will be no overdue PMs. Those
chat are currently overdue will be completed by the end of
the year.
STMC will arepare a yearly schcdule of planned PMs for
central scleduling to review and approve.
The inspectors performed a tour of t5e switchyards and the
switchyard cont N1 house on October 2. The inspectors questioned
central scheduling personnel about untaped s)are electrical leads
observed in the switchyard control house. Tlese electrical leads
were identified in the IFl. The inspectors were informed by
central scheduling and STMC personnel that it was a common
practice of the switchyard maintenance crew state wide, to leave
the ends of the electrical leads pointing straight up and un-
taped. Housekeeping and material conditions were good.
Enclosure 2
_ _ . . _ . _ _ _ _ _ _ _ _ _ . _ . . _ . . , _ . _ . . _ . - . _ _ . _ _ . _ . _ . _ _ _ . _ _ _
. ,
i
I
4
i
28 j
-Basea upon the inspectors * review of licensee actions, this item I
is closed. j
.
M8,4 (Closed) IFI 50-321. 366/97-0 D J: Review of Licensee's i
Assessment of the ALARA Process for the Unit 2 Reactor Coolant !
~
Leak Repair on the RWCll Heat Exchanger, This item was identified :
due to a significant difference between the ALARA staff's
estimated dose of (15 person rem) and the actual dose
, (28.33 person rem) received during the leak repair activities, '
The licensee conducted a review of the activities and identified i
that the type of welding process and the amount of welding- !
contributed to the dose received, Ins)ection report
50 321, 366/97-07- identified other worc coordination and
exmunication deficiencies that also contributed to the increased i
dose. The licensee's review did not identify any significant new l
information. The inspectors concluded that the initial ALARA !
assessment, the followup ALARA review, and the ALARA review .
methodology were satisfactory. Based upon the inspectors' review
3
of licensee actions, this item is closed.
III. Enaineerina
El Conduct of Engineering (37551)
On site engineering activities were reviewed to determine their
effectiveness in preventing, identifying, and resolving safety ;
issues, events, ma problems, ,
1
,
El.1 Review of Units 1 and ? Inadeauate Cable Seoaration Issues (37551) i
(92903)
The inspectors continued to monitor the licensee's progress and ;
work activities associated with the cable separation issue. This i
issue was originally documented as IFl 50-321, 366/97-03 05 and !
was discussed in Inspection Report 50 321, 366/97-07. The
inspectors have concluded that-the licensee is making progress in
resolving the issue.
E4 Engineering Staff Knowledge and Performance
E4,1 Pre Outaae Fuel Insoection and Preoaration
.a. Insoection Ccooe (60705l
The inspectors reviewed procedure 42FH ERP-012-05, "New Fuel and ;
-
New Channel Handling." Rev, 7. and observed licenree activities i
for new fuel receipt, inspection, and-storage. >
h
!
Enclosure 2
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.,.__._._,,..,m__ _ - . - - -
. _ - - -
.
-
. p
..
29 i
!
- b. Observations and Findinas j
i i
-The inspectors observed that new fuel received on site was i
'
temporarily stored at a location near the intake structure. The
area was properl ;
materials area. yThe identified
inspectors andobserved
controlled theasshi> a radioactive
ping crate
4 unloading, crate disassembly, and HP survey of tie new fuel. ;
Reactor engineering personnel were present and provided oversight
and direction of the activity. Inventory sheets-for .
accountability and tracking of the new fuel were completed. !
Security personnel provided satisfactory security oversight. ,
The inspectors observed new fuel inspection and channeling .
activities from the Unit I refueling floor. New fuel channels !
'
were Installed and the fuel was moved to the spent fuel pool for !
storage. 1
- c. Conclusions
The inspectors concluded that new fuel receipt. inspection, and ;
^
> storage were completed with appropriate oversight and control, and
in accordance with applicable plant 3rocedures. Engineering. HP. :
and security personnel support for t1e activity was satisfactory.
I E8 , Miscellaneous Engineering Issues (92903) $
E8.1 (Closed) IFI 50 321/96-14-05: Restoration of IB EDG Motor Control ,
Center (MCC). This item was initiated following the
implementation of temporary modification (TM) 1-96-41, This TM i
was implemented because the Unit 1 supply breaker in the IB EDG i
'
MCC 1R24-S026 did not coordinate properly with its downstream load
breakers. This was an operability concern for the MCC and the
IB EDG during events re
1
A fault at any of the r:on-safety quiring alignment
related loads ofsupplied
the 1B EDGfrom to Unit 1. ;
MCC 1B had the potential to cause the breaker to trip, thus
-
leaving the safety related loads su) plied by MCC IB inoperable.
