ML20058J244
| ML20058J244 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 11/17/1993 |
| From: | Balmain P, Brian Bonser, Skinner P, Starkey R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058J225 | List: |
| References | |
| 50-424-93-23, 50-425-93-23, NUDOCS 9312140020 | |
| Download: ML20058J244 (23) | |
See also: IR 05000424/1993023
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UNITED STATES
[p nes%. NUCLEAR REGULATORY COMMISSION
y+, k REGION 11
.. ; ~ 7, 101 MARIETTA STREET, N.W., SUITE 2900
% :s j ATLANTA. GEORGIA 30323-0199
% 4
%, .....f
Report Nos.: 50-424/93-23 and 50-425/93-23
' Licensee: Georgia Power Company
P. O. Box 1295
Birmingham, AL 35201
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Docket Nos.: 50-424 and 50-425 License Nos.: NPF-68 and HPF-81
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Facility Name: Vogtle 1 and 2
Inspection Conducted: September 19, 1993 - October 23, 1993
Inspector: h8 r,A # ' l'//f/f3
g,t B. R. B gnfe , Senior Resident Inspector Date Signed
&Al "/khe
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h . TT~gpkey, Resident Inspector Date Signed
... Ar Bal
.LM / II//fl%
,, ifr,) Resident Inspector Date Signed
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Approved by: )WF
P. Skinnef, Chief '
dV I/!/7/93
Date Signed-
Reactor Projects Section 3B
Division of Reactor Projects
SUMMARY
Scope: This routine, inspection entailed inspection in the following
areas: plant operations, surveillance, complex surveillance,
maintenance, mid loop / reduced inventory activities, modifications,
review of overtime records, startup from refueling, and review of
Independent Safety Engineering Group.
Results: One violation and one Inspector Followup Item (IFI) were
identified.
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The violation involved a failure to meet all the applicable
surveillanc? requirements for the Unit 2 Turbine Driven Auxiliary
feedwater (TDAFW) pump prior to entry into Mode 2 following a
refueling outage. The TDAFW pump was subsequently found
inoperable when the surveillance test was performed. The
, inspectors will also followup on the licensee's investigation into
the design change which led to the pump inoperability (paragraph
7b).
9312140020 931117
PDR ADOCK 05000424
G PDR
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The licensee requested an exemption from 10 CFR 50, Appendix J, !
Type C testing requirements, and an exigent Technical
Specification amendment related to Unit 1 Auxiliary Component i
Cooling Water (ACCW) system containment isolation valves. A safe- l
ty evaluation prepared for a 1992 change to the Final' Safety'
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Analysis Report for these valves failed to' consider that the ACCW !
system in containment is not a closed system and incorrectly i
concluded that Type C testing for these valves was not required. :
An IFI was opened to review safety evaluations in future inspec- i
tions to determine if this was an isolated occurrence (paragraph .!
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The inspectors reviewed the circumstances surrounding a ;
Notification of Unusual Event that was declared for a toxic gas ;
release onsite. There was a lack of guidance available to j
determine what constitutes a toxic gas release. The inspectors .!
will followup on this concern by reviewing the licensee's ;
corrective actions for this event (paragraph 2f).
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REPORT DETAILS
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1. Persons Contacted i
Licensee Employees
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J. Beasley, General Manager Nuclear Plant I
W. Burmeister, Manager Engineering Support. ,
- P. Burwinkel, Plant Engineering Supervisor !
- S. Chesnut, Manager Engineering Technical Support i
C. Christiansen, SAER Supervisor i
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R. Dorman, Manager Training and Emergency Preparedness
- W. Dunn, Jr., Unit Superintendent ;
- C. Eckert, Senior Technical Specialist, SAER I
G. Frederick, Manager Maintenance I
- W. Gabbard, Nuclear Specialist, Technical Support
M. Griffis, Manager Plant Modifications
- K. Holmes, Manager Operations
- D. Huyck, Nuclear Security Manager
- W. Kitchens, Assistant General Manager Plant Support
R. LeGrand, Manager Health Physics and ChemiS+ry
- G. McCarley, ISEG Supervisor
- A. Parton, Chemistry Superintendent
- S. Phillips, Maintenance Superintendent
- J. Roberts, Emergency Preparedness Coordinator
M. Sheibani, Nuclear Safety and Compliance Supervisor
- C. Stinespring, Manager Administration
- J. Swartzwelder, Manager Outage and Planning
Other licensee employees contacted included technicians, supervisors,
engineers, operators, maintenance personnel, quality control' inspectors,
and office personnel.
Oglethorpe Power Company Representative
T. Mozingo j
NRC Resident Inspectors
- B. Bonser
D. Starkey I
- P. Balmain l
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- Attended Exit Interview
An alphabetical list of abbreviations is located in the last paragraph ,
of the inspection report.
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2. Plant Operations (71707) l
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a. General 1
The inspection staff reviewed plant operations throughout the 1
reporting period to verify conformance with regulatory i
requirements, Technical Specifications, and administrative .i
controls. Control logs, shift supervisors' logs, shift relief i
records, LC0 status logs, night orders, standing orders, and
clearance logs were routinely reviewed. Discussions were i
conducted with plant operations, maintenance, chemistry, health ;
physics, engineering support and technical support personnel. ?
Daily plant status meetings were routinely attended. -l
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Activities within the control room were monitored during shifts l
and shift changes. Actions observed were conducted as required by a
the licensee's procedures. The complement of licensed personnel !
on each shift met or exceeded the minimum required by TS. Direct
observations were conducted of control room panels, i
instrumentation and recorder traces important to safety. l
4 Operating parameters were verified to be within TS limits. The. !
inspectors also reviewed DCs to determine whether the licensee'was !
, appropriately documenting problems and implementing corrective' i
actions. '
Plant tours were taken during the reporting period on a routine
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basis. They included, but were not limited to the turbine l
building, the auxiliary building, electrical equipment rooms, !
cable spreading rooms, NSCW towers, DG buildings, AFW buildings,
and the low voltage switchyard. The inspectors also periodically :
toured the Unit 2 containment building during the refueling
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During plant tours, housekeeping, security, equipment status and
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radiation control practices were observed.
The inspectors verified that the licensee's health physics- i
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policies / procedures were followed. This included observation of i
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HP practices and review of area surveys, radiation work permits,- :
postings, and instrument calibration.
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The inspectors verified that the security organization was i
properly manned and security personnel were capable of performing !
their assigned functions. Inspectors observed that persons and i
packages were checked prior to entry into the PA; vehicles were l
properly authorized, searched, and escorted within the PA; persons i
within the PA displayed photo identification badges; and personnel !
in vital areas were authorized. ~
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b. Unit 1 Summary i
The unit began the period operating at 100% power and' operated at '
full power throughout the inspection period. ;
c. Unit 2 Summary
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The unit began the period operating in Mode 6. Reactor defueling -!
was completed on September 24. Reactor refueling began and Mode 6 l
was entered on October 2. Mode 5 was entered on October 9. The t
. unit entered Mode 4 and Mode 3 on October 16. The unit entered
Mode 2 and was taken critical on October 18 and then entered Mode l
1 on October 20. The unit reached 100% power on October 23. l
d. Containment and Emergency Sump Walkdowns
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Periodically during the Unit 2 refueling outage the inspectors
performed walkdowns of the containment building. Prior to
entering Mode 4, the inspectors performed a containment walkdown- l
to verify that no obvious loose material was present in the !
a containment. The inspectors identified and removed several items !
including plastic bags and a hard hat. The inspectors also iden- !
tified several missing or loose fasteners on the emergency sump l
suction inlet strainers and brought these items to the attention - !
of licensee management, j
TS 4.5.2, ECCS, requires the licensee to perform a visual !
inspection of containment to verify that no debris is present that l
could be transported to the containment emergency sumps prior to ;
establishing containment integrity and entering Mode 4. TS 4.5.2 ;
also requires the licensee to perform a visual inspection of the
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containment emergency sumps and verification that the suction
inlet strainers are not restricted by debris. The inspector -
verified, from discussions with the Operations manager who
performed these containment surveillances, that any loose debris
found were removed from the containment and smergency sumps. The
inspector also reviewed completed surveillance procedures 14900-2, ;
Containment Exit Inspection, and 14903-2, Containment Emergency j
Sump Inspection, and verified that the results of the i
surveillances were adequate and met all acceptance criteria. l
e. ACCW TS Exemption Request >
On September 27, the licensee requested an exemption and exigent !
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TS amendment on Unit 1. The one time exemption requested an
exemption from 10 CFR 50, Appendix J requirements as they relate ;
to the Unit 1 ACCW supply and return containment isolation valves.
Appendix J requires that type C tests be performed during each ,
reactor shutdown for refueling but in no case at intervals greater l
than two years. The proposed exemption would allow the required .
test interval for valves IHV-1974 (and associated check valve !
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l-1217-U4-113), 1975, 1978, 1979 to be extended from 24 months to !
prior to entry into Mode 4 following the next scheduled refueling -l
outage or forced outage. The licensee also proposed to amend TS ;
4.6.1.2d, Containment Leakage Surveillance Requirements. )
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The licensee explained the basis for their request to' regional and l
headquarters NRC staff and the process to prepare an exigent TS l
amendment was initiated. The inspectors were primarily concerned !
, with the circumstances that led to the request. l
In February 1992, plant management approved an LDCR which revised !
containment penetration isolation valve information in the Vogtle i
FSAR with respect to'the ACCW supply and return containment .
isolation salves. Prior to the change the ACCW valves were !
subject to 10 CFR 50, Appendix J, Type C leakage testing j
requirements. The requirements were changed to only type A !
testing. l
The basis for the 1992 LDCR was that the ACCW valves do not i
receive a containment isolation signal (they are remote manually !
operated valves) and the associated penetrations are considered j
essential due to the desirability of maintaining cooling water to i
the RCPs under post-accident conditions. In addition,-it was i
thought that the ACCW system was a closed system since it does not l
communicate directly with the containment atmosphere or primary j
coolant. Type A testing was, therefore, considered sufficient for i
these penetrations. -]
The safety evaluation, however, failed to consider that the ACCW
. system in containment does not meet standards in ANSI N271-1976,
Containment Isolation Provisions for-Fluid Systems, .for closed
systems inside containment. Therefore the subject ACCW valves
should have been considered to perform an isolation function and
subject to Type C testing requirements.
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Further details describing the errors in the safety evaluation,
its safety impact and justification for the exemption and TS
change are contained in correspondence to the NRC dated September
30, 1993 and in LER 50-424/93-11. Although this error in the
, safety evaluation appeared to the inspectors to be an isolated
case, IFI 424,425/93-23-01, Review Licensee Safety Evaluations,
will be opened to monitor licensee safety evaluations for similar
,> mistakes. i
f. Notification of Unusual Event Due To Onsite Toxic Release
At 4:15 am on the morning of October 7, 1993, with Unit 2 in Mode
6, chemistry department personnel injected about 30 gallons of
hydrazine and about 15 gallons of ammonia into the Unit 2
feedwater system. These chemicals are used to prevent corrosion. i
in the steam generators during unit shutdown.
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At about 4:45 am a report of fumes in the control building was l
received and at 5:05 am a precautionary evacuation of portions of ,
the control building, the North Main Steam Valve room was i
initiated. .j
At about 5:30 am, 2HV-5195, a chemical injection system valve, was I
found to be leaking past the seat, through drain valves, and into l
a floor drain. The drain valves were closed to isolate the !
leakage and flushing of the floor drains with utility water was - :
begun. Liquid hydrazine and ammonia were flushed to the Waste l
Water Retention Basin where it was later neutralized. l
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At 5:43 am a NOUE was declared based on measured concentrations of
hydrazine fumes. Fumes inside the building were purged to the i
atmosphere. At about 9:05 am all areas were verified clear of ,
ammonia and hydrazine, and an announcement was made that all !
levels of the power block were released for access. At 10:09 am ;
the NOVE was terminated. During this event the atmosphere and -
ventilation in the control room were not affected.