The TM resolved the immediate opera)ility concern t./ moving the- .
non-safety related loads to another bus.
As a permanent resolution, the licensee implemented design change
.
request (DCR) 1 96-055. The.DCR modified safety-related EDG -
building 600/208-volt MCC 1B 1R24-S024 to eliminate possible
>
non coordination-between safety-related supply breakers and
downstream non safety related loads for certain postulated faults. '
Based upon the inspectors' review of DCR 1-96-055. licensee's- !
actions, and discussions with the system engineer, this item is
closed. ,
!
Enclosure 2
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.
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IV P1 ant Suooort- }
R1 Radiological Protection and Chemistry Controls t
i
R1.1 Observation of Routine Radioloaical Controls
a. insoection Scone (71750) )
General Health Physics (HP) activities were observed during the- {
report period. This included locked high radiation area doors. ,
proper radiological posting. and personnel frisking upon exiting j
the Radiologically Controlled Area (RCA). The inspectors made
- frequent tours of the RCA and discussed radiological controls with >
HP technicians and HP management. - Minor deficiencies were t
-
discussed with HP technicians and HP management personnel.
RI.2 person Exits Plant Site A'ter Receivina Alarm on the Exit Portal
ionitor Wearina Potentially Contaminated Clothina !
a. Insoection Scoce (71750)(92904) i
t
On September 29, 1997, a contract HP technician left the plant !
site after receiving an alarm on the exit portal' monitor. This i
was contrary to HP practices and plant procedures. The inspectors
-
,
reviewed documentation provided by HP personnel and plant ;
procedures. and discussed the issue with licensee management.
i
b. Observations and Findinas
On September 29, the ins)ectors were informed by HP supervision
that a contractor HP tec1nician exited the Plant Entry Security
Building (PESB) on September 26 after receiving an alarm on the
)ortal monitor. This portal monitor is located at the exit of the ,
)ESB and is the final monitoring point for contamination prior to
leaving the protective area.
l
The licensee informed the inspectors that upon initial exit
'
through the portal monitor the individual received an alarm.
Since.there was a HP technician monitoring personnel leaving the
area, to assure that the people used the exit portal monitor
properly, the individual was monitored using a PM 6 radiation
detector. This monitor also alarmed, The individual was
instructed to report-to the HP office for assistance in
determining why the contamination alarms were sounding. After
about 10 minutes. he returned to the PESB and attemated to exit
again. This time he again-received an alarm from tie monitor and
was told by the HP technician that he could not leave the site.
The individual ignored alarm and the instructions of the HP
-technician, exited the PESB.'and left the site. ,
!
Enclosure 2 ;
,
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--- -. - _ - -
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31- !
i
The inspectors reviewed a written statement provided by the HP l
foreman who spoke with the individual u)on his return to the HP k
-
office. The statement indicated that tle HP foreman did not
recall many of the details of the conversation he had with the
individual but did recall that the individual ap> eared unhappy
'
about not being allowed to exit.from the PESB. Tie individual did :
'
not agree with the reasons provided by the HP assigned at the exit '
point in the PESB for not allowing him to leave. The HP foreman
also indicated in the written statement that he is certain that he ,
would not have given the individual authorization to ignore an .
alarming portal monitor.-
j
,
in followup actions by the licensee. HP supervision called site -
security and requested that access to the protective area be
denied to the individual upon his return. The individual returned i
to the site the following morning (September 27) and was met at :
the entrance to the PESB by his contract su>ervisor and two HP i
-foremen. The individual was instructed by MP supervision to take
the weekend off and report back to work on Monday morning for a .
discussion of the issue with HP supervision. The individual
objected to returning the following Honday morning for a
discussion and indicated that he resigned.
The individual was then escorted to dosimetry by his contract i
supervisor for a whole body count. The results of the whole body I
count were normal and the individual was escorted to the exit of
the PESB. ,
The HP survey taken when the individual initially attempted to
exit the site indicated a reading of approximately 8500 .
disintegrations per minute (dpm) on one of the individual's knees. '
The portal monitor was set to alarm at 5000 dpm.