The direct cause of the event was the failure to establish an
adequate flow path prior to commencing the injection of chemicals
into the feedwater system. This resulted in the SG wet layup pump
increasing system pressure until 2HV-5195 leaked by its seat and
out the system through the tagged open drain valves. Hoses had.
been attached to the drain valves to direct any system leakage to :
drains in the north main steam valve room. From there it was i
drained to the control building via a normally closed drain valve !
which had been left open due to maintenance activities that were j
in progress. Fumes from the chemicals carried out of the drain i
system and into the control building. l
The licensee's investigation determined that there were several- i
factors which led to this problem. The procedcres used to perform >
this task could be improved to give better guidance on adding
chemicals to SGs during wet layup using AFW chemical injection. .
The directions given for restoration of a valve in the chemical i
injection flow path were in error. Valve 2HV-5195 had been
identified earlier in the outage as leaking. A " priority 1" work ,
order was written to repair 2HV-5195 but was not worked promptly ,
and the valve was used incorrectly as a boundary valve for this
chemical injection. The inspectors were satisfied that the ,
licensee's critique identified the causes of this event and that !
appropriate corrective actions were recommended. The inspectors )
will follow the completion of the licensee's corrective for this !
event.
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The inspectors also reviewed the licensee's decision to classify '
this event as a NOUE. The licensee's emergency classification
procedures classify a toxic gas release as a NOVE. Uncontrolled
toxic gas or flammable gasses entering the protected area is
classified as an Alert. The SS declared the NOUE based on
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knowledge of the approximate quantity of chemicals released and l
knowing that the release path was isolated. The evacuation was l
performed as a precautionary measure. Hydrazine and ammonia air !
samples were taken, but there was no information available to j
interpret the data and determine the immediate affects of the ;
airborne concentrations or aetermine toxicity. Hydrazine is noted ;
especially as being potentially toxic. Hydrazine has a TLV of 0.1 ,
ppm. During the event, the concentrations in several areas were '
greater than the TLV. TLV, however, is a term to express the
airborne concentration of material to which people typically can
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be exposed day after day without adverse affects. Also, the ,
hydrazine used in the SGs is not pure hydrazine, which would i
mitigate the toxic affects. The inspectors concluded that the ;
licensee acted safely and conservatively in evacuating the control :
building and ieclaring an NOVE. The licensee has recognized the '
need for more definitive guidance on toxic gas concentrations. !
The inspectors as part of the followup to this event will review :
the licensee's corrective actions in this area. ,
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No violations or deviations were identified. ;
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3. Surveillance Observation (61726) (61701)
a. General
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Surveillance tests were reviewed by the inspector.s to verify i
procedural and performance adequacy. The completed tests reviewed l
were examined for necessary test prerequisites, instructions, ;
acceptance criteria, technical content, data collection, indepen- .
dent verification where required, handling of deficiencies noted, !
and review of completed work. The tests witnessed, in whole or in ,
part, were inspected to determine that approved procadures were !
available, equipment was calibrated, prerequisites were met, tests !
- were conducted according to procedure, test results were
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acceptable and systems restoration was completed. The !
surveillances reviewed are listed below: :
SURVEILLANCE NO. TITLE
14721-2 ECCS Subsystem Flow Balance and Checkvalve
Refueling IST, Section 5.2 ,
T-ENG-93-27 DP Stroke Test For 2-HV-8821A, 8821B, and ,
2-HV-8813 j
e 14666-2, 14667-2 Train A, Train B Diesel Generator and ,
ESFAS test :
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14807-2 Motor Driven Auxiliary Feedwater Pump
Inservice Test 7
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14808-2 Centrifugal Charging Pump and Check Valve
Inservice Test
14710-2 Remote Shutdown Panel Transfer Switch'and
Control Circuit 18 Month Surveillance Test
(CCP B)
28815-C Class IE Battery Performance Check
55047-C Class 1E Battery Performance Test Evalua-
tion
14785-2 Turbine Overspeed Trip Device Operability
Test
The inspectors did not identify any problems during the
observation of these maintenance activities.
b. Missed Containment Hydrogen Recombiner Surveillance
On October 13 control room personnel identified a missed semi-
annual TS surveillance test on the Unit 1 Train B Containment
Hydrogen Recombiner. Procedure 14970, Hydrogen Recombiner Func-
tional Test, requires the transfer of data from the~ previous sur-
veillance test before it is performed. When an operator went to
obtain the referenced data from the last B train test no copy of
the test procedure could be found. The licensee's investigation
identified that an A train test was performed instead of the B
train test. The surveillance task sheet had clearly stated Train
B, however, in the completed procedure recombiner A was circled.
TS 4.6.4.2.a, Electric Hydrogen Recombiners Surveillance Require-
ments, require that at least once per six months each recombiner
system shall be demonstrated operable by performing a functional
test. Since the B train test had not been performed within the
allowable time period this represented a missed surveillance and a
violation of the TS surveillance requirements. The licensee:
immediately entered the LCO and the train B testing was completed
satisfactorily
The inspectors reviewed this event and the corrective action with
licensee management. The inspectors concluded that this event was
an isolated personnel error by the supervisor that authorized, and
reviewed and approved the completed test. Since this was an
isolated event and caused by a personnel error this event was not
cited.
The inspectors will verify completion of the licensee's corrective
action through followup of LER 50-424/93-12.
No violations or deviations were identified.
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4. Complex Surveillance Observation (61701)
a. General
The inspectors observed surveillance testing of several of the
more complex safety-related systems and subsystems to verify
conformance with regulatory requirements and industry standards.
The inspectors witnessed portions of the surveillances discussed
in the following paragraphs to determine that test equipment was
calibrated; test prerequisites were completed; current revisions
of procedures were used; and actions taken for test failures or
out-of-specification conditions were in compliance with TS and
reporting requirements.
b. ECCS Subsystem Flow Balance
On September 29, the inspector observed the performance of
procedure 14721-2, ECCS Subsystem Flow Balance, Section 5.2,
Safety Injection Pump Cold Leg Injection. The acceptance criteria
of the test were met, however, the test results indicated that the
header flow rates for pumps A and B were 634 gpm 'and 631.4-gpm
respectively which exceeded the expected header flow rate of 620
gpm The pump miniflow rates for pumps A and B were 22 gpm and
25.7 gpm respectively which were below the expected miniflow of 30
gpm. Also the pump developed head during flow balancing was less
than the minimum allowable pump TDH. Total pump flow (header flow
+ miniflow), however, did not exceed the TS limit of 660 gpm for
either train.