The inspectors were informed by HP personnel that four different
scenarios were run using computer modeling to determine a
hypothetical dose which the individual would have received. Each
scenario was based upon conservative assumptions and assumed a
point. source of radiation and a 4-hour exposure to the radiation.
Two of the scenarios constituted a set that assumed that the ;
contamination was due to the decay of noble gases-such as krypton.
'
xenon. and iodine. One of these scenarios assumed that the 8500
dpm obtained from the HP survey was contamination on the pant leg
with an air gap to the skin. The dose resulting from this.
scenario was 6 milli-rem (mrem) to the skin. The other scenario
in this set assumed that the contamination was on the skin.
resulting in a dose of 79 mrem to the skin.
Enclosure 2
. _ _ - _ _ _ -
-;
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. ~ , , -
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.
.
.
32
The remaining scenarios assumed that the 8500 dpm contamination
was from a hot particle that resulted from activated corrosion :
products. A 1 mrem dose was received when it was assumed that the '
contamination was on the pant leg with an air gap and 28 mrem
resulted when it was assumed that the contamination was on the
skin.
The results of the above computer modeling was provioM by Plant
Hatch's HP personnel to the company's corporate office. The
corporate office provided the information to the states of Georgia
and Alabama, Based upon the results of the computer modeling, the
states decided not to pursue the issue.
The inspectors were informed by Nuclear Safety and Compliance
management that the company will continue to pursue the matter '
because the contaminated clothing was not recovered for frisking.
The insores were later informed that telephone contact was
later m&:e M that the individual was reluctant to discuss the
issue. Tre &tn',ee also indicated that there is a high
probability t u the contamination was due to short-lived decay
products, but that there was a concern that it may be due to a hot
particle.
The inspectors reviewed Administrative Control Procedure
60AC-HPX-012-05. " Overview of Radiological Work Practices and
Radiation Protection ACPS." Revision 4. and observed that all
procedure requirements were not met. The cause of the
contamination alarm should have been determined and a)propriate
corrective actions taken before the individual left t1e site.
c. Conclusions
The inspectors concluded that the contract HP technician who left
the plant site after receiving an alarm on the exit portal monitor
presented minimal safety significance to the individual or public.
The actions taken by the licensee were appropriate and no further
NRC actions are planned based upon the fact that the individual is
no longer employed at the site and site access was immediately
terminated.
R1.3 Pre-Outaae Radiolooical Protection Activities
a. Insoection Scone (60705) (71750)
The inspectors observed licensee HP activities in preparation for
the upcoming Unit I refueling outage.
Enclosure 2
_ _
]
.
33
b. Observations and Findinas
The inspectors observed that HP management initiated several
actions to strengthen the HP area. Meetings were held with all
Hatch personnel to communicate management's expectations for HP
activities. The meetings included discussions on procedural
requirements, required actions for unexpected conditions, and
recent changes for radiological work permit (RWP) requirements.
Health Physics department management issued " Rad Bulletins" to
remind all plant personnel of the renewed emphasis for HP
improvements. The Bulletins communicated new RWP requirements a
special emphasis to eliminate personnel contaminations, and to
improve contamination controls and overall radiation worker
practices. The Bulletins were made available to all site
personnel. A new listing of radworker expectations was developed
ana conspicuously posted in various areas of the plant. HP
management developed a checklist for good rad practices. The
checklist was used as a quick reference and feedback tool by
various managers. supervisors, and coworkers during plant tours
and peer checks.
The General Manager conducted a period of stop work and assembled
all available aersonnel in order to communicate his expectations
for improved H) practices. A resident inspector attended the
meeting and observed that several key items were discussed. A
video tape was made available for site personnel who were not able
to attend the stop work meeting.
During the last refueling outage, and for the upc'aing Unit I
refueling outage the HP department conducted tours of the cite
for new contractor personnel. The inspectors observed one site
tour for new contractors. The tour included discussions for
site-specific frisking techniques, egress points, and routine
posting and boundaries. The licensee completed approximately 25
tours for about 150 personnel and additional tours were planned.
The inspectors attended several HP shift briefings and observed
some improvements in communications. specific job assignments, and
overall HP staff work practices. The inspectors observed
pre-staging activities for Unit I refueling activities and
observed that radiological and contamination control boundaries
were correctly established. The inspectors oLserved that HP
personnel routinely toured the site to assist other workers. The
inspectors observed some minor deficiencies that were attributed
to individual worker poor work practices. This included some
anti-contamination clothing that was not properly placed in the
l disposal containers. Other items were laying across the
- contamination control boundary markers, These deficiencies were
l
brought to the attention to HP personnel for resolution.