The licensee, after Westinghouse evaluated the test data,
concluded that the test deviations were acceptable and that a
rebalance of the systems was not required. Furthermore,
Westinghouse is evaluating expanding the minimum and maximum flow
values and changing the pump curve.
The inspector reviewed the test data, discussed the data with the
system engineer, and reviewed the written response from
Westinghouse. Since TS limits were not exceeded and the licensee
took appropriate action to resolve the test data, the inspector
considers this action to be acceptable.
c. Diesel Generator ano ESFAS Testing
On October 1, the inspector observed the performance of procedure
14657-2, Train B Diesel Generator and ESFAS Test, section 5.1, 24
Hour Diesel Run. The inspector verified by reviewing data
collected on Data Sheet 1, that the 2B DG met the surveillance
requirements of TS 4.8.1.1.2.h.7 for the 24-hour test. The
inspector observed the hot restart portion of the surveillance
test and verified that the restart was initiated within-five
minutes after completion of the 24 hour-test. The DG did not
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achieve the required voltage and frequency within 11.4 seconds as
required by TS. This failure is further discussed in section Sc
of this report. Following repair of the 2B DG, the hot restart ,
was successfully completed on October 2. I
On October 4, the inspector observed performance of procedure
14667-2, Train A DG and ESFAS test, Section 5.2, LDSP and )
Concurrent SI. The inspector reviewed results documented in the i
completed procedure and verified that test results met the I
acceptance criteria of section 7.2. The inspector also reviewed
the failed component / test exception logs for both the A and B
train ESFAS tests and verified that test exceptions were retested
or dispositioned properly.
d. Review of 60 Month Battery Performance Surveillances
The inspector reviewed the results of surveillance procedure
28815-C, Class IE Battery Performance Check, for the Unit 2 Class
1E batteries and verified the calculated battery performance was
accurate and exceeded 80% of the manufacturers rating as required
by TS 4.8.2.1.e. The inspector reviewed performance test
evaluation data sheets for each of the 1E batteries to verify that
TS 4.8.2.1.f surveillance requirements to evaluate battery
degradation were met. None of the batteries showed signs of
, excessive degradation and were within 10% of the last performance
measurements. The 2C battery exhibited a 7% decrease in capacity,
which was the largest capacity decrease measured for the Unit 2
, batteries. Based on this review, the inspector did not have
concerns with the Unit 2 1E battery capability.
No violations or deviations were identified. 'l
1 5. Maintenance Observation (62703)
a. General ,
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Maintenance activities were reviewed during the reporting period
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to verify that work was conducted in accordance with approved
procedures, TSs, and applicable industry codes and standards. ,
Activities, procedures, and work orders were examined to verify !
proper authorization to begin work, provisions for fire, -1 '
cleanliness, and exposure control, proper return of equipment to
service, and that limiting conditions for operation were met. The
inspectors independently verified that selected equipment was
properly returned to service.
, The inspectors witnessed or reviewed the following maintenance
activities ,
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MWO N05. WORK DESCRIPTION
29301947 Recoat CCW HX A End Bell and Caps
29301523 AFW Pump A Replace Packing Configuration
With Mechanical Seals 1
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29301632 Bypass Test Instrumentation Panel 4
installation (Nuclear Instrument Rack #2) l
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29303314 Investigate and repair cause of DG 2B
axcessive start time during Hot Restart
test ,
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29301162,1165 Perform PM checklist SCL 00142 to verify ;
electrical and mechanical overspeed trips
on TDAFW turbine
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The inspectors did not identify any problems during the
observation of these maintenance activities.
b. Inspection of Diesel Generator Cylinder Liners ;
In January 1992, Cooper Industries, the Vogtle DG vendor, notified 1
the NRC (10 CFR Part 21 Report) of a potential cracking problem in l
TDI diesel generator power cylinder liners. The use of loose fit i
liners, which can result in liner movement in the block during
engine operation and liner cycle fatigue, was ' identified as the ,
root cause of the cracking problems. Each of the four Vogtle DGs i
are equipped with loose fit liners. In July 1993, Cooper issued i
an amendment to the Part 21 Report recommending a programmatic. :
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inspection schedule for engines with less than 3000 hours0.0347 days <br />0.833 hours <br />0.00496 weeks <br />0.00114 months <br /> run-
time. The program recommends inspecting a minimum sampling of 25% :
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of the liners beginning with the next refueling outage. During ;
1R4 the licensee inspected 4 liner's during the five year :
disassembly inspection of DG 1A. Three of the 4 liners inspected
had indications of cracking. One of the three liners was replaced :
due to a liquid penetrant indication 270 degrees around the liner.
The other two liners had only minor indications and were
reinstalled in the engine. Cooper recommends replacement if the
indication is 360 degrees around the liner. ,
During the current 2R3 refueling outage the inspector reviewed the
inspection process when six cylinder liners were removed from DG :
2A and liquid penetrant testing was performed. No indications-of 1
cracking were found by the licensee on the six liners. l
Ne.?rtheless, the six liners were replaced with new liners in
accoroonce with the licensee's outage plan. The six liners'will-
be shipped to Cooper for additional magnetic particle inspection. l
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The inspector determined that the licensee is following the i
recommended vendor inspection sampling of DG cylinder liners and ,
plans to continue these inspections during future refueling 'I'
outages. The inspectors will continue to monitor the results of
future cylinder liner inspections. :
c. 2B Diesel Generator Failure During Hot Restart Test
On October 1, during the hot restart portion of surveillance !
procedure 14667-2, Train B Diesel Generator and ESFAS test, the 2B i
DG failed to start within the time requirements of TS- :
4.8.1.1.2.h.7. Following the failure, the licensee's l
troubleshooting (MWO 29303314) revealed that the slow start was t
caused by debris clogging a pneumatic Timer /Not logic element !