I
Enclosure 2
l
- . . - ---.- _~ ~ - _ - _ _ - - - - . - _ . . -
,
'
. # j
)
34
i
c. Conclusions l
t
i
The inspectors concluded that management personnel had placed
special emphasis for improved HP and general rad worker
activities. The stop work meeting, plant tours for- new
contractors, and radworker expectations list were identified as a
strength.
P4 Staff Knowledge and Performance in EP
P4.1 Annual Emeraency Preoaredness (EP) Exercise
- a. Insoection Scoce (82301)
The inspectors reviewed procedures 73EP-EIP 063 05. " Technical
Support Center Activation," Rev. 6, 73EP-EIP-001 05. " Emergency
Classification and Initial Actions," Rev.12. and the Hatch
Emergency Plan for Unit I and Unit 2. and observed licensee
actions during the annual exercise. Federal, state and county
officials participated in the annual exercise.
b. Observations and Findinas
On August 20, 1997, the inspectors participated in the licensee's
<
annual EP exercise. One inspector observed overall activities and
monitored licensee performance._ The inspectors observed operator
performance in the plant simulator technical support center
(TSC), operations support center (OSC) and emergency operation
facility (EOF). The inspectors concluded that operator
performance in the simulator was excellent. Operators correctly
classified the events in accordance with procedure
73EP EIP-001-0S. The inspectors observed that event
classification problems identified in past exercises had been
corrected. This was demonstrated by actual event classification
and observed in training and during this and previous exercises.
'
The inspectors noted that the TSC was activated in accordance with
procedure 73EP-EIP-063-05. The inspectors verified that minimum
" manning,hed.
establis Thecommunication inspectors observed links, and that TSC analysishabitability were
of plant
conditions and corrective actions were correct and appropriate.
- Interactions with offsite agencies were appropriate and timely.
- The.-inspectors noted that several people assigned to key TSC
positions were alternates. The inspectors confirmed that the
alternate personnel were qualified-to perform their assigned
.
-
positions.
.
'
Enclosure 2
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-'gw--4-gyam+gufe-- -u.agy-gy-p ma..pg#- c m; 4 3g grg.ip ,p p g - 4 7.s g 9 gg.99_.,-.-pys *'a-sr---g% y,%s Me-m-y-;-
_ .. _ _ _ - _.._e _ _ _. ____._ _ . _ . . _ _
,
.
'
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i
35
.The inspectors verified that the areas identified for improvement !
during previous exercises were addressed and had improved in all ;
'
areas. The inspectors did not identify an l
deficiencies with performance in the TSC. y significant i
The inspectors observed that control of the activities in the OSC l
> had improved over the last several exercises. Control, noise !'
level, and individual attention were areas on which the licensee
had placed increased emphasis during this and otner recent- ,
exercises. OSC performance during this exercise was excellent. :
The inspectors attended the post-exercise critique and observed i
that the licensee was very self-critical. Ope,n and frank
discussions were held with respect to ir.di,idual and overall' site
exercise performance. Areas for improvement were identified as
. well as aspects of the exercise that were considered strengths.
The ins)ectors identified the post exercise critique process as a
strengt1.
'
Following a detailed review and assessment of overall performance.
the licensee determined that all exercise objectives were met.
The inspectors did not identify any significant deficiencies,
c,. Conclusions
Overall performance during the annual exercise conducted on >
,
August 20, 1997, was good. Event classifications during the
exercise were correct. Operator performance in the simulator and
overall performance in the operations support center were '
excellent. .
S2 Status of Security Facilities and Equipment (71750)
The inspectors toured the protected area and observed that the :
perimeter fence was intact and not compromised by erosion nor !
disrepair. The fence fabric was secured and barbed wire was
angled as required by the licensee's Plant Security Program (PSP).
Isolation zones were maintained on both sides of the barrier and
were free of objects which could shield or conceal an individual.
The inspectors observed that personnel and packages entering the
protected area were searched either by special purpose detectors
or by a physical patdown for-firearms. explosives, and contraband.
Bad e issuance was observed, as was the processing and escorting
of isitors. Vehicles were searched, escorted, and secured as
described in applicable procedures.