located in the DG engine control system. I
j The Timer /Not element functions during a normal engine startup to i
disable the low lube oil pressure and high vibration trips, since
these conditions are expected when the engine is initially
started. After a short time delay (60 seconds) these trips are ,
reenabled and can function while the engine is operating. During i
a normal shutdown, a stop signal is initiated from the control ;
room and the engine control shutdown logic begins a shutdown
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sequence that isolates the fuel and intake air supplies to the
engine. The failure of the Timer /NOT logic element caused the low
lube oil pressure trip to remain blocked throughout the 24-hour ,
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test and subsequent shutdown sequence. When the shutdown sequence !
completed the timer /NOT element was reset which reenabled the low ,
lube oil pressure trip that caused a second shutdown sequence to ;
initiate immediately after the first. While the second shutdown ,
sequence was being processed, a start signal was actuated from the
control room approximately 2 minutes after the 24-hour test was
completed. The DG was delayed in starting, since isolation of the
fuel and air intake supplies reoccurred during this the second
shutdown sequence. The DG subsequently started after the second
shutdown sequence completed and reached required voltage and
frequency in approximately 2 minutes instead of 11.4 seconds as
required by TS.
The inspector reviewed the results of the licensee's event
investigation and verified that the failure of the Timer /Not logic ,
element resulted in disabling the 2B DG low lube oil pressure trip
and high vibration trips for the duration of the 24-hour test. l
The event critique team determined, by reviewing maintenance
functional testing procedures performed following DG maintenance ,
during the refueling outage, that the failure occurred subsequent :
l to the testing. The inspector concluded, since the unit was
defueled during this surveillance, that there was no safety
significance to the failure. In addition, although the failure ,
resulted in the degradation of engine protective trips, it did not i
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impair the ability of the DG to function as an onsite emergency
power supply. I
No violations or deviations were identified.
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6. Mid-loop / Reduced Inventory Activities (GL 88-17)
'
The inspector reviewed the licensee's preparation for midloop/ reduced
inventory activities for 2R3. The inspector verified that appropriate i
procedures were in place which addressed the concerns of Generic Letter l
88-17, Loss of Decay Heat Removal, dated October 17, 1988. A reduced
RCS inventory with fuel in the reactor vessel was not originally '
scheduled to occur during the 2R3 outage. However, midway through 2R3, 'i
with work progressing faster than expected on plant systems and slower
than expected on SG eddy current testing, the licensee determined that a !
time savings could be achieved by beginning refueling activities while l
SG eddy current testing continued. The midloop draindown permitted SG ;
nozzle dam removal and manway installation. During the midloop both DGs !
and the two off-site power sources were available.
The inspector reviewed the procedures for use during midloop/ reduced
inventory conditions and verified that they were active and implemented ;
requirements for the following areas: l
Containment closure capability for mitication of radioactive releases -
Procedure 14210-2, Containment Building Penetration Verification- !
Refueling, Rev. 8, is used to verify containment building penetration l
status prior to and during refueling, core alterations, or movement of i
irradiated fuel within the containment. Procedure 18019-C, Loss of !
Residual Heat Removal, Rev.15, states wMn to initiate containment :
closure procedure 14210-2 during a loss of RHR capability or-RCS !
leakage. Additionally, procedure 12008-C, Mid-Loop Operations, Rev.8, ,
requires that, while operating with the RCS level below 191 feet ;
elevation (reduced inventory is defined as 3 feet below the reactor
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vessel flange and the reactor vessel flange at Vogtle is at 194 feet),
the containment equipment hatch shall be closed with a minimum of four l
bolts. This limitation may be waived provided that: (1) A method is ;
provided for closing the containment equipment hatch without the use of ,
electrically operated equipment for blackout concerns; (2) The }
containment equipment hatch is capable of being closed with a minimum of
four bolts within 25 minutes without using electrically operated
equipment; (3) The containment equipment hatch is continuously manned :
with a hatch closure crew while operating the RCS level below 191 feet
elevation; and, (4) Four containment cooling units are operable and ;
capable of being started. Maintenance procedure, 27505-C, Opening and ;
Closing Containment Equipment Hatch, Rev. 4, gives direction for the ,
actual closing of the equipment hatch. l
RCS temperature indications - Procedure 12008-C, Mid-Loop Operations, j
Rev 8, requires a minimum of two incore thermocouples in opposite !
quadrants for use while the reactor head is installed. !
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RCS level indication - Procedure 12007-C, Refueling Operations, Rev. 28,
requires _that when RCS level is below 15% pressurizer cold calibration ~ ,
level (approximately 207 feet) that temporary RCS level indication must !
be installed. There are two independent Control Room indicators and a !
local RCS sight glass which are used to meet this requirement. :
Additionally, there is a control room recorder which is used to trend 3
changes in RCS level. An RCS sight glass watch is required any time the !
RCS level is being changed while the RCS level is below 15% pressurizer
level. With the control room temporary RCS level indicators in service, !
comparison checks are made every four hours between the Control Room
temporary RCS level indicators and the RCS sight glass using procedure !
11899-2, RCS Draindown Configuration Checklist. The Control Room ,
indicators should agree within seven per cent of scale with the sight l
glass. If neither Control Room RCS level indicator is available, then a $
continuous sight glass watch is established while RCS level is below 15%
pressurizer level. Similar temporary level indication requirements are 1
stated in Procedure 12006-C, Unit Cooldown to Cold Shutdown, Rev. 29, !
Section D. Procedure 23985-2, RCS Temporary Water Level System, Rev. 4, ;
provides instructions for the installation, channel calibration and
removal of the RCS Temporary Water Level System. ;
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RCS perturbations avoidance - Procedure 12008-C, Mid-Loop Operations,
Rev. 8, states that with the RCS level below 191 feet elevation, all ;
work activities should be closely scrutinized and to limit any work !
activity that has the potential for reducing RHR system capability. ;
RCS inventory addition - Procedure 18019-C, Loss of Residual Heat !
Removal, Rev.15, Attachment A, provides instructions to operators on ;
how to gravity drain the RWST to the RCS. Procedure 12007-C, Refueling !
Operations, Rev. 28 describes two boron injection flow paths, one of i
which must be available while in Mode 5 and 6. One of these flow paths :
is from the Boric Acid Storage Tank via a Boric Acid Transfer Pump and a ;
Charging pump to the RCS The second flow path is from the RWST via a i
charging pump to the RCS.
Nozzle dams / loon ston valves - Procedure 12008-C, Mid-Loop Operations, ,
Rev. 8, addresses the use of nozzle dams. This procedure states that if ;
a cold leg opening is not going to be established, then: (1) Remove the '
pressurizer manway, or (2) Remove a SG manway on a hot leg that will not
be dammed, or (3) Remove three pressurizer code safeties. If there is ,
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or will be a cold leg opening, then the only adequate vent path is to
remove a SG hot leg manway on a SG with no dam installed. l
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Renower to vital busses from alternate source if crimary source is lost
- Procedure 13427-2, 4160V AC IE Electrical Distribution System, Rev.
13, provides instructions on powering the 4160V IE Switchgear through
the emergency incoming breaker. Procedure 13417-2, Main and Unit- '
Auxiliary Transformer Backfeed to the 13.8KV and 4160V Busses, Rev. 7,
provides instructions for energizing 4160V IE Busses from the 4160V Non-
IE Busses when backfeed through the main and Unit Auxiliary Transformers. )
is the c11y off-site source of power available, DG 2A and 2B are
inoperable, and either RAT can be energized. <
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On October 7 and 8, Unit 2 was taken to mid-loop and level was i
subsequently restored without problems.
No violations or deviations were identified. !
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7. Modifications (37828) l
a. High Head Safety Injection Alternate Miniflow Line !
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The inspector reviewed DCP 91-V2N0157, including the safety l
evaluation, which implemented changes to the high head (CCP) !
safety injection alternate miniflow line. Accessible portions of !
the in plant changes were also walked down. These design changes !
were made during the ongoing Unit 2 refueling outage, 2R3, and I
will be made to Unit I during its next refueling outage. The CCP l
alternate miniflow is designed to protect the high head safety l
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injection pumps when the RCS repressurizes after a safety- :
injection is actuated such as in a secondary system break. The i
subject of high head safety injection alternate miniflow l
configuration has been previously addressed in NRC Inspection !
Reports 50-424,425/92-18, 92-20, and 92-27. l
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Prior to this design change, the alternate miniflow line consisted
of two motor operated valves in series, one of which was normally
closed and the other normally open, followed by a downstream
pressure relief valve. Flow through the alternate miniflow line ,
is directed to the RWST. Under the old configuration, the normal j
miniflow automatically isolated upon receipt of an SI signal, to i
ensure that all SI flow was directed to.the RCS and that the. !
normally closed alternate miniflow line M0V automatically opened j
with pressure maintained by the downstream relief valve. The DCP
removed the pressure relief valve, left in place the existing MOVs
and added logic to the operation of the normally closed MOV such
that it will operate in a pressure control mode following a safety
injection actuation. In this mode the MOV will open and close !
. based on CCP discharge pressura. A pressure switch was added at ;
the CCP discharge header of each train to control operation of the l
- associated M0V. Upon receipt of an SI signal, the pressure i
control mode will be automatically enabled. Each MOV will then ;
open if the CCP discharge pressure is above the setpoint of the l
associated pressure switch, and will close if the pressure falls ;
below the reset pressure. The existing CCP normal miniflow !
1 orifice in each train will be used to regulate flow in the l
alternate miniflow path by relocating the takeoff to the alternate !
miniflow path from upstream to downstream of' the orifice and by l
rerouting a portion of the alternate miniflow piping. .The nominal i
design flow rate for the alternate miniflow path is 60 gpm. A new :
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handswitch, with a " pull to lock" position, for the MOVs was ;
. installed to permit operators to manually enable the pressure i
control mode. !
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The inspector concluded that the licensee had performed an
adequate safety evaluation of this DCP and that this DC
represented a significant improvement over the previous alternate
miniflow piping configuration.
b. Turbine Driven Auxiliary Feedwater Pump Terry Turbine Speed
Ir strumentation Design Change
During the Unit 2 refueling outage the licensee replaced the
electrical speed monitoring instrumentation on the TDAFW pump
Terry turbine (DCP 93-VAN 0057). The electrical speed monitor on
the turbine has two functions. Output signals are sent to a local
tachometer and to the electrical overspeed relay that trips the
turbine on electrical overspeed. The existing speed
instrumentation was replaced because the instrumentation was
obsolete and replacement parts could not be readily obtained from.
the manufacturer. The design change replaced a single device
mounted in the TDAFW pump control panel with a replacement speed
monitor and associated DC to DC power supply. This DCP did not
change the system operation or response.
The design change was installed, the speed monitor was calibrated,
and an uncoupled run of the Terry turbine on auxiliary steam was
performed on October 13, to verify the accuracy of the electrical
and mechanical overspeed trip setpoints. At this point the
licensee considered the DCP functional testing complete and
satisfactory.
On October 17, with Unit 2 in Mode 3, monthly surveillance
procedure 14546-2, TDAFW Pump Operability Test, was run and
completed satisfactorily. This test verifies that the pump
delivers the required discharge pressure and flow. On October 19, s.
after entering Mode 2, the licensee started the TDAFW pump to run
procedure 14810, TDAFW Pump and Check' Valve IST Response Time Test
and Manual Initiating Handswitch TADOT. This test is a quarterly
IST and also verifies pump operability. The pump immediately
tripped on electrical overspeed at about 3500 rpm (electrical trip
setpoint is 4620 ISO rpm). The licensee declared the pump
inoperable and initiated an investigation.