The inspectors observed on the morning of August 21 that the
elevated lights at the front of the PESB were not lit. This
resulted in reduced visibility in the area leading to the entry to
Enclosure 2
.
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'
. .
36-
-the protected area. -The inspectors observed upon entry into the
protected area that a com)ensatory post was established to provide
a visual observation of tie area-leading to the entrance of the
PESB.
The inspectors concluded th'at the areas of security inspected met
the applicable requirements.
V. Manaoement Meetings
'X.2 Review of UFSAR Commitments
A recent discovery of a licensee operating its facility in a
manner contrary to the Updated Final Safety Analysis Report
(UFSAR)' description highlighted the need for a special focused
review that compares plant aractices, procedures and/or parameters-
to the UFSAR description. While performing the ins)ections
discussed in this re> ort the inspectors reviewed tie applicable
portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the
observed plant )ractices, procedures, and/or parameters, except as
noted above in )aragraph M3.3. Table 3.2-1 of the Unit 2 UFSAR
lists the TIP piping as ASME Code Section Ill. Class 2. This
included the flange. TIP tubing and tubing valves. All TIP
flanges, TIP tubing and tubing valves do not meet the ASME Code
Section 111. Class 2-requirement. The licensee is evaluating a
change to table 3.2-1 of the UFSAR for submittal.
X3 Exit Meeting Summary
The inspectors presented the inspection results to members of the
licensee management at the conclusion of the inspection on October
16. 1997. 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,
PARTIAL LIST OF PERSONS CONTACTED
Licensee
Anderson, J., Unit Superintendent
Betsill'. J., Assistant General Manager - Operations
Breitenbach.-C.. Engineering Support tanager - Acting
Curtis. S.. Unit Superintendent
Davis. D. Plant Administration Manager
Fornel. P, Performance Team Manager
Fraser. 0.. Safety Audit and Engineering Review Supervisor
Hammonds'. J., Operations Support Superintendent
Kirkley,LW.,- Health Physics and Chemistry Manager
Enclosure-2
1- .. _ _ .1 _ _i _ ._.i _. . _ ,
I
. l
.
.
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37
Lewis, J., Training and Emergency Preparedness Manager '
Madison. 0.. Operations Manager
Moore. C.. Assistant General Manager - Plant Support '
Reddick. R., Site Emergency Preparedness Coordinator
Roberts. P.. Outages and Planning Manager
Thompson. J., Nuclear Security Manager
Tipps. S.. Nuclear Safety and Compliance Manager
Wells. P. General Manager - Nuclear Plant
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 60705: Preparations for R.efueling
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support Activities
IP 82301: Evaluation Of Exercises for Power Reactors
IP 92700: Onsite follow up of Written Reports of Nonroutine
Events at Power Reactor Facilities
IP 92901: Followup - Operations
IP 92902: Followup - Maintenance / Surveillance
IP 92903: Followup - Followup Engineering
IP 92904: Followup - Plant Support
ITEMS OPENED. CLOSED AND DISCUSSED
Opened
50 321, 366/97-09-01 V10 Failure to Follow Procedures -
Multiple Examples (Sections
04.2. 08.2 and M3.2).
Closed
50-321, 366/96-13-04 IFI Inability to Correctly
Classify Events
(Section 08.1).
50-366/97-08 LER Main Pump Journal Bearing
Damage Renders HPCI Systen
Inoperable (Section M8.1).
50-321, 366/96 14-02 IFl Potential Single Failure
Vulnerability in the Freeze
Protection System
(Section M8.2).
Enclosure 2
.
. . .
.-
.
.. .
L
38
50-321, 366/97-07-01 IFl Review of Licensee's
Assessment of the A&LARA
Process for the Unit 2 Reactor
Coolant Leak Repair on the
RWCU Heat Exchanger
(Section M8.4).
50 321/96 14-05 IFI Restoration of IB EDG Motor
Control Center (MCC)
(Section E8.1).
50-321/96-15-04 IFI Switchyard Maintenance and
Material Condition
(Section M8.3).
50-366/97-09 LER Removal of DG Battery Chargers
From Service Results in
Inoperability of Both the 2A
Subsystems (Section 08.2).
Discussed
50 321, 366/97-03-05 IFI Review of 4160-VAC Wiring
Separation Deficiencies
(Section E1.1).
'
,
!
p
l
Enclosure 2
L
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