After several hours of investigation the licensee found a problem
in the electrical overspeed instrumentation that was replaced as
part of the DCP. The licensee identified that the new DC power
supply to the speed sensing instrumentation was experiencing noise
when the DC powered MOVs in the TDAFW system cycled. The
interference from the power supply was transmitted through a low
voltage speed signal (measured in millivolts) used to actuate the
electrical overspeed trip. The signal, which is proportional to
speed, fluctuated significantly while the DC valves were
operating. The signal interference appeared to trip the pump only
when the TDAFW pump pressure differential controller was set at
full demand when the pump was started. Previous surveillance
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tests were not performed with the pump controller set at full j
demand during pump startup. This phenomenon occurred very quickly j
and was measured in milliseconds. After the licensee identified !
the problem and considered possible options, the original speed .l
instrumentation was reinstalled and the pump was verified j
operable. j
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The inspectors were concerned that the licensee had entered Mode 2 ;
and subsequently found the TDAFW pump inoperable. The inspectors i
reviewed the completed functional testing to verify the functional i
requirements of the design change were met. Although the !
functional testing appeared adequate, the inspectors were troubled 4
that the functional testing had not identified the problem. The !
inspectors also reviewed the surveillances the licensee had .
performed to verify operability of the TDAFW pump. Prior to {
entering Mode 2, the licensee had completed monthly surveillance !
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procedure 14546, TDAFW Pump Operability Test. Two other !
- surveillances were postponed, procedure 14810 and procedure 14748, !
AFW Pump and Check Valve Cold Shutdown IST And TDAFW Pump Auto j
Start-Test. Procedure 14748 is an 18 month surveillance that, in i
part, verifies that automatic valves in the AFW flow path actuate !
to their correct position and that the TDAFW pump starts
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automatically upon receipt of an AFW actuation test signal. The ,
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TDAFW pump is in automatic and water is injected into the SGs !
j during this test. The inspectors agreed that it would create l
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unnecessary risk to the plant to perform this test in Mode 3 when ;
the plant is not making nuclear heat and could not recover quickly j
to the introduction of cold water into the SGs. The inspectors, !
however, did not agree with the licensee's decision to postpone i
procedure 14810 to Mode 2. This is an IST surveillance that is i
run at least quarterly and is part of the Section XI ASME Boiler l
and Pressure Vessel Code IST program, which is part of the TS ,
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Surveillance hequirements. The inspectors concluded that
performance of this test was necessary prior to entry into Mode 2 l
since the pump had been uncoupled and gone through routine !
servicing. Had this test been performed in Mode 3 the licensee
would have identified prior to Mode 2 that the pump was j
inoperable. l
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TS 4.0.4, Surveillance Requirements, establishes the requirement }
that all applicable surveillances must be met before entry into an ;
operational mode. The purpose being to ensure that' system and '
component operability requirements or parameter limits are met :
before entry into a mode for which these systems ensure safe I
operation of the facility. The inspectors concluded that the l
licensee was in error when procedure 14810 was not performed prior ;
to entry into Mode 2 and violated the requirements established in }
TS 4.0.4. This is identified as a violation, VIO 425/93-23-01, l
Entry Into An Operational Mode Before Meeting LC0 Surveillance !
Requirements. l
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The licensee has initiated an investigation into the TDAFW pump
speed sensing instrumentation design change to determine the
causes behind the inadequate DCP. The inspectors will review the
investigation when it is complete,
c. Review of Sequencer Functional Testing
During this inspection period, the inspector observed sequencer
functional testing and reviewed the completed testing procedures
performed under T-ENG 93-22 and 93-23, A Train and B Train
Sequencer Functional Test. These procedures controlled the
functional testing of the Unit 2 sequencers following installation
of DCP 92-V2N040, Automatic Reset and DCP 92-V2N0172, ATI Step 61
Anomaly Correction. The inspector verified, during observation of
several test SI actuations from the sequencer manual test panel,
that the ATI function was restored and the step 61 anomaly was
eliminated. The inspector also verified, by reviewing completed
test procedures, that the sequencer automatic reset during a mid
sequence DG trip functioned as designed.
d. Review of Bypass Test Instrumentation Installation
During the inspection period the inspector observed portions of
BTI panel installation on Unit 2 and observed testing activities
following the installation. The BTI was designed with the intent-
of bypassing (instead of tripping) RPS channels during TS required
surveillances. The inspector witnessed several connections being
wire-wrapped and verified the pin connections were made according
to MWO work instructions. The inspector also observed functional
testing of the BTI panel for NIS rack #2 and verified it was
acceptable. The inspector had no concerns based on this review.
One violation was identified.
8. Review of Overtime Records
During this inspection period the inspector reviewed a sample of
overtime records for members of the plant staff who perform safety-
related functions. The inspector performed this review to verify
compliance with the requirements of TS 6.2.2.e, Plant Staff, which
provides guidelines to limit the working hours of the plant staff in
performance of safety-related functions. The inspector also reviewed
procedure 00005-C, Overtime Authorization, and verified that the
procedure implemented controls to limit working hours as required by TS 6.2.2.e.
The inspector reviewed a sample of timesheets for personnel in the
Operations Department (September 20 - October 1), Health
Physics / Chemistry Department (October 4 - October 16) and I&C,
Electrical and Mechanical Maintenance Departments (September 6 -
September 18). The inspector identified one isolated occurrence in the
Operations Department where greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a seven day period
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was worked without the written authorization required by procedure )
00005-C. The licensee completed this documentation following j
identification of the discrepancy. The inspector did not identify any '
additional cmcerns.
The inspector noted, during the review, that deviations from TS 6.2.2.e ,
guidelines were approved in accordance with procedure 00005-C. In I
addition, the inspector noted that excess overtime was not considered on j
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an individual basis for the Mechanical and Electrical Maintenance
Department and was approved by the maintenance manager and authorized by {
the general manager prior to exceeding TS guidelines. The inspector i
verified that this met the requirements of TS 6.2.2.e since the overtime 3
was used during an extended period of shutdown for refueling. i
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No violations or deviations were identified.
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9. Plant Startup from Refueling (71711) j
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Following the Unit 2 refueling outage the inspectors observed portions i
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of the plant startup, heatup, approach to criticality and core physics i
testing activities. During the plant heatup the inspectors verified !
that activities were performed according to procedure 12001-C, Unit j
Heatup to Hot Shutdown (Mode 5 to Mode 4) and procedure 12002-C, Unit j
Heatup to Normal Operating Temperature and Pressure (Mode 4 to Mode 3). ;
The inspectors witnessed initial startup activities and approach to !
. criticality in the main control room and verified proper control room f
conduct. The inspectors observed portions of core physics testing !
conducted in accordance with 88002-C, Reload Low Power Physics Testing, l
and witnessed portions of the isothermal temperature coefficient g
measurement and reference bank reactivity determination. The inspectors !
also observed activities conducted under procedure 80019-C, Power !
Ascension After Refueling.
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No violations or deviations were identified.
10. Review of Independent Safety Engineering Group (40500)
!
During the inspection period the inspectors evaluated ISEG. The }
inspectors focussed on determining whether ISEG is effective in .
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achieving its stated purpose. The ISEG is required by TS to examine
plant operating characteristics, NRC issuances, industry advisories, ;
LERs, and other sources of plant design and operating experience
Information, which may indicate areas for improving plant safety. ISEG ;
is also required to make detailed recommendations for improving plant
safety to the Vice President Nuclear. l
The ISEG is part of the SNC SAER organization and reports to the manager
of SAER in the SNC headquarters office. ISEG personnel are located on ;
site and are a full time group consisting of a supervisor and four group l
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members. Currently all five ISEG members possess bachelors degrees in
- engineering or science. The Vogtle TSs were recently revised to allow 6
professional experience in lieu of a degree for ISEG membership. One ;
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member holus an SRO license the other group members have received plant ~ .
specific systems training. ISEG members have also received root cause i
analysis training.
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The inspectors reviewed current ISEG administrative procedures which
provide organizational policies, responsibilities and program guidance. ;
The ISEG program was reviewed with the ISEG supervisor, several critique l
- meetings were recently attended, and ISEG monthly reports, special
reports, NRC Information Notice reviews, event critiques and shutdown !
risk assessments were reviewed. j
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ISEG carries out their program requirements through several types of
reviews and assessments. The operating experience program reviews
industry information mostly issued by INP0 and NRC Information Notices. :
The reviews verify current plant practices or make recommendations'when
applicable. ISEG routinely participates or leads plant event critiques. ;
The critiques result in the identification of the causes of events and i
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thr identification of corractive action recommendations to plant ;
f sanagement. ISEG also performs HPES evaluations of less significant i
events and identifies lessons learned and makes corrective action i
recommendations. The group performs special projects as requested by ;
management. Recent special projects have consisted of a review of the i'
use and implementation of Standing Orders.and a review of how concerns
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regarding Interfacing System LOCAs have been addressed. ISEG also j
! conducts qualitative shutdown risk assessments. The risk assessments ;
consist of a review and comment on the outage schedule prior to the j
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outage and a review and assessment of shutdown plant conditions during ;
the outage. ISEG activities and the results of reviews are documented !
in a monthly report to the Vice President Nuclear. j
The inspectors concluded from this review and other observations of ISEG .
activities that this group is effectively fulfilling the !
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l- responsibilities specified in the TS. ISEG activities are providing a
continuing and independent assessment of plant activities through the
operating experience program, event critiques and HPES reviews, and ,
outage risk assessments. The assessments and recommendations resulting
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from these activities are substantive and plant management is responsive ;
i to them. :
11. Exit Meeting
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y The inspection scope and findings were summarized on October 22,
1993, with those persons indicated in paragraph I. The' inspector '
described the areas inspected and discussed in detail the inspection i
findings listed below. No dissenting comments were received from the j
licensee. The licensee did not identify as proprietary any of the
material provided to or reviewed by the inspectors during the ,
inspection. !
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Item No. Description and Reference l
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VIO 425/93-23-01 Entry Into An Operational Mode Before Meeting l
LC0 Surveillance Requirements (paragraph 7b) j
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IFI 424,425/93-23-02 Review Licensee Safety Evaluations (paragraph
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2e)
12. Abbreviations _
AC - Alternating Current f
ACCW - Auxiliary Component Cooling Water System l
AFW - Auxiliary Feedwater System .
ANSI - American National Standards Institute !
ASME - American Society of Mechanical Engineers !
ATI - Automatic Test Insertion >
BTI - Bypass Test Instrumentation !
CAS - Central Alarm Station ;
CCP - Centrifigal Charging Pump !
- CCW - Component Cooling Water .;
- CFR - Code of Federal Regulations ,
DC - Deficiency Card
DC - Direct Current !
DCP - Design Change Package i
1 DG - Diesel Generator i
DP - Differential Pressure :
1 ECCS - Emergency Core Cooling System i
ESFAS - Engineered Safety Features Actuation System ;
FSAR - Final Safety Analysis Report :
GL - Generic Letter !
gpm - gallons per minute i
HP - Health Physics !
HPES - Human Performance Evaluation System i
j HX - Heat Exchanger !
j I&C - Instrumentation and Controls !
-
IFI - Inspector Followup Item t
INP0 - Institute for Nuclear Power Operations !
IR - Inspection Report 1
ISEG - Independent Safety Engineering Group >
IST - Inservice Test ,
j LC0 - Limiting Condition for Operation !
, LDCR - Licensing Document Change Request !
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LER - Licensee Event Report
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LOCA - Loss of Coolant Accident :
LOSP - Loss of Offsite Power !
MOV - Motor Operated Valve l
MWO - Maintenance Work Order !'
NCV - Non-Cited Violation
NIS - Nuclear Instrumentation System i
NOUE - Notification of Unusual Event i
NPF - Nuclear Power Facility i
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NRC - Nuclear Regulatory Commission
NSCW - Nuclear Service Cooling Water System i
PA - Protected Area !
PM - Preventive Maintenance ;
ppm - parts per million
RAT - Reserve Auxiliary Transformer
RCP - Reactor Coolant Pump !
RHR - Residual Heat Removal System
rpm - revolutions per minute
RPS - Reactor Protection System ;
RWST - Refueling Water Storage Tank
SAER - Safety Audit And Engineering Review l
SI - Safety Injection
SNC - Southern Nuclear Company l'
SRO - Senior Reactor Operator
SS - Shift Supervisor j
TADOT - Trip Actuating Device Operational Test l
TDAFW - Turbine Driven Auxiliary Feedwater Pump ;
TDH - Total Developed Head l
TLV - Threshold Limit Value ;
TS - Technical Specifications ;
URI - Unresolved Item
V10 - Violation l
2R3 - Unit 2 Third Refueling Outage
